Form 20-F BP PLC For: Dec 31
Exhibit 2 DESCRIPTION OF SECURITIES REGISTERED UNDER SECTION 12 OF THE EXCHANGE ACT As of 31 December 2020 BP p.l.c. (“BP,” the “Company,” “we,” “us,” and “our”) had the following series of securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934: Title of each class Name of each exchange on which registered American Depositary Shares New York Stock Exchange Ordinary Shares of 25c each New York Stock Exchange(*) Floating Rate Guaranteed Notes due 2021 New York Stock Exchange Floating Rate Guaranteed Notes due 2022 New York Stock Exchange 4.742% Guaranteed Notes due 2021 New York Stock Exchange 3.561% Guaranteed Notes due 2021 New York Stock Exchange 2.112% Guaranteed Notes due 2021 New York Stock Exchange 2.500% Guaranteed Notes due 2022 New York Stock Exchange 2.520% Guaranteed Notes due 2022 New York Stock Exchange 3.245% Guaranteed Notes due 2022 New York Stock Exchange 3.062% Guaranteed Notes due 2022 New York Stock Exchange 2.750% Guaranteed Notes due 2023 New York Stock Exchange 2.937% Guaranteed Notes due 2023 New York Stock Exchange 3.216% Guaranteed Notes due 2023 New York Stock Exchange 3.994% Guaranteed Notes due 2023 New York Stock Exchange 3.535% Guaranteed Notes due 2024 New York Stock Exchange 3.814% Guaranteed Notes due 2024 New York Stock Exchange 3.224% Guaranteed Notes due 2024 New York Stock Exchange 3.790% Guaranteed Notes due 2024 New York Stock Exchange 3.194% Guaranteed Notes due 2025 New York Stock Exchange 3.506% Guaranteed Notes due 2025 New York Stock Exchange 3.796% Guaranteed Notes due 2025 New York Stock Exchange 3.119% Guaranteed Notes due 2026 New York Stock Exchange 3.410% Guaranteed Notes due 2026 New York Stock Exchange 3.017% Guaranteed Notes due 2027 New York Stock Exchange 3.279% Guaranteed Notes due 2027 New York Stock Exchange 3.543% Guaranteed Notes due 2027 New York Stock Exchange 3.588% Guaranteed Notes due 2027 New York Stock Exchange 3.723% Guaranteed Notes due 2028 New York Stock Exchange 3.937% Guaranteed Notes due 2028 New York Stock Exchange 4.234% Guaranteed Notes due 2028 New York Stock Exchange 1.749% Guaranteed Notes due 2030 New York Stock Exchange 3.633% Guaranteed Notes due 2030 New York Stock Exchange 2.772% Guaranteed Notes due 2050 New York Stock Exchange 3.000% Guaranteed Notes due 2050 New York Stock Exchange
2 3.067% Guaranteed Notes due 2050 New York Stock Exchange 2.939% Guaranteed Notes due 2051 New York Stock Exchange 4.375% Perpetual Subordinated Non-Call 5.25 Fixed Rate Reset Notes New York Stock Exchange 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes New York Stock Exchange (*) Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission. Capitalized terms used but not defined herein have the meanings given to them in BP’s Annual Report and Form 20-F 2020. I. ORDINARY SHARES The following description of our ordinary shares of US$0.25 each is a summary and does not purport to be complete. It is subject to and qualified in its entirety by BP’s Articles of Association and by the Companies Act 2006 (the “Act”) and any other applicable English law concerning companies, as amended from time to time. A copy of BP’s Articles of Association is filed as Exhibit 1 to BP’s Annual Report and Form 20-F 2020. A. General The number of ordinary shares outstanding at 31 December 2020, excluding treasury shares, and including certain shares that will be issuable in the future under employee share-based payment plans was 20,264,027,711. The primary market for the company’s ordinary shares (trading symbol ‘BP.’) is the London Stock Exchange (LSE). The company’s ordinary shares are a constituent element of the Financial Times Stock Exchange 100 Index. In the US, the company’s securities are listed and traded on the New York Stock Exchange (NYSE) in the form of ADSs (trading symbol ‘BP’), for which JPMorgan Chase Bank, N.A. is the depositary (the Depositary) and transfer agent. The Depositary’s principal office is 383 Madison Avenue, Floor 11, New York, NY, 10179, US. Each ADS represents six ordinary shares. ADSs are evidenced by American depositary receipts (ADRs), which may be issued in either certificated or book entry form. The company's ordinary shares are also traded in the form of a global depositary certificate representing the company's ordinary shares on the Frankfurt, Hamburg and Dusseldorf Stock Exchanges. All of the existing issued BP ordinary shares are fully paid. BP ordinary shares are represented in certificated registered form and also in uncertificated form under “CREST”. CREST is an electronic settlement system in the U.K. which enables BP ordinary shares to be evidenced and transferred electronically without use of a physical certificate. B. Dividend rights If recommended by the directors of BP, shareholders of BP may, by resolution, declare dividends but no such dividend may be declared in excess of the amount recommended by the directors. The directors may also pay interim dividends without obtaining shareholder approval. No dividend may be paid other than out of profits available for distribution, as determined under IFRS and the Act. Dividends on ordinary shares are payable only after payment of dividends on BP preference shares. Any dividend unclaimed after a period of 10 years from the date of declaration of such dividend shall be forfeited and reverts to BP. If the company
3 exercises its right to forfeit shares and sells shares belonging to an untraced shareholder then any entitlement to claim dividends or other monies unclaimed in respect of those shares will be for a period of twelve months after the sale. The company may take such steps as the directors decide are appropriate in the circumstances to trace the member entitled and the sale may be made at such time and on such terms as the directors may decide. The directors have the power to declare and pay dividends in any currency provided that a sterling equivalent is announced. It is not the company’s intention to change its current policy of paying dividends in US dollars. At the company’s AGM held on 15 April 2010, shareholders approved the introduction of a Scrip Dividend Programme (the “Scrip Programme”) and to include provisions in the Articles of Association to enable the company to operate the Scrip Programme. The Scrip Programme was renewed at the company’s AGM held on 21 May 2018 for a further three years. The Scrip Programme enables ordinary shareholders and BP ADS holders to elect to receive new fully paid ordinary shares (or BP ADSs in the case of BP ADS holders) instead of cash. The operation of the Scrip Programme is always subject to the directors’ decision to make the scrip offer available in respect of any particular dividend. Should the directors decide not to offer the scrip in respect of any particular dividend, cash will automatically be paid instead. The directors may determine in relation to any scrip dividend plan or programme how the costs of the programme will be met, the minimum number of ordinary shares required in order to be able to participate in the programme and any arrangements to deal with legal and practical difficulties in any particular territory. Apart from shareholders’ rights to share in BP’s profits by dividend (if any is declared or announced), BP’s Articles of Association provide that the directors may set aside: • A special reserve fund out of the balance of profits each year to make up any deficit of cumulative dividend on the BP preference shares. • A general reserve out of the balance of profits each year, which shall be applicable for any purpose to which the profits of the company may properly be applied. This may include capitalization of such sum, pursuant to an ordinary shareholders’ resolution, and distribution to shareholders as if it were distributed by way of a dividend on the ordinary shares or in paying up in full unissued ordinary shares for allotment and distribution as bonus shares. Any such sums so deposited may be distributed in accordance with the manner of distribution of dividends as described above. Holders of shares are not subject to calls on capital by the company, provided that the amounts required to be paid on issue have been paid off. All shares are fully paid. C. Voting rights BP’s Articles of Association provide that voting on resolutions at a shareholders’ meeting will be decided on a poll other than resolutions of a procedural nature, which may be decided on a show of hands. If voting is on a poll, every shareholder who is present in person or by proxy has one vote for every ordinary share held and two votes for every £5 in nominal amount of BP preference shares held. If voting is on a show of hands, each shareholder who is present at the meeting in person or whose duly appointed proxy is present in person will have one vote, regardless of the number of shares held, unless a poll is requested. Shareholders do not have cumulative voting rights. For the purposes of determining which persons are entitled to attend or vote at a shareholders’ meeting and how many votes such persons may cast, the company may specify in the notice of the meeting a time, not
4 more than 48 hours before the time of the meeting, by which a person who holds shares in registered form must be entered on the company’s register of members in order to have the right to attend or vote at the meeting or to appoint a proxy to do so. Holders on record of ordinary shares may appoint a proxy, including a beneficial owner of those shares, to attend, speak and vote on their behalf at any shareholders’ meeting, provided that a duly completed proxy form is received not less than 48 hours (or such shorter time as the directors may determine) before the time of the meeting or adjourned meeting or, where the poll is to be taken after the date of the meeting, not less than 24 hours (or such shorter time as the directors may determine) before the time of the poll. Proxies may be delivered electronically. Corporations who are members of the company may appoint one or more persons to act as their representative or representatives at any shareholders’ meeting provided that the company may require a corporate representative to produce a certified copy of the resolution appointing them before they are permitted to exercise their powers. Matters are transacted at shareholders’ meetings by the proposing and passing of resolutions, of which there are two types: ordinary or special. An ordinary resolution requires the affirmative vote of a majority of the votes of those persons voting at a meeting at which there is a quorum. A special resolution requires the affirmative vote of not less than three quarters of the persons voting at a meeting at which there is a quorum. Any AGM requires 21 clear days’ notice. The notice period for any other general meeting is 14 clear days subject to the company obtaining annual shareholder approval, failing which, a 21 clear day notice period will apply. D. Liquidation rights; redemption provisions In the event of a liquidation of BP, after payment of all liabilities and applicable deductions under UK laws and subject to the payment of secured creditors, the holders of BP preference shares would be entitled to the sum of (1) the capital paid up on such shares plus, (2) accrued and unpaid dividends and (3) a premium equal to the higher of (a) 10% of the capital paid up on the BP preference shares and (b) the excess of the average market price over par value of such shares on the London Stock Exchange during the previous six months. The remaining assets (if any) would be divided pro rata among the holders of ordinary shares. Without prejudice to any special rights previously conferred on the holders of any class of shares, BP may issue any share with such preferred, deferred or other special rights, or subject to such restrictions as the shareholders by resolution determine (or, in the absence of any such resolutions, by determination of the directors), and may issue shares that are to be or may be redeemed. Subject to authorisation by shareholder resolution, BP may purchase its own shares in accordance with the Act. E. Pre-emption rights and new issues of shares Under Section 549 of the Act, the directors are, with certain exceptions, unable to allot equity securities without the authority of the shareholders in a general meeting. The term “equity securities” as defined in the Act includes BP ordinary shares or securities convertible into BP ordinary shares. In addition, Section 561 of the Act imposes further restrictions on the issue of equity securities (as defined in the Act, which would include BP ordinary shares or securities convertible into BP ordinary shares) which are, or are to be, paid up wholly in cash and not first offered to existing shareholders in proportion to their existing
5 shareholdings. Holders of BP ADSs would, acting through the Depositary, be entitled to participate in any such preemptive offer. BP’s Articles of Association authorize the directors to issue equity securities subject to the provisions of the Act and any resolution passed by shareholders in general meeting (such authority is sought on an annual basis). In accordance with institutional investor guidelines, the company deems it appropriate to grant authority to the directors to allot shares and other securities and to disapply pre-emption rights by way of shareholders resolutions at each AGM in place of authority granted by virtue of the company’s Articles of Association. At the AGM on 27 May 2020, authorization was given to the directors to allot shares in the company and to grant rights to subscribe for, or to convert any security into, shares in the company up to an aggregate nominal amount as if section 561(1) of the Act (providing for pre-emption rights for the shareholders of a company in respect of allotments by such company of its equity securities) did not apply. The resolutions dis-applying pre-emption rights comply with institutional shareholder guidance and in particular the Statement of Principles on Disapplying Pre-Emption Rights most recently published by the Pre-Emption Group. These authorities were given for the period until the next AGM in 2021 or 27 August 2021, whichever is the earlier. These authorities are renewed annually at the AGM. F. Variation of rights The rights attached to any class of shares may be varied with the consent in writing of holders of 75% of the shares of that class or on the adoption of a special resolution passed at a separate meeting of the holders of the shares of that class. At every such separate meeting, all of the provisions of the Articles of Association relating to proceedings at a general meeting apply, except that the quorum with respect to a meeting to change the rights attached to the preference shares is 10% or more of the shares of that class, and the quorum to change the rights attached to the ordinary shares is one third or more of the shares of that class. G. Shareholders’ meetings and notices Shareholders must provide BP with a postal or electronic address in the UK to be entitled to receive notice of shareholders’ meetings. Holders of BP ADSs are entitled to receive notices under the terms of the deposit agreement relating to BP ADSs. The substance and timing of notices are described above under the heading Voting rights. Under the Act, the AGM of shareholders must be held once every year, within each six month period beginning with the day following the company’s accounting reference date. All general meetings shall be held at a time and place determined by the directors. If any shareholders’ meeting is adjourned for lack of quorum, notice of the time and place of the adjourned meeting may be given in any lawful manner, including electronically. Powers exist for action to be taken either before or at the meeting by authorized officers to ensure its orderly conduct and safety of those attending. The directors have power to convene a general meeting which is a hybrid meeting, that is to provide facilities for shareholders to attend a meeting which is being held at a physical place by electronic means as well (but not to convene a purely electronic meeting). The provisions of the Articles of Association in relation to satellite meetings permit facilities being provided by electronic means to allow those persons at each place to participate in the meeting. H. Limitations on voting and shareholding
6 There are no limitations, either under the laws of the UK or under the company’s Articles of Association, restricting the right of non-resident or foreign owners to hold or vote BP ordinary or preference shares in the company other than limitations that would generally apply to all of the shareholders and limitations applicable to certain countries and persons subject to EU economic sanctions or those sanctions adopted by the UK government which implement resolutions of the Security Council of the United Nations. I. Transfer of Shares Except as described in this paragraph, the Articles of Association do not restrict the transferability of BP ordinary shares. BP ordinary shares may be transferred by an instrument in any usual form or in any other form acceptable to the directors. The directors may refuse to register a transfer: • if it is of shares which are not fully paid; or • if it is in favor of more than four persons jointly BP may not refuse to register transfers of BP ordinary shares if it would prevent dealings in the shares on the London Stock Exchange from taking place on an open and proper basis. J. Disclosure of interests in shares The Act permits a public company to give notice to any person whom the company believes to be or, at any time during the three years prior to the issue of the notice, to have been interested in its voting shares requiring them to disclose certain information with respect to those interests. Failure to supply the information required may lead to disenfranchisement of the relevant shares and a prohibition on their transfer and receipt of dividends and other payments in respect of those shares and any new shares in the company issued in respect of those shares. In this context the term ‘interest’ is widely defined and will generally include an interest of any kind whatsoever in voting shares, including any interest of a holder of BP ADSs. There are no provisions in the BP’s Articles of Association whereby persons acquiring, holding or disposing of a certain percentage of BP’s shares are required to make disclosure of their ownership percentage, although there are such requirements under Part 6 of the Financial Services and Markets Act 2000 and Rule 5 of the Disclosure Guidance and Transparency Rules made by the Financial Conduct Authority (successor to the UK Financial Services Authority). These requirements impose a statutory obligation on a person to notify BP and the Financial Conduct Authority of the percentage of the voting rights in BP such person directly or indirectly holds or controls, or has rights over, through his direct or indirect holding of certain financial instruments, if the percentage of those voting rights: • reaches, exceeds or falls below 3% and/or any subsequent whole percentage figure as a result of an acquisition or disposal of shares or financial instruments; or • reaches, exceeds or falls below any such threshold as a result of any change in the breakdown or number of voting rights attached to shares in BP. The Disclosure Guidance and Transparency Rules set out in detail the circumstances in which an obligation of disclosure will arise, as well as certain exemptions from those obligations for specified persons. Under section 793 of the Act, BP may, by notice in writing, require a person that BP knows or has reasonable cause to believe is or was during the three years preceding the date of notice interested in BP’s shares to indicate whether or not that is the case and, if that person does or did hold an interest in BP’s shares, to provide certain information as set out in that Act.
7 Article 19 of the EU Market Abuse Regulation (2014/596) further requires persons discharging managerial responsibilities within BP (and their persons closely associated) to notify BP of transactions conducted on their own account in BP shares or derivatives or certain financial instruments relating to BP shares. The City Code on Takeovers and Mergers also imposes strict disclosure requirements with regard to dealings in the securities of an offeror or offeree company on all parties to a takeover and also on their respective associates during the course of an offer period. K. Company records and service of notice In relation to notices not covered by the Act, the reference to notice by advertisement in a national newspaper also includes advertisements via other means such as a public announcement.
8 II. AMERICAN DEPOSITARY SHARES A. General The ordinary shares of BP may be issued in the form of American Depositary Shares (ADSs). Each ADS represents six ordinary shares. ADSs are listed on the NYSE. ADSs are evidenced by American depositary receipts (ADRs), which may be issued in either certificated or book entry form. JPMorgan Chase Bank, N.A. is the depositary (the “Depositary”) and transfer agent. Each ADS represents an ownership interest in six ordinary shares deposited with the custodian, as agent of the depositary, under the Second Amended and Restated Deposit Agreement, dated 6 December 2013, as amended (the Deposit Agreement). The Depositary’s principal office is presently located at 383 Madison Avenue, Floor 11, New York, NY, 10179, US. You may hold ADSs either directly or indirectly through your broker or other financial institution. If you hold ADSs directly, by having an ADS registered in your name on the books of the depositary, you are an ADR holder. If you hold the ADSs through your broker or financial institution nominee, you must rely on the procedures of such broker or financial institution to assert the rights of an ADR holder described in this section. You should consult with your broker or financial institution to find out what those procedures are. The following is a summary of the material terms of the Deposit Agreement. Because it is a summary, it does not contain all the information that may be important to you. For more complete information, you should read the entire form of Deposit Agreement and the form of ADR, which contain the terms of the ADSs. Please refer to Exhibit 99.(A) filed on a post-effective amendment to Form F-6 (File No. 333- 144817) with the SEC on 12 June 2013, Exhibit 99.(a)(2) filed on a post-effective amendment to Form F- 6 (File No. 333-144817) with the SEC on 9 February 2017 and Exhibit 99.(a)(3) filed on a post-effective amendment to Form F-6 (File No. 333-144817) with the SEC on 27 March 2020. Copies of the Deposit Agreement are also available for inspection at the offices of the Depositary. B. Voting Procedure Record holders of BP ADSs are also entitled to attend, speak and vote at any shareholders’ meeting of BP by the appointment by the Depositary of them as proxies in respect of the ordinary shares represented by their ADSs. Each such proxy may also appoint a proxy. Alternatively, holders of BP ADSs are entitled to vote by supplying their voting instructions to the Depositary, who will vote the ordinary shares represented by their ADSs in accordance with their instructions. If ADSs are held indirectly through a brokerage account or otherwise in street name, the holder must rely on the procedures established by his or her broker or financial institution to assert the rights of ADS holders described in this section. In the event a situation arises where the aggregate number of votes to be cast by or on behalf of the Depositary at a BP shareholder meeting exceeds the total number of ordinary shares registered in the name of the Depositary or its custodian as of the record date for ordinary shares, the BP Articles of Association provide an adjustment mechanism intended to ensure that the Depositary may only vote those shares which are registered in its name at the record date for ordinary shares. The adjustment may be made on a pro rata basis or may be made with respect to specific votes. In any circumstance where the Depositary is unable to make an adjustment, the chairman may make any adjustment of the votes to be cast by or on behalf of the Depositary on a pro rata basis or in such other manner as may have been prescribed by regulations or procedures established by the directors.
9 Except in respect of an adjustment of votes as described in the preceding paragraph, if any question arises as to whether an ADS holder, as proxy for the Depositary, or the proxy of an ADS holder, has been validly appointed to vote (or exercise any other right), according to BP’s Articles of Association the question shall be determined: • by the chairman of the meeting or in accordance with procedures established by the board of directors, if such question arises at or in relation to a general shareholders meeting; or • by the board of directors at their discretion, if such question arises in any other circumstances. The Depositary or BP will notify direct ADS holders of the upcoming meeting and arrange to distribute certain materials to such holders. The materials will: • contain such information as is contained in the meeting’s notice or in the solicitation materials; and • explain how ADS holders may instruct the Depositary to vote the ordinary shares or other deposited securities (if any) underlying ADSs if the ADS holder appoints the Depositary as proxy, or how an ADS holder may appoint a proxy other than the Depositary. ADS holders may also vote directly as an ordinary shareholder by withdrawing from the Depositary at least six of the BP ordinary shares underlying one of their ADSs. C. Share Dividends and Other Distributions The Depositary will pay to ADS holders the cash dividends or other distributions it or the custodian receives on ordinary shares or any other deposited securities, after deducting any applicable fees and expenses. The Depositary may also, pursuant to BP’s Articles of Association, request BP to pay to the ADS holder directly the cash dividends or other distributions, if the ADSs are held directly. ADS holders will receive those distributions in proportion to the number or of ordinary shares represented by their ADSs. ADS holders will generally receive cash dividends payable on ordinary shares or any other deposited securities in U.S. dollars. To the extent that BP pays any cash dividend other than in U.S. dollars, the Depositary will convert such dividend into U.S. dollars and distribute the amount received in U.S. dollars except where the Depositary determines that in its judgment any foreign currency received by it cannot be converted on a reasonable basis into U.S. dollars transferable in the U.S. or if any governmental approval for payment in U.S. dollars is required and cannot be obtained with a reasonable cost or within a reasonable time period. In that circumstance the Deposit Agreement allows the Depositary to distribute, subject to applicable laws and regulations, foreign currency only to those ADS holders who are entitled to receive payment in foreign currency. It will hold the foreign currency it cannot convert for the account of ADS holders who have not been paid. It will not invest the foreign currency and it will not be liable for any interest. Before making a distribution the Depositary deducts any withholding taxes. The Depositary will distribute only whole U.S. dollars and cents. Fractional cents will be withheld without liability and dealt with by the Depositary in accordance with its then current practices. If the exchange rates fluctuate during a time when the Depositary cannot convert the foreign currency, holders may lose some or all of the value of the distribution depending on the extent of such currency fluctuation. The Depositary may distribute new ADSs representing any shares BP distributes as a dividend or free distribution, if BP requests it to make this distribution. The Depositary may issue fractional ADSs only in connection with such share distributions. Fractional ADSs may only be issued through the direct registration
10 system maintained by the Depositary. If the Depositary does not distribute additional ADSs, each ADS will also represent the proportion of the new shares allocable to such ADS. If BP offers holders of its securities any rights to subscribe for additional shares or any other rights, BP may make these rights available to holders of ADSs by means of warrants or otherwise, if lawful and feasible. If it is not lawful and not feasible and it is practical to sell the rights, the Depositary may in its discretion sell the rights and distribute the proceeds to ADS holders in the same way as it does with cash. The Depositary may allow rights that are not distributed or sold to lapse. In that case, holders of ADSs will receive no value for them. The Deposit Agreement provides that in respect of any other distributions the Depositary will make distributions to ADS holders by any means the Depositary thinks is equitable and practical, including the sale of what BP distributed and distribute the net proceeds, in the same way as it does with cash, or it may adopt such other methods it deems equitable and practical. The Depositary is not responsible if it decides that it is unlawful or impractical to make a distribution available to any ADS holders. BP has no obligation to register ADSs, shares, rights or other securities under the Securities Act of 1933. It also has no obligation to take any other action to permit the distribution of ADSs, shares, rights or anything else to ADS holders. This means that ADS holders may not receive the distributions BP makes on its shares or any value for them if it is unlawful or impractical for them to be made available to ADS holders. D. Deposit, Withdrawal and Cancellation ADS holders who hold or acquire ordinary shares may deposit them with the Depositary or custodian for the Depositary and hold ADSs instead. Where ordinary shares are deposited with the custodian they will be held by the custodian for the account and to the order of the Depositary. To the extent that an ADS holder is requested to do so by the custodian for the Depositary, an ADS holder must deliver to it the following: • certificates or other instruments of title for the ordinary shares to be deposited, properly endorsed and in a form satisfactory to the custodian; • a written order directing the Depositary to issue to an ADS holder, or upon the written order of an ADS holder, ADRs evidencing the number of ADSs which will represent the number of ordinary shares deposited; • any required payments; • an instrument which provides for the prompt transfer to the custodian of any dividend, right to subscribe for additional ordinary shares or right to receive other property--or, in lieu of such a transfer instrument, an agreement of indemnity; and • any other required documents. The custodian will then as soon as practicable present the ordinary shares for registration of the transfer into the name of the custodian, or its nominee, and notify the Depositary that the registration occurred. The deposit of the ordinary shares will be done at the ADS holder’s cost and expense. Once the Depositary receives notice of the deposit, it shall issue to an ADS holder American Depositary receipts evidencing the number of ADSs to which that holder is entitled. ADSs will be issued in book-entry form, unless an ADS holder specifically requests them in certificated form.
11 ADS holders may deposit ordinary shares directly with the Depositary for the purpose of having them forwarded to the custodian, but a charge will apply and delivery will be at the holder’s risk. Where an ADS holder wishes to hold ordinary shares instead of ADSs, the holder must submit a written order to the Depositary to withdraw ordinary shares from deposit and surrender the ADSs at the Depositary’s office. Upon payment of its fees and expenses and of any taxes or charges, the Depositary will deliver the underlying shares at the office of the custodian. At the holder’s request, risk and expense, the Depositary may also deliver the deposited securities at office or any other place specified by the holder. Fractional shares are not deliverable on the cancellation of ADSs and, to the extent the cancellation of ADSs would give rise to the delivery of a fractional share, the Depositary will promptly advise the holder and will either deliver a new ADR in book entry form evidencing such fractional ADS or arrange to sell the fractional share and deliver the net proceeds from such sale net of the costs and expenses of such sale to the holder entitled thereto. E. Amendment and Termination BP may agree with the Depositary to amend the Deposit Agreement and the ADRs without the consent of ADR holders, and for any reason. If the amendment adds or increases fees or charges, except for taxes and governmental charges, or prejudices an important right of ADR holders, it will only become effective 30 days after the Depositary notifies ADR holders of the amendment. At the time an amendment becomes effective, ADR holders are considered to agree to the amendment and to be bound by the Deposit Agreement as amended. However, no amendment will impair the right of an ADS holder to receive the deposited securities in exchange for ADRs, except in order to comply with mandatory provisions of applicable law. The Depositary will terminate the Deposit Agreement if BP asks it to do so, in which case it must notify ADR holders at least 30 days before termination. The Depositary may also terminate the Deposit Agreement after notifying ADR holders. If the Depositary informs BP that it would like to resign and BP does not appoint a new depositary within 60 days, the Depositary is subject to certain obligations with respect to distributions and deposited securities which are set forth in the Deposit Agreement. F. Reports and Other Communications The Depositary will make available for inspection by holders at its office and at any other designated transfer offices any reports and other communications received from BP which are made generally available to the holders of ordinary shares by BP and will arrange for the transmittal or, when requested by BP, otherwise make available to holders copies of such reports and communications, as provided in the Deposit Agreement. The Depositary will also make available at its offices a register for the transfer of ADRs, which at all reasonable times will be open for the inspection of holders. G. Reclassifications, Recapitalizations and Mergers If BP: • changes the par value of, splits, cancels, consolidates or otherwise reclassifies any of the BP ordinary shares; or • recapitalizes, reorganizes, merges, consolidates, sells its assets, or takes any similar action, then: (1) The cash, ordinary shares or other securities received by the Depositary automatically will become new deposited securities under the Deposit Agreement, and each ADR will
12 represent its equal share of the new deposited securities unless additional ADRs are delivered as in the case of a stock dividend; and (2) The Depositary will, if BP asks it to, issue new ADSs or ask the ADR holder to surrender outstanding ADRs in exchange for new ADRs identifying the new deposited securities. H. Limitations on Obligations and Liability to ADR Holders The Deposit Agreement expressly limits the obligations of BP and the Depositary. It also limits their liability. Pursuant to the Deposit Agreement, BP and the Depositary: • are obliged only to take the actions specifically set forth in the Deposit Agreement without negligence or bad faith; • are not liable if either of them is prevented or delayed by law, any provision of the BP Articles of Association or circumstances beyond their control from performing their obligations under the Deposit Agreement; • are not liable if either of them exercises, or fails to exercise, any discretion permitted under the agreement; • have no obligation to become involved in a lawsuit or proceeding related to the ADRs or the Deposit Agreement on an ADR holder’s behalf or on behalf of any other party unless they are indemnified to their satisfaction; • may rely upon any advice of or information from any legal counsel, accountants, any person depositing ordinary shares, any ADR holder or any other person whom they believe in good faith is competent to give them that advice or information; • may rely and shall be protected in acting upon any written notice or other document believed by them to be genuine; and • shall not be responsible for any failure to carry out any instructions to vote any of the ordinary shares. In the Deposit Agreement, BP and the Depositary agree to indemnify each other under specified circumstances.
13 III. DEBT SECURITIES Each series of notes listed on the New York Stock Exchange and set forth on the cover page to BP’s Annual Report and Form 20-F 2020 has been issued by BP Capital Markets plc. (“BP Capital UK”) or BP Capital Markets America Inc. (“BP Capital America” and, together with BP Capital UK, the “BP Debt Issuers”) and guaranteed by BP. Each of these series of notes and related guarantees was issued pursuant to an effective registration statement and a related prospectus and prospectus supplement (if applicable) setting forth the terms of the relevant series of notes and related guarantees (collectively, the “Notes”). The following description of our Notes is a summary and does not purport to be complete and is qualified in its entirety by the full terms of the Notes. The following table sets forth the aggregate principal amount outstanding, issuer, file numbers of the registration statements and dates of issuance for each relevant series of Notes. Certain of the Notes issued by BP Capital UK (the “Old Exchange Notes”) were exchanged for new Notes issued by BP Capital America on 14 December 2018 (the “New Exchange Notes”) pursuant to an registration statement filed on Form F-4 (Registration Nos. 333-228369 and 333-228369-01). The New Exchange Notes have substantially identical terms to the Old Exchange Notes for which they were exchanged. Series Aggregate Principal Amount Outstanding Date(s) of Issuance Issuer(s) Registration Statement File No. Floating Rate Guaranteed Notes due 2021 $250,000,000 16 September 2016 BP Capital U.K. 333-208478 and 333-208478-01 Floating Rate Guaranteed Notes due 2022 — — — — Old Exchange Notes $117,849,000 19 September 2017 BP Capital U.K. 333-208478 and 333-208478-01 New Exchange Notes $182,151,000 12 December 2018 BP Capital America 333-228369 and 333-228369-01 4.742% Guaranteed Notes due 2021 — — — — Old Exchange Notes $272,684,000 11 March 2011 BP Capital U.K. 333-157906 and 333-157906-01 New Exchange Notes $1,127,316,000 12 December 2018 BP Capital America 333-228369 and 333-228369-01 3.561% Guaranteed Notes due 2021 $1,000,000,000 1 November 2011 BP Capital U.K. 333-157906 and 333-157906-01 2.112% Guaranteed Notes due 2021 — — — — Old Exchange Notes $146,557,000 16 September 2016 BP Capital U.K. 333-208478 and 333-208478-01 New Exchange Notes $603,443,000 12 December 2018 BP Capital America 333-228369 and 333-228369-01 2.500% Guaranteed Notes due 2022 $1,000,000,000 6 November 2012 BP Capital U.K. 333-179953 and 333-179953-01 2.520% Guaranteed Notes due 2022 — — — — Old Exchange Notes $135,041,000 19 September 2017 BP Capital U.K. 333-208478 and 333-208478-01 New Exchange Notes $564,959,000 12 December 2018 BP Capital America 333-228369 and 333-228369-01
14 Series Aggregate Principal Amount Outstanding Date(s) of Issuance Issuer(s) Registration Statement File No. 3.245% Guaranteed Notes due 2022 — — — — Old Exchange Notes $349,823,000 7 May 2012 BP Capital U.K. 333-179953 and 333-179953-01 New Exchange Notes $1,400,177,000 12 December 2018 BP Capital America 333-228369 and 333-228369-01 3.062% Guaranteed Notes due 2022 $1,000,000,000 17 March 2015 BP Capital U.K. 333-201894 and 333-201894-01 2.750% Guaranteed Notes due 2023 — — — — Old Exchange Notes $398,152,000 10 May 2013 BP Capital U.K. 333-179953 and 333-179953-01 New Exchange Notes $1,101,848,000 12 December 2018 BP Capital America 333-228369 and 333-228369-01 2.937% Guaranteed Notes due 2023 $750,000,000 6 April 2020 BP Capital America 333-226485 and 333-226485-02 3.216% Guaranteed Notes due 2023 Old Exchange Notes $206,060,000 28 November 2016 BP Capital U.K. 333-208478 and 333-208478-01 New Exchange Notes $993,940,000 12 December 2018 BP Capital America 333-228369 and 333-228369-01 3.994% Guaranteed Notes due 2023 $750,000,000 26 September 2013 BP Capital U.K. 333-179953 and 333-179953-01 3.535% Guaranteed Notes due 2024 $750,000,000 4 November 2014 BP Capital U.K. 333-179953 and 333-179953-01 3.814% Guaranteed Notes due 2024 $1,250,000,000 10 February 2014 BP Capital U.K. 333-179953 and 333-179953-01 3.224% Guaranteed Notes due 2024 — — — — Old Exchange Notes $903,287,000 14 February 2017 BP Capital U.K. 333-208478 and 333-208478-01 New Exchange Notes $96,713,000 12 December 2018 BP Capital America 333-228369 and 333-228369-01 3.790% Guaranteed Notes due 2024 $1,000,000,000 6 November 2018 BP Capital America 333-226485 and 333-226485-02 3.194% Guaranteed Notes due 2025 $750,000,000 6 April 2020 BP Capital America 333-226485 and 333-226485-02 3.506% Guaranteed Notes due 2025 $1,000,000,000 17 March 2015 BP Capital U.K. 333-201894 and 333-201894-01 3.796% Guaranteed Notes due 2025 $1,000,000,000 21 September 2018 BP Capital America 333-226485 and 333-226485-02 3.119% Guaranteed Notes due 2026 — — — — Old Exchange Notes $251,423,000 4 May 2016 BP Capital U.K. 333-208478 and 333-208478-01 New Exchange Notes $998,577,000 12 December 2018 BP Capital America 333-228369 and 333-228369-01 3.410% Guaranteed Notes due 2026 $1,000,000,000 11 February 2019 BP Capital America 333-226485 and 333-226485-02
15 Series Aggregate Principal Amount Outstanding Date(s) of Issuance Issuer(s) Registration Statement File No. 3.017% Guaranteed Notes due 2027 — — — — Old Exchange Notes $123,582,000 16 September 2016 BP Capital U.K. 333-208478 and 333-208478-01 New Exchange Notes $876,418,000 12 December 2018 BP Capital America 333-228369 and 333-228369-01 3.279% Guaranteed Notes due 2027 $1,500,000,000 19 September 2017 BP Capital U.K. 333-208478 and 333-208478-01 3.543% Guaranteed Notes due 2027 $500,000,000 6 April 2020 BP Capital America 333-226485 and 333-226485-02 3.588% Guaranteed Notes due 2027 — — — — Old Exchange Notes $236,291,000 14 February 2017 BP Capital U.K. 333-208478 and 333-208478-01 New Exchange Notes $613,709,000 12 December 2018 BP Capital America 333-228369 and 333-228369-01 3.723% Guaranteed Notes due 2028 $800,000,000 28 November 2016 BP Capital U.K. 333-208478 and 333-208478-01 3.937% Guaranteed Notes due 2028 $1,000,000,000 21 September 2018 BP Capital America 333-226485 and 333-226485-02 4.234% Guaranteed Notes due 2028 $2,000,000,000 6 November 20181 and 11 February 2019 BP Capital America 333-226485 and 333-226485-02 1.749% Guaranteed Notes due 2030 $1,000,000,000 10 August 2020 BP Capital America 333-226485 and 333-226485-02 3.633% Guaranteed Notes due 2030 $1,250,000,000 6 April 2020 BP Capital America 333-226485 and 333-226485-02 2.772% Guaranteed Notes due 2050 $1,500,000,000 10 August 2020 BP Capital America 333-226485 and 333-226485-02 3.000% Guaranteed Notes due 2050 $2,000,000,000 24 February 20202 and 9 March 2020 BP Capital America 333-226485 and 333-226485-02 3.067% Guaranteed Notes due 2050 $500,000,000 13 December 2019 BP Capital America 333-226485 and 333-226485-02 2.939% Guaranteed Notes due 2051 $1,500,000,000 4 December 2020 BP Capital America 333-226485 and 333-226485-02 4.375% Perpetual Subordinated Non-Call 5.25 Fixed Rate Reset Notes $2,500,000,000 22 June 2020 BP Capital U.K. 333-226485 and 333-226485-01 4.875% Perpetual Subordinated Non-call 10 Fixed Rate Reset Notes $2,500,000,000 22 June 2020 BP Capital U.K. 333-226485 and 333-226485-01 1 6 November 2018 (with respect to $1,000,000,000 aggregate principal amount of notes) and 11 February 2019 (with respect to $1,000,000,000 aggregate principal amount of notes). 2 24 February 2020 (with respect to $1,250,000,000 aggregate principal amount of notes) and 9 March 2020 (with respect to $750,000,000 aggregate principal amount of notes).
16 A. Descriptions of Notes Description of Floating Rate Guaranteed Notes due 2021 The following terms are applicable to the Floating Rate Guaranteed Notes due 2021. • Issuer: BP Capital U.K. • Title: Floating Rate Guaranteed Notes due 2021 • Total principal amount outstanding: $250,000,000 • Issuance date: 16 September 2016 • Maturity date: 16 September 2021 • Interest rate: The interest rate for the first interest period will be the 3-month U.S. dollar London Interbank Offered Rate ("U.S. dollar LIBOR"), as determined on 14 September 2016, plus the spread (as described below). Thereafter, the interest rate for any interest period will be U.S. dollar LIBOR, as determined on the applicable interest determination date, plus the spread. The interest rate will be reset quarterly on each interest reset date. • Date interest starts accruing: 16 September 2016 • Interest payment dates: Each 16 March, 16 June, 16 September and 16 December of each year, subject to the Day Count Convention. • First interest payment date: 16 December 2016 • Spread: 0.870% • Interest reset dates: The interest reset date for each interest period other than the first interest period will be the first day of such interest period, subject to the day count convention. • Interest periods: The period beginning on, and including an interest payment date and ending on, but not including, the following interest payment date? provided that the first interest period will begin on 16 September 2016, and will end on, but not include, the first interest payment date. • Interest determination date: The interest determination date relating to a particular interest reset date will be the second London business day preceding such interest reset date. • London business day: Any week day on which banking or trust institutions in London are not authorized generally or obligated by law, regulation or executive order to close. • Calculation Agent: The Bank of New York Mellon Trust Company, N.A. • Calculation of U.S. dollar LIBOR: The calculation agent will determine U.S. dollar LIBOR in accordance with the following provisions: With respect to any interest determination date, U.S. dollar LIBOR will be the rate for deposits in U.S. dollars having a maturity of three months commencing on the interest reset date that appears on the designated LIBOR page as of 11:00 a.m., London time, on that interest determination date. If no rate appears, U.S. dollar LIBOR, in respect
17 of that interest determination date, will be determined as follows: the calculation agent will request the principal London offices of each of four major reference banks in the London interbank market, as selected and identified by the issuer, to provide the calculation agent with its offered quotation for deposits in U.S. dollars for the period of three months, commencing on the interest reset date, to prime banks in the London interbank market at approximately 11:00 a.m., London time, on that interest determination date and in a principal amount that is representative for a single transaction in U.S. dollars in that market at that time. If at least two quotations are provided, then U.S. dollar LIBOR on that interest determination date will be the arithmetic mean of those quotations. If fewer than two quotations are provided, then U.S. dollar LIBOR on the interest determination date will be the arithmetic mean of the rates quoted at approximately 11:00 a.m., New York City time, on the interest determination date by three major banks in The City of New York selected and identified by the issuer for loans in U.S. dollars to leading European banks, having a three-month maturity and in a principal amount that is representative for a single transaction in U.S. dollars in that market at that time? provided, however, that if the banks selected and identified by the issuer are not providing quotations in the manner described by this sentence, U.S. dollar LIBOR determined as of that interest determination date will be U.S. dollar LIBOR in effect on that interest determination date. The designated LIBOR page is the Reuters screen "LIBOR01", or any successor service for the purpose of displaying the London interbank rates of major banks for U.S. dollars. The Reuters screen "LIBOR01" is the display designated as the Reuters screen "LIBOR01", or such other page as may replace the Reuters screen "LIBOR01" on that service or such other service or services as may be nominated for the purpose of displaying London interbank offered rates for U.S. dollar deposits by ICE Benchmark Administration Limited ("IBA") or its successor or such other entity assuming the responsibility of IBA or its successor in calculating the London Interbank Offered Rate in the event IBA or its successor no longer does so. All calculations made by the calculation agent for the purposes of calculating the interest rates on the 2021 floating rate notes shall be conclusive and binding on the holders of the 2021 floating rate notes, BP, the issuer and the trustee, absent manifest error. Description of Floating Rate Guaranteed Notes due 2022 The following terms are applicable to the Floating Rate Guaranteed Notes due 2022. • Issuers: BP Capital U.K. (Old Exchange Notes) and BP Capital America (New Exchange Notes) • Title: Floating Rate Guaranteed Notes due 2022 • Total principal amount outstanding: $117,849,000 (Old Exchange Notes) and $182,151,000 (New Exchange Notes) • Issuance dates: 19 September 2017 (Old Exchange Notes) and 12 December 2018 (New Exchange Notes) • Maturity date: 19 September 2022 • Interest rate: The interest rate for the first interest period will be the 3-month U.S. dollar London Interbank Offered Rate ("U.S. dollar LIBOR"), as determined on 15 September 2017, plus the spread (as described below). Thereafter, the interest rate for any interest period will be U.S. dollar LIBOR, as determined on the applicable interest determination date, plus the spread. The interest rate will be reset quarterly on each interest reset date. • Date interest starts accruing: 19 September 2017
18 • Interest payment dates: 19 March, 19 June, 19 September and 19 December of each year, subject to the Day Count Convention. • First interest payment date: 19 December 2017 • Spread: 0.650% • Interest reset dates: The interest reset date for each interest period other than the first interest period will be the first day of such interest period, subject to the day count convention. • Interest periods: The period beginning on, and including an interest payment date and ending on, but not including, the following interest payment date? provided that the first interest period will begin on 19 September 2017, and will end on, but not include, the first interest payment date. • Interest determination date: The interest determination date relating to a particular interest reset date will be the second London business day preceding such interest reset date. • London business day: Any week day on which banking or trust institutions in London are not authorized generally or obligated by law, regulation or executive order to close, on which dealings in deposits in U.S. dollars are transacted in the London interbank market. • Calculation Agent: The Bank of New York Mellon Trust Company, N.A. • Calculation of U.S. dollar LIBOR: The calculation agent will determine U.S. dollar LIBOR in accordance with the following provisions: With respect to any interest determination date, U.S. dollar LIBOR will be the rate for deposits in U.S. dollars having a maturity of three months commencing on the interest reset date that appears on the designated LIBOR page as of 11:00 a.m., London time, on that interest determination date. If no rate appears, U.S. dollar LIBOR, in respect of that interest determination date, will be determined as follows: the calculation agent will request the principal London offices of each of four major reference banks in the London interbank market, as selected and identified by the issuer, to provide the calculation agent with its offered quotation for deposits in U.S. dollars for the period of three months, commencing on the interest reset date, to prime banks in the London interbank market at approximately 11:00 a.m., London time, on that interest determination date and in a principal amount that is representative for a single transaction in U.S. dollars in that market at that time. If at least two quotations are provided, then U.S. dollar LIBOR on that interest determination date will be the arithmetic mean of those quotations. If fewer than two quotations are provided, then U.S. dollar LIBOR on the interest determination date will be the arithmetic mean of the rates quoted at approximately 11:00 a.m., New York City time, on the interest determination date by three major banks in The City of New York selected and identified by the issuer for loans in U.S. dollars to leading European banks, having a three-month maturity and in a principal amount that is representative for a single transaction in U.S. dollars in that market at that time? provided, however, that if the banks selected and identified by the issuer are not providing quotations in the manner described by this sentence, U.S. dollar LIBOR determined as of that interest determination date will be U.S. dollar LIBOR in effect on that interest determination date (i.e., the same as the rate determined for the immediately preceding interest reset date). The designated LIBOR page is Bloomberg L.P.'s page "BBAM", or any successor service for the purpose of displaying the London interbank rates of major banks for U.S. dollars. Bloomberg L.P.'s page "BBAM" is the display designated as "BBAM", or such other page as may replace Bloomberg L.P.'s page "BBAM" on that service or such other service or services as may be nominated for the purpose of displaying London interbank offered rates for U.S. dollar deposits by ICE Benchmark Administration Limited ("IBA") or its successor or such other entity assuming
19 the responsibility of IBA or its successor in calculating the London Interbank Offered Rate in the event IBA or its successor no longer does so. All calculations made by the calculation agent for the purposes of calculating the interest rates on the 2022 floating rate notes shall be conclusive and binding on the holders of the 2022 floating rate notes, BP, the issuer and the trustee, absent manifest error. Description of 4.742% Guaranteed Notes due 2021 The following terms are applicable to the 4.742% Guaranteed Notes due 2021. • Issuer: BP Capital U.K. (Old Exchange Notes) and BP Capital America (New Exchange Notes) • Title: 4.742% Guaranteed Notes due 2021. • Total principal amount outstanding: $272,684,000 (Old Exchange Notes) and $1,127,316,000 (New Exchange Notes) • Issuance date: 11 March 2011 (Old Exchange Notes) and 12 December 2018 (New Exchange Notes) • Maturity date: 11 March 2021. • Interest rate: 4.742% per annum. • Date interest starts accruing: 11 March 2011. • Interest payment dates: Each 11 March and 11 September. • First interest due date: 11 September 2011. • Optional make-whole redemption: The issuer has the right to redeem the 2021 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2021 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2021 notes to be redeemed (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of redemption. For purposes of determining the optional make-whole redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2021 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by the issuer "Reference treasury dealer" means BNP Paribas Securities Corp. and Citigroup Global Markets Inc. or their affiliates which are primary U.S.
20 government securities dealers, and their respective successors, and two other primary U.S. government securities dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), the issuer shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.561% Guaranteed Notes due 2021 The following terms are applicable to the 3.561% Guaranteed Notes due 2021. • Issuer: BP Capital U.K. • Title: 3.561% Guaranteed Notes due 2021. • Total principal amount outstanding: $1,000,000,000. • Issuance date: 1 November 2011. • Maturity date: 1 November 2021. • Interest rate: 3.561% per annum. • Date interest starts accruing: 1 November 2011. • Interest payment dates: Each 1 May and 1 November, subject to the day count convention. • First interest due date: 1 May 2012. • Optional make-whole redemption:3 The issuer has the right to redeem the 2021 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2021 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2021 notes to be redeemed (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of redemption. For purposes of determining the optional make-whole redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated 3 As of 31 December 2020, the issuer had activated the make-whole redemption right of the 3.561% Guaranteed Notes due 2021.
21 maturity comparable to the remaining term of the 2021 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by the issuer "Reference treasury dealer" means Citigroup Global Markets Inc. and HSBC Securities (USA) Inc. or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 2.112% Guaranteed Notes due 2021 The following terms are applicable to the 2.112 Guaranteed Notes due 2021. • Issuer: BP Capital U.K. (Old Exchange Notes) and BP Capital America (New Exchange Notes) • Title: 2.112% Guaranteed Notes due 2021 • Total principal amount outstanding: $146,557,000 (Old Exchange Notes) and $603,443,000 (New Exchange Notes) • Issuance date: 16 September 2016 (Old Exchange Notes) and 12 December 2018 (New Exchange Notes) • Maturity date: 16 September 2021 • Interest rate: 2.112% per annum • Date interest starts accruing: 16 September 2016 • Interest payment dates: Each 16 September and 16 March, subject to the day count convention. • First interest payment date: 16 March 2017 • Optional redemption: Prior to 16 August 2021 (the date that is one month prior to the scheduled maturity date for the 2021 fixed rate notes), the issuer has the right to redeem the 2021 fixed rate notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2021 fixed rate notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2021 fixed rate notes to be redeemed that would be due if such notes matured on 16 August 2021 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 15 basis points, plus in each case accrued and unpaid interest to the date of redemption. On or after 16 August 2021 (the date that is one month prior to
22 the scheduled maturity date for the 2021 fixed rate notes), the issuer has the right to redeem the 2021 fixed rate notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2021 fixed rate notes to be redeemed , plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2021 fixed rate notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by the issuer "Reference treasury dealer" means Barclays Capital Inc., BNP Paribas Securities Corp., HSBC Securities (USA) Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Mizuho Securities USA Inc. and Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 2.500% Guaranteed Notes due 2022 The following terms are applicable to the 2.500% Guaranteed Notes due 2022. • Issuer: BP Capital U.K. • Title: 2.500% Guaranteed Notes due 2022. • Total principal amount outstanding: $1,000,000,000. • Issuance date: 6 November 2012. • Maturity date: 6 November 2022. • Interest rate: 2.500% per annum. • Date interest starts accruing: 6 November 2012. • Interest payment dates: Each 6 May and 6 November. • First interest due date: 6 May 2013.
23 • Optional make-whole redemption: The issuer has the right to redeem the 2022 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2022 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2022 notes to be redeemed (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 15 basis points, plus in each case accrued and unpaid interest to the date of redemption. For purposes of determining the optional make-whole redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2022 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by the issuer “Reference treasury dealer” means Citigroup Global Markets Inc., HSBC Securities (USA) Inc. and UBS Securities LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 2.520% Guaranteed Notes due 2022 The following terms are applicable to the 2.520% Guaranteed Notes due 2022. • Issuer: BP Capital U.K. (Old Exchange Notes) and BP Capital America (New Exchange Notes) • Title: 2.520% Guaranteed Notes due 2022 • Total principal amount outstanding: $135,041,000 (Old Exchange Notes) and $564,959,000 (New Exchange Notes) • Issuance date: 19 September 2017 (Old Exchange Notes) and December 12, 2018 (New Exchange Notes) • Maturity date: 19 September 2022 • Interest rate: 2.520% per annum • Date interest starts accruing: 19 September 2017
24 • Interest payment dates: Each 19 March and 19 September, subject to the day count convention. • First interest payment date: 19 March 2018 • Optional redemption: Prior to 19 August 2022 (the date that is one month prior to the scheduled maturity date for the 2022 fixed rate notes), the issuer has the right to redeem the 2022 fixed rate notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2022 fixed rate notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2022 fixed rate notes to be redeemed that would be due if such notes matured on 19 August 2022 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 12.5 basis points, plus in each case accrued and unpaid interest to the date of redemption. On or after 19 August 2022 (the date that is one month prior to the scheduled maturity date for the 2022 fixed rate notes), the issuer has the right to redeem the 2022 fixed rate notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2022 fixed rate notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2022 fixed rate notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by the issuer “Reference treasury dealer” means Credit Suisse Securities (USA) LLC, Goldman Sachs & Co. LLC, HSBC Securities (USA) Inc., J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and UBS Securities LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.245% Guaranteed Notes due 2022 The following terms are applicable to the 3.245% Guaranteed Notes due 2022. • Issuer: BP Capital U.K. (Old Exchange Notes) and BP Capital America (New Exchange Notes) • Title: 3.245% Guaranteed Notes due 2022.
25 • Total principal amount outstanding: $349,823,000 (Old Exchange Notes) and $1,400,177,000 (New Exchange Notes). • Issuance date: 7 May 2012 (Old Exchange Notes) and December 12, 2018 (New Exchange Notes) • Maturity date: 6 May 2022. • Interest rate: 3.245% per annum. • Date interest starts accruing: 7 May 2012. • Interest payment dates: Each 6 May and 6 November. • First interest due date: 6 November 2012. • Optional make-whole redemption: The issuer has the right to redeem the 2022 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2022 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2022 notes to be redeemed (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of redemption. For purposes of determining the optional make-whole redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2022 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by the issuer “Reference treasury dealer” means Credit Suisse Securities (USA) LLC, Mizuho Securities USA Inc., Morgan Stanley & Co. LLC, RBS Securities Inc. and UBS Securities LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.062% Guaranteed Notes due 2022 The following terms are applicable to the 3.062% Guaranteed Notes due 2022.
26 • Issuer: BP Capital U.K. • Title: 3.062% Guaranteed Notes due 2022 • Total principal amount outstanding: $1,000,000,000 • Issuance date: 17 March 2015 • Maturity date: 17 March 2022 • Interest rate: 3.062% per annum • Date interest starts accruing: 17 March 2015 • Interest payment dates: Each 17 March and 17 September, subject to the day count convention. • First interest payment date: 17 September 2015 • Optional make-whole redemption:4 The issuer has the right to redeem the 2022 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2022 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2022 notes to be redeemed (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of redemption. For purposes of determining the optional make-whole redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2022 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by the issuer “Reference treasury dealer” means Barclays Capital Inc., HSBC Securities (USA) Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley & Co. LLC and UBS Securities LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in 4 As of 31 December 2020, the issuer had activated the make-whole redemption right of the 3.062% Guaranteed Notes due 2022.
27 each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 2.750% Guaranteed Notes due 2023 The following terms are applicable to the 2.750% Guaranteed Notes due 2023. • Issuer: BP Capital U.K. (Old Exchange Notes) and BP Capital America (New Exchange Notes) • Title: 2.750% Guaranteed Notes due 2023 • Total principal amount outstanding: $398,152,000 (Old Exchange Notes) and $1,101,848,000 (New Exchange Notes) • Issuance date: 10 May 2013 (Old Exchange Notes) and 12 December 2018 (New Exchange Notes) • Maturity date: 10 May 2023. • Interest rate: 2.750% per annum. • Date interest starts accruing: 10 May 2013. • Interest payment dates: Each 10 May and 10 November. • First interest due date: 10 November 2013. • Optional make-whole redemption: The issuer has the right to redeem the 2023 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2023 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2023 notes to be redeemed (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of redemption. For purposes of determining the optional make-whole redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semiannual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2023 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by the issuer “Reference treasury dealer” means Merrill Lynch, Pierce, Fenner & Smith Incorporated, Mizuho Securities USA Inc., Morgan Stanley & Co. LLC and SG Americas Securities, LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and one primary treasury dealer selected by Mitsubishi UFJ Securities (USA), Inc., and
28 two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 2.937% Guaranteed Notes due 2023 The following terms are applicable to the 2.937% Guaranteed Notes due 2023. • Issuer: BP Capital America • Title: 2.937% Guaranteed Notes due 2023 • Total principal amount outstanding: $750,000,000 • Issuance date: April 6, 2020 • Maturity date: April 6, 2023 • Interest rate: 2.937% per annum • Date interest starts accruing: April 6, 2020 • Interest payment dates: Each April 6 and October 6, subject to the day count convention. • First interest payment date: October 6, 2020 • Optional redemption: BP Capital America has the right to redeem the 2023 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2023 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2023 notes to be redeemed (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 40 basis points, plus in either case accrued and unpaid interest to the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2023 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such 2023 notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation Agent” means one of the reference treasury dealers appointed by BP Capital America. “Reference treasury dealer” means
29 BNP Paribas Securities Corp., BofA Securities, Inc., Citigroup Global Markets Inc., HSBC Securities (USA) Inc., J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.216% Guaranteed Notes due 2023 The following terms are applicable to the 3.216% Guaranteed Notes due 2023. • Issuer: BP Capital U.K. (Old Exchange Notes) and BP Capital America (New Exchange Notes) • Title: 3.216% Guaranteed Notes due 2023 • Total principal amount outstanding: $206,060,000 (Old Exchange Notes) and $993,940,000 (New Exchange Notes) • Issuance date: 28 November 2016 (Old Exchange Notes) and 12 December 2018 (New Exchange Notes) • Maturity date: 28 November 2023 • Interest rate: 3.216% per annum • Date interest starts accruing: 28 November 2016 • Interest payment dates: Each 28 May and 28 November, subject to the day count convention. • First interest payment date: 28 May 2017 • Optional redemption: Prior to 28 September 2023 (the date that is two months prior to the scheduled maturity date for the 2023 notes), the issuer has the right to redeem the 2023 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2023 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2023 notes to be redeemed that would be due if such notes matured on 28 September 2023 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of redemption. On or after 28 September 2023 (the date that is two months prior to the scheduled maturity date for the 2023 notes), the issuer has the right to redeem the 2023 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2023 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per
30 annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2023 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by the issuer “Reference treasury dealer” means BNP Paribas Securities Corp., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Goldman, Sachs & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated and MUFG Securities Americas Inc. or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.994% Guaranteed Notes due 2023 The following terms are applicable to the 3.994% Guaranteed Notes due 2.23. • Issuer: BP Capital U.K. • Title: 3.994% Guaranteed Notes due 2023. • Total principal amount outstanding: $750,000,000. • Issuance date: 26 September 2013. • Maturity date: 26 September 2023. • Interest rate: 3.994% per annum. • Date interest starts accruing: 26 September 2013. • Interest payment dates: Each 26 March and 26 September. • First interest due date: 26 March 2014. • Optional make-whole redemption: The issuer has the right to redeem the 2023 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2023 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2023 notes to be redeemed (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of
31 twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of redemption. For purposes of determining the optional make-whole redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semiannual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2023 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by the issuer “Reference treasury dealer” means BNP Paribas Securities Corp., Citigroup Global Markets Inc. and HSBC Securities (USA) Inc. or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.535% Guaranteed Notes due 2024 The following terms are applicable to the 2.535% Guaranteed Notes due 2024. • Issuer: BP Capital U.K. • Title: 3.535% Guaranteed Notes due 2024 • Total principal amount outstanding: $750,000,000 • Issuance date: 4 November 2014 • Maturity date: 4 November 2024 • Interest rate: 3.535% per annum • Date interest starts accruing: 4 November 2014 • Interest payment dates: Each 4 May and 4 November, subject to the day count convention. • First interest payment date: 4 May 2015 • Optional make-whole redemption: The issuer has the right to redeem the 2024 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2024 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2024 notes to be redeemed (not
32 including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of redemption. For purposes of determining the optional make-whole redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2024 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by the issuer “Reference treasury dealer” means Barclays Capital Inc., BNP Paribas Securities Corp., HSBC Securities (USA) Inc., J.P. Morgan Securities LLC and Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.814% Guaranteed Notes due 2024 The following terms are applicable to the 3.814% Guaranteed Notes due 2024. • Issuer: BP Capital U.K. • Title: 3.814% Guaranteed Notes due 2024 • Total principal amount outstanding: $1,250,000,000 • Issuance date: 10 February 2014 • Maturity date: 10 February 2024 • Interest rate: 3.814% per annum. • Date interest starts accruing: 10 February 2014. • Interest payment dates: Each 10 February and 10 August, subject to the day count convention. • First interest payment date: 10 August 2014
33 • Optional make-whole redemption: The issuer has the right to redeem the 2024 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2024 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2024 notes to be redeemed (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of redemption. For purposes of determining the optional make-whole redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semiannual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2024 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by the issuer “Reference treasury dealer” means Barclays Capital Inc., BNP Paribas Securities Corp., Credit Suisse Securities (USA) LLC, Morgan Stanley & Co. LLC and RBS Securities Inc. or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.224% Guaranteed Notes due 2024 The following terms are applicable to the 3.224% Guaranteed Notes due 2024. • Issuer: BP Capital U.K. (Old Exchange Notes) and BP Capital America (New Exchange Notes) • Title: 3.224% Guaranteed Notes due 2024 • Total principal amount outstanding: $903,287,000 (Old Exchange Notes) and $96,713,000 (New Exchange Notes) • Issuance date: 14 February 2017 (Old Exchange Notes) and 12 December 2018 (New Exchange Notes) • Maturity date: 14 April 2024 • Interest rate: 3.224% per annum • Date interest starts accruing: 14 February 2017
34 • Interest payment dates: Each 14 April and 14 October, subject to the day count convention. • First interest payment date: 14 October 2017 • Optional redemption: Prior to 14 February 2024 (the date that is two months prior to the scheduled maturity date for the 2024 notes), the issuer has the right to redeem the 2024 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2024 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2024 notes to be redeemed that would be due if such notes matured on 14 February 2024 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi- annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of redemption. On or after 14 February 2024 (the date that is two months prior to the scheduled maturity date for the 2024 notes), the issuer has the right to redeem the 2024 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2024 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2024 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by the issuer “Reference treasury dealer” means Barclays Capital Inc., BNP Paribas Securities Corp., Deutsche Bank Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, MUFG Securities Americas Inc., and RBS Securities Inc. (marketing name “NatWest Markets”) or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.790% Guaranteed Notes due 2024 The following terms are applicable to the 3.790% Guaranteed Notes due 2024. • Issuer: BP Capital America • Title: 3.790% Guaranteed Notes due 2024 • Total principal amount outstanding: $1,000,000,000
35 • Issuance date: 6 November 2018 • Maturity date: 6 February 2024 • Interest rate: 3.790% per annum • Date interest starts accruing: 6 November 2018 • Interest payment dates: Each 6 February and 6 August, subject to the day count convention. • First interest payment date: 6 February 2019 • Optional redemption: Prior to 6 January 2024 (the date that is one month prior to the scheduled maturity date for the 2024 notes), BP Capital America has the right to redeem the 2024 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2024 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2024 notes to be redeemed that would be due if such notes matured on 6 January 2024 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 15 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 6 January 2024 (the date that is one month prior to the scheduled maturity date for the 2024 notes), BP Capital America has the right to redeem the 2024 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2024 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2024 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by BP Capital America. “Reference treasury dealer” means Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC, NatWest Markets Securities Inc., SG Americas Securities, LLC and UBS Securities LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.194% Guaranteed Notes due 2025
36 The following terms are applicable to the 3.194% Guaranteed Notes due 2025. • Issuer: BP Capital America • Title: 3.194% Guaranteed Notes due 2025 • Total principal amount outstanding: $750,000,000 • Issuance date: April 6, 2020 • Maturity date: April 6, 2025 • Interest rate: 3.194% per annum • Date interest starts accruing: April 6, 2020 • Interest payment dates: Each April 6 and October 6, subject to the day count convention. • First interest payment date: October 6, 2020 • Optional redemption: Prior to March 6, 2025 (the date that is one month prior to the scheduled maturity date for the 2025 notes), BP Capital America has the right to redeem the 2025 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2025 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2025 notes to be redeemed that would be due if such 2025 notes matured on March 6, 2025 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 45 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after March 6, 2025 (the date that is one month prior to the scheduled maturity date for the 2025 notes), BP Capital America has the right to redeem the 2025 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2025 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2025 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such 2025 notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by BP Capital America. “Reference treasury dealer” means BNP Paribas Securities Corp., BofA Securities, Inc., Citigroup Global Markets Inc., HSBC Securities (USA) Inc., J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary
37 treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.506% Guaranteed Notes due 2025 The following terms are applicable to the 3.506% Guaranteed Notes due 2025. • Issuer: BP Capital U.K. • Title: 3.506% Guaranteed Notes due 2025 • Total principal amount outstanding: $1,000,000,000 • Issuance date: 17 March 2015 • Maturity date: 17 March 2025 • Interest rate: 3.506% per annum • Date interest starts accruing: 17 March 2015 • Interest payment dates: Each 17 March and 17 September, subject to the day count convention. • First interest payment date: 17 September 2015 • Optional make-whole redemption: The issuer has the right to redeem the 2025 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2025 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2025 notes to be redeemed (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 25 basis points, plus in each case accrued and unpaid interest to the date of redemption. For purposes of determining the optional make-whole redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2025 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by the issuer “Reference treasury dealer” means Barclays Capital Inc., HSBC Securities (USA) Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley & Co. LLC and UBS Securities LLC or their affiliates, each of which is a primary
38 U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.796% Guaranteed Notes due 2025 The following terms are applicable to the 3.796% Guaranteed Notes due 2025. • Issuer: BP Capital America • Title: 3.796% Guaranteed Notes due 2025 • Total principal amount outstanding: $1,000,000,000 • Issuance date: 21 September 2018 • Maturity date: 21 September 2025 • Interest rate: 3.796% per annum • Date interest starts accruing: 21 September 2018 • Interest payment dates: Each 21 March and 21 September, subject to the day count convention. • First interest payment date: 21 March 2019 • Optional redemption: Prior to 21 July 2025 (the date that is two months prior to the scheduled maturity date for the 2025 notes), BP Capital America has the right to redeem the 2025 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2025 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2025 notes to be redeemed that would be due if such notes matured on 21 July 2025 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 15 basis points, plus in each case accrued and unpaid interest to the date of redemption. On or after 21 July 2025 (the date that is two months prior to the scheduled maturity date for the 2025 notes), BP Capital America has the right to redeem the 2025 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2025 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities
39 selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2025 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by BP Capital America. “Reference treasury dealer” means Citigroup Global Markets Inc., Goldman Sachs & Co. LLC, HSBC Securities (USA) Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Mizuho Securities USA LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.119% Guaranteed Notes due 2026 The following terms are applicable to the 3.119% Guaranteed Notes due 2026. • Issuer: BP Capital U.K. (Old Exchange Notes) and BP Capital America (New Exchange Notes). • Title: 3.119% Guaranteed Notes due 2026 • Total principal amount outstanding: $251,423,000 (Old Exchange Notes) and $998,577,000 (New Exchange Notes) • Issuance date: 4 May 2016 (Old Exchange Notes) and 12 December 2018 (New Exchange Notes) • Maturity date: 4 May 2026 • Interest rate: 3.119% per annum • Date interest starts accruing: 4 May 2016 • Interest payment dates: Each 4 May and 4 November, subject to the day count convention. • First interest payment date: 4 November 2016 • Optional make-whole redemption: Prior to 4 February 2026 (the date that is three months prior to the scheduled maturity date for the 2026 notes), the issuer has the right to redeem the 2026 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2026 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2026 notes to be redeemed that would be due if such notes matured on 4 February 2026 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of
40 redemption. On or after 4 February 2026 (the date that is three months prior to the scheduled maturity date for the 2026 notes), the issuer has the right to redeem the 2026 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2026 notes to be redeemed , plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional make-whole redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2026 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by the issuer “Reference treasury dealer” means Citigroup Global Markets Inc., Deutsche Bank Securities Inc., HSBC Securities (USA) Inc., J.P. Morgan Securities LLC and Mizuho Securities USA Inc. or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.410% Guaranteed Notes due 2026 The following terms are applicable to the 3.410% Guaranteed Notes due 2026. • Issuer: BP Capital America • Title: 3.410% Guaranteed Notes due 2026 • Total principal amount outstanding: $1,000,000,000 • Issuance date: 11 February 2019 • Maturity date: 11 February 2026 • Interest rate: 3.410% per annum • Date interest starts accruing: 11 February 2019 • Interest payment dates: Each 11 February and 11 August, subject to the day count convention. • First interest payment date: 11 August 2019
41 • Optional redemption: Prior to 11 December 2025 (the date that is two months prior to the scheduled maturity date for the 2026 notes), BP Capital America has the right to redeem the 2026 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2026 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2026 notes to be redeemed that would be due if such notes matured on 11 December 2025 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 15 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 11 December 2025 (the date that is two months prior to the scheduled maturity date for the 2026 notes), BP Capital America has the right to redeem the 2026 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2026 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2026 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by BP Capital America. “Reference treasury dealer” means BNP Paribas Securities Corp., Deutsche Bank Securities Inc., HSBC Securities (USA) Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.017% Guaranteed Notes due 2027 The following terms are applicable to the 3.017% Guaranteed Notes due 2027. • Issuer: BP Capital U.K. (Old Exchange Notes) and BP Capital America (New Exchange Notes) • Title: 3.017% Guaranteed Notes due 2027 • Total principal amount outstanding: $123,582,000 (Old Exchange Notes) and $876,418,000 (New Exchange Notes) • Issuance date: 16 September 2016 (Old Exchange Notes) and 12 December 2018 (New Exchange Notes) 16 December 2016
42 • Maturity date: 16 January 2027 • Interest rate: 3.017% per annum • Date interest starts accruing: 16 September 2016 • Interest payment dates: Each 16 January and 16 July, subject to the day count convention. • First interest payment date: 16 January 2017 • Optional redemption: Prior to 16 October 2026 (the date that is three months prior to the scheduled maturity date for the 2027 fixed rate notes), the issuer has the right to redeem the 2027 fixed rate notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2027 fixed rate notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2027 fixed rate notes to be redeemed that would be due if such notes matured on 16 October 2026 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of redemption. On or after 16 October 2026 (the date that is three months prior to the scheduled maturity date for the 2027 fixed rate notes), the issuer has the right to redeem the 2027 fixed rate notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2027 fixed rate notes to be redeemed , plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2027 fixed rate notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by the issuer “Reference treasury dealer” means Barclays Capital Inc., BNP Paribas Securities Corp., HSBC Securities (USA) Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Mizuho Securities USA Inc. and Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.279% Guaranteed Notes due 2027 The following terms are applicable to the 3.279% Guaranteed Notes due 2027.
43 • Issuer: BP Capital U.K. • Title: 3.279% Guaranteed Notes due 2027 • Total principal amount outstanding: $1,500,000,000 • Issuance date: 19 September 2017 • Maturity date: 19 September 2027 • Interest rate: 3.279% per annum • Date interest starts accruing: 19 September 2017 • Interest payment dates: Each 19 March and 19 September, subject to the day count convention. • First interest payment date: 19 March 2018 • Optional redemption: Prior to 19 June 2027 (the date that is three months prior to the scheduled maturity date for the 2027 fixed rate notes), the issuer has the right to redeem the 2027 fixed rate notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2027 fixed rate notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2027 fixed rate notes to be redeemed that would be due if such notes matured on 19 June 2027 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of redemption. On or after 19 June 2027 (the date that is three months prior to the scheduled maturity date for the 2027 fixed rate notes), the issuer has the right to redeem the 2027 fixed rate notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2027 fixed rate notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2027 fixed rate notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by the issuer “Reference treasury dealer” means Credit Suisse Securities (USA) LLC, Goldman Sachs & Co. LLC, HSBC Securities (USA) Inc., J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and UBS Securities LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date,
44 the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.543% Guaranteed Notes due 2027 The following terms are applicable to the 3.543% Guaranteed Notes due 2027. • Issuer: BP Capital America • Title: 3.543% Guaranteed Notes due 2027 • Total principal amount outstanding: $500,000,000 • Issuance date: April 6, 2020 • Maturity date: April 6, 2027 • Interest rate: 3.543% per annum • Date interest starts accruing: April 6, 2020 • Interest payment dates: Each April 6 and October 6, subject to the day count convention. • First interest payment date: October 6, 2020 • Optional redemption: Prior to February 6, 2027 (the date that is two months prior to the scheduled maturity date for the 2027 notes), BP Capital America has the right to redeem the 2027 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2027 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2027 notes to be redeemed that would be due if such 2027 notes matured on February 6, 2027 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 45 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after February 6, 2027 (the date that is two months prior to the scheduled maturity date for the 2027 notes), BP Capital America has the right to redeem the 2027 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2027 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2027 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such 2027 notes. “Comparable treasury price” means, with respect to any redemption date, the average of the
45 reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by BP Capital America. “Reference treasury dealer” means BNP Paribas Securities Corp., BofA Securities, Inc., Citigroup Global Markets Inc., HSBC Securities (USA) Inc., J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.588% Guaranteed Notes due 2027 The following terms are applicable to the 3.588% Guaranteed Notes due 2027. • Issuer: BP Capital U.K. (Old Exchange Notes) and BP Capital America (New Exchange Notes) • Title: 3.588% Guaranteed Notes due 2027 • Total principal amount outstanding: $236,291,000 (Old Exchange Notes) and $613,709,000 (New Exchange Notes) • Issuance date: 14 February 2017 (Old Exchange Notes) and 12 December 2018 (New Exchange Notes) • Maturity date: 14 April 2027 • Interest rate: 3.588% per annum • Date interest starts accruing: 14 February 2017 • Interest payment dates: Each 14 April and 14 October, subject to the day count convention. • First interest payment date: 14 October 2017 • Optional redemption: Prior to 14 January 2027 (the date that is three months prior to the scheduled maturity date for the 2027 notes), the issuer has the right to redeem the 2027 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2027 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2027 notes to be redeemed that would be due if such notes matured on 14 January 2027 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of redemption. On or after 14 January 2027 (the date that is three months prior to the scheduled maturity date for the 2027 notes), the issuer has the right to redeem the 2027 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2027 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of
46 redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2027 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by the issuer “Reference treasury dealer” means Barclays Capital Inc., BNP Paribas Securities Corp., Deutsche Bank Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, MUFG Securities Americas Inc., and RBS Securities Inc. (marketing name “NatWest Markets”) or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefore another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.723% Guaranteed Notes due 2028 The following terms are applicable to the 3.723% Guaranteed Notes due 2028. • Issuer: BP Capital U.K. • Title: 3.723% Guaranteed Notes due 2028 • Total principal amount outstanding: $800,000,000 • Issuance date: 28 November 2016 • Maturity date: 28 November 2028 • Interest rate: 3.723% per annum • Date interest starts accruing: 28 November 2016 • Interest payment dates: Each 28 May and 28 November, subject to the day count convention. • First interest payment date: 28 May 2017 • Optional redemption: Prior to 28 August 2028 (the date that is three months prior to the scheduled maturity date for the 2028 notes), the issuer has the right to redeem the 2028 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2028 notes to be redeemed and (ii) the sum of the present values of the
47 remaining scheduled payments of principal and interest on the 2028 notes to be redeemed that would be due if such notes matured on 28 August 2028 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 25 basis points, plus in each case accrued and unpaid interest to the date of redemption. On or after 28 August 2028 (the date that is three months prior to the scheduled maturity date for the 2028 notes), the issuer has the right to redeem the 2028 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2028 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2028 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by the issuer “Reference treasury dealer” means BNP Paribas Securities Corp., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Goldman, Sachs & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated and MUFG Securities Americas Inc. or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.937% Guaranteed Notes due 2028 The following terms are applicable to the 3.937% Guaranteed Notes due 2028. • Issuer: BP Capital America • Title: 3.937% Guaranteed Notes due 2028 • Total principal amount outstanding: $1,000,000,000 • Issuance date: 21 September 2018 • Maturity date: 21 September 2028 • Interest rate: 3.937% per annum • Date interest starts accruing: 21 September 2018
48 • Interest payment dates: Each 21 March and 21 September, subject to the day count convention. • First interest payment date: 21 March 2019 • Optional redemption: Prior to 21 June 2028 (the date that is three months prior to the scheduled maturity date for the 2028 notes), BP Capital America has the right to redeem the 2028 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2028 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2028 notes to be redeemed that would be due if such notes matured on 21 June 2028 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 15 basis points, plus in each case accrued and unpaid interest to the date of redemption. On or after 21 June 2028 (the date that is three months prior to the scheduled maturity date for the 2028 notes), BP Capital America has the right to redeem the 2028 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2028 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2028 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by BP Capital America. “Reference treasury dealer” means Citigroup Global Markets Inc., Goldman Sachs & Co. LLC, HSBC Securities (USA) Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Mizuho Securities USA LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 4.234% Guaranteed Notes due 2028 The following terms are applicable to the 4.234% Guaranteed Notes due 2028. • Issuer: BP Capital America • Title: 4.234% Guaranteed Notes due 2028 • Total principal amount outstanding: $2,000,000,000
49 • Issuance date: 6 November 2018 (with respect to $1,000,000,000 aggregate principal amount of notes) and 11 February 2019 (with respect to $1,000,000,000 aggregate principal amount of notes) • Maturity date: 6 November 2028 • Interest rate: 4.234% per annum • Date interest starts accruing: 6 November 2018 • Interest payment dates: Each 6 May and 6 November, subject to the day count convention. • First interest payment date: 6 May 2019 • Optional redemption: Prior to 6 August 2028 (the date that is three months prior to the scheduled maturity date for the 2028 notes), BP Capital America has the right to redeem the 2028 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2028 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2028 notes to be redeemed that would be due if such notes matured on 6 August 2028 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 6 August 2028 (the date that is three months prior to the scheduled maturity date for the 2028 notes), BP Capital America has the right to redeem the 2028 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2028 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2028 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by BP Capital America. “Reference treasury dealer” means Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC, NatWest Markets Securities Inc., SG Americas Securities, LLC and UBS Securities LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date.
50 Description of 1.749% Guaranteed Notes due 2030 The following terms are applicable to the 1.749% Guaranteed Notes due 2030. • Issuer: BP Capital America • Title: 1.749% Guaranteed Notes due 2030 • Total principal amount outstanding: $1,000,000,000 • Issuance date: August 10, 2020 • Maturity date: August 10, 2030 • Interest rate: 1.749% per annum • Date interest starts accruing: August 10, 2020 • Interest payment dates: Each February 10 and August 10, subject to the day count convention. • First interest payment date: February 10, 2021 • Optional redemption: Prior to May 10, 2030 (the date that is three months prior to the scheduled maturity date for the 2030 notes), BP Capital America has the right to redeem the 2030 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2030 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2030 notes to be redeemed that would be due if such 2030 notes matured on May 10, 2030 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after May 10, 2030 (the date that is three months prior to the scheduled maturity date for the 2030 notes), BP Capital America has the right to redeem the 2030 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2030 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2030 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such 2030 notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by BP Capital America. “Reference treasury dealer” means Citigroup Global Markets Inc., HSBC Securities (USA) Inc., J.P. Morgan Securities LLC, Mizuho Securities USA LLC and Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors,
51 and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.633% Guaranteed Notes due 2030 The following terms are applicable to the 3.633% Guaranteed Notes due 2030. • Issuer: BP Capital America • Title: 3.633% Guaranteed Notes due 2030 • Total principal amount outstanding: $1,250,000,000 • Issuance date: April 6, 2020 • Maturity date: April 6, 2030 • Interest rate: 3.633% per annum • Date interest starts accruing: April 6, 2020 • Interest payment dates: Each April 6 and October 6, subject to the day count convention. • First interest payment date: October 6, 2020 • Optional redemption: Prior to January 6, 2030 (the date that is three months prior to the scheduled maturity date for the 2030 notes), BP Capital America has the right to redeem the 2030 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2030 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2030 notes to be redeemed that would be due if such 2030 notes matured on January 6, 2030 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 45 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after January 6, 2030 (the date that is three months prior to the scheduled maturity date for the 2030 notes), BP Capital America has the right to redeem the 2030 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2030 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated
52 maturity comparable to the remaining term of the 2030 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such 2030 notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by BP Capital America. “Reference treasury dealer” means BNP Paribas Securities Corp., BofA Securities, Inc., Citigroup Global Markets Inc., HSBC Securities (USA) Inc., J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 2.772% Guaranteed Notes due 2050 The following terms are applicable to the 2.772% Guaranteed Notes due 2050. • Issuer: BP Capital America • Title: 2.772% Guaranteed Notes due 2050 • Total principal amount outstanding: $1,500,000,000 • Issuance date: August 10, 2020 • Maturity date: November 10, 2050 • Interest rate: 2.772% per annum • Date interest starts accruing: August 10, 2020 • Interest payment dates: Each May 10 and November 10, subject to the day count convention. • First interest payment date: May 10, 2021 • Optional redemption: Prior to May 10, 2050 (the date that is six months prior to the scheduled maturity date for the 2050 notes), BP Capital America has the right to redeem the 2050 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2050 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2050 notes to be redeemed that would be due if such 2050 notes matured on May 10, 2050 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 25 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after May 10, 2050 (the date that is six months prior to the scheduled maturity date for the 2050 notes), BP Capital America has the right to redeem the 2050 notes, in whole or
53 in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2050 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2050 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such 2050 notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by BP Capital America. “Reference treasury dealer” means Citigroup Global Markets Inc., HSBC Securities (USA) Inc., J.P. Morgan Securities LLC, Mizuho Securities USA LLC and Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.000% Guaranteed Notes due 2050 The following terms are applicable to the 3.000% Guaranteed Notes due 2050. • Issuer: BP Capital America • Title: 3.000% Guaranteed Notes due 2050 • Total principal amount outstanding: $2,000,000,000 • Issuance date: February 24, 2020 (with respect to $1,250,000,000 aggregate principal amount of notes) and March 9, 2020 (with respect to $750,000,000 aggregate principal amount of notes) • Maturity date: February 24, 2050 • Interest rate: 3.000% per annum • Date interest starts accruing: February 24, 2020 • Interest payment dates: Each February 24 and August 24, subject to the day count convention. • First interest payment date: August 24, 2020
54 • Optional redemption: Prior to August 24, 2049 (the date that is six months prior to the scheduled maturity date for the notes), BP Capital America has the right to redeem the notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of 100% of the principal amount of the notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed that would be due if such notes matured on August 24, 2049 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after August 24, 2049 (the date that is six months prior to the scheduled maturity date for the notes), BP Capital America has the right to redeem the notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by BP Capital America. “Reference treasury dealer” means Barclays Capital Inc., BofA Securities, Inc., Goldman Sachs & Co. LLC and Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.067% Guaranteed Notes due 2050 • Issuer: BP Capital America • Title: 3.067% Guaranteed Notes due 2050 • Total principal amount outstanding: $500,000,000 • Issuance date: 13 December 2019 • Maturity date: 30 March 2050 • Interest rate: 3.067% per annum
55 • Date interest starts accruing: 13 December 2019 • Interest payment dates: 30 March and 30 September of each year, subject to the day count convention. • First interest payment date: 30 March 2020 (short first coupon) • Redemption at the option of BP Capital America: On or after 31 March 2025 and prior to 30 September 2049 (the date that is six months prior to the scheduled maturity date for the notes), BP Capital America has the right to redeem the notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed that would be due if such notes matured on 30 September 2049 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 15 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 30 September 2049 (the date that is six months prior to the scheduled maturity date for the notes), BP Capital America has the right to redeem the notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semiannual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by BP Capital America “Reference treasury dealer” means Citigroup Global Markets Inc. or one of its affiliates, which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and its successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. • Redemption at the option of the holder: Holders of the notes have the right to elect to have BP Capital America redeem the notes in whole or in part in increments of $1,000 on 30 March 2025 at a price equal to 94.022% of the principal amount of the notes to be redeemed together with accrued interest to such date. If the notes are held in book-entry form through DTC, then in order to exercise the option to redeem the notes, a beneficial holder of the notes must (i) instruct its direct or indirect participant through which it holds an interest in the notes to notify the trustee of its election to exercise its repayment option in accordance with the then-applicable operating procedures of DTC and (ii) provide an email notice of such holder’s intention to exercise its option to redeem the notes
56 to [email protected]. In order for the exercise of the option to be effective and the note to be repaid, such notice must be delivered to the trustee through DTC during the period from and including 30 January 2025 to and including the close of business on February 28, 2025 (or, if 28 February 2025 is not a business day, the next succeeding business day). DTC must receive any such notice from its participants in time to exercise such repayment option request in accordance with their applicable operating procedures and the terms of the notes. Different firms have different deadlines for accepting instructions from their customers. The beneficial holder should consult the direct or indirect participant through which it holds an interest in the notes to ascertain the deadline for ensuring that timely notice will be delivered to DTC. If the notes are not held in book-entry form, then in order for the exercise of the option to be effective and a note to be repaid, BP Capital America must receive, at the office of the trustee located at The Bank of New York Mellon Trust Company, N.A., 2 North LaSalle Street, Suite 700, Chicago, Illinois 60602 Attention: Corporate Trust Administration, with a copy (which shall not constitute notice) sent to [email protected], during the period from and including January 30, 2025 to and including the close of business on 28 February 2025 (or, if 28 February 2025 is not a business day, the next succeeding business day), such note, together with the form entitled “Option to Elect Repayment” attached to such note duly completed. Exercise of the repayment option by the holder of a note shall be irrevocable. No transfer or of any note (or, in the event that any note is to be repaid in part, such portion of the note to be repaid) will be permitted after exercise of the repayment option. Description of 2.939% Guaranteed Notes due 2051 The following terms are applicable to the 2.939% Guaranteed Notes due 2051. • Issuer: BP Capital America • Title: 2.939% Guaranteed Notes due 2051 • Total principal amount outstanding: $1,500,000,000 • Issuance date: December 4, 2020 • Maturity date: June 4, 2051 • Interest rate: 2.939% per annum • Date interest starts accruing: December 4, 2020 • Interest payment dates: Each June 4 and December 4, subject to the day count convention. • First interest payment date: June 4, 2021 • Optional redemption: Prior to December 4, 2050 (the date that is six months prior to the scheduled maturity date for the notes), BP Capital America has the right to redeem the notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed that would be due if such notes matured on December 4, 2050 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after
57 December 4, 2050 (the date that is six months prior to the scheduled maturity date for the notes), BP Capital America has the right to redeem the notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. “Treasury rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. “Comparable treasury issue” means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. “Comparable treasury price” means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. “Quotation agent” means one of the reference treasury dealers appointed by BP Capital America. “Reference treasury dealer” means Barclays Capital Inc., BofA Securities, Inc., Goldman Sachs & Co. LLC and J.P. Morgan Securities LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. “Reference treasury dealer quotations” means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 4.375% Perpetual Subordinated Non-Call 5.25 Fixed Rate Reset Notes The following terms are applicable to the 4.375% Perpetual Subordinated Non-Call 5.25 Fixed Rate Reset Notes. • Issuer: BP Capital U.K. • Title: 4.375% Perpetual Subordinated Non-Call 5.25 Fixed Rate Reset Notes • Total principal amount outstanding: $2,500,000,000 • Issuance date: June 22, 2020 • Maturity date: The notes are perpetual securities in respect of which there is no fixed redemption date. BP Capital U.K. shall only have the right to redeem, purchase or substitute or vary the notes in accordance with “—Optional Redemption on Interest Payment Date”, “—Optional Redemption for Certain Events”, “—Optional Tax Redemption”, “—Substitution or Variation” as described in the applicable Prospectus Supplement or otherwise in accordance with the terms of the notes. • Ranking of the Notes: The notes are unconditional, unsecured and subordinated obligations of BP Capital U.K. and will rank pari passu without any preference among themselves and pari passu with any Parity Obligations of BP Capital U.K. but junior to any Senior Obligations of BP Capital U.K. and senior to the Ordinary Shares of BP Capital U.K.
58 • To give effect to the intended ranking described above, if at any time a Winding-Up of BP Capital U.K. occurs (otherwise than for the purposes of a Solvent Reorganization of BP Capital U.K.), the amount payable by BP Capital U.K. to a Noteholder under or in relation to such noteholder’s notes (in lieu of any other payment by BP Capital U.K. to such noteholder under or in relation to the notes, including pursuant to the terms of the notes or the Indenture) shall be the amount that would have been payable to such noteholder if, immediately prior to and throughout such Winding-Up, such noteholder was the holder of Notional Preference Shares in BP Capital U.K. For the purposes only of that calculation, in respect of each note and accrued but unpaid interest (including any outstanding Arrears of Interest in respect of such interest) a noteholder will be deemed to hold a Notional Preference Share in BP Capital U.K. entitling the holder thereof to receive in respect of such Notional Preference Share an amount in the Winding-Up of BP Capital U.K. that is equal to the principal amount of the relevant note and any accrued but unpaid interest and any outstanding Arrears of Interest in respect of such interest (without double counting) (and, in the case of an administration, on the same assumption that shareholders were entitled to claim and recover in respect of their shares to the same degree as in a Winding- Up). Amounts payable to the noteholders of the notes pursuant to this provision will only be paid after the debts owing to the holders of the Senior Obligations of BP Capital U.K. have been paid in full. The subordination provisions applicable to the notes will be governed by English law. • “Winding-Up” means an order being made, or an effective resolution being passed, for the winding-up of BP Capital U.K. or BP, as the case may be, or an administrator of BP Capital U.K. or BP, as the case may be, being appointed and such administrator giving notice that it intends to declare and distribute a dividend. • Ranking of the Guarantee: The payment of the principal of and interest on the notes is fully guaranteed by BP. The obligations of BP under the Guarantee are unconditional, unsecured and subordinated and the rights and claims of noteholders will rank pari passu without any preference among themselves and pari passu with any Parity Obligations of BP but junior to any Senior Obligations of BP and senior to the Ordinary Shares of BP. • To give effect to the intended ranking described above, if at any time a Winding-Up of BP occurs (otherwise than for the purposes of a Solvent Reorganization of BP), the amount payable by BP to a noteholder under or in relation to the Guarantee (in lieu of any other payment by BP to such noteholder under or in relation to the Guarantee), shall be the amount that would have been payable to such noteholder if, immediately prior to and throughout such Winding-Up, such noteholder was the holder of Notional Preference Shares in BP. For the purposes only of that calculation, in respect of each note and accrued but unpaid interest (including any outstanding Arrears of Interest in respect of such interest payment) a noteholder will be deemed to hold a Notional Preference Share in BP entitling the holder thereof to receive in respect of such Notional Preference Share an amount in the Winding-Up of BP that is equal to the principal amount of the relevant note and any accrued but unpaid interest and any outstanding Arrears of Interest in respect of such interest (without double counting) (and, in the case of an administration, on the assumption that the shareholders were entitled to claim and recover in respect of their shares to the same degree as in a Winding-Up). For the purpose of construing the provisions of the Guarantee and BP’s payment obligations in respect thereof, the latter amounts shall be treated as due and payable by the Issuer on the date such Winding-Up order of BP Capital U.K. is made or such resolution is passed or notice is given, as the case may be and, consequently, a claim under the Guarantee in respect of such amount may be made on, or at any time after,
59 such date. Amounts payable to the noteholder upon Winding-Up will only be paid after the debts owing to the holders of the Senior Obligations of BP have been paid in full. The subordination provisions applicable to the Guarantee will be governed by English law. • Deferral of Interest: BP Capital U.K. may elect, in its sole discretion, to defer payment of the amount of interest (in whole or in part) (a “Deferred Interest Payment”) due on any Interest Payment Date in respect of the notes. Such Deferred Interest Payments will accrue additional interest at the relevant interest rate prevailing from time to time (which will also be added to any Deferred Interest Payments on each subsequent Interest Payment Date and accrue interest in the same manner). Any such deferred payments and any additional interest thereon are referred to as “Arrears of Interest”. BP Capital U.K. must pay Arrears of Interest in respect of the relevant notes upon the date for redemption of all the relevant notes or in certain other limited circumstances. • Interest rate: (a) 4.375% per annum, for the period from (and including) the Issue Date to (but excluding) the relevant First Reset Date and (b) from (and including) the relevant First Reset Date, at an Interest Rate per annum equal to the relevant Reset Interest Rate, in each case on the outstanding principal amount of the Notes. • Reset Date: The Reset Dates will be (a) the relevant First Reset Date and (b) each date that falls five, or a multiple of five, years following the relevant First Reset Date. • First Reset Date: The First Reset Date will be September 22, 2025. • Reset Determination Date: The Reset Determination Date will be the day falling two Business Days prior to the relevant Reset Date. • Reset Interest Rate: The Reset Interest Rate, in relation to any Reset Period, is the sum of the relevant Five-Year Treasury Rate, calculated as provided for in the relevant Prospectus Supplement, in relation to that Reset Period plus the Margin applicable to that Reset Period. • Reset Period: The period from (and including) the relevant First Reset Date to (but excluding) the next relevant Reset Date, and each successive period from (and including) a Reset Date to (but excluding) the next succeeding Reset Date. • Date interest starts accruing: June 22, 2020 • Interest payment dates: Each March 22 and September 22, subject to the day count convention and the Optional Interest Deferral described in the relevant Prospectus Supplement. • Interest Periods: The period beginning on (and including) the Issue Date and ending on (but excluding) the first Interest Payment Date and each successive period beginning on (and including) an Interest Payment Date and ending on (but excluding) the next succeeding Interest Payment Date. • First interest payment date: September 22, 2020 • Interest Amount: Subject to Optional Interest Deferral, the amount of interest payable in respect of the Calculation Amount on each Interest Payment Date to (and including) the relevant First Reset Date shall be, with respect to the Non-Call 5.25 Notes, $21.88. Subject to Optional Interest Deferral, the amount of interest payable in respect of the Calculation Amount for any other period for which interest is to be calculated shall be calculated by:
60 • applying the applicable Interest Rate to the Calculation Amount; • multiplying the product thereof by the Day Count Fraction; and • rounding the resulting figure to the nearest cent (half a cent being rounded upwards). • The relevant amount of interest payable in respect of the notes for any period shall be the product of: (i) the relevant amount of interest per Calculation Amount determined as described above; and (ii) the number by which the Calculation Amount is required to be multiplied to equal the principal amount of the notes. • “Calculation Amount” means $1,000. • “Day Count Fraction” means 30/360. Where it is necessary to calculate an amount of interest in respect of any Note for a period which is less than or equal to a complete Interest Period, such interest shall be calculated on the basis of a 360-day year consisting of 12 months of 30 days each and, in the case of an incomplete month, the number of days elapsed. • Optional redemption: Subject to applicable laws, BP Capital U.K. may, by giving not less than 10 nor more than 60 days’ notice to the Trustee and the relevant Noteholders in accordance with the notice provisions set forth in the Indenture (which notice shall be irrevocable), redeem the relevant notes (in whole but not in part) on the First Call Date, which shall be June 22, 2025, and on any day thereafter to (and including) the First Reset Date, which shall be September 22, 2025, or on any Interest Payment Date thereafter, at their outstanding principal amount plus any accrued but unpaid interest up to (but excluding) the relevant Redemption Date and any outstanding Arrears of Interest (without double counting). • Outstanding Liabilities: As of December 31, 2020 the total finance debt and lease liabilities of the BP group, all of which would rank senior to the notes and the related guarantee upon liquidation, equaled approximately $81,926,000,000 in aggregate principal amount. This does not include obligations of the subsidiaries of BP (other than BP Capital Markets U.K.), to which the obligations of BP under the Guarantee are structurally subordinated. As of December 31, 2020, BP had outstanding 5,473,414 cumulative second preference shares of £1 each, which will rank as Parity Obligations to the Guarantee as of the Issue Date. As of December 31, 2020 BP also had outstanding 7,232,838 cumulative first preference shares of £1 each, which will rank as Senior Obligations to the Guarantee as of the Issue Date. • Limitations on the Issuance of Additional Senior Indebtedness: None of the notes, the guarantee or the indenture under which the notes were issued restrict BP Capital U.K. or BP from issuing additional securities (including preference shares or other equity securities) which will be deemed Parity Obligations or Senior Obligations of the notes and Guarantee, as applicable. • Substitution or Variation: If a Rating Agency Event, an Accounting Event, a Tax Deduction Event or an event that permits an Optional Tax Redemption to occur (a “Substitution or Variation Event”) has occurred and is continuing, then BP Capital U.K. or BP may, as an alternative to redemption, subject to the conditions set forth under “—Conditions to Special Event Redemption and Substitution or Variation” in the applicable Prospectus Supplement (without any requirement for the consent or approval of the Noteholders) and subject to the Trustee, immediately prior to the giving of any notice referred to herein, having received an officers’ certificate and an opinion of
61 counsel (each as defined in the Indenture), each stating to the effect that the provisions of this section have been complied with, and having given not less than 10 nor more than 60 days’ notice to the Trustee, the Calculation Agent and the relevant Noteholders (which notice shall be irrevocable), at any time either (i) substitute all, but not less than all, of the relevant notes for, or (ii) vary the terms of the relevant notes with the effect that they remain or become (as the case may be), Qualifying Securities, and the Noteholders shall be bound by such substitution or variation. Upon expiry of such notice, BP Capital U.K. or BP will either vary the terms of or, as the case may be, substitute the relevant notes in accordance with this section. In connection with the substitution of Qualifying Securities for the relevant notes or the variation of the terms of the relevant notes, each Noteholder by the purchase of the relevant notes authorizes the Trustee to, and the Trustee shall, authenticate such new notes in accordance with Section 303 of the Indenture. In connection with any substitution or variation in accordance with this section, BP Capital U.K. will comply with the rules of any stock exchange on which the relevant notes are for the time being listed or admitted to trading. Any such substitution or variation in accordance with the foregoing provisions following a Substitution or Variation Event shall only be permitted if it does not give rise to any other Substitution or Variation Event with respect to the Qualifying Securities. Any such substitution or variation in accordance with the foregoing provisions following a Substitution or Variation Event shall only be permitted if it does not result in the Qualifying Securities no longer being eligible for the same, or a higher amount of, “equity credit” (or such other nomenclature that the Rating Agency may then use to describe the degree to which an instrument exhibits the characteristics of an ordinary share) as is attributed to the relevant notes on the date notice is given to Noteholders of the substitution or variation. In no event shall the Trustee have any responsibility whatsoever to determine whether any such substitution or variation results in the Qualifying Securities. Any such substitution or variance could have unexpected commercial consequences depending on the circumstances of an individual Noteholder, and we will consider the impact on the class of Noteholders taken as a whole and are not required to take into account the individual circumstances of each Noteholder. “Qualifying Securities” means securities that contain terms not materially less favorable to the class of Noteholders of the Non-Call 5.25 Notes or Non-Call 10 Notes, as the case may be, and in each case taken as a whole, than the terms of the respective notes (as reasonably determined by BP Capital U.K. (in consultation with an independent investment bank or counsel of international standing)) and provided that an officers’ certificate to such effect (and confirming that the conditions set out in (a) to (j) below have been satisfied) shall have been delivered to the Trustee prior to the substitution or variation of the relevant notes upon which certificate the Trustee shall rely absolutely). Such Qualifying Securities: a) shall be issued by (x) BP Capital U.K. (or any successor thereto as issuer of the relevant notes) with a guarantee of BP (or any successor thereto as guarantor of the relevant notes), (y) BP or (z) a wholly owned direct or indirect finance subsidiary of BP with a guarantee of BP (or any successor thereto as guarantor of the relevant notes); and b) (and/or, as appropriate, the guarantee as aforesaid) shall rank pari passu on a Winding-Up of BP Capital U.K. (or any successor thereto as issuer of the relevant notes) with the relevant notes or on a Winding-Up of BP (or any successor thereto as guarantor of the relevant notes) with the Guarantee; and c) shall contain terms which provide for the same or a more favorable Interest Rate from time to time applying to the relevant notes and preserve the same Interest Payment Dates; and
62 d) shall preserve the obligations (including the obligations arising from the exercise of any right) of BP Capital U.K. (or any successor thereto as issuer of the relevant notes) as to redemption of the relevant notes, including (without limitation) as to timing of, and amounts payable upon, such redemption; and e) shall preserve any existing rights under the terms of the relevant notes to any accrued interest, any Deferred Interest Payments, any Arrears of Interest and any other amounts payable under the relevant notes which, in each case, has accrued to Noteholders and not been paid; and f) shall not contain terms providing for loss absorption through principal write-down or conversion to ordinary shares; and g) shall otherwise contain substantially identical terms (as reasonably determined by BP Capital U.K. (or any successor thereto as issuer of the relevant notes)) to the relevant notes, save where (without prejudice to the requirement that the terms are not materially less favorable to the class of relevant Noteholders taken as a whole than the terms of the relevant notes as described above) any modifications to such terms are required to be made to avoid the occurrence or effect of a Rating Agency Event, an Accounting Event, a Tax Deduction Event or an event that permits an Optional Tax Redemption to occur; and h) shall, immediately after such substitution or variation, be assigned at least the same credit rating(s) by the same Rating Agencies as may have been assigned to the relevant notes at the invitation of or with the consent of BP Capital U.K. (or any successor thereto as issuer of the relevant notes) immediately prior to such substitution or variation; and i) shall not provide for the mandatory deferral or cancellation of payments of interest and/or principal; and j) shall be (x) listed on the Official List and admitted to trading on the London Stock Exchange plc’s Main Market or (y) listed on such other stock exchange as is a Recognised Stock Exchange at that time or admitted to trading on a Multilateral Trading Facility as selected by BP Capital U.K (or any successor thereto as issuer of the relevant notes). For the purposes of the definition of Qualifying Securities: “Multilateral Trading Facility” means a multilateral trading facility described in section 987(1)(b) of the Income Tax Act 2007 of the United Kingdom, as the same may be amended from time to time and any provision, statute or statutory instrument replacing the same from time to time; “Official List” means the Official List of the Financial Conduct Authority in its capacity as competent authority under the Financial Services and Markets Act 2000 of the United Kingdom (as the same may be amended from time to time and any provision, statute or statutory instrument replacing the same from time to time); and “Recognised Stock Exchange” means a recognised stock exchange as defined in section 1005 of the Income Tax Act 2007 of the United Kingdom as the same may be amended from time to time and any provision, statute or statutory instrument replacing the same from time to time.
63 • Events of Default Provisions • An Event of Default under the relevant notes occurs only in the event of a Winding-Up of BP Capital U.K. or BP other than for the purposes of a Solvent Reorganization of BP Capital U.K. or BP. If, for a period of 30 days or more, BP Capital U.K. or BP are in default in the payment of any principal or interest (including any Arrears of Interest) in respect of the relevant notes which is due and payable (a “Payment Default”), then BP Capital U.K. and/or BP, as the case may be, will be deemed to be in default under the Indenture and the relevant notes, and the Trustee may, and if instructed by the holders as described in “— Entitlement of the Trustee” below shall, take such actions as set forth under “— Proceedings” or “—Enforcement” below to institute actions, steps or proceedings for the Winding-Up of BP Capital U.K. and/or BP. For the avoidance of doubt, a Payment Default is not an Event of Default and shall not result in any right of Acceleration pursuant to Section 502 of the Indenture. • Proceedings: If a Payment Default occurs and is continuing, then BP Capital U.K. or BP, as the case may be, shall, without notice from the Trustee, be deemed to be in default under the Indenture and the relevant notes and (subject to the provisions set forth below) the Trustee may, and if instructed by the holders as described in “—Entitlement of the Trustee” below shall, institute actions, steps or proceedings for the Winding-Up of BP Capital U.K. and/or BP and/or prove in the Winding-Up of BP Capital U.K. and/or BP and/or claim in the liquidation or administration of BP Capital U.K. and/or BP, such claim being subordinated, and for the amount, as provided in “—Subordination and Waiver of Set-off Provisions”. • Enforcement: Without prejudice to “—Proceedings” and subject to the provisions set forth below, the Trustee may, and if instructed by the holders as described in “—Entitlement of the Trustee” below shall, at any time and without further notice, institute such proceedings or take such steps or actions against BP Capital U.K. and/or BP as it may think fit to enforce any term or condition binding on BP Capital U.K. and/or BP under the Indenture or the relevant notes, but in no event shall BP Capital U.K. and/or BP, by virtue of the institution of any such proceedings, steps or actions, be obliged to pay any sum or sums in cash or otherwise, sooner than the same would otherwise have been payable by it under the Indenture or the relevant notes. • Entitlement of Trustee: The Trustee shall not be bound to take any of the actions referred to in the provisions set forth under “— Proceedings” or “—Enforcement” above against BP Capital U.K. and/or BP to enforce the terms of the Indenture or the relevant notes at the request of the Noteholders or take any other action or step under or pursuant to the terms of the relevant notes or the Indenture unless (i) it shall have been so requested in writing by the Noteholders of at least 25% in principal amount of the relevant notes then outstanding and (ii) it shall have been indemnified and/or secured and/or prefunded by the relevant Noteholders to its satisfaction. However, if a Payment Default or an Event of Default has occurred and is continuing, the Trustee shall exercise such of the rights and powers vested in it by the Indenture, and use the same degree of care and skill in their exercise, as a prudent person would exercise or use under the circumstances in the conduct of his or her own affairs. The Trustee shall not be liable with respect to any action taken or omitted to be taken by it in good faith in accordance with the request of the Noteholders of at least 25% in principal amount of the relevant notes then outstanding.
64 • Right of Noteholders: No Noteholder shall be entitled to proceed directly against BP Capital U.K. or BP or to institute proceedings for the Winding-Up or claim in the liquidation of BP Capital U.K. or BP or to prove in such Winding-Up unless the Trustee, having become so bound to proceed, institute, prove or claim, fails to do so within a 60 day period and such failure shall be continuing, in which case the Noteholder shall have only such rights against BP Capital U.K. or BP as those which the Trustee is entitled to exercise as set out in this section. • Extent of Noteholders’ Remedy: No remedy against BP Capital U.K. or BP, other than as referred to in the relevant prospectus supplement, shall be available to the Trustee or the Noteholders, whether for the recovery of amounts owing in respect of the relevant notes or under the Indenture or in respect of any breach by BP Capital U.K. or BP of any of their other obligations under or in respect of the relevant notes or under the Indenture. For the avoidance of doubt, nothing in the foregoing shall (i) prevent the Trustee from proving in any Winding-Up (otherwise than for the purposes of a Solvent Reorganization of BP Capital U.K. or BP, as the case may be) or administration of BP Capital U.K. or BP and/or claiming in any liquidation of BP Capital U.K. or BP (even if not instituted by the Trustee), or (ii) impair the right of any Noteholder to receive payment of principal, premium or interest (including Arrears of Interest) on such noteholder’s notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such noteholder’s notes. • Defined Terms: The following definitions shall apply to subordination of the notes and subordination of the guarantee provisions: • “Notional Preference Shares” means, with respect to BP Capital U.K. or BP, as the case may be, a notional class of preference shares in the capital of BP Capital U.K. or BP, as the case may be: (i) ranking junior to the claims of all holders of Senior Obligations of BP Capital U.K. or BP, as the case may be; (ii) having an equal right to return of assets in the Winding-Up of BP Capital U.K. or BP, as the case may be, and so ranking pari passu with any Parity Obligations of BP Capital U.K. or BP, as the case may be; and (iii) having a right to return of capital ahead of, and so ranking ahead of, the claims of holders of the Ordinary Shares of BP Capital U.K. or BP, as the case may be. • “Parity Obligations” means, with respect to BP Capital U.K. or BP, as the case may be: (a) the most junior class of preference share capital of BP Capital U.K. or BP, as the case may be; and (b) any other security, guarantee or other instrument issued by, or any other obligation of BP Capital U.K. or BP, as the case may be, which ranks or is expressed to rank pari passu with BP Capital U.K.’s obligations under the Notes or BP’s obligations under the Guarantee, including the Other Hybrid Capital Notes. • “Ordinary Shares” means (i) any ordinary shares in the capital of BP Capital U.K. or BP, as the case may be, or (ii) any present or future shares of any other class of shares of BP Capital U.K. or BP, as the case may be, ranking pari passu with the ordinary shares of BP Capital U.K. or BP, as the case may be or, in either case, any depository or other receipts or certificates, including American depositary receipts representing such shares. • “Senior Obligations” means all obligations of BP Capital U.K. or BP, as the case may be, but excluding any Parity Obligations and any Ordinary Shares of BP Capital U.K. or BP, as the case may be.
65 Description of 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes The following terms are applicable to the 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes. • Issuer: BP Capital U.K. • Title: 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes • Total principal amount outstanding: $2,500,000,000 • Issuance date: June 22, 2020 • Maturity date: The notes are perpetual securities in respect of which there is no fixed redemption date. BP Capital U.K. shall only have the right to redeem, purchase or substitute or vary the notes in accordance with “—Optional Redemption on Interest Payment Date”, “—Optional Redemption for Certain Events”, “—Optional Tax Redemption”, “—Substitution or Variation” as described in the applicable Prospectus Supplement or otherwise in accordance with the terms of the notes. • Ranking of the Notes: The notes are unconditional, unsecured and subordinated obligations of BP Capital U.K. and will rank pari passu without any preference among themselves and pari passu with any Parity Obligations of BP Capital U.K. but junior to any Senior Obligations of BP Capital U.K. and senior to the Ordinary Shares of BP Capital U.K. • To give effect to the intended ranking described above, if at any time a Winding-Up of BP Capital U.K. occurs (otherwise than for the purposes of a Solvent Reorganization of BP Capital U.K.), the amount payable by BP Capital U.K. to a Noteholder under or in relation to such noteholder’s notes (in lieu of any other payment by BP Capital U.K. to such noteholder under or in relation to the notes, including pursuant to the terms of the notes or the Indenture) shall be the amount that would have been payable to such noteholder if, immediately prior to and throughout such Winding-Up, such noteholder was the holder of Notional Preference Shares in BP Capital U.K. For the purposes only of that calculation, in respect of each note and accrued but unpaid interest (including any outstanding Arrears of Interest in respect of such interest) a noteholder will be deemed to hold a Notional Preference Share in BP Capital U.K. entitling the holder thereof to receive in respect of such Notional Preference Share an amount in the Winding-Up of BP Capital U.K. that is equal to the principal amount of the relevant note and any accrued but unpaid interest and any outstanding Arrears of Interest in respect of such interest (without double counting) (and, in the case of an administration, on the same assumption that shareholders were entitled to claim and recover in respect of their shares to the same degree as in a Winding- Up). Amounts payable to the noteholders of the notes pursuant to this provision will only be paid after the debts owing to the holders of the Senior Obligations of BP Capital U.K. have been paid in full. The subordination provisions applicable to the notes will be governed by English law. • “Winding-Up” means an order being made, or an effective resolution being passed, for the winding-up of BP Capital U.K. or BP, as the case may be, or an administrator of BP Capital U.K. or BP, as the case may be, being appointed and such administrator giving notice that it intends to declare and distribute a dividend.
66 • Ranking of the Guarantee: The payment of the principal of and interest on the notes is fully guaranteed by BP. The obligations of BP under the Guarantee are unconditional, unsecured and subordinated and the rights and claims of noteholders will rank pari passu without any preference among themselves and pari passu with any Parity Obligations of BP but junior to any Senior Obligations of BP and senior to the Ordinary Shares of BP. • To give effect to the intended ranking described above, if at any time a Winding-Up of BP occurs (otherwise than for the purposes of a Solvent Reorganization of BP), the amount payable by BP to a noteholder under or in relation to the Guarantee (in lieu of any other payment by BP to such noteholder under or in relation to the Guarantee), shall be the amount that would have been payable to such noteholder if, immediately prior to and throughout such Winding-Up, such noteholder was the holder of Notional Preference Shares in BP. For the purposes only of that calculation, in respect of each note and accrued but unpaid interest (including any outstanding Arrears of Interest in respect of such interest payment) a noteholder will be deemed to hold a Notional Preference Share in BP entitling the holder thereof to receive in respect of such Notional Preference Share an amount in the Winding-Up of BP that is equal to the principal amount of the relevant note and any accrued but unpaid interest and any outstanding Arrears of Interest in respect of such interest (without double counting) (and, in the case of an administration, on the assumption that the shareholders were entitled to claim and recover in respect of their shares to the same degree as in a Winding-Up). For the purpose of construing the provisions of the Guarantee and BP’s payment obligations in respect thereof, the latter amounts shall be treated as due and payable by the Issuer on the date such Winding-Up order of BP Capital U.K. is made or such resolution is passed or notice is given, as the case may be and, consequently, a claim under the Guarantee in respect of such amount may be made on, or at any time after, such date. Amounts payable to the noteholder upon Winding-Up will only be paid after the debts owing to the holders of the Senior Obligations of BP have been paid in full. The subordination provisions applicable to the Guarantee will be governed by English law. • Deferral of Interest: BP Capital U.K. may elect, in its sole discretion, to defer payment of the amount of interest (in whole or in part) (a “Deferred Interest Payment”) due on any Interest Payment Date in respect of the notes. Such Deferred Interest Payments will accrue additional interest at the relevant interest rate prevailing from time to time (which will also be added to any Deferred Interest Payments on each subsequent Interest Payment Date and accrue interest in the same manner). Any such deferred payments and any additional interest thereon are referred to as “Arrears of Interest”. BP Capital U.K. must pay Arrears of Interest in respect of the relevant notes upon the date for redemption of all the relevant notes or in certain other limited circumstances. • Interest rate: (a) 4.875% per annum, for the period from (and including) the Issue Date to (but excluding) the relevant First Reset Date and (b) from (and including) the relevant First Reset Date, at an Interest Rate per annum equal to the relevant Reset Interest Rate, in each case on the outstanding principal amount of the Notes. • Reset Date: The Reset Dates will be (a) the relevant First Reset Date and (b) each date that falls five, or a multiple of five, years following the relevant First Reset Date. • First Reset Date: The First Reset Date will be June 22, 2030. • Reset Determination Date: The Reset Determination Date will be the day falling two Business Days prior to the relevant Reset Date.
67 • Reset Interest Rate: The Reset Interest Rate, in relation to any Reset Period, is the sum of the relevant Five-Year Treasury Rate, calculated as provided for in the relevant Prospectus Supplement, in relation to that Reset Period plus the Margin applicable to that Reset Period. • Reset Period: The period from (and including) the relevant First Reset Date to (but excluding) the next relevant Reset Date, and each successive period from (and including) a Reset Date to (but excluding) the next succeeding Reset Date. • Date interest starts accruing: June 22, 2020 • Interest payment dates: Each June 22 and December 22, subject to the day count convention and the Optional Interest Deferral described in the relevant Prospectus Supplement. • Interest Periods: The period beginning on (and including) the Issue Date and ending on (but excluding) the first Interest Payment Date and each successive period beginning on (and including) an Interest Payment Date and ending on (but excluding) the next succeeding Interest Payment Date. • First interest payment date: December 22, 2020 • Interest Amount: Subject to Optional Interest Deferral, the amount of interest payable in respect of the Calculation Amount on each Interest Payment Date to (and including) the relevant First Reset Date shall be, with respect to the Non-Call 10 Notes, $24.38. Subject to Optional Interest Deferral, the amount of interest payable in respect of the Calculation Amount for any other period for which interest is to be calculated shall be calculated by: • applying the applicable Interest Rate to the Calculation Amount; • multiplying the product thereof by the Day Count Fraction; and • rounding the resulting figure to the nearest cent (half a cent being rounded upwards). • The relevant amount of interest payable in respect of the notes for any period shall be the product of: (i) the relevant amount of interest per Calculation Amount determined as described above; and (ii) the number by which the Calculation Amount is required to be multiplied to equal the principal amount of the notes. • “Calculation Amount” means $1,000. • “Day Count Fraction” means 30/360. Where it is necessary to calculate an amount of interest in respect of any Note for a period which is less than or equal to a complete Interest Period, such interest shall be calculated on the basis of a 360-day year consisting of 12 months of 30 days each and, in the case of an incomplete month, the number of days elapsed. • Optional redemption: Subject to applicable laws, BP Capital U.K. may, by giving not less than 10 nor more than 60 days’ notice to the Trustee and the relevant Noteholders in accordance with the notice provisions set forth in the Indenture (which notice shall be irrevocable), redeem the relevant notes (in whole but not in part) on the First Call Date, which shall be March 22, 2030, and on any day thereafter to (and including) the First Reset Date, which shall be June 22, 2030, or on any Interest Payment Date thereafter, at their outstanding principal amount plus any accrued but
68 unpaid interest up to (but excluding) the relevant Redemption Date and any outstanding Arrears of Interest (without double counting). • Outstanding Liabilities: As of December 31, 2020 the total finance debt and lease liabilities of the BP group, all of which would rank senior to the notes and the related guarantee upon liquidation, equaled approximately $81,926,000,000 in aggregate principal amount. This does not include obligations of the subsidiaries of BP (other than BP Capital Markets U.K.), to which the obligations of BP under the Guarantee are structurally subordinated. As of December 31, 2020, BP had outstanding 5,473,414 cumulative second preference shares of £1 each, which will rank as Parity Obligations to the Guarantee as of the Issue Date. As of December 31, 2020, BP also had outstanding 7,232,838 cumulative first preference shares of £1 each, which will rank as Senior Obligations to the Guarantee as of the Issue Date. • Limitations on the Issuance of Additional Senior Indebtedness: None of the notes, the guarantee or the indenture under which the notes were issued restrict BP Capital U.K. or BP from issuing additional securities (including preference shares or other equity securities) which will be deemed Parity Obligations or Senior Obligations of the notes and Guarantee, as applicable. • Substitution or Variation: If a Rating Agency Event, an Accounting Event, a Tax Deduction Event or an event that permits an Optional Tax Redemption to occur (a “Substitution or Variation Event”) has occurred and is continuing, then BP Capital U.K. or BP may, as an alternative to redemption, subject to the conditions set forth under “—Conditions to Special Event Redemption and Substitution or Variation” in the applicable Prospectus Supplement (without any requirement for the consent or approval of the Noteholders) and subject to the Trustee, immediately prior to the giving of any notice referred to herein, having received an officers’ certificate and an opinion of counsel (each as defined in the Indenture), each stating to the effect that the provisions of this section have been complied with, and having given not less than 10 nor more than 60 days’ notice to the Trustee, the Calculation Agent and the relevant Noteholders (which notice shall be irrevocable), at any time either (i) substitute all, but not less than all, of the relevant notes for, or (ii) vary the terms of the relevant notes with the effect that they remain or become (as the case may be), Qualifying Securities, and the Noteholders shall be bound by such substitution or variation. Upon expiry of such notice, BP Capital U.K. or BP will either vary the terms of or, as the case may be, substitute the relevant notes in accordance with this section. In connection with the substitution of Qualifying Securities for the relevant notes or the variation of the terms of the relevant notes, each Noteholder by the purchase of the relevant notes authorizes the Trustee to, and the Trustee shall, authenticate such new notes in accordance with Section 303 of the Indenture. In connection with any substitution or variation in accordance with this section, BP Capital U.K. will comply with the rules of any stock exchange on which the relevant notes are for the time being listed or admitted to trading. Any such substitution or variation in accordance with the foregoing provisions following a Substitution or Variation Event shall only be permitted if it does not give rise to any other Substitution or Variation Event with respect to the Qualifying Securities. Any such substitution or variation in accordance with the foregoing provisions following a Substitution or Variation Event shall only be permitted if it does not result in the Qualifying Securities no longer being eligible for the same, or a higher amount of, “equity credit” (or such other nomenclature that the Rating Agency may then use to describe the degree to which an instrument exhibits the characteristics of an ordinary share) as is attributed to the relevant notes on the date notice is given to Noteholders of the substitution or variation. In no event shall the Trustee have any responsibility whatsoever to determine whether any such substitution or variation results in the Qualifying Securities. Any such substitution or variance could have unexpected commercial consequences depending on the circumstances of an individual Noteholder, and we will consider the impact on
69 the class of Noteholders taken as a whole and are not required to take into account the individual circumstances of each Noteholder. “Qualifying Securities” means securities that contain terms not materially less favorable to the class of Noteholders of the Non-Call 5.25 Notes or Non-Call 10 Notes, as the case may be, and in each case taken as a whole, than the terms of the respective notes (as reasonably determined by BP Capital U.K. (in consultation with an independent investment bank or counsel of international standing)) and provided that an officers’ certificate to such effect (and confirming that the conditions set out in (a) to (j) below have been satisfied) shall have been delivered to the Trustee prior to the substitution or variation of the relevant notes upon which certificate the Trustee shall rely absolutely). Such Qualifying Securities: a) shall be issued by (x) BP Capital U.K. (or any successor thereto as issuer of the relevant notes) with a guarantee of BP (or any successor thereto as guarantor of the relevant notes), (y) BP or (z) a wholly owned direct or indirect finance subsidiary of BP with a guarantee of BP (or any successor thereto as guarantor of the relevant notes); and b) (and/or, as appropriate, the guarantee as aforesaid) shall rank pari passu on a Winding-Up of BP Capital U.K. (or any successor thereto as issuer of the relevant notes) with the relevant notes or on a Winding-Up of BP (or any successor thereto as guarantor of the relevant notes) with the Guarantee; and c) shall contain terms which provide for the same or a more favorable Interest Rate from time to time applying to the relevant notes and preserve the same Interest Payment Dates; and d) shall preserve the obligations (including the obligations arising from the exercise of any right) of BP Capital U.K. (or any successor thereto as issuer of the relevant notes) as to redemption of the relevant notes, including (without limitation) as to timing of, and amounts payable upon, such redemption; and e) shall preserve any existing rights under the terms of the relevant notes to any accrued interest, any Deferred Interest Payments, any Arrears of Interest and any other amounts payable under the relevant notes which, in each case, has accrued to Noteholders and not been paid; and f) shall not contain terms providing for loss absorption through principal write-down or conversion to ordinary shares; and g) shall otherwise contain substantially identical terms (as reasonably determined by BP Capital U.K. (or any successor thereto as issuer of the relevant notes)) to the relevant notes, save where (without prejudice to the requirement that the terms are not materially less favorable to the class of relevant Noteholders taken as a whole than the terms of the relevant notes as described above) any modifications to such terms are required to be made to avoid the occurrence or effect of a Rating Agency Event, an Accounting Event, a Tax Deduction Event or an event that permits an Optional Tax Redemption to occur; and h) shall, immediately after such substitution or variation, be assigned at least the same credit rating(s) by the same Rating Agencies as may have been assigned to the relevant notes at the invitation of or with the consent of BP Capital U.K. (or any successor thereto as issuer of the relevant notes) immediately prior to such substitution or variation; and
70 i) shall not provide for the mandatory deferral or cancellation of payments of interest and/or principal; and j) shall be (x) listed on the Official List and admitted to trading on the London Stock Exchange plc’s Main Market or (y) listed on such other stock exchange as is a Recognised Stock Exchange at that time or admitted to trading on a Multilateral Trading Facility as selected by BP Capital U.K (or any successor thereto as issuer of the relevant notes). For the purposes of the definition of Qualifying Securities: “Multilateral Trading Facility” means a multilateral trading facility described in section 987(1)(b) of the Income Tax Act 2007 of the United Kingdom, as the same may be amended from time to time and any provision, statute or statutory instrument replacing the same from time to time; “Official List” means the Official List of the Financial Conduct Authority in its capacity as competent authority under the Financial Services and Markets Act 2000 of the United Kingdom (as the same may be amended from time to time and any provision, statute or statutory instrument replacing the same from time to time); and “Recognised Stock Exchange” means a recognised stock exchange as defined in section 1005 of the Income Tax Act 2007 of the United Kingdom as the same may be amended from time to time and any provision, statute or statutory instrument replacing the same from time to time. • Events of Default Provisions • An Event of Default under the relevant notes occurs only in the event of a Winding-Up of BP Capital U.K. or BP other than for the purposes of a Solvent Reorganization of BP Capital U.K. or BP. If, for a period of 30 days or more, BP Capital U.K. or BP are in default in the payment of any principal or interest (including any Arrears of Interest) in respect of the relevant notes which is due and payable (a “Payment Default”), then BP Capital U.K. and/or BP, as the case may be, will be deemed to be in default under the Indenture and the relevant notes, and the Trustee may, and if instructed by the holders as described in “— Entitlement of the Trustee” below shall, take such actions as set forth under “— Proceedings” or “—Enforcement” below to institute actions, steps or proceedings for the Winding-Up of BP Capital U.K. and/or BP. For the avoidance of doubt, a Payment Default is not an Event of Default and shall not result in any right of Acceleration pursuant to Section 502 of the Indenture. • Proceedings: If a Payment Default occurs and is continuing, then BP Capital U.K. or BP, as the case may be, shall, without notice from the Trustee, be deemed to be in default under the Indenture and the relevant notes and (subject to the provisions set forth below) the Trustee may, and if instructed by the holders as described in “—Entitlement of the Trustee” below shall, institute actions, steps or proceedings for the Winding-Up of BP Capital U.K. and/or BP and/or prove in the Winding-Up of BP Capital U.K. and/or BP and/or claim in the liquidation or administration of BP Capital U.K. and/or BP, such claim being subordinated, and for the amount, as provided in “—Subordination and Waiver of Set-off Provisions”.
71 • Enforcement: Without prejudice to “—Proceedings” and subject to the provisions set forth below, the Trustee may, and if instructed by the holders as described in “—Entitlement of the Trustee” below shall, at any time and without further notice, institute such proceedings or take such steps or actions against BP Capital U.K. and/or BP as it may think fit to enforce any term or condition binding on BP Capital U.K. and/or BP under the Indenture or the relevant notes, but in no event shall BP Capital U.K. and/or BP, by virtue of the institution of any such proceedings, steps or actions, be obliged to pay any sum or sums in cash or otherwise, sooner than the same would otherwise have been payable by it under the Indenture or the relevant notes. • Entitlement of Trustee: The Trustee shall not be bound to take any of the actions referred to in the provisions set forth under “— Proceedings” or “—Enforcement” above against BP Capital U.K. and/or BP to enforce the terms of the Indenture or the relevant notes at the request of the Noteholders or take any other action or step under or pursuant to the terms of the relevant notes or the Indenture unless (i) it shall have been so requested in writing by the Noteholders of at least 25% in principal amount of the relevant notes then outstanding and (ii) it shall have been indemnified and/or secured and/or prefunded by the relevant Noteholders to its satisfaction. However, if a Payment Default or an Event of Default has occurred and is continuing, the Trustee shall exercise such of the rights and powers vested in it by the Indenture, and use the same degree of care and skill in their exercise, as a prudent person would exercise or use under the circumstances in the conduct of his or her own affairs. The Trustee shall not be liable with respect to any action taken or omitted to be taken by it in good faith in accordance with the request of the Noteholders of at least 25% in principal amount of the relevant notes then outstanding. • Right of Noteholders: No Noteholder shall be entitled to proceed directly against BP Capital U.K. or BP or to institute proceedings for the Winding-Up or claim in the liquidation of BP Capital U.K. or BP or to prove in such Winding-Up unless the Trustee, having become so bound to proceed, institute, prove or claim, fails to do so within a 60 day period and such failure shall be continuing, in which case the Noteholder shall have only such rights against BP Capital U.K. or BP as those which the Trustee is entitled to exercise as set out in this section. • Extent of Noteholders’ Remedy: No remedy against BP Capital U.K. or BP, other than as referred to in the relevant prospectus supplement, shall be available to the Trustee or the Noteholders, whether for the recovery of amounts owing in respect of the relevant notes or under the Indenture or in respect of any breach by BP Capital U.K. or BP of any of their other obligations under or in respect of the relevant notes or under the Indenture. For the avoidance of doubt, nothing in the foregoing shall (i) prevent the Trustee from proving in any Winding-Up (otherwise than for the purposes of a Solvent Reorganization of BP Capital U.K. or BP, as the case may be) or administration of BP Capital U.K. or BP and/or claiming in any liquidation of BP Capital U.K. or BP (even if not instituted by the Trustee), or (ii) impair the right of any Noteholder to receive payment of principal, premium or interest (including Arrears of Interest) on such noteholder’s notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such noteholder’s notes. • Defined Terms: The following definitions shall apply to subordination of the notes and subordination of the guarantee provisions:
72 • “Notional Preference Shares” means, with respect to BP Capital U.K. or BP, as the case may be, a notional class of preference shares in the capital of BP Capital U.K. or BP, as the case may be: (i) ranking junior to the claims of all holders of Senior Obligations of BP Capital U.K. or BP, as the case may be; (ii) having an equal right to return of assets in the Winding-Up of BP Capital U.K. or BP, as the case may be, and so ranking pari passu with any Parity Obligations of BP Capital U.K. or BP, as the case may be; and (iii) having a right to return of capital ahead of, and so ranking ahead of, the claims of holders of the Ordinary Shares of BP Capital U.K. or BP, as the case may be. • “Parity Obligations” means, with respect to BP Capital U.K. or BP, as the case may be: (a) the most junior class of preference share capital of BP Capital U.K. or BP, as the case may be; and (b) any other security, guarantee or other instrument issued by, or any other obligation of BP Capital U.K. or BP, as the case may be, which ranks or is expressed to rank pari passu with BP Capital U.K.’s obligations under the Notes or BP’s obligations under the Guarantee, including the Other Hybrid Capital Notes. • “Ordinary Shares” means (i) any ordinary shares in the capital of BP Capital U.K. or BP, as the case may be, or (ii) any present or future shares of any other class of shares of BP Capital U.K. or BP, as the case may be, ranking pari passu with the ordinary shares of BP Capital U.K. or BP, as the case may be or, in either case, any depository or other receipts or certificates, including American depositary receipts representing such shares. • “Senior Obligations” means all obligations of BP Capital U.K. or BP, as the case may be, but excluding any Parity Obligations and any Ordinary Shares of BP Capital U.K. or BP, as the case may be. B. Other Terms Applicable to All Notes The following terms are applicable to all Notes, except where otherwise noted. Guarantee: Payment of the principal of and interest on the notes is fully guaranteed by BP. Denomination: The notes will be issued in denominations of $1,000 and integral multiples of $1,000. Regular record dates for interest: The 15th calendar day preceding each interest payment date, whether or not such day is a business day. Business day: If any payment is due in respect of the notes on a day that is not a business day, it will be made on the next following business day, provided that no interest will accrue on the payment so deferred. A “business day” for these purposes is any week day on which banking or trust institutions in neither New York nor London are authorized generally or obligated by law, regulation or executive order to close. Ranking: The notes are unsecured and unsubordinated and will rank equally with all of the issuer’s other unsecured and unsubordinated indebtedness, except for the 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes and the 4.375% Perpetual Subordinated Non-Call 5.25 Fixed Rate Reset Notes, each of which ranks as specified in Section A herein. Further issuances: The issuer of the Notes may, at its sole option, at any time and without the consent of the then existing note holders issue additional notes in one or more transactions subsequent to the date of the applicable prospectus supplement with terms (other than the issuance date, issue price and, possibly, the first call date, first reset date, the first interest payment date and/or the date interest starts accruing)
73 identical to the notes issued under such prospectus supplement. These additional notes will be deemed part of the same series as the notes issued under such prospectus supplement and will provide the holders of these additional notes the right to vote together with holders of the notes issued under such prospectus supplement, provided that such additional notes will be issued with no more than de minimis original issue discount or will be part of a “qualified reopening” for U.S. federal income tax purposes, except that in the case of the 4.375% Perpetual Subordinated Non-Call 5.25 Fixed Rate Reset Notes and the 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes, additional notes of such series will be only issued if they are fungible with the original notes for U.S. federal income tax purposes. Day Count: • For Notes which are floating rate notes – Actual / 360 • For Notes which are fixed rate notes – 30/360 Day count convention: • For Notes which are floating rate notes – Modified following. If any interest payment date falls on a day that is not a business day, that interest payment date will be postponed to the next succeeding business day unless that business day is in the next succeeding calendar month, in which case the interest payment date will be the immediately preceding business day. • For Notes which are fixed rate notes – Following Unadjusted Trading through DTC, Clearstream, Luxembourg and Euroclear: Initial settlement for the notes has been made in immediately available funds. Secondary market trading between DTC participants will occur in the ordinary way in accordance with DTC’s rules and will be settled in immediately available funds using DTC’s Same-Day Funds Settlement System. Secondary market trading between Clearstream Banking, société anonyme, in Luxembourg (“Clearstream, Luxembourg”), customers and/or Euroclear Bank S.A./N.V. (“Euroclear”) participants will occur in the ordinary way in accordance with the applicable rules and operating procedures of Clearstream, Luxembourg and Euroclear and will be settled using the procedures applicable to conventional Eurobonds in immediately available funds. Name of depositary: The Depository Trust Company, commonly referred to as “DTC”. Sinking Fund: There is no sinking fund. Trustee: • If the issuer is BP Capital U.K., the notes have been issued under an indenture with The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee, dated as of 8 March 2002, as supplemented by a supplemental indenture with respect to the notes entered into on the issuance date. • If the issuer is BP Capital America, the notes have been issued under an indenture with The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee, dated as of 4 June 2003, as supplemented by a supplemental indenture with respect to the notes entered into on the issuance date.
74 Use of proceeds: The net proceeds from the sale of the notes will be used for general corporate purposes, including working capital for BP or other companies in the BP Group and the repayment of existing borrowings of BP and its subsidiaries. Governing law and jurisdiction: The indenture, the notes and the guarantee are governed by New York law, except for the subordination provisions and waiver of set-off provisions in respect of each of the 4.375% Perpetual Subordinated Non-Call 5.25 Fixed Rate Reset Notes and the 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes, which will be governed by English law. Any legal proceeding arising out of or based upon the indenture, the notes or the guarantee may be instituted in any state or federal court in the Borough of Manhattan in New York City, New York. BP Capital U.K.’s principal executive offices are located at Chertsey Road, Sunbury on Thames, Middlesex TW16 7BP, England. BP Capital America’s principal executive offices are located at 501 Westlake Park Boulevard, Houston, Texas 77079. C. Description of Debt Securities and Guarantees The following terms are applicable to all Notes, except where otherwise specified. In the following description, “you” means direct holders of the Notes (and not street name or other indirect holders of securities).
75 DESCRIPTION OF DEBT SECURITIES AND GUARANTEES Each of the BP Debt Issuers may issue guaranteed debt securities using this prospectus. As required by U.S. federal law for all bonds and notes of companies that are publicly offered, the debt securities are governed by a document called the indenture. BP Capital America has entered into Indenture, dated 4 June 2003, between BP Capital America., BP p.l.c. and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A.) as trustee. BP Capital U.K. has entered into an Indenture, dated 8 March 2002, between BP Capital U.K., BP p.l.c. and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A.) as trustee. The trustee under each of the indentures has two main roles: • first, it can enforce your rights against us if we default. There are some limitations on the extent to which the trustee acts on your behalf, described under “Default and Related Matters—Events of Default—Remedies If an Event of Default Occurs” below; and • second, the trustee performs administrative duties for us, such as sending you interest payments, transferring your debt securities to a new buyer if you sell and sending you notices. BP acts as the guarantor of the guaranteed debt securities issued under the BP Debt Issuers’ indentures. The guarantees are described under “—Guarantees” below. The indentures and their associated documents contain the full legal text governing the matters described in this section. The indentures, the debt securities and the guarantees are governed by New York law. The indentures are exhibits to our registration statement. This section contains what we believe is a materially complete and accurate summary of the material provisions of the indentures, which are substantially identical to each other, the debt securities and the guarantees. However, because it is a summary, it does not describe every aspect of the indentures, the debt securities or the guarantees. This summary is subject to and qualified in its entirety by reference to all the provisions of the indentures, including some of the terms used in the indentures. We describe the meaning for only the more important terms. We also include references in parentheses to some sections of the indentures. Whenever we refer to particular sections or defined terms of the indentures in this prospectus or in the prospectus supplement, those sections or defined terms are incorporated by reference here or in the prospectus supplement. This summary also is subject to and qualified by reference to the description of the particular terms of your series described above. The BP Debt Issuers may each issue as many distinct series of debt securities under its respective indenture as it wishes. This section summarizes all material terms of the debt securities that are common to all series, unless otherwise described above. We may issue the debt securities as original issue discount securities, which are debt securities that are offered and sold at a substantial discount to their stated principal amount. (Section 101) Special U.S. federal income tax, accounting and other considerations may apply to original issue discount securities. The applicable U.S. federal income tax considerations for original issue discount securities are described under “Original Issue Discount” below. The debt securities may also be issued as indexed securities or securities denominated in foreign currencies or currency units, as described in more detail above. Accordingly, this summary also is subject to and qualified by reference to the description of the terms of the series described above.
76 Unless otherwise described above, the debt securities will be issued only in fully registered form without interest coupons. Guarantees BP will fully and unconditionally guarantee the payment of the principal of, premium, if any, and interest on the guaranteed debt securities, including certain additional amounts which may be payable under the guarantees, as described under “Special Situations—Payment of Additional Amounts”. BP guarantees the payment of such amounts when such amounts become due and payable, whether at the stated maturity of the debt securities, by declaration of acceleration, call for redemption or otherwise. Overview of Remainder of This Description The remainder of this description summarizes: • Additional mechanics relevant to the debt securities under normal circumstances, such as how you transfer ownership and where we make payments. • Your rights under several special situations, such as if we merge with another company or if we want to change a term of the debt securities. • Your rights to receive payment of additional amounts due to changes in U.K. tax withholding or deduction requirements. • Your rights if we default or experience other financial difficulties. • Our relationship with the trustee. Additional Mechanics Exchange and Transfer You may have your debt securities broken into more debt securities of smaller denominations or combined into fewer debt securities of larger denominations, as long as the total principal amount is not changed. (Section 305) This is called an exchange. You may exchange or transfer registered debt securities at the office of the trustee. The trustee acts as our agent for registering debt securities in the names of holders and transferring registered debt securities. We may change this appointment to another entity or perform the service ourselves. The entity performing the role of maintaining the list of registered holders is called the security registrar. It will also register transfers of the registered debt securities. (Section 305) You will not be required to pay a service charge to transfer or exchange debt securities, but you may be required to pay for any tax or other governmental charge associated with the exchange or transfer. The transfer or exchange of a registered debt security will only be made if the security registrar is satisfied with your proof of ownership. If we have designated additional transfer agents, they are described above. We may cancel the designation of any particular transfer agent. We may also approve a change in the office through which any transfer agent acts. (Section 1002) If the debt securities are redeemable and we redeem less than all of the debt securities of a particular series, we may block the transfer or exchange of debt securities during a specified period of time in order to freeze the list of holders to prepare the mailing. The period begins 15 days before the day we mail the notice of
77 redemption and ends on the day of that mailing. We may also refuse to register transfers or exchanges of debt securities selected for redemption. However, we will continue to permit transfers and exchanges of the unredeemed portion of any security being partially redeemed. (Section 305) Payment and Paying Agents We will pay interest to you if you are a direct holder listed in the trustee’s records at the close of business on a particular day in advance of each due date for interest, even if you no longer own the security on the interest due date. That particular day, usually about two weeks in advance of the interest due date, is called the regular record date and is as described above. (Section 307) We will pay interest, principal and any other money due on the registered debt securities at the corporate trust office of the trustee in Chicago, Illinois. That office is currently located at The Bank of New York Mellon Trust Company, N.A., 2 North LaSalle Street, Suite 700, Chicago, Illinois 60602. You must make arrangements to have your payments picked up at or wired from that office. We may also choose to pay interest by mailing checks. Interest on global securities will be paid to the holder thereof by wire transfer of same-day funds. Holders buying and selling debt securities must work out between them how to compensate for the fact that we will pay all the interest for an interest period to the one who is the registered holder on the regular record date. The most common manner is to adjust the sales price of the debt securities to pro rate interest fairly between buyer and seller. This prorated interest amount is called accrued interest. We may also arrange for additional payment offices, and may cancel or change these offices, including our use of the trustee’s corporate trust office. These offices are called paying agents. We may also choose to act as our own paying agent. We must notify you through the trustee of changes in the paying agents for any particular series of debt securities. (Section 1002) Notices We and the trustee will send notices only to direct holders, using their addresses as listed in the trustee’s records. (Section 106) Regardless of who acts as paying agent, all money that we pay to a paying agent that remains unclaimed at the end of two years after the amount is due to direct holders will be repaid to us. After that two-year period, you may look only to us for payment and not to the trustee, any other paying agent or anyone else. (Section 1006) Special Situations Mergers and Similar Events We are generally permitted to consolidate or merge with another company or firm. We are also permitted to sell or lease substantially all of our assets to another corporation or other entity or to buy or lease substantially all of the assets of another corporation or other entity. No vote by holders of debt securities approving any of these actions is required, unless as part of the transaction we make changes to the indenture requiring your approval, as described below under “—Modification and Waiver”. We may take these actions as part of a transaction involving outside third parties or as part of an internal corporate reorganization. We may take these actions even if they result in: • a lower credit rating being assigned to the debt securities; or
78 • additional amounts becoming payable in respect of U.K. withholding tax, and the debt securities thus being subject to redemption at our option, as described below under “—Optional Tax Redemption”. We have no obligation under the indenture to seek to avoid these results, or any other legal or financial effects that are disadvantageous to you, in connection with a merger, consolidation or sale or lease of assets that is permitted under the indenture. However, we may not take any of these actions unless all the following conditions are met: • Where a BP Debt Issuer or BP, as applicable, merges out of existence or sells or leases substantially all of its assets, the other entity must assume its obligations on the debt securities or the guarantees. Such other entity must be organized under the laws of such BP entity’s jurisdiction or a political subdivision thereof. • The merger, sale or lease of assets or other transaction must not cause a default on the debt securities, and we must not already be in default. For purposes of this no-default test, a default would include an event of default that has occurred and not been cured, as described below under “Default and Related Matters—Events of Default—What Is an Event of Default?” A default for this purpose would also include any event that would be an event of default if the requirements for giving us default notice or our default having to exist for a specific period of time were disregarded. • It is possible that the merger, sale or lease of assets or other transaction would cause some of our property to become subject to a mortgage, security interest, lien or other legal mechanism giving lenders preferential rights in that property over other lenders or over our general creditors if we fail to pay them back. • It is possible that the U.S. Internal Revenue Service may deem a merger or other similar transaction to cause an exchange for U.S. federal income tax purposes of debt securities for new securities by the holders of the debt securities. This could result in the recognition of taxable gain or loss for U.S. federal income tax purposes and possible other adverse tax consequences. Modification and Waiver There are three types of changes we can make to the indenture and the debt securities. Changes Requiring Your Approval • First, there are changes that cannot be made to your debt securities without your specific approval. We must obtain your specified approval in order to: • change the stated maturity of the principal or interest on a debt security; • reduce any amounts due on a debt security; • reduce the amount of principal payable upon acceleration of the maturity of a debt security following a default; • change the place or currency of payment on a debt security; • impair your right to sue for payment;
79 • reduce the percentage of holders of debt securities whose consent is needed to modify or amend the indenture; • reduce the percentage of holders of debt securities whose consent is needed to waive compliance with various provisions of the indenture or to waive various defaults; • modify any other aspect of the provisions dealing with modification and waiver of the indenture; and • change the obligations of BP to pay any principal, premium or interest under the guarantees. (Section 902) Changes Requiring a Majority Vote • The second type of change to the indenture and the debt securities is the kind that requires a vote in favor by holders of debt securities owning a majority of the principal amount of the particular series affected. Most changes fall into this category, except for clarifying changes and other changes that would not adversely affect holders of the debt securities in any material respect. The same vote would be required for us to obtain a waiver of all or part of the covenants described in this summary or a waiver of a past default. However, we cannot obtain a waiver of a payment default or any other aspect of the indenture or the debt securities listed in the first category described above under “Changes Requiring Your Approval” unless we obtain your individual consent to the waiver. (Section 513) Changes Not Requiring Approval The third type of change does not require any vote by holders of debt securities. This type is limited to clarifications and other changes that would not adversely affect holders of the debt securities in any material respect. (Section 901) Further Details Concerning Voting When taking a vote, we will use the following rules to decide how much principal amount to attribute to a security: • For original issue discount securities, we will use the principal amount that would be due and payable on the voting date if the maturity of the debt securities were accelerated to that date because of a default. • For debt securities whose principal amount is not known (for example, because it is based on an index), we will use a special rule for that security, as described above. • For debt securities denominated in one or more foreign currencies or currency units, we will use the U.S. dollar equivalent as of the date of original issuance. • Debt securities will not be considered outstanding, and therefore not eligible to vote, if we have deposited or set aside in trust for you money for their payment or redemption. Debt securities will also not be eligible to vote if they have been fully defeased as described below under “—Defeasance and Discharge”. (Section 101)
80 • We will generally be entitled to set any day as a record date for the purpose of determining the holders of outstanding debt securities that are entitled to vote or take other action under the indenture. If we set a record date for a vote or other action to be taken by holders of a particular series, that vote or action may be taken only by persons who are holders of outstanding debt securities of that series on the record date and must be taken within 90 days following the record date or another period that we may specify (or as the trustee may specify, if it set the record date). We may shorten or lengthen (but not beyond 90 days) this period from time to time. (Sections 501, 502, 512, 513 and 902) Redemption and Repayment Unless otherwise described above, your debt security will not be entitled to the benefit of any sinking fund—that is, we will not deposit money on a regular basis into any separate custodial account to repay your debt securities. In addition, we will not be entitled to redeem your debt security before its stated maturity unless a redemption commencement date is specified above. You will not be entitled to require us to buy your debt security from you, before its stated maturity, unless one or more repayment dates is specified above. If a redemption commencement date or a repayment date is specified above, one or more redemption prices or repayment prices may be specified, which may be expressed as a percentage of the principal amount of your debt security or by reference to one or more formulae used to determine the redemption price(s). It may also specify one or more redemption periods during which the redemption prices relating to a redemption of debt securities during those periods will apply. If a redemption commencement date is specified above, we may redeem your debt security at our option at any time on or after that date. If we redeem your debt security, we will do so at the specified redemption price, together with interest accrued to the redemption date. If different prices are specified for different redemption periods, the price we pay will be the price that applies to the redemption period during which your debt security is redeemed. If a repayment date is specified above, your debt security will be repayable by us at your option on the specified repayment date(s) at the specified repayment price(s), together with interest accrued to the repayment date. In the event that we exercise an option to redeem any debt security, we will give written notice of the principal amount of the debt security to be redeemed to the trustee at least 45 days before the applicable redemption date and to the holder not less than 30 days nor more than 60 days before the applicable redemption date. We will give the notice in the manner described above under “Additional Mechanics— Notices”. If a debt security represented by a global security is subject to repayment at the holder’s option, the depositary or its nominee, as the holder, will be the only person that can exercise the right to repayment. Any indirect holders who own beneficial interests in the global security and wish to exercise a repayment right must give proper and timely instructions to their banks or brokers through which they hold their interests, requesting that they notify the depositary to exercise the repayment right on their behalf. Different firms have different deadlines for accepting instructions from their customers; we urge you to take care to act promptly enough to ensure that your request is given effect by the depositary before the applicable deadline for exercise.
81 We or our affiliates may purchase debt securities from investors who are willing to sell from time to time, either in the open market at prevailing prices or in private transactions at negotiated prices. Debt securities that we or they purchase may, in our discretion, be held, resold or canceled. Payment of Additional Amounts The government of any jurisdiction where BP or BP Capital U.K. is incorporated may require BP or BP Capital U.K. to withhold or deduct amounts from payments on the principal or interest on a debt security or any amounts to be paid under the guarantees for or on account of taxes or any other governmental charges. If the jurisdiction requires a withholding or deduction of this type, BP or BP Capital U.K., as the case may be, may be required to pay you an additional amount so that the net amount you receive will be the amount specified in the debt security to which you are entitled. However, in order for you to be entitled to receive the additional amount, you must not be resident in the jurisdiction that requires the withholding or deduction. BP or BP Capital U.K., as the case may be, will not have to pay additional amounts under any of the following circumstances: • The U.S. government or any political subdivision of the U.S. government is the entity that is imposing the tax or governmental charge. • The tax or governmental charge is imposed due to the presentation of a debt security, if presentation is required, for payment on a date more than 30 days after the security became due or after the payment was provided for. • The tax or governmental charge is on account of an estate, inheritance, gift, sale, transfer, personal property or similar tax or other governmental charge. The tax or governmental charge is for a tax or governmental charge that is payable in a manner that does not involve withholdings. • The tax or governmental charge is imposed or withheld because the holder or beneficial owner failed: • to provide information about the nationality, residence or identity of the holder or beneficial owner, or • to make a declaration or satisfy any information requirements, that the statutes, treaties, regulations or administrative practices of the taxing jurisdiction require as a precondition to exemption from all or part of such tax or governmental charge. • The withholding or deduction is imposed pursuant to European Council Directive 2003/48/EC or European Council Directive 2014/48/EC, regarding taxation of, and information exchange among member states of the European Union with respect to, interest income, or any other Directive implementing the conclusions of the ECOFIN Council meeting of 26-27 November 2000, or any law implementing or complying with, or introduced in order to conform to, such Directives. • The withholding or deduction is imposed on a holder or beneficial owner who could have avoided such withholding or deduction by presenting its debt securities to another paying agent.
82 • The tax or governmental charge is withheld or imposed due to a combination of the items listed above (other than the first bulleted item listed above). • The holder is a fiduciary or partnership or an entity that is not the sole beneficial owner of the payment of the principal of, or any interest on, any security, and the laws of the jurisdiction require the payment to be included in the income of a beneficiary or settlor for tax purposes with respect to such fiduciary or a member of such partnership or a beneficial owner who would not have been entitled to such additional amounts had it been the holder of such security. These provisions will also apply to any taxes or governmental charges imposed by any jurisdiction in which a successor to BP or BP Capital U.K., as the case may be, is organized. Additional circumstances in which BP would not be required to pay additional amounts, if any, are described above and in the prospectus supplement relating to the debt securities. (Section 1010) Optional Tax Redemption We may also have the option to redeem the debt securities of a given series if, as a result of any change in United Kingdom tax treatment, BP or BP Capital U.K. would be required to pay additional amounts as described in the previous subsection under “—Payment of Additional Amounts”. This option applies only in the case of changes in United Kingdom tax treatment that occur on or after the date specified above for the applicable series of debt securities. The redemption price for the debt securities, other than original issue discount debt securities, will be equal to the principal amount of the debt securities being redeemed plus accrued interest. The redemption price for original issue discount debt securities will be specified above for such securities. (Section 1108) Event Risk Provisions The debt securities do not contain event risk provisions designed to require BP or the BP Debt Issuers to redeem or repurchase the debt securities, reset the interest rate or take other actions in response to highly leveraged transactions, changes in credit ratings or similar occurrences. Defeasance and Discharge The following discussion of full defeasance and discharge will be applicable to your series of debt securities only if we choose to have them apply to that series. If we do so choose, it will be stated in the above description of your debt securities. (Section 403) We can legally release ourselves from any payment or other obligations on the debt securities, except for various obligations described below, if we, in addition to other actions, put in place the following arrangements for you to be repaid: • We must deposit in trust for your benefit and the benefit of all other direct holders of the debt securities a combination of money and U.S. government or U.S. government agency notes or bonds that will generate enough cash to make interest, principal and any other payments on the debt securities on their various due dates. In addition, on the date of such deposit, we must not be in default. For purposes of this no-default test, a default would include an event of default that has occurred and not been cured, as described below under “Default and Related Matters— Events of Default—What Is an Event of Default?” A default for this purpose would also include any event that would be an event of default if the requirements for giving us default notice or our default having to exist for a specific period of time were disregarded.
83 • We must deliver to the trustee a legal opinion of our counsel confirming that under current U.S. federal income tax law we may make the above deposit without causing you to be taxed on the debt securities any differently than if we did not make the deposit and just repaid the debt securities ourselves. In the case of debt securities being discharged, we must deliver along with this opinion a private letter ruling from U.S. Internal Revenue Service to this effect or a revenue ruling pertaining to a comparable form of transaction to that effect published by the U.S. Internal Revenue Service. • If the debt securities are listed on the New York Stock Exchange, we must deliver to the trustee a legal opinion of our counsel confirming that the deposit, defeasance and discharge will not cause the debt securities to be delisted. However, even if we take these actions, a number of our obligations relating to the debt securities will remain. These include the following obligations: • to register the transfer and exchange of debt securities; • to replace mutilated, destroyed, lost or stolen debt securities; • to maintain paying agencies; and • to hold money for payment in trust. Default and Related Matters Ranking • The debt securities are not secured by any of our property or assets. Accordingly, your ownership of debt securities means you are one of our unsecured creditors. The debt securities are not subordinated to any of our other debt obligations and therefore they rank equally with all our other unsecured and unsubordinated indebtedness. Events of Default You will have special rights if an event of default occurs and is not cured, as described later in this subsection. What Is an Event of Default? The term “event of default” means, with respect to a debt security other than the 4.375% Perpetual Subordinated Non-Call 5.25 Fixed Rate Reset Notes and the 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes, any of the following: • We do not pay the principal or any premium on the debt security at maturity. • We do not pay interest on the debt security within 30 days of its due date. • We do not deposit any sinking fund payment for the debt security on its due date. • We remain in breach of a covenant or any other term of the applicable indenture for 90 days after we receive a notice of default stating we are in breach. The notice must be sent by either the trustee or holders of 25% of the principal amount of debt securities of the affected series.
84 • We file for bankruptcy or certain other events if bankruptcy, insolvency or reorganization occur. • Any other event of default described above occurs. (Section 501) An “event of default” under the 4.375% Perpetual Subordinated Non-Call 5.25 Fixed Rate Reset Notes and the 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes occurs only in the event of a Winding-Up of BP Capital U.K. or BP other than for the purposes of a Solvent Reorganization of BP Capital U.K. or BP. If, for a period of 30 days or more, BP Capital U.K. or BP are in default in the payment of any principal or interest (including any Arrears of Interest) in respect of such subordinated notes which is due and payable (a “Payment Default”), then BP Capital U.K. and/or BP, as the case may be, will be deemed to be in default under the Indenture and the relevant Notes, and the Trustee may, and if instructed by the holders as described in “—Entitlement of the Trustee” in the relevant prospectus supplement shall, take such actions as set forth under “—Proceedings” or “—Enforcement” in the relevant prospectus supplement, to institute actions, steps or proceedings for the Winding-Up of BP Capital U.K. and/or BP. For the avoidance of doubt, a Payment Default is not an Event of Default and shall not result in any right of Acceleration pursuant to Section 502 of the Indenture. Remedies If an Event of Default Occurs. If an event of default has occurred and has not been cured, the trustee or the holders of 25% in principal amount of the debt securities of the affected series may declare the entire principal amount of all the debt securities of that series to be due and immediately payable. This is called a declaration of acceleration of maturity. A declaration of acceleration of maturity may be canceled by the holders of at least a majority in principal amount of the debt securities of the affected series if: • all amounts due (as interest, principal and otherwise) are paid or deposited with the trustee; and • all events of default, other than the non-payment of the principal of the debt securities which have become due solely by such declaration of acceleration, have been cured or waived. (Section 502) Except in cases of default, where the trustee has some special duties, the trustee is not required to take any action under the indenture at the request of any holders unless the holders offer the trustee reasonable protection from expenses and liability. This protection is called an indemnity. (Section 603) If reasonable indemnity is provided, the holders of a majority in principal amount of the outstanding debt securities of the relevant series may direct the time, method and place of conducting any lawsuit or other formal legal action seeking any remedy available to the trustee. These majority holders may also direct the trustee in performing any other action under the indenture. (Section 512) Before you bypass the trustee and bring your own lawsuit or other formal legal action or take other steps to enforce your rights or protect your interests relating to the debt securities, the following must occur, provided that the provisions of this paragraph do not apply to the 4.375% Perpetual Subordinated Non-Call 5.25 Fixed Rate Reset Notes and the 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes: • You must give the trustee written notice that an event of default has occurred and remains uncured. • The holders of 25% in principal amount of all outstanding debt securities of the relevant series must make a written request that the trustee take action because of the default, and must offer reasonable indemnity to the trustee against the cost and other liabilities of taking that action.
85 • The trustee must have not taken action for 60 days after receipt of the above notice, request and offer of indemnity. (Section 507) We will furnish to the trustee every year a written statement of certain of our officers certifying that, to their knowledge, we are in compliance with the indenture and the debt securities, or else specifying any default. (Section 1008) Regarding the Trustee BP and several of its subsidiaries maintain banking relations with the trustee group of companies in the ordinary course of their business. The Bank of New York Mellon Trust Company, N.A. acts as trustee under other indentures under which BP acts as guarantor. If an event of default occurs, or an event occurs that would be an event of default if the requirements for giving us default notice or our default having to exist for a specific period of time were disregarded, the trustee may in certain circumstances prescribed by the Trust Indenture Act of 1939 be considered to have a conflicting interest with respect to the debt securities or the applicable indenture. In that case, the trustee may be required to resign as trustee under the applicable indenture and we would be required to appoint a successor trustee.
Address Occupation 0. R \)\,, f' R tw'l!R 'i) �)Rt<'. G'v f\ 14 Secret [*****************************]
EXHIBIT 12
Rule 13a—14(a) Certificates
I, Bernard Looney, certify that:
1. I have reviewed this annual report on Form 20-F of BP p.l.c.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;
4. The company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures
(as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act
Rules 13a-15(f) and 15d-15(f)) for the company and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and
5. The company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.
| Date: 22 March 2021 | /s/ Bernard Looney | ||||
| Bernard Looney | |||||
| Chief Executive Officer | |||||
I, Murray Auchincloss, certify that:
1. I have reviewed this annual report on Form 20-F of BP p.l.c.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;
4. The company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures
(as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act
Rules 13a-15(f) and 15d-15(f)) for the company and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and
5. The company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.
| Date: 22 March 2021 | /s/ Murray Auchincloss | ||||
| Murray Auchincloss | |||||
| Chief Financial Officer | |||||
Exhibit 13
Rule 13a — 14(b) Certificates
Certification
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)
Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code), the undersigned officer of BP p.l.c., a company incorporated under the laws of England and Wales (the “company”), hereby certifies, to such officer’s knowledge, that:
The Annual Report on Form 20-F for the year ended December 31, 2020 (the “Report”) of the company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the company.
| Date: 22 March 2021 | /s/ Bernard Looney | ||||
| Bernard Looney | |||||
| Chief Executive Officer | |||||
The foregoing certification is being furnished solely pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document.
A signed original of this written statement required by Section 906 has been provided to the company and will be retained by the company and furnished to the Securities and Exchange Commission or its staff upon request.
Certification
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)
Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code), the undersigned officer of BP p.l.c., a company incorporated under the laws of England and Wales (the “company”), hereby certifies, to such officer’s knowledge, that:
The Annual Report on Form 20-F for the year ended December 31, 2020 (the “Report”) of the company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the company.
| Date: 22 March 2021 | /s/ Murray Auchincloss | ||||
| Murray Auchincloss | |||||
| Chief Financial Officer | |||||
The foregoing certification is being furnished solely pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document.
A signed original of this written statement required by Section 906 has been provided to the company and will be retained by the company and furnished to the Securities and Exchange Commission or its staff upon request.
DeGolyer and MacNaughton 5001 Spring Val ley Road Suite 800 East Dallas, Texas 75244 March 22, 2021 BP p.l.c. 1 St. James Square London, SW1Y 4PD United Kingdom Ladies and Gentlemen: We hereby consent to (i) the references to DeGolyer and MacNaughton contained in the section entitled “Oil and gas disclosures for the group” of the Annual Report and Form 20- F for the year ended December 31, 2020, of BP p.l.c. (the Form 20-F), as set forth under the heading “Compliance” on page 313 and (ii) the inclusion of our report of third party dated March 9, 2021, presenting our estimates of the net proved oil, condensate, natural gas liquids, and gas reserves, as of December 31, 2020, of certain properties in which PJSC Rosneft Oil Company has represented it holds an interest (the Report of Third Party), which is included as Exhibit 15.2 to the Form 20-F, and to the incorporation by reference of the reference to DeGolyer and MacNaughton in the Form 20-F and of the Report of Third Party in the Registration Statements on Form F-3 (File Nos. 333-226485, 333-226485-01, and 333- 226485-02) of BP p.l.c., BP Capital Markets p.l.c., and BP Capital Markets America Inc. and the Registration Statements on Form S-8 (File Nos. 333-67206, 333-79399, 333-103924, 333- 123482, 333-123483, 333-131583, 333-131584, 333-132619, 333-146868, 333-146870, 333-146873, 333-173136, 333-177423, 333-179406, 333-186462, 333-186463, 333- 199015, 333-200794, 333-200795, 333-207188, 333-207189, 333-210316, 333-210318, and 333-253287) of BP p.l.c. Very truly yours, /s/ DeGolyer and MacNaughton DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716
DeGolyer and MacNaughton 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244 This is a digital representation of a DeGolyer and MacNaughton report. This file is intended to be a manifestation of certain data in the subject report and as such are subject to the same conditions thereof. The information and data contained in this file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.
DeGolyer and MacNaughton 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244 March 9, 2021 BP Russian Investments Limited Chertsey Road Sunbury on Thames, Middlesex, TW16 7BP United Kingdom Ladies and Gentlemen: Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2020, of the extent of the estimated net proved oil, condensate, natural gas liquids (NGL), and gas reserves of certain fields in which PJSC Rosneft Oil Company (ROSNEFT) has represented it holds or controls an interest. This evaluation was completed on January 25, 2021. The fields evaluated consist of working interests located in the Russian Federation, Canada, Egypt, Kurdistan, Iraq, and Vietnam. ROSNEFT has represented that it holds or controls an interest in certain fields located in the Russian Federation either directly or through various subsidiary enterprises. ROSNEFT has represented that all fields are held at 100 percent by the respective subsidiary enterprise. ROSNEFT has represented that its ownership in all the subsidiary enterprises ranges between 20 and 100 percent. ROSNEFT has represented that these fields account for 100 percent on a net equivalent barrel basis of ROSNEFT’s net proved reserves as of December 31, 2020. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. At the request of BP Russian Investments Limited (BP), a wholly owned subsidiary of BP p.l.c., this report was prepared in accordance with guidelines specified in Item 1202(a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by BP p.l.c. Also included in this report are interests held through five production sharing agreements (PSA) and five joint ventures (JV). As represented by ROSNEFT, the PSA holdings include the Sakhalin-1 Project in Russia, the Shorouk Concession in Egypt,
2 DeGolyer and MacNaughton the Bijeel field in Kurdistan, the Salman field in Iraq, and Block 6.1 in Vietnam. The JV holdings include four JVs in Russia and one JV in Canada. These subsidiary enterprises, the ROSNEFT direct holdings in the Russian Federation (including those in the Chechen Republic), the Sakhalin-1 Project, the Egyptian PSA, the Kurdish PSA, the Iraqi PSA, the Vietnam PSA, the Russian JVs, and the Canadian JV are collectively referred to hereinafter as “ROSNEFT Holdings.” BP has represented that it holds a 22.03-percent interest in ROSNEFT Holdings. Certain properties in which ROSNEFT has an interest are subject to the terms of various PSAs. The terms of these PSAs generally allow for working interest participants to be reimbursed for portions of capital costs and operating expenses and to share in the profits. The reimbursements and profit proceeds are converted to a barrel of oil equivalent or standard cubic foot of gas equivalent by dividing by product prices to estimate the “entitlement quantities.” These entitlement quantities are equivalent in principle to net reserves and are used to calculate an equivalent net share, termed an “entitlement interest.” In this report, ROSNEFT net reserves or interest for certain properties subject to these PSAs is the entitlement based on ROSNEFT’s working interest. The reserves estimated herein are reported at 100 percent for those subsidiaries of which ROSNEFT has majority control, either through direct ownership or through voting rights. The estimated reserves for those subsidiaries which ROSNEFT does not control are reported at ROSNEFT’s working interest. All of the fields evaluated are located in the Russian Federation, Canada, Egypt, Kurdistan, Iraq, or Vietnam. ROSNEFT has represented that upon completion of the primary terms of its current licenses, each of the subsidiary enterprises intends to continue to extend these licenses until the end of the economic lives of the associated fields, and that they intend to proceed accordingly with development and operation of these fields. Based on these representations and consistent with Russian law, estimates of proved, reserves associated with the fields evaluated herein were not limited by the primary terms of their licenses. Reserves estimated herein are expressed as net reserves attributable to or controlled by ROSNEFT (ROSNEFT net). Gross reserves are defined as the total estimated petroleum remaining to be produced from these fields after December 31, 2020. ROSNEFT net reserves are defined as that portion of the gross reserves attributable to the interests held by ROSNEFT after deducting all interests
3 DeGolyer and MacNaughton held by others plus certain interests not held by ROSNEFT, which ROSNEFT has represented that it controls. For the PSAs, these reserves are expressed in terms of the barrel equivalent of the cost recovery and profit share (entitlement) after deducting interests held by others. Estimates of reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information. Information used in the preparation of this report was obtained from ROSNEFT and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by ROSNEFT with respect to the field interests being evaluated, production from such fields, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination was not considered necessary for the purposes of this report. Definition of Reserves Petroleum reserves estimated by us and included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by us in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows: Proved oil and gas reserves – 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
4 DeGolyer and MacNaughton economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the
5 DeGolyer and MacNaughton engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating
6 DeGolyer and MacNaughton that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty. Methodology and Procedures Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019.” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. Based on the current stage of field development, production performance, the development plans provided by ROSNEFT, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The proved undeveloped reserves estimates were based on opportunities identified in the plan of development provided by ROSNEFT. The proved developed non-producing reserves include those quantities associated with behind-pipe zones and include minor remaining capital expenditure as compared to the cost of a new well. ROSNEFT has represented that its senior management is committed to the development plan provided by ROSNEFT and that ROSNEFT has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.
7 DeGolyer and MacNaughton The volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production as defined under the Definition of Reserves heading of this report or to the limit of the production licenses as appropriate. In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available. Data provided by ROSNEFT from wells drilled through December 2020 and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through June 2020. Estimated cumulative production, as of December 31, 2020, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 6 months. Estimates of prices, as of December 31, 2020, were used in calculations to estimate the entitlement reserves for properties in the Sakhalin-1, Vietnam Block 6.1, Egyptian, Kurdish, and Iraqi PSAs. Oil and condensate reserves estimated herein are to be recovered by normal field separation. NGL reserves estimated herein include pentanes and heavier fractions (C5+) and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions, and are the result of low-temperature plant processing. Oil, condensate, and NGL reserves included in this report are expressed in thousands of barrels (103bbl). In these estimates, 1 barrel equals 42 United States gallons. For
8 DeGolyer and MacNaughton reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity. Gas reserves estimated herein are expressed as fuel gas, sales gas, and marketable gas. Fuel gas is that portion of the total volume of gas to be produced from the reservoirs used in the operation of the field. In certain cases, fuel gas also represents the estimated volume of gas utilized in existing and future power-generation plants. ROSNEFT provided information about currently operating and future plants, including a schedule of operation, plant inlet rates, fields associated with each plant, and pertinent economic parameters. Sales gas is defined as the total volume of gas to be produced from the reservoirs, measured at the point of delivery, available for sales, after deduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Marketable gas is defined as the sum of fuel gas and sales gas. The fuel gas reserves included as a portion of ROSNEFT net marketable gas reserves, as of December 31, 2020, are summarized as follows, expressed in millions of cubic feet (106ft3): Fuel Gas Portion of ROSNEFT Net Marketable Gas Reserves (106ft3) Proved Developed 2,592,267 Proved Undeveloped 861,644 Total Proved 3,453,911 Gas quantities are expressed at a temperature base of 20 degrees Celsius (°C) and at a pressure base of 1 atmosphere (atm). Gas quantities included in this report are expressed in millions of cubic feet (106ft3). Gas reserves are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas reserves estimated herein include both associated and nonassociated gas. ROSNEFT has represented that most of gas produced from the fields evaluated herein and located in the Unified gas supply system zone will be delivered to market
9 DeGolyer and MacNaughton through the Gazprom Gas Transmission System (GTS). In accordance with Russian Federation Resolution no. 858, dated July 14, 1997, ROSNEFT is entitled to access to the GTS for transportation and delivery of gas. Additionally, Russian Federation Resolution no. 1021, dated December 29, 2000, obligates Gazprom and its affiliates to sell gas, produced by Gazprom and its affiliates, at a price within a range of wholesale prices regulated by the Federal Anti-Monopoly Service with adjustment for the energy value of the gas, and permits Gazprom to collect a service charge for retail distribution. The range of prices is established for each Russian region where the gas is sold. ROSNEFT has represented that all gas not used for fuel will be sold, whether at an agreed-upon contract price or at the lower price associated with gas sales through the GTS. Sales gas reserves have been estimated herein on the basis of these representations. ROSNEFT provided sales gas prices to be used for the estimation of the value of the gas reserves reported herein, and it has represented that these prices are consistent with the conditions described above. Primary Economic Assumptions This report has been prepared using initial prices, expenses, and costs provided by ROSNEFT in United States dollars (U.S.$). Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the reserves reported herein: Oil and Condensate Prices ROSNEFT has represented that the sales prices of oil and condensate were based on a 12-month average price (reference price), calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. ROSNEFT supplied oil and condensate prices, which were based on a Urals reference price of 21,776 Russian rubles per metric ton (U.S.$41.46 per barrel). The Urals reference oil price is an average of the Urals (MED) and Urals (Rdam) prices as published in the Platts Oilgram Price Report. For the ROSNEFT Holdings in the Russian Federation (including those in both the Chechen Republic and the Sakhalin-1 Project), the volume-weighted average oil and condensate prices over the lives of the fields were
10 DeGolyer and MacNaughton U.S.$35.32 per barrel and U.S.$29.61 per barrel, respectively. For the JV holding in Canada, ROSNEFT supplied differentials to an Edmonton Light Oil reference price of U.S.$44.50 per barrel and the prices were held constant thereafter. The volume-weighted average oil price over the lives of the fields in the Canadian JV was U.S.$29.97 per barrel. For the PSA holdings in Vietnam, ROSNEFT supplied differentials to the Brent oil reference price of U.S.$41.31 per barrel. The volume-weighted average price of the condensate over the lives of the fields for the Vietnamese holdings was U.S.$39.66 per barrel. For the PSA holdings in Egypt, ROSNEFT supplied differentials to the Brent oil reference price of U.S.$41.31 per barrel. The volume-weighted average price of condensate over the lives of the fields for the Egyptian holdings was U.S.$38.63 per barrel. NGL Prices For the ROSNEFT Holdings in the Russian Federation (including those in the Chechen Republic), the volume-weighted average NGL price over the lives of the fields was U.S.$6.88 per barrel. For the JV holding in Canada, ROSNEFT supplied an NGL price of U.S.$12.19 per barrel and the prices were held constant thereafter. Gas Prices For the ROSNEFT Holdings in the Russian Federation (including those in both the Chechen Republic and the Sakhalin-1 Project), the volume-weighted average price over the lives of the fields was U.S.$0.79 per thousand cubic feet (103ft3). For the JV holding in Canada, ROSNEFT supplied differentials to an Alberta Export Canadian metering outlet (AECO) reference price of U.S.$1.76 per 103ft3 and the prices were held constant thereafter. The volume-weighted average gas price over the lives of the fields in the Canadian JV was U.S.$1.37 per 103ft3. For the PSA holdings in Vietnam, ROSNEFT has represented that sales gas is priced according to terms of a Gas Sales Agreement. The volume-weighted average gas price over
11 DeGolyer and MacNaughton the lives of the Vietnamese fields was U.S.$2.98 per 103ft3. For the PSA holdings in Egypt, ROSNEFT has represented that sales gas is priced according to terms of a Gas Sales Agreement. The volume-weighted average gas price over the lives of the Egyptian fields was U.S.$5.35 per 103ft3. Expenses and Costs Current expenses and costs, and forecasts of expenses and costs, provided by ROSNEFT were used in estimating future expenditures required to operate the fields. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. In our opinion, the information relating to estimated proved reserves of oil, condensate, NGL, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4 and 932-235-50-6 through 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC; provided, however, that (i) estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year, (ii) certain proved undeveloped reserves are scheduled for development more than 5 years after initial disclosure, and (iii) certain economically producible quantities of reserves beyond the primary term of the current production licenses have been classified as proved reserves in this report based on ROSNEFT’s representation that each of the subsidiary enterprises discussed therein has the ability to and intends to extend the applicable current production licenses to the end of the economic lives of the associated fields and that ROSNEFT believes with reasonable certainty that the inclusion of the reserves and revenue under extended license terms is consistent with SEC regulations. ROSNEFT has represented to us that the Russian Law on Subsoil requires that an operator develop a field according to a development plan that has been submitted to and approved by the appropriate government authority. Once approved, failure to follow the development plan is a violation of the Russian Law on Subsoil and may result in the cancellation of the operator’s production license for the field.
12 DeGolyer and MacNaughton Since the implementation of the approved development plan, including that portion that may occur more than 5 years after initial disclosure, is a requirement for maintaining the production license, we have included in certain of our estimates of SEC proved reserves those quantities associated with development activities that are part of the approved development plan and scheduled more than 5 years after initial disclosure. We believe that, since they must be developed to prevent the loss of licenses, there is reasonable certainty that the reserves will be developed. We believe it is reasonable therefore to include these quantities as SEC proved reserves. ROSNEFT has represented to us that the development plans provided to us are in accordance with the approved development plans. We cannot render an opinion regarding the actual possibility that a license will be terminated for failure to follow approved development plans nor an opinion on how many companies have lost their licenses for not following approved development plans. We are not in a position to offer an opinion on the duration of the subsidiary enterprises’ production licenses under the Russian Law on Subsoil, but, in light of the above, believe ROSNEFT’s view on the probability of license extensions to be reasonable, although such view may not be confirmed by the SEC. We believe it is reasonable therefore to include these quantities as SEC proved reserves. To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.
13 DeGolyer and MacNaughton Summary of Conclusions The estimated ROSNEFT net proved reserves, as of December 31, 2020, of the fields evaluated herein were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (103bbl) and millions of cubic feet (106ft3): ROSNEFT Net Reserves Rosneft Holdings Reserves Classification Oil and Condensate (103bbl) NGL (103bbl) Marketable Gas (106ft3) Sales Gas (106ft3) Russia Proved Developed 13,942,638 490,391 39,306,698 36,730,862 Proved Undeveloped 11,183,095 193,357 33,142,769 32,289,477 Total Proved 25,125,733 683,748 72,449,467 69,020,339 Canada Proved Developed 150 85 704 704 Proved Undeveloped 0 0 0 0 Total Proved 150 85 704 704 Egypt Proved Developed 2,377 0 1,264,062 1,247,631 Proved Undeveloped 1,206 0 642,320 633,968 Total Proved 3,583 0 1,906,382 1,881,599 Kurdistan Proved Developed 928 0 0 0 Proved Undeveloped 1,868 0 0 0 Total Proved 2,796 0 0 0 Iraq Proved Developed 0 0 0 0 Proved Undeveloped 0 0 0 0 Total Proved 0 0 0 0 Vietnam Proved Developed 55 0 30,176 30,176 Proved Undeveloped 0 0 0 0 Total Proved 55 0 30,176 30,176 Total Proved Developed 13,946,148 490,476 40,601,640 38,009,373 Proved Undeveloped 11,186,169 193,357 33,785,089 32,923,445 Total Proved 25,132,317 683,833 74,386,729 70,932,818 Note: ROSNEFT has represented that it controls the management of certain of the ROSNEFT Holdings in Russia through various subsidiary enterprises. For those ROSNEFT Holdings controlled by ROSNEFT, 100 percent of the reserves are reported herein as ROSNEFT net reserves and include those reserves not directly held by ROSNEFT.
14 DeGolyer and MacNaughton The estimated ROSNEFT net proved reserves, as of December 31, 2020, attributable to the evaluated fields, adjusted for BP’s working interest of 22.03 percent, are summarized as follows, expressed in thousands of barrels (103bbl) and millions of cubic feet (106ft3): BP Share of ROSNEFT Net Reserves Country Reserves Classification Oil and Condensate (103bbl) NGL (103bbl) Marketable Gas (106ft3) Sales Gas (106ft3) Russia Proved Developed 3,071,563 108,033 8,659,266 8,091,809 Proved Undeveloped 2,463,636 42,597 7,301,352 7,113,372 Total Proved 5,535,199 150,630 15,960,618 15,205,181 Canada Proved Developed 33 19 155 155 Proved Undeveloped 0 0 0 0 Total Proved 33 19 155 155 Egypt Proved Developed 524 0 278,473 274,853 Proved Undeveloped 265 0 141,503 139,663 Total Proved 789 0 419,976 414,516 Kurdistan Proved Developed 204 0 0 0 Proved Undeveloped 412 0 0 0 Total Proved 616 0 0 0 Iraq Proved Developed 0 0 0 0 Proved Undeveloped 0 0 0 0 Total Proved 0 0 0 0 Vietnam Proved Developed 12 0 6,648 6,648 Proved Undeveloped 0 0 0 0 Total Proved 12 0 6,648 6,648 Total Proved Developed 3,072,336 108,052 8,944,542 8,373,465 Proved Undeveloped 2,464,313 42,597 7,442,855 7,253,035 Total Proved 5,536,649 150,649 16,387,397 15,626,500 BP has represented that the BP share of ROSNEFT net reserves account for 47 percent of BP net proved reserves as of December 31, 2020, on a barrel of oil equivalent basis. In addition to the 22.03-percent net interest in ROSNEFT’s net reserves, BP also holds a separate direct working interest in two of the ROSNEFT subsidiary enterprises in Russia: 49-percent interest in Kharampurneftegaz and 20-percent interest in Taas-Yuryakh Neftegazdobycha. This direct working interest is referred to hereinafter as “BP Holdings.”
15 DeGolyer and MacNaughton The estimates of BP Holdings’ net proved reserves, as of December 31, 2020, attributable to the evaluated fields are summarized as follows, expressed in thousands of barrels (103bbl) and millions of cubic feet (106ft3): BP Holdings Net Reserves BP Holdings Reserves Classification Oil and Condensate (103bbl) NGL (103bbl) Marketable Gas (106ft3) Sales Gas (106ft3) Kharampurneftegaz Proved Developed 34,328 40,498 2,792,659 2,792,659 Proved Undeveloped 41,346 10,196 2,438,589 2,438,589 Total Proved 75,674 50,694 5,231,248 5,231,248 Taas-Yuryakh Neftegazdobycha Proved Developed 25,430 0 15,144 0 Proved Undeveloped 18,216 0 1,576 0 Total Proved 43,646 0 16,720 0 Total Proved Developed 59,758 40,498 15,144 2,792,659 Proved Undeveloped 59,562 10,196 1,576 2,438,589 Total Proved 119,320 50,694 16,720 5,231,248 The BP Holdings net reserves shown above are included in the ROSNEFT net reserves shown herein. Additionally, a portion of the BP Holdings net reserves shown above is included in the BP share of ROSNEFT net reserves shown herein. BP has represented that the BP Holdings net reserves account for 3 percent of BP net proved reserves as of December 31, 2020, on a barrel of oil equivalent basis. While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2020, estimated reserves.
16 DeGolyer and MacNaughton Thomas D. Scott, Jr., T.P.G., C.P.G. Senior Vice President DeGolyer and MacNaughton Michael A. Eubanks, P.E. Vice President DeGolyer and MacNaughton DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in ROSNEFT or BP. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of BP. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report. Submitted, DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716
DeGolyer and MacNaughton Thomas D. Scott, Jr., T.P.G., C.P.G. Senior Vice President DeGolyer and MacNaughton CERTIFICATE of QUALIFICATION I, Thomas D. Scott, Jr., Petroleum Geologist and Texas Professional Geoscientist with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify: 1. That I am a Senior Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to BP dated March 9, 2021, and that I, as Senior Vice President, was responsible for the preparation of this report of third party. 2. That I attended the University of Oklahoma, and that I graduated with a Master of Science degree in Geology in the year 1988; that I am a Registered Certified Professional Geologist in the State of Texas; that I am a Registered Professional Geologist with the American Association of Petroleum Geologists; and that I have in excess of 30 years of experience in oil and gas reservoir studies and evaluations.
DeGolyer and MacNaughton Michael A. Eubanks, P.E. Vice President DeGolyer and MacNaughton CERTIFICATE of QUALIFICATION I, Michael A. Eubanks, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify: 1. That I am a Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to BP dated March 9, 2021, and that I, as Vice President, was responsible for the preparation of this report of third party. 2. That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 2005; that I am a Registered Professional Engineer in the State of Texas; and that I have in excess of 14 years of experience in oil and gas reservoir studies and evaluations.
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS We hereby consent to (i) the reference to Netherland, Sewell & Associates contained in the section entitled "Oil and gas disclosures for the group" of the Annual Report and Form 20-F for the year ended December 31, 2020, of BP p.l.c. (the Form 20-F), as set forth under the heading "Compliance" on page 313 and (ii) the inclusion of our third-party letter report dated January 13, 2021, concerning our estimates of the proved reserves and future revenue, as of December 31, 2020, to the BP America Production Company interest in certain oil and gas properties located in the United States (the Third-Party Report), which is included as Exhibit 15.4 to the Form 20-F, and to the incorporation by reference of the reference to Netherland, Sewell & Associates in the Form 20-F and of the Third-Party Report in the following Registration Statements: Registration Statement on Form F-3 (File Nos. 333-226485, 333-226485-01, and 333-226485-02) of BP p.l.c., BP Capital Markets p.l.c., and BP Capital Markets America Inc. and the Registration Statements on Form S-8 (File Nos. 333-67206, 333-79399, 333-103924, 333-123482, 333-123483, 333-131583, 333-131584, 333-132619, 333-146868, 333-146870, 333-146873, 333-173136, 333-177423, 333-179406, 333-186462, 333-186463, 333-199015, 333-200794, 333-200795, 333-207188, 333-207189, 333-210316, 333-210318, and 333-253287) of BP p.l.c. NETHERLAND, SEWELL & ASSOCIATES, INC. /s/ Danny D. Simmons By: ____________________________________ Danny D. Simmons, P.E. President and Chief Operating Officer Houston, Texas March 22, 2021
January 13, 2021 Mr. Kyle Koontz BP America Production Company 1700 Platte Street, Suite 150 Denver, Colorado 80202 Dear Mr. Koontz: In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2020, to the BP America Production Company (BP) interest in certain oil and gas properties located in Louisiana, Texas, and Wyoming. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves within BP's U.S. Lower 48 business unit and that the proved reserves within BP's U.S. Lower 48 business unit represent 8.1 percent of the BP p.l.c. subsidiaries' proved reserves. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities— Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for BP p.l.c.'s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose. We estimate the net reserves and future net revenue to the BP interest in these properties, as of December 31, 2020, to be: Net Reserves Future Net Revenue(1) (M$) Oil NGL Gas Present Worth Category (MBBL) (MBBL) (MMCF) Total at 10% Proved Developed Producing 102,907.1 73,505.4 1,521,516.9 691,042.6 1,039,073.2 Proved Developed Non-Producing(2) 438.7 85.4 500.2 2,551.4 -66.3 Proved Undeveloped(2) 340,805.7 194,069.8 3,273,965.8 4,421,146.0 637,293.7 Total Proved 444,151.6 267,660.6 4,795,982.9 5,114,739.9 1,676,300.6 Totals may not add because of rounding. (1) Future net revenue is after deducting estimated abandonment costs. (2) Estimates of reserves have been included for certain wells that generate positive future net revenue but have negative present worth discounted at 10 percent based on the constant price and cost parameters discussed in subsequent paragraphs of this letter. The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Estimates of reserves have been included for certain wells that generate positive future net revenue but have negative present worth discounted at 10 percent based on the constant price and cost parameters discussed in subsequent paragraphs of this letter. These wells have been included based on the operators' declared intent to drill these wells, as evidenced by BP's internal budget, reserves estimates, and price forecast. No study was made to determine whether probable or possible reserves might be established for
these properties. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Gross revenue is BP's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for BP's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties. Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2020. For oil and NGL volumes, the average West Texas Intermediate Platt's Mth1 (Adj) Mid spot price of $39.57 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Louisiana-Onshore South Henry Hub spot price of $1.94 per MMBTU is adjusted for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $36.75 per barrel of oil, $9.30 per barrel of NGL, and $1.60 per MCF of gas. Operating costs used in this report are based on operating expense records of BP. For the nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, operating costs for the operated properties are limited to direct lease- and field-level costs and BP's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs have been divided into field-level costs and per-unit-of-production costs and are not escalated for inflation. Capital costs used in this report were provided by BP and are based on authorizations for expenditure, budget estimates, and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are BP's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation. For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the BP interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on BP receiving its net revenue interest share of estimated future gross production. Additionally, although we are aware of firm transportation contracts that are in place for these properties, the associated costs are considered by BP to be corporate-level expenses; no adjustments have been made to our estimates of future revenue to account for such contracts. The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by BP, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover
the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report. For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for non-producing zones, undeveloped locations, and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment. The data used in our estimates were obtained from BP, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. C. Ashley Smith, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2006 and has over 5 years of prior industry experience. Edward C. Roy III, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2008 and has over 11 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis. Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-2699 /s/ C.H. (Scott) Rees III By: C.H. (Scott) Rees III, P.E. Chairman and Chief Executive Officer /s/ C. Ashley Smith /s/ Edward C. Roy III By: By: C. Ashley Smith, P.E. 100560 Edward C. Roy III, P.G. 2364 Vice President Vice President Date Signed: January 13, 2021 Date Signed: January 13, 2021 CAS:MSS Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 1 of 6 The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations. (1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties. (2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) Same environment of deposition; (iii) Similar geological structure; and (iv) Same drive mechanism. Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest. (3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons. (4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature. (5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. (6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Supplemental definitions from the 2018 Petroleum Resources Management System: Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation. Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. (7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. (ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 2 of 6 (iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. (iv) Provide improved recovery systems. (8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. (9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. (10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section. (11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date. (12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory- type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs. (ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. (iii) Dry hole contributions and bottom hole contributions. (iv) Costs of drilling and equipping exploratory wells. (v) Costs of drilling exploratory-type stratigraphic test wells. (13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section. (14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir. (15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. (16) Oil and gas producing activities. (i) Oil and gas producing activities include: (A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations; (B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; (C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: (1) Lifting the oil and gas to the surface; and (2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 3 of 6 (D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as: a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered. (ii) Oil and gas producing activities do not include: (A) Transporting, refining, or marketing oil and gas; (B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; (C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or (D) Production of geothermal steam. (17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. (v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. (18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 4 of 6 (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. (19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence. (20) Production costs. (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: (A) Costs of labor to operate the wells and related equipment and facilities. (B) Repairs and maintenance. (C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. (D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. (E) Severance taxes. (ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. (21) Proved area. The part of a property to which proved reserves have been specifically attributed. (22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 5 of 6 (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. (23) Proved properties. Properties with proved reserves. (24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease. (25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. (26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas: 932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year: a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B) b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7). The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. 932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B: a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves. d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 6 of 6 e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves. f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. (27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. (28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations. (29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion. (30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area. (31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. From the SEC's Compliance and Disclosure Interpretations (October 26, 2009): Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule. Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following: The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities); The company's historical record at completing development of comparable long-term projects; The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities; The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority). (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. (32) Unproved properties. Properties with no proved reserves.
Exhibit 15.7
Consent of Independent Registered Public Accounting Firm
We consent to the incorporation by reference of our reports dated 22 March 2021 relating to the consolidated financial statements of BP p.l.c. (the “Company”) and the effectiveness of the Company’s internal control over financial reporting, appearing in this Annual Report on Form 20-F of the Company for the year ended 31 December 2020, in the following Registration Statements:
Registration Statement Nos. 333-226485, 333-226485-01 and 333-226485-02 of the Company, BP Capital Markets p.l.c. and BP Capital Markets America Inc. on Form F-3; and Registration Statement Nos. 333-67206, 333-79399, 333-103924, 333-123482, 333-123483, 333-131583, 333-131584, 333-132619, 333-146868, 333-146870, 333-146873, 333-173136, 333-177423, 333-179406, 333-186462, 333-186463, 333-199015, 333-200794, 333-200795, 333-207188, 333-207189, 333-210316, 333-210318, and 333-253287 of the Company on Form S-8.
/s/ Deloitte LLP
London, United Kingdom
22 March 2021
Exhibit 15.8
Consent of Independent Auditors
We consent to the incorporation by reference of our report dated 27 March 2020 (except for Note 7, as to which the date is 22 March 2021), with respect to the consolidated financial statements of Rosneft Oil Company for the year ended 31 December 2019, included in Exhibit 99.1 of this Annual Report on Form 20-F of BP p.l.c. for the year ended 31 December 2020, in the following Registration Statements:
Registration Statements on Form F-3 (File Nos. 333-226485, 333-226485-01, and 333-226485-02) of BP p.l.c., BP Capital Markets p.l.c., and BP Capital Markets America Inc.; and the Registration Statements on Form S-8 (File Nos. 333-67206, 333-79399, 333-103924, 333-123482, 333-123483, 333-131583, 333-131584, 333-132619, 333-146868, 333-146870, 333-146873, 333-173136, 333-177423, 333-179406, 333-186462, 333-186463, 333-199015, 333-200794, 333-200795, 333-207188, 333-207189, 333-210316, 333-210318, and 333-253287) of BP p.l.c.
/s/ Ernst & Young LLC
Moscow, Russia
22 March 2021
Consolidated financial statements of Rosneft Oil Company as at and for the years ended December 31, 2020 (unaudited) and 2019
A member firm of Ernst & Young Global Limited Ernst & Young LLC Sadovnicheskaya Nab., 77, bld. 1 Moscow, 115035, Russia Tel: +7 (495) 705 9700 +7 (495) 755 9700 Fax: +7 (495) 755 9701 www.ey.com/ru ООО «Эрнст энд Янг» Россия, 115035, Москва Садовническая наб., 77, стр. 1 Тел.: +7 (495) 705 9700 +7 (495) 755 9700 Факс: +7 (495) 755 9701 ОКПО: 59002827 ОГРН: 1027739707203 ИНН: 7709383532 Report of independent auditors To the Shareholders and Board of Directors of Rosneft Oil Company We have audited the accompanying consolidated financial statements of Rosneft Oil Company, which comprise the consolidated balance sheet as of December 31, 2019, and the related consolidated statements of profit or loss, comprehensive income, changes in equity and cash flows for the year then ended, and the related notes to the consolidated financial statements. Management’s responsibility for the financial statements Management is responsible for the preparation and fair presentation of these financial statements in conformity with International Financial Reporting Standards; this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error. Auditor’s responsibility Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
A member firm of Ernst & Young Global Limited Opinion In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Rosneft Oil Company at December 31, 2019, and the consolidated results of its operations and its cash flows for the year then ended in conformity with International Financial Reporting Standards. Other matters The accompanying financial statements for 2020 were not audited by us and, accordingly, we do not express an opinion on them. /s/ Ernst & Young LLC Moscow, Russia March 27, 2020 (except for the effects of finalized purchase price allocation of 2019 acquisitions described in Note 7, as to which the date is March 22, 2021)
Rosneft Oil Company Consolidated balance sheet (in billions of Russian rubles) The accompanying notes to the consolidated financial statements are an integral part of these statements. As of December 31, Notes 2020 (unaudited) 2019* ASSETS Current assets Cash and cash equivalents 18 806 228 Restricted cash 18 17 10 Other short-term financial assets 19 817 501 Accounts receivable 20 468 620 Bank loans granted 131 130 Inventories 21 361 438 Prepayments and other current assets 22 322 469 Total current assets 2,922 2,396 Non-current assets Property, plant and equipment 23 10,401 8,706 Right-of-use assets 24 155 160 Intangible assets 25 80 66 Other long-term financial assets 26 275 229 Investments in associates and joint ventures 27 846 801 Bank loans granted 363 291 Deferred tax assets 15 54 33 Goodwill 25 82 93 Other non-current non-financial assets 28 172 171 Total non-current assets 12,428 10,550 Total assets 15,350 12,946 LIABILITIES AND EQUITY Current liabilities Accounts payable and accrued liabilities 29 1,546 1,162 Loans and borrowings and other financial liabilities 30 798 795 Income tax liabilities 14 23 Other tax liabilities 31 301 379 Provisions 32 68 55 Prepayment on long-term oil and petroleum products supply agreements 33 357 332 Other current liabilities 8 9 Total current liabilities 3,092 2,755 Non-current liabilities Loans and borrowings and other financial liabilities 30 3,810 3,033 Deferred tax liabilities 15 1,072 843 Provisions 32 437 343 Prepayment on long-term oil and petroleum products supply agreements 33 1,401 750 Other non-current liabilities 34 51 73 Total non-current liabilities 6,771 5,042 Equity Share capital 36 1 1 Treasury shares 36 (370) – Additional paid-in capital 1,100 635 Reserve for foreign exchange differences on translation of foreign operations (66) (185) Other funds and reserves 34 31 Retained earnings 36 4,007 4,032 Rosneft shareholders’ equity 4,706 4,514 Non-controlling interests 16 781 635 Total equity 5,487 5,149 Total liabilities and equity 15,350 12,946 * Certain amounts have been restated to reflect the effects of finalized purchase price allocation of 2019 acquisitions (Note 7).
Rosneft Oil Company Consolidated statement of profit or loss (in billions of Russian rubles, except earnings per share data, and share amounts) The accompanying notes to the consolidated financial statements are an integral part of these statements. For the years ended December 31, Notes 2020 (unaudited) 2019* Revenues and equity share in profits of associates and joint ventures Oil, gas, petroleum products and petrochemicals sales 8 5,628 8,490 Support services and other revenues 77 86 Equity share in profits of associates and joint ventures 27 52 100 Total revenues and equity share in profits of associates and joint ventures 5,757 8,676 Costs and expenses Production and operating expenses 767 715 Cost of purchased oil, gas, petroleum products, goods for retail and refining costs 691 1,566 General and administrative expenses 127 200 Transportation costs and other commercial expenses 661 733 Exploration expenses 15 11 Depreciation, depletion and amortization 23-25 663 687 Taxes other than income tax 9 2,121 2,666 Export customs duty 10 334 793 Total costs and expenses 5,379 7,371 Operating income 378 1,305 Finance income 11 95 143 Finance expenses 12 (220) (227) Other income 13 533 11 Other expenses 13 (463) (156) Foreign exchange differences (163) 64 Realized foreign exchange differences on hedge instruments 6 2 (146) Income before income tax 162 994 Income tax benefit/(expense) 15 19 (192) Net income 181 802 Net income attributable to: - Rosneft shareholders 147 705 - non-controlling interests 16 34 97 Net income attributable to Rosneft shareholders per common share (in RUB) – basic and diluted 17 14.88 66.52 Weighted average number of shares outstanding (millions) 9,876 10,598 * Certain amounts have been restated to reflect the effects of finalized purchase price allocation of 2019 acquisitions (Note 7).
Rosneft Oil Company Consolidated statement of comprehensive income (in billions of Russian rubles) The accompanying notes to the consolidated financial statements are an integral part of these statements. For the years ended December 31, Notes 2020 (unaudited) 2019* Net income 181 802 Other comprehensive income – to be reclassified to profit or loss in subsequent periods Foreign exchange differences on translation of foreign operations 119 (88) Foreign exchange cash flow hedges 6 (2) 146 Income from changes in fair value of debt financial assets at fair value through other comprehensive income 3 5 Increase in loss allowance for expected credit losses on debt financial assets at fair value through other comprehensive income 1 1 Equity share in other comprehensive loss of associates (1) (4) Income tax related to other comprehensive income – to be reclassified to profit or loss in subsequent periods 6 – (29) Total other comprehensive income – to be reclassified to profit or loss in subsequent periods, net of tax 120 31 Other comprehensive income – not to be reclassified to profit or loss in subsequent periods Income from changes in fair value of equity financial assets at fair value through other comprehensive income 3 7 Income tax related to other comprehensive income – not to be reclassified to profit or loss in subsequent periods (1) (1) Total other comprehensive income – not to be reclassified to profit or loss in subsequent periods, net of tax 2 6 Total comprehensive income, net of tax 303 839 Total comprehensive income, net of tax, attributable to: - Rosneft shareholders 269 742 - non-controlling interests 34 97 * Certain amounts have been restated to reflect the effects of finalized purchase price allocation of 2019 acquisitions (Note 7).
Rosneft Oil Company Consolidated statement of changes in equity (in billions of Russian rubles, except share amounts) The accompanying notes to the consolidated financial statements are an integral part of these statements. Number of shares (millions) Share capital Treasury shares Additional paid-in capital Reserve for foreign exchange differences on translation of foreign operations Other funds and reserves* Retained earnings Rosneft share- holders’ equity Non- controlling interests Total equity Balance at January 1, 2019 10,598 1 – 633 (97) (94) 3,610 4,053 624 4,677 Net income – – – – – – 705 705 97 802 Other comprehensive (loss)/income – – – – (88) 125 – 37 – 37 Total comprehensive (loss)/income – – – – (88) 125 705 742 97 839 Dividends declared (Note 36) – – – – – – (283) (283) (99) (382) Change of interest in subsidiaries – – – 1 – – – 1 3 4 Other movements (Note 16) – – – 1 – – – 1 10 11 Balance at December 31, 2019 10,598 1 – 635 (185) 31 4,032 4,514 635 5,149 Net income – – – – – – 147 147 34 181 Other comprehensive income – – – – 119 3 – 122 – 122 Total comprehensive income – – – – 119 3 147 269 34 303 Dividends declared (Note 36) – – – – – – (172) (172) (63) (235) Acquisition of treasury shares (Note 36) (1,098) – (370) – – – – (370) – (370) Change of interest in subsidiaries (Note 16) – – – 469 – – – 469 174 643 Disposal of subsidiaries – – – – – – – – 1 1 Other movements (Note 16) – – – (4) – – – (4) – (4) Balance at December 31, 2020 (unaudited) 9,500 1 (370) 1,100 (66) 34 4,007 4,706 781 5,487 * Other funds and reserves include a reserve for changes in fair value of equity and debt financial assets at fair value through other comprehensive income, a reserve for expected credit losses on such debt financial assets, a reserve for equity share in other comprehensive income of associates and joint ventures, and a reserve for foreign exchange cash flow hedges.
Rosneft Oil Company Consolidated statement of cash flows (in billions of Russian rubles) The accompanying notes to the consolidated financial statements are an integral part of these statements. For the years ended December 31, Notes 2020 (unaudited) 2019 Operating activities Net income 181 802 Adjustments to reconcile net income to net cash provided by operating activities Depreciation, depletion and amortization 23-25 663 687 Loss on disposal of non-current assets 13 15 16 Dry hole costs 8 3 Offset of prepayments received on oil and petroleum products long term supply agreements 33 (300) (344) Offset of prepayments made on oil and petroleum products long term supply agreements 9 138 Foreign exchange gain on non-operating activities 252 (105) Realized foreign exchange differences on hedge instruments 6 (2) 146 Offset of other financial liabilities (160) (172) Equity share in profits of associates and joint ventures 27 (52) (100) Changes in provisions for financial assets (14) 41 Non-cash income from acquisitions and sales, net (512) – Loss from changes in reserves and impairment of assets 388 108 Finance expenses 12 220 227 Finance income 11 (95) (143) Income tax (income)/expense 15 (19) 192 Changes in operating assets and liabilities Decrease/(increase) in accounts receivable, gross 46 (139) Decrease/(increase) in inventories 48 (43) (Increase)/decrease in restricted cash (7) 2 Decrease/(increase) in prepayments and other current assets 58 (58) Increase in long-term prepayments made on oil and petroleum products supply agreements including current portion (12) (67) (Decrease)/increase in accounts payable and accrued liabilities (73) 14 (Decrease)/increase in other tax liabilities (78) 49 Decrease in other current liabilities (3) (9) Increase in other non-current liabilities – 3 (Decrease)/increase in current reserves (3) 2 Proceeds under long-term oil and petroleum products supply agreements 1,004 – Interest paid on long-term prepayment received on oil and petroleum products supply agreements (14) (8) Net increase in operating assets of subsidiary banks (34) (61) Net increase in operating liabilities of subsidiary banks 227 4 Net cash provided by operating activities before income tax and interest 1,741 1,185 Income tax payments (126) (202) Interest received 98 77 Dividends received 32 50 Net cash provided by operating activities 1,745 1,110
Rosneft Oil Company Consolidated statement of cash flows (continued) (in billions of Russian rubles) The accompanying notes to the consolidated financial statements are an integral part of these statements. For the years ended December 31, Notes 2020 (unaudited) 2019 Investing activities Capital expenditures (785) (854) Acquisition of licenses and auction fee payments (4) (11) Acquisition of short-term financial assets (378) (93) Proceeds from sale of short-term financial assets 100 240 Proceeds from sale of long-term financial assets 13 12 Acquisition of long-term financial assets (51) (18) Acquisition of interest and additional capital contribution to the associates and joint ventures (4) (4) Acquisition of interest in subsidiaries, net of cash acquired, and joint arrangements 7 (633) (12) Proceeds from sale of interest in subsidiaries, net of cash acquired 31 5 Proceeds from sale of property, plant and equipment 17 6 Net cash used in investing activities (1,694) (729) Financing activities Proceeds from short-term loans and borrowings 623 401 Repayment of short-term loans and borrowings (797) (689) Proceeds from long-term loans and borrowings 1,218 393 Repayment of long-term loans and borrowings (588) (540) Proceeds from other financial liabilities 54 185 Repayment of other financial liabilities (107) (57) Interest paid (256) (280) Repurchase of bonds (29) – Proceeds from sale of non-controlling share in subsidiary 16 644 – Other financing received 3 12 Dividends paid to Rosneft shareholders 36 (172) (283) Dividends paid to non-controlling shareholders (63) (99) Net cash provided by / (used in) financing activities 530 (957) Net increase/(decrease) in cash and cash equivalents 581 (576) Cash and cash equivalents at the beginning of the year 18 228 832 Effect of foreign exchange on cash and cash equivalents (3) (28) Cash and cash equivalents at the end of the year 18 806 228
Rosneft Oil Company Notes to the consolidated financial statements December 31, 2020 (all amounts in tables are in billions of Russian rubles, except as noted otherwise) 1. General Public Joint Stock Company (“PJSC”) Rosneft Oil Company (“Rosneft”) and its subsidiaries (collectively, the “Company”) are principally engaged in exploration, development, production and sale of crude oil and gas and refining, transportation and sale of petroleum products in the Russian Federation and in certain international markets. Rosneft State Enterprise was incorporated as an open joint stock company on December 7, 1995. All assets and liabilities previously managed by Rosneft State Enterprise were transferred to the Company at their book value effective on that date together with ownership rights to other privatized oil and gas companies belonging to the Government of the Russian Federation (the “State”). The transfer of assets and liabilities was made in accordance with Russian Government Resolution No. 971 dated September 29, 1995, On the Transformation of Rosneft State Enterprise into Open Joint Stock Company “Oil Company Rosneft”. These transfers involved the reorganization of assets under the common control of the State and, accordingly, were accounted for at their book value. In 2005, the State contributed the shares of Rosneft to the share capital of JSC ROSNEFTEGAS. As of December 31, 2005, 100% of the shares of Rosneft less one share were owned by JSC ROSNEFTEGAS and one share was owned by the Russian Federation Federal Agency for the Management of Federal Property. Subsequently, JSC ROSNEFTEGAS’s ownership interest decreased through the additional issue of shares during Rosneft’s Initial Public Offering (“IPO”) in Russia, an issue of Global Depository Receipts (“GDR”) for shares on the London Stock Exchange and the share swap between Rosneft and certain subsidiaries in 2006. As of December 31, 2020 JSC ROSNEFTEGAS’s owned 40.4% shares in Rosneft. Under Russian legislation, natural resources, including oil, gas, precious metals and minerals and other commercial minerals situated in the territory of the Russian Federation, are the property of the State until they are extracted. Law of the Russian Federation No. 2395-1, On Subsurface Resources, regulates relations arising in connection with the geological study, development and extraction, use and protection of subsurface resources in the territory of the Russian Federation. Pursuant to the law, subsurface resources may be developed only on the basis of a license. A license is issued by the regional governmental body and contains information on the site to be developed and the period of activity, as well as financial and other conditions. The Company holds licenses issued by competent authorities for the geological study, exploration and development of oil and gas blocks, fields, and shelf in areas within Russian Federation where its subsidiaries are located. The Company is subject to export quotas set by the Russian Federation State Pipeline Commission to allow equal access to the limited capacity of the oil pipeline system owned and operated by PJSC AK Transneft. The Company exports certain quantities of crude oil through bypassing the PJSC AK Transneft system thus achieving higher export capacity. The remaining production is processed at the Company’s and third parties’ refineries for further sale on domestic and international markets. 2. Basis of preparation These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards, including all International Financial Reporting Standards (“IFRS”) and Interpretations issued by the International Accounting Standards Board (“IASB”) and effective in the reporting period, and are fully compliant therewith. These consolidated financial statements have been prepared on a historical cost basis, except certain financial assets and liabilities measured at fair value (Note 37).
2. Basis of preparation (continued) Rosneft and its subsidiaries maintain their books and records in accordance with statutory accounting and taxation principles and practices applicable in respective jurisdictions. These consolidated financial statements were derived from the Company’s statutory books and records. In course of preparation of these consolidated financial statements the Company’s management considered the current international economic environment including complex of uncertainties due to COVID-19 pandemic. These consolidated financial statements were prepared on a going concern basis. The Company’s consolidated financial statements are presented in billions of Russian rubles (“RUB”), unless otherwise indicated. The consolidated financial statements were approved and authorized for issue by the Chief Executive Officer of the Company on February 12, 2021. Subsequent events have been evaluated through February 12, 2021, the date these consolidated financial statements were issued. 3. Significant accounting policies The accompanying consolidated financial statements differ from the financial statements issued for statutory purposes in accordance with Russian accounting principles (RAP) in that they reflect certain adjustments, not recorded in the Company’s statutory books, which are appropriate for presenting the financial position, results of operations and cash flows in accordance with IFRS. The principal adjustments relate to: (1) recognition of certain expenses; (2) valuation and depreciation of property, plant and equipment; (3) deferred income taxes; (4) impairment of assets; (5) accounting for the time value of money; (6) accounting for investments in oil and gas property and conveyances; (7) consolidation principles; (8) recognition and disclosure of guarantees, contingencies, commitments and certain other assets and liabilities; (9) business combinations and goodwill; (10) accounting for derivative instruments; (11) purchase price allocation to the identifiable assets acquired and the liabilities assumed. The consolidated financial statements include assets, liabilities, equity, income, expenses and cash flows of the parent and its subsidiaries presented as those of a single economic entity. All significant intercompany transactions and balances have been eliminated. The equity method is used to account for investments in associates in which the Company has the ability to exert significant influence over the associates’ operating and financial policies. Investments in entities where the Company holds the majority of shares, but does not exercise control, are also accounted for using the equity method. Investments in other companies are accounted for at fair value or cost adjusted for impairment, if any. Determination of the level of control or influence in the entities where the Company holds a share is carried out taking into account the powers established by the agreement in respect of the investment and the existing rights that provide the Company with the opportunity to manage significant activities at the present time. Business combinations and goodwill Acquisitions by the Company of controlling interests in third parties (or interest in their charter capital) are accounted for using the acquisition method. The date of acquisition is the date when effective control over the acquiree passes to the Company.
3. Significant accounting policies (continued) Business combinations and goodwill (continued) The cost of an acquisition is measured as an aggregate of the consideration transferred, measured at acquisition date fair value, and the amount of any non-controlling interest in the acquiree. For each business combination, the Company elects whether it measures the non-controlling interest in the acquiree either at fair value or at the proportionate share of the acquiree’s identifiable net assets. Acquisition costs incurred are expensed and included in administrative expenses. Any contingent consideration to be transferred by the acquirer is recognized at fair value at the acquisition date. Subsequent changes to the fair value of the contingent consideration which is deemed to be an asset or a liability should be recognized within profit or loss for the period if they do not represent measurement-period adjustments. If the contingent consideration is classified as equity, it should not be re-measured. Goodwill is initially measured at cost being the excess of the aggregate of the consideration transferred and the amount recognized for non-controlling interests over the fair value of net identifiable assets acquired and liabilities assumed. If the aggregate of the consideration transferred and the amount of non-controlling interest is lower than the fair value of the net assets of the subsidiary acquired and liabilities assumed, the difference is recognized in profit or loss for the period. From the date of initial recognition, goodwill is measured at initial cost less accumulated impairment losses. For the purpose of impairment testing, goodwill acquired in a business combination shall, from the acquisition date, be allocated to the Company’s cash-generating units, which are expected to benefit from the synergies of the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units or groups of units. If the Company disposes of a part of a cash generating unit, the goodwill associated with the part disposed of shall be included in the carrying amount of this part when determining the gain or loss on disposal; the above mentioned part of goodwill to be disposed of shall be measured on the basis of the relative values of the part disposed of and the total value of the cash-generating unit. The Company reassesses whether it controls the investees when facts and circumstances indicate that there are changes to one of the three elements of control. Associates Investments in associates are accounted for using the equity method unless they are classified as non-current assets held for sale. Under this method, the carrying value of investments in associates is initially recognized at the acquisition cost. The carrying value of investments in associates is increased or decreased by the Company’s reported share in the profit or loss and other comprehensive income of the investee after the acquisition date. The Company’s share in the profit or loss and other comprehensive income of an associate is recognized in the Company’s consolidated statement of profit or loss or in the consolidated statement of comprehensive income, respectively. Dividends paid by the associate are accounted for as a reduction of the carrying value of investments.
3. Significant accounting policies (continued) Associates (continued) The Company’s net investments in associates include the carrying value of the investments in these associates as well as other long-term investments that, in substance, form part of the Company’s net investments in associates. For example, an item for which settlement is neither planned nor likely to occur in the foreseeable future is, in substance, an extension of the Company’s investment in that associate. Such items may include entry bonuses, preference shares and long-term receivables or loans, but do not include trade receivables, trade payables or any long-term receivables for which adequate collateral exists, such as secured loans. If the share in losses exceeds the carrying value of the investments in associates and the value of other long-term investments related to investments in these associates, the Company ceases to recognize its share in losses when the carrying value reaches zero. Any additional losses are provided for and liabilities are recognized only to the extent that the Company has legal or constructive obligations or has made payments on behalf of the associate. If the associate subsequently makes profits, the Company resumes recognizing its share in these profits only after its share of the profits equals the share of losses not recognized. The carrying value of investments in associates is tested for impairment by reconciling its recoverable amount (the higher of its value in use and fair value less costs to sell) to its carrying value, whenever impairment indicators are identified. Joint arrangements The Company participates in joint arrangements either in the form of joint ventures or joint operations. A joint venture implies that the parties that have joint control of the arrangement have rights to the net assets of the arrangement. A joint venture involves establishing a legal entity where the Company and other participants have respective equity interests. Equity interests in joint ventures are accounted for under the equity method, as described above in respect of associates. The Company’s share in net profit or loss and in other comprehensive income of joint ventures is recognized in the consolidated statement of profit or loss and in the consolidated statement of comprehensive income, respectively, from the date when joint control commences until the date when joint control ceases. A joint operation implies that the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement. In relation to its interest in a joint operation the Company recognizes its assets, including its share of any assets held jointly, its liabilities, including its share of any liabilities incurred jointly, its revenue from the sale of its share of the output arising from the joint operation, its share of the revenue from the sale of the output by the joint operation, and expenses, including its share of any expenses incurred jointly. Cash and cash equivalents Cash represents cash on hand, in the Company’s bank accounts, in transit and interest-bearing deposits which can be effectively withdrawn at any time without prior notice or any penalties reducing the principal amount of the deposit. Cash equivalents are highly liquid, short-term investments that are readily convertible to known amounts of cash and have original maturities of three months or less from their date of purchase. They are carried at cost plus accrued interest, which approximates fair value. Restricted cash is presented separately in the consolidated balance sheet if its amount is significant. Financial assets The Company recognizes financial assets in its balance sheet when, and only when, it becomes a party to the contractual provisions of the financial instrument. When financial assets are recognized initially, they are measured at fair value, which is usually the price of the transaction, i.e. the fair value of consideration paid or received.
3. Significant accounting policies (continued) Financial assets (continued) When financial assets are recognized initially, they are classified as one of the following, as appropriate: (1) Financial assets at fair value through profit or loss; (2) Financial assets at fair value through other comprehensive income, or (3) Financial assets at amortised cost. The Company classifies financial assets on the basis of both the Company’s business model for managing the financial assets, as well as the contractual cash flow characteristics of the financial assets. A financial asset shall be measured at fair value through profit or loss unless it is measured at amortised cost or at fair value through other comprehensive income. However, the Company may make an irrevocable election at initial recognition for particular instruments in equity instruments that would otherwise be measured at fair value through profit or loss to present subsequent changes in fair value in other comprehensive income. All derivative instruments are recorded in the consolidated balance sheet at fair value in either current financial assets, non-current financial assets, current liabilities related to derivative instruments, or non-current liabilities related to derivative instruments. The recognition and classification of a gain or loss that results from recognition of an adjustment of a derivative instrument at fair value depends on the purpose for issuing or holding the derivative instrument. Gains and losses from derivatives that are not accounted for as hedges under International Financial Reporting Standard (“IFRS”) 9 Financial Instruments are recognized immediately in the profit or loss for the period. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Subsequent to initial recognition, the fair value of financial assets at fair value that are quoted in an active market is defined as bid prices for assets and ask prices for issued liabilities as of the measurement date. If no active market exists for financial assets, the Company measures the fair value using the following methods: • Analysis of recent transactions with peer instruments between independent parties; • Current fair value of similar financial instruments; • Discounting future cash flows. The discount rate reflects the minimum return on investment an investor is willing to accept before starting an alternative project, given its risk and the opportunity cost of forgoing other projects. A financial asset shall be measured at amortised cost if both of the following conditions are met: (a) The financial asset is held within a business model whose objective is to hold financial assets in order to collect contractual cash flows, and (b) The contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding. Examples of financial assets that may fall into this category are loans given, accounts receivable, bonds and notes issued by 3rd parties, which are not quoted at active market – if they fulfill the requirements set above.
3. Significant accounting policies (continued) Financial assets (continued) A financial asset shall be measured at fair value through other comprehensive income if both of the following conditions are met: (a) The financial asset is held within a business model whose objective is achieved by both collecting contractual cash flows and selling financial assets, and (b) The contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding. In particular, this category includes shares of other companies, which are not included in the category of measured at fair value through profit or loss. Dividends and interest income are recognized in the consolidated statement of profit or loss on an accrual basis. The amount of accrued interest income is calculated using the effective interest rate. Upon de-recognition of debt financial assets (bonds, notes etc.) classified as financial instruments at fair value through other comprehensive income, cumulative gains or losses previously recognized in other comprehensive income are reclassified to profit or loss. In case of equity financial assets (shares, stocks etc.), classified as financial instruments at fair value through other comprehensive income, such cumulative gain or loss shall never be subsequently transferred to profit or loss. Interest income as a component of finance income is disclosed in the notes to financial statements separately for each category of financial assets. Regular way purchases and sales of financial assets are accounted for at trade date. Financial liabilities The Company recognizes financial liabilities on its balance sheet when, and only when, it becomes a party to the contractual provisions of the financial instrument. When financial liabilities are recognized initially, they are measured at fair value, which is usually the price of the transaction, i.e. the fair value of consideration paid or received. When financial liabilities are recognized initially, they are classified as one of the following: • Financial liabilities at fair value through profit or loss; • Other financial liabilities. Financial liabilities at fair value through profit or loss are financial liabilities held for trading unless such liabilities are linked to the delivery of unquoted equity instruments. At the initial recognition, the Company may include in this category any financial liability, except for equity instruments that are not quoted in an active market and whose fair value cannot be reliably measured. After initial recognition, however, the liability cannot be reclassified. Financial liabilities not classified as financial liabilities at fair value through profit or loss are designated as other financial liabilities. Other financial liabilities include, inter alia, trade and other accounts payable, and loans and borrowings payable.
3. Significant accounting policies (continued) Financial liabilities (continued) Subsequent to initial recognition, financial liabilities at fair value through profit or loss are measured at fair value, with changes in fair value recognized in profit or loss in the consolidated statement of profit or loss. Other financial liabilities are carried at amortized cost. The Company writes off a financial liability (or part of a financial liability) from its balance sheet when, and only when, it is extinguished – i.e. when the obligation specified in the contract is discharged, cancelled or expires. The difference between the carrying value of a financial liability (or a part of a financial liability) extinguished or transferred to another party and the redemption value, including any transferred non-monetary assets and assumed liabilities, is recognized in profit or loss. Any previously recognized components of comprehensive income pertaining to this financial liability are also included in the financial result and are recognized as gains and losses for the period. Cash flows from the operating activities of subsidiary banks are included within operating activities of the Consolidated Statement of Cash Flows. Operating liabilities of subsidiary banks, including interbank loans, customer deposits, promissory notes and REPO obligations, are included within Accounts payable and accrued liabilities. Earnings per share Basic earnings per share is calculated by dividing net earnings attributable to common shares by the weighted average number of common shares outstanding during the corresponding period. In the absence of any securities-to-shares conversion transactions, the amount of basic earnings per share stated in these consolidated financial statements is equal to the amount of diluted earnings per share. Treasury shares Treasury shares are outstanding Treasury shares purchased from the shareholders. Treasury shares are presented in the consolidated balance sheet as a deduction from equity at cost of repurchase. Inventories Inventories consisting primarily of crude oil, petroleum products, petrochemicals and materials and supplies are accounted for at the weighted average cost unless net realizable value is less than cost. Materials that are used in production are not written down below cost if the finished products into which they will be incorporated are expected to be sold above cost. Repurchase and resale agreements Securities sold under repurchase agreements (“REPO”) and securities purchased under agreements to resell (“reverse REPO”) generally do not constitute a sale of the underlying securities for accounting purposes, and so are treated as collateralized financing transactions. Interest paid or received on all REPO and reverse REPO transactions is recorded in Finance expense or Finance income, respectively, at the contractually specified rate using the effective interest method. Exploration and production assets Exploration and production assets include exploration and evaluation assets, mineral rights and oil and gas properties (development assets and production assets).
3. Significant accounting policies (continued) Exploration and evaluation costs The Company recognizes exploration and evaluation costs using the successful efforts method as permitted by IFRS 6 Exploration for and Evaluation of Mineral Resources. Under this method, costs related to exploration and evaluation (license acquisition costs, exploration and appraisal drilling) are temporarily capitalized in cost centers by field (well) until the drilling program results in the discovery of economically feasible oil and gas reserves. The length of time necessary for this determination depends on the specific technical or economic difficulties in assessing the recoverability of the reserves. If a determination is made that the well did not encounter oil and gas in economically viable quantities, the well costs are expensed to Exploration expenses in the consolidated statement of profit or loss. Exploration and evaluation costs, except for costs associated with seismic, topographical, geological, and geophysical surveys, are initially capitalized as exploration and evaluation assets. Exploration and evaluation assets are recognized at cost less impairment, if any, as property, plant and equipment until the existence (or absence) of commercial reserves has been established. The initial cost of exploration and evaluation assets acquired through a business combination is formed as a result of purchase price allocation. The cost allocation to mineral rights for proved properties and mineral rights for unproved properties is performed based on the respective oil and gas reserves information. Exploration and evaluation assets are subject to technical, commercial and management review as well as review for indicators of impairment at least once a year. This is to confirm the continued intent to develop or otherwise extract value from the discovery. When indicators of impairment are present, an impairment test is performed. If, subsequently, commercial reserves are discovered, the carrying value, less losses from impairment of the respective exploration and evaluation assets, is classified as oil and gas properties (development assets). However, if no commercial reserves are discovered, such costs are expensed after exploration and evaluation activities have been completed. Development and production Oil and gas properties (development assets) are accounted for on a field-by-field basis and represent (1) capitalized costs to develop discovered commercial reserves and to put fields into production, and (2) exploration and evaluation costs incurred to discover commercial reserves reclassified from exploration and evaluation assets to oil and gas properties (development assets) following the discovery of commercial reserves. The cost of oil and gas properties (development assets) also includes the expenditures to acquire such assets, directly identifiable overhead expenses, capitalized financing costs and related asset retirement (decommissioning) obligation costs. Oil and gas properties (development assets) are generally recognized as construction in progress. Following the commencement of commercial production, oil and gas properties (development assets) are reclassified as oil and gas properties (production assets). Other property, plant and equipment Other property, plant and equipment is stated at historical cost as of the acquisition date, except for property, plant and equipment acquired prior to January 1, 2009, which is stated at deemed cost, net of accumulated depreciation and impairment. The cost of maintenance, repairs, and the replacement of minor items of property is charged to operating expenses. Renewals and betterments of assets are capitalized.
3. Significant accounting policies (continued) Other property, plant and equipment (continued) Upon the sale or retirement of property, plant and equipment, the cost and related accumulated depreciation are eliminated from the accounts. Any resulting gains or losses are included in profit or loss. Depreciation, depletion and amortization Oil and gas properties are depleted using the unit-of-production method on a field-by-field basis starting from the commencement of commercial production. In applying the unit-of-production method to mineral licenses, the depletion rate is based on total proved reserves. In applying the unit-of-production method to producing wells and the related oil and gas infrastructure, the depletion rate is based on proved developed reserves. Other property, plant and equipment are depreciated using the straight-line method over their estimated useful lives from the time they are ready for use, except for catalysts which are amortized using the unit-of-production method. Components of other property, plant and equipment and their respective estimated useful lives are as follows: Property, plant and equipment Useful life, not more than Buildings and structures 30-45 years Plant and machinery 5-25 years Vehicles and other property, plant and equipment 6-10 years Service vessels 20 years Offshore drilling assets 20 years Land generally has an indefinite useful life and is therefore not depreciated. Intangible assets (excl. goodwill) Intangible assets with finite lives are amortised over the useful economic life and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortisation period and the amortisation method for an intangible asset with a finite useful life are reviewed at least at the end of each reporting period. Changes in the expected useful life or the expected pattern of consumption of future economic benefits embodied in the asset are considered to modify the amortisation period or method, as appropriate, and are treated as changes in accounting estimates. Construction grants The Company recognizes construction grants from local governments when there is a reasonable assurance that the Company will comply with the conditions attached and that the grant will be received. The construction grants are accounted for as a reduction of the cost of the asset for which the grant is received. Impairment of non-current assets The Company assesses at each balance sheet date whether there is any indication that an asset or cash-generating unit may be impaired. If any such indication exists, the Company estimates the recoverable amount of the asset or cash-generating unit.
3. Significant accounting policies (continued) Impairment of non-current assets (continued) In assessing whether there is any indication that an asset may be impaired, the Company considers internal and external sources of information. It considers at least the following: External sources of information: • During the period, an asset’s market value has declined significantly more than would be expected as a result of the passage of time or normal use; • Significant changes with an adverse effect on the Company have taken place during the period, or will take place in the near future, in the technological, market, economic or legal environment in which the Company operates or in the market to which an asset is dedicated; • Market interest rates or other market rates of return on investments have increased during the period, and those increases are likely to affect the discount rate used in calculating an asset’s value in use and decrease the asset’s recoverable amount materially; • The carrying amount of the net assets of the Company is more than its market capitalization. Internal sources of information: • Evidence is available of obsolescence or physical damage of an asset; • Significant changes with an adverse effect on the Company have taken place during the period, or are expected to take place in the near future, in the extent to which, or manner in which, an asset is used or is expected to be used (e.g., the asset becoming idle, or the useful life of an asset is reassessed as finite rather than indefinite); • Information on dividends from a subsidiary, joint venture or associate; • Evidence is available from internal reporting that indicates that the economic performance of an asset is, or will be, worse than expected. Such evidence includes the existence of: • Cash flows on acquiring the asset, or subsequent cash needs for operating or maintaining it, that are significantly higher than those originally budgeted; • Actual net cash flows or operating profit or loss flowing from the asset that are significantly worse than those budgeted; • A significant decline in budgeted net cash flows or operating profit, or a significant increase in budgeted losses, flowing from the asset; • Operating losses or net cash outflows for the asset, when current period amounts are aggregated with budgeted amounts for the future. The following factors indicate that exploration and evaluation assets may be impaired: • The period for which the Company has the right to explore in the specific area has expired during the period or will expire in the near future, and is not expected to be renewed; • Substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is neither budgeted nor planned; • Exploration for and evaluation of mineral resources in the specific area have not led to the discovery of commercially viable quantities of mineral resources and the Company has decided to discontinue such activities in the specific area; • Sufficient data exist to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale.
3. Significant accounting policies (continued) Impairment of non-current assets (continued) The recoverable amount of an asset or a cash-generating unit is the higher of: • The value in use of an asset (cash-generating unit); and • The fair value of an asset (cash-generating unit) less costs to sell. If the asset does not generate cash inflows that are largely independent of those from other assets, its recoverable amount is determined for the asset’s cash-generating unit. The Company initially measures the value in use of a cash-generating unit. When the carrying amount of a cash-generating unit is greater than its value in use, the Company measures the unit’s fair value for the purpose of measuring the recoverable amount. When the fair value is less than the carrying value an impairment loss is recognized. Value in use is determined by discounting the estimated value of the future cash inflows expected to be derived from the asset or cash-generating unit, including cash inflows from its sale. The value of the future cash inflows from a cash-generating unit is determined based on the forecast approved by management of the business unit to which the unit in question pertains. Impairment of financial assets At each balance sheet date the Company recognizes an allowance for expected credit losses on a financial asset measured at amortised cost, and at fair value through other comprehensive income, a lease receivable, a contract asset or a loan commitment and a financial guarantee contract to which the impairment requirements apply. Requirements of IFRS 9 concerning impairment do not apply to equity instruments of any category as well as to the instruments at fair value though profit or loss. Expected credit losses for significant counterparties, including banks, are determined based on credit rating of particular counterparty and relevant probability of default. The allowance for financial asset at amortised cost is recognized in profit or loss in correspondence with a balance sheet account reducing the carrying amount of the financial asset. The allowance for financial assets at fair value through other comprehensive income shall be recognized in other comprehensive income and shall not reduce the carrying amount of the financial asset in the statement of financial position. Total increase in the allowance for expected credit losses on the financial assets totaled RUB 53 billion in 2020; total decrease of this allowance for the same year totaled RUB 58 billion; above mentioned movements are recognized within the Statement of profit or loss of the Company. Bank loans granted by the subsidiary banks of the Company are presented in consolidated financial statements net of provision for expected credit losses. The provision for such expected credit losses totaled RUB 8 billion and RUB 13 billion as of December 31, 2019 and 2020, respectively. Capitalized interest Interest expense on borrowed funds used for capital construction projects and the acquisition of property, plant and equipment is capitalized provided that the interest expense could have been avoided if the Company had not made capital investments. Interest is capitalized only during the period when construction activities are actually in progress and until the resulting properties are put into operation. Capitalized borrowing costs include exchange differences arising from foreign currency borrowings to the extent that they are regarded as an adjustment to interest costs.
3. Significant accounting policies (continued) Leasing agreements In respect of the contracts (or separate components of a contract), which convey to the Company the right to control the use of an identified asset (as it is determined in IFRS 16 Lease) for a period of time in exchange for consideration, the Company recognizes a right-of-use asset and a lease liability at the commencement date. Non-lease components of the contract are accounted for in accordance with other relevant IFRS. In accordance with requirements of IFRS 16 Lease para 3-8, the Company does not apply the Standard to leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources and to leases of wells, to short-term leases (taking into consideration economically feasible prolongations), as well as to leases for which the underlying asset is of low value (less kRUB 300). The Company determines the lease term as the non-cancellable period of a lease, together with both: periods covered by an option to extend the lease if the lessee is reasonably certain to exercise that option; and periods covered by an option to terminate the lease if the lessee is reasonably certain not to exercise that option. At the commencement date, the Company measures the lease liability at the present value of the lease payments that are not paid at that date. The lease payments are discounted using the incremental borrowing rate, as interest rate implicit in the lease, as a rule, cannot be readily determined. As the finance function lays predominantly within the parent company, incremental borrowing rates are calculated centrally, except for the banks of the Group and cases of direct financing of the subsidiaries. At the commencement date, the Company measures the right-of-use asset at cost, which comprises the amount of the initial measurement of the lease liability, any lease payments made at or before the commencement date, less any lease incentives received, any initial direct costs incurred by the lessee, an estimate of costs to be incurred by the lessee in dismantling and removing the underlying asset, restoring the site on which it is located or restoring the underlying asset to the condition required by the terms and conditions of the lease, unless those costs are incurred to produce inventories. Lease payments are evenly distributed between finance expenses and a decrease of a lease liability so that a constant periodic rate of interest is produced on the remaining balance of the lease liability. Finance expenses are recognized in Consolidated statement of profit or loss. In respect of subsequent accounting for a leased property the same accounting policies are applied as for the owned assets, e.g. depreciation policy. Asset retirement (decommissioning) obligations The Company has asset retirement (decommissioning) obligations associated with its core business activities. The nature of the assets and potential obligations are as follows: The Company’s exploration, development and production activities involve the use of wells, related equipment and operating sites, oil gathering and treatment facilities, tank farms and in-field pipelines. Generally, licenses and other regulatory acts require that such assets be decommissioned upon the completion of production. According to these requirements, the Company is obliged to decommission wells, dismantle equipment, restore the sites and perform other related activities. The Company’s estimates of these obligations are based on current regulatory or license requirements, as well as actual dismantling and other related costs. These liabilities are measured by the Company using the present value of the estimated future costs of decommissioning of these assets. The discount rate is reviewed at each reporting date and reflects current market assessments of the time value of money and the risks specific to the liability.
3. Significant accounting policies (continued) Asset retirement (decommissioning) obligations (continued) In accordance with IFRS Interpretations Committee (“IFRIC”) Interpretation 1 Changes in Existing Decommissioning, Restoration and Similar Liabilities, the provision is reviewed at each balance sheet date as follows: • Upon changes in the estimates of future cash flows (e.g., the costs of and timeframe for abandoning one well) or the discount rate, changes in the amount of the liability are included in the cost of the item of property, plant, and equipment, whereby such cost may not be negative and may not exceed the recoverable value of the item of property, plant, and equipment; • Any changes in the liability due to its nearing maturity (change in the discount) are recognized in Finance expenses. The Company’s refining and distribution activities involve refining operations, marine and other distribution terminals, and retail sales. The Company’s refining operations consist of major petrochemical operations and industrial complexes. Legal or contractual asset retirement (decommissioning) obligations related to petrochemical, oil refining and distribution activities are not recognized due to the limited history of such activities in these segments, the lack of clear legal requirements as to the recognition of obligations, as well as the fact that decommissioning periods for such assets are not determinable. Because of the reasons described above, the fair value of an asset retirement (decommissioning) obligation in the refining and distribution segment cannot be reasonably estimated. Due to continuous changes in the Russian regulatory and legal environment, there could be future changes to the requirements and contingencies associated with the retirement of long-lived assets. Income tax Since 2012 Russian tax legislation has allowed income taxes to be calculated on a consolidated basis. The main subsidiaries of the Company were therefore combined into a consolidated group of taxpayers (Note 15). For subsidiaries which are not included in the consolidated group of taxpayers, income tax is calculated on an individual subsidiary basis. Deferred income tax assets and liabilities are recognized in the accompanying consolidated financial statements in the amount determined by the Company in accordance with IAS 12 Income Taxes. Deferred tax is provided using the liability method on temporary differences at the reporting date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. A deferred tax liability is recognized for all taxable temporary differences, except to the extent that the deferred tax liability arises from: • The initial recognition of goodwill; • The initial recognition of an asset or liability in a transaction which: • Is not a business combination; and • Affects neither accounting profit, nor taxable profit; • Investments in subsidiaries when the Company is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future.
3. Significant accounting policies (continued) Income tax (continued) A prior period tax loss planned to be used to reduce the current or future amount of income tax is recognized as a deferred tax asset. A deferred tax asset is recognized only to the extent that it is probable that taxable profit will be available against which the deductible temporary differences can be utilized, unless the deferred tax asset arises from the initial recognition of an asset or liability in a transaction that: • Is not a business combination; and • At the time of the transaction, affects neither accounting profit nor taxable profit (tax loss). The Company recognizes deferred tax assets for all deductible temporary differences arising from investments in subsidiaries and associates, and interests in joint ventures, to the extent that the following two conditions are met: • The temporary difference will reverse in the foreseeable future; and • Taxable profit will be available against which the temporary difference can be utilized. Deferred tax assets and liabilities shall be measured at the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted by the end of the reporting period. The measurement of deferred tax assets and liabilities reflects the tax consequences that would follow from the manner in which the Company expects, at the end of the reporting period, to recover or settle the carrying amount of its assets and liabilities. Deferred tax assets and liabilities are offset when there is a legally enforceable right to set off current tax assets against current tax liabilities and when they relate to income taxes levied by the taxation authority of the same jurisdiction and the Company intends to settle its current tax assets and liabilities on a net basis. The carrying amount of a deferred tax asset is reviewed at each balance sheet date. The Company reduces the carrying amount of a deferred tax asset to the extent that it is no longer probable that sufficient taxable profit will be available to allow the benefit of part or all of that deferred tax asset to be utilized. Deferred tax assets and liabilities are classified as Non-current Deferred tax assets and Non-current Deferred tax liabilities, respectively. Deferred tax assets and liabilities are not discounted. Recognition of revenues Revenues are recognized when (or as) the Company satisfies a performance obligation by transferring a promised good or service (i.e. an asset) to a customer. An asset is transferred when (or as) the customer obtains control of that asset, which usually occurs when the title is passed, provided that the contract price is fixed or determinable and collectability of the amount of the consideration is probable. Specifically, domestic sales of crude oil and gas, as well as petroleum products and materials are usually recognized when title passes. For export sales, title generally passes at the border of the Russian Federation. Revenue is measured at the fair value of the consideration received or receivable taking into account the amount of any trade discounts, volume rebates and reimbursable taxes.
3. Significant accounting policies (continued) Recognition of revenues (continued) Sales of support services are recognized as services are performed provided that the service price can be determined and no significant uncertainties regarding the receipt of revenues exist. Transportation expenses Transportation expenses recognized in the consolidated statement of profit or loss represent all expenses incurred by the Company to transport crude oil for refining and to end customers, and to deliver petroleum products from refineries to end customers (these may include pipeline tariffs and any additional railroad transportation costs, handling costs, port fees, sea freight and other costs). Refinery maintenance costs The Company recognizes the costs of overhauls and preventive maintenance performed with respect to oil refining assets as expenses when incurred. Environmental liabilities Expenditures that relate to an existing condition caused by past operations, and do not have a future economic benefit, are expensed. Liabilities for these expenditures are recorded when environmental assessments or clean-ups are probable and the costs can be reasonably estimated. Accounting for contingencies Certain conditions may exist as of the date of these consolidated financial statements which may further result in a loss to the Company, but which will only be resolved when one or more future events occur or fail to occur. The Company’s management makes an assessment of such contingent liabilities which is based on assumptions and is a matter of opinion. In assessing loss contingencies relating to legal or tax proceedings that involve the Company or unasserted claims that may result in such proceedings, the Company, after consultation with legal or tax advisors, evaluates the perceived merits of any legal or tax proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. Provisions and contingent liabilities do not constitute finally asserted legal obligations of PJSC “Rosneft Oil Company”. If the assessment of a contingency indicates that it is probable that a loss will be incurred and the amount of the liability can be estimated, then the estimated liability is accrued in the Company’s consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable, but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, would be disclosed. Loss contingencies considered remote are generally not disclosed unless they involve financial guarantees, in which case the nature of the guarantee would be disclosed. However, in some instances in which disclosure is not otherwise required, the Company may disclose contingent liabilities or other uncertainties of an unusual nature which, in the judgment of management after consultation with its legal or tax counsel, may be of interest to shareholders or others.
3. Significant accounting policies (continued) Taxes collected from customers and remitted to governmental authorities Refundable taxes (excise and value-added tax (“VAT”)) are deducted from revenues. Other taxes and duties are not deducted from revenues and are recognized as expenses in Taxes other than income tax in the consolidated statement of profit or loss. VAT and excise receivable and payable are recognized as Prepayments and other current assets and Other tax liabilities in the consolidated balance sheet, respectively. Excises non-refundable by customers Excises non-refundable by customers are presented within Taxes other than income tax in the Consolidated statement of profit or loss. The expenses mentioned above are decreased by reverse excise on petroleum crudes. Tax on additional income (AIT) AIT is recognized as an expense within Taxes other than income tax in Consolidated statement of profit or loss. Functional and presentation currency The consolidated financial statements are presented in Russian rubles, which is the functional currency of Rosneft Oil Company and all of its subsidiaries operating in the Russian Federation. The functional currency of the foreign subsidiaries is generally the U.S. dollar. Transactions and balances Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of these transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation of monetary assets and liabilities denominated in foreign currencies at year-end exchange rates are recognized in the profit or loss for the period. Foreign exchange gains and losses resulting from the translation of monetary assets and liabilities designated as foreign currency cash flow hedging instruments are recognized within other comprehensive income and reclassified to profit or loss in the period when the hedged item affects profit or loss. Non-monetary items that are measured in terms of historical cost in a foreign currency are translated using the exchange rates as at the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value is determined. Company’s subsidiaries, joint ventures and associates The results and financial position of all of the Company’s subsidiaries, joint ventures and associates that have a functional currency which is different from the presentation currency are translated into the presentation currency as follows: • Assets and liabilities for each balance sheet presented are translated at the closing rate at that reporting date; • Income and expenses for each statement of profit or loss and each statement of comprehensive income are translated at average exchange rates (unless this average is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the rate on the dates of the transactions); and • All resulting exchange differences are recognized as a separate component of comprehensive income.
3. Significant accounting policies (continued) Prepayment on oil and petroleum products supply agreements In the ordinary course of business, the Company enters into long-term oil supply contracts. The contract terms may require the buyer to make a prepayment. The Company considers long-term oil supply contracts to be regular-way sale contracts entered into and continued to be held for the purpose of the receipt or delivery of non-financial items in accordance with the Company’s expected purchase, sale or usage requirements. Regular-way sale contracts are exempted from the scope of IAS 32 Financial Instruments: Presentation and IFRS 9 Financial Instruments. Conditions for meeting the definition of a regular-way sale are not met if either of the following applies: • The ability to settle net in cash or another financial instrument, or by exchanging financial instruments, is not explicit in the terms of the contract, but the Company has a practice of settling similar contracts net in cash or via another financial instrument or by exchanging financial instruments (whether with the counterparty, by entering into offsetting contracts or by selling the contract before its exercise or lapse); • For similar contracts, the Company has a practice of taking delivery of the underlying goods and selling them within a short period after delivery for the purpose of generating a profit from short-term fluctuations in price or from a dealer’s margin. Prepayments received for the delivery of goods or respective deferred revenue are accounted for as non- financial liabilities because the outflow of economic benefits associated with them is the delivery of goods and services rather than a contractual obligation to pay cash or another financial asset. Changes in accounting policies and disclosures The accounting policies adopted are consistent with those of the previous financial year except for the adoption of the amendments to existing standards as well as revised version of Conceptual Framework for Financial Reporting effective as of January 1, 2020. The following amendments were applied for the first time in 2020: • Amendments to IFRS 3 Business Combinations. The amendments enhanced definition of a business set out by the standard. As far as the amendments must be prospectively applied to transactions that are either business combinations or asset acquisitions for which the acquisition date is on or after the date of initial application, consequently the amendments did not have a material impact on the consolidated financial statements as of the transfer date. • Amendments to IFRS 7 Financial instruments: Disclosures and IFRS 9 Financial instruments named Interest Rate Benchmark Reform. The amendments provided relief from certain requirements of hedge accounting, as their fulfillment could lead to discontinuation of hedge accounting due to uncertainty caused by the reform. The amendments did not have a material impact on the consolidated financial statements. • Amendments to IAS 1 Presentation of Financial Statements and IAS 8 Accounting Policies, Changes in Accounting Estimates and Errors. The amendments to IAS 1 and IAS 8 introduced new definition of material. The amendments did not have a material impact on the consolidated financial statements. • Revised version of Conceptual Framework for Financial Reporting. In particular, the revised version introduced new definitions of assets and liabilities, as well as amended definitions of income and expenses. The revised version of Conceptual Framework did not have a material impact on the consolidated financial statements. • Amendments to IFRS 16 Leases named COVID-19-related Rent Concessions. The amendments provides relief to lessees from assessment whether a COVID-19-related rent concession is a lease modification. The amendments did not have a material impact on the consolidated financial statements, as the Company has not received significant rent concessions related to pandemic.
4. Significant accounting judgements, estimations and assumptions The preparation of consolidated financial statements requires management to make a number of accounting estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities. The actual results, however, could differ from those estimates. The most significant accounting estimates and assumptions used by the Company’s management in preparing the consolidated financial statements include: • Estimation of oil and gas reserves; • Estimation of rights to, recoverability and useful lives of non-current assets; • Impairment of goodwill, fixed assets and right-of-use assets (Note 25 “Intangible assets and goodwill”, Note 23 “Property, plant and equipment and construction in progress” and Note 24 “Lease agreements”); • Estimated credit losses for accounts receivable (Note 20 “Accounts receivable” etc.); • Assessment of asset retirement (decommissioning) obligations (Note 3 “Significant accounting policies”, section: “Asset retirement (decommissioning) obligations”, and Note 32 “Provisions”); • Assessment of legal and tax contingencies, recognition and disclosure of contingent liabilities (Note 40 “Contingencies”); • Assessment of deferred income tax assets and liabilities (Note 3 “Significant accounting policies”, section: “Income tax”, and Note 15 “Income tax”); • Assessment of environmental remediation obligations (Note 32 “Provisions” and Note 40 “Contingencies”); • Fair value measurements (Note 37 “Fair value of financial instruments”); • Purchase price allocation to the identifiable assets acquired and the liabilities assumed (Note 7 “Acquisition of subsidiaries and shares in joint operations”); • Treatment of certain taxes as income taxes, production taxes or other taxes, e.g. treatment of the tax on additional income (Note 3 “Significant accounting policies”); • Assessment of the COVID-19 pandemic impact on financial position and financial results of the Company (Note 20 “Accounts receivable” etc.). Significant estimates and assumptions affecting the reported amounts are those used in determining the economic recoverability of reserves. Such estimates and assumptions may change over time when new information becomes available, e.g.: • More detailed information on reserves was obtained (either as a result of more detailed engineering calculations or additional exploration drilling activities); • Supplemental activities to enhance oil recovery were conducted; • Changes were made in economic estimates and assumptions (e.g. a change in pricing factors).
5. New and amended standards and interpretations issued but not yet effective In May 2017, the IASB issued IFRS 17 Insurance Contracts. IFRS 17 establishes a single framework for the accounting for insurance contracts and contains requirements for related disclosures. The new standard replaces IFRS 4 Insurance Contracts. The standard is effective for annual periods beginning on or after January 1, 2021. The Company does not expect the standard to have a material impact on the consolidated financial statements. In January 2020, the IASB issued amendments to IAS 1 Presentation of Financial Statements named Classification of Liabilities as Current or Non-current. The amendments clarify requirements for classifying liabilities as current or non-current. The amendments are effective on or after January 1, 2023; earlier application is permitted. The Company does not expect the amendments to have a material impact on the consolidated financial statements, as the Company already applies criteria set by the amendments. In May 2020, the IASB issued amendments to IFRS 3 Business Combinations named Reference to the Conceptual Framework. The amendments replace references to the Conceptual Framework for Financial Reporting with the current version issued in March 2018, without significantly changing the requirements of the standard. The amendments are effective on or after January 1, 2022; earlier application is permitted. The Company does not expect the amendments to have a material impact on the consolidated financial statements. In May 2020, the IASB issued amendments to IAS 16 Property, Plant and Equipment named Property, Plant and Equipment: Proceeds Before Intended Use. The amendments prohibit entities from deducting from the cost of an item of property, plant and equipment any proceeds of the sale of items produced while bringing that asset to the location and condition necessary for it to be capable of operating in the manner intended by management. Instead, an entity recognises the proceeds from selling such items, and the costs of producing those items, in profit or loss. The amendments are effective on or after January 1, 2022 and should be applied retrospectively. The Company does not expect the amendments to have a material impact on the consolidated financial statements. In May 2020, the IASB issued amendments to IAS 37 Provisions, Contingent Liabilities and Contingent Assets named Onerous Contracts – Costs of Fulfilling a Contract. The amendments specify which costs an entity needs to include when assessing whether a contract is onerous. The amendments are effective on or after January 1, 2022; earlier application is permitted. The Company does not expect the amendments to have a material impact on the consolidated financial statements. In August 2020, the IASB issued amendments to IFRS 7 Financial Instruments: Disclosures, IFRS 9 Financial Instruments as well as IFRS 4 Insurance Contracts and IFRS 16 Leases named Interest Rate Benchmark Reform – Phase II. The amendments provide certain temporary reliefs which address the financial reporting effects related to the transfer to the risk-free interest rate. The amendments are effective on or after January 1, 2021; earlier application is permitted. The Company does not expect the amendments to have a material impact on the consolidated financial statements. Additionally a number of amendments, not yet effective, were issued during annual improvement process conducted by IASB. They include the amendments to IFRS 1 Fist-time Adoption named First-time Adoption: Subsidiary as a First-time Adopter, and the amendments to IFRS 9 Financial Instruments named Fees in the ‘10 per cent’ Test for Derecognition of Financial Liabilities. The Company does not expect the amendments to have a material impact on the consolidated financial statements. The Company does not plan for early adoption in respect of above-mentioned new standards and amendments to existing standards to which this option is available, except for the amendment named Classification of Liabilities as Current or Non-current.
6. Capital and financial risk management Capital management The Company’s capital management objectives are to ensure its ability to continue as a going concern and to optimize the cost of capital in order to enhance value to shareholders. Total capital employed and financial liabilities less liquid financial assets are non-IFRS measures. The Company’s management performs a regular assessment of the financial liabilities less liquid financial assets to capital employed ratio to ensure it meets the Company’s requirements to fulfil the Company’s commitments and to retain strong financial stability. The Company’s employed capital is calculated as the sum of equity attributable to equity holders of Rosneft: share capital, reserves, retained earnings and non-controlling interests; financial liabilities, which include long and short-term loans and borrowings, other financial liabilities, as reported in the consolidated balance sheet, less liquid financial assets, including cash and cash equivalents, other short-term financial assets and certain long-term deposits. The Company’s financial liabilities less liquid financial assets to capital employed ratio was as follows: As of December 31, 2020 (unaudited) 2019 Financial liabilities less liquid financial assets to capital employed ratio, % 34.3% 37.0% Financial risk management In the normal course of business, the Company is exposed to the following financial risks: market risk (including foreign currency risk, interest rate risk and commodity price risk), credit risk and liquidity risk. The Company has introduced a risk management system and developed a number of procedures to measure, assess and monitor risks and select the relevant risk management techniques. The Company has developed, documented and approved the relevant policies pertaining to market, credit and liquidity risks and the use of derivative financial instruments. Commodity price risk The Company operates in the worldwide and domestic markets for crude oil, petroleum products and petrochemicals and is exposed to price risk due to price fluctuations in the global and domestic markets. Changes in commodity prices can have a significant impact on the results of current operations and the efficiency of investments in new projects. The Company regularly analyzes its exposure to price risk, including modeling the possible behavior of crude oil and petroleum products prices, export and domestic margins. Information on the assessment of market risks, including commodity price risk, is provided to the management of the Company on an ongoing basis. Foreign exchange risk The Company undertakes transactions denominated in foreign currencies and is exposed to foreign exchange risk arising from various currency exposures, primarily with respect to the U.S. dollar and euro. Foreign exchange risk arises from assets, liabilities, commercial transactions and financing denominated in foreign currencies.
6. Capital and financial risk management (continued) Foreign exchange risk (continued) The carrying values of monetary assets and liabilities denominated in foreign currencies are presented in the table below: Assets Liabilities As of December 31, As of December 31, 2020 (unaudited) 2019 2020 (unaudited) 2019 US$ 1,347 1,351 (2,182) (1,688) EUR 222 138 (386) (330) Total 1,569 1,489 (2,568) (2,018) The Company seeks to identify and manage foreign exchange rate risk in a comprehensive manner, including an integrated analysis of natural economic hedges, in order to benefit from the correlation between income and expenses. The Company chooses the currency in which to hold cash, such as the Russian ruble, U.S. dollar or other currency for short-term risk management purposes. The Company performs analysis of its exposure to foreign exchange rate risk on regular basis, including modeling of the possible behavior of the exchange rate of Russian ruble to U.S. dollar and euro to U.S. dollar. The long-term risk management strategy of the Company may involve the use of derivative or non-derivative financial instruments in order to minimize foreign exchange rate risk exposure. Cash flow hedging of the Company’s future exports The Company designated certain U.S. dollar-denominated borrowings as a hedge of the expected highly probable U.S. dollar-denominated export revenue stream in accordance with IFRS 9 Financial Instruments. A portion of future monthly export revenues expected to be received in U.S. dollars was designated as a hedged item. The nominal amounts of the hedged item and the hedging instruments were equal. To the extent that a change in the foreign currency rate impacts the fair value of the hedging instrument, the effects are recognized in other comprehensive income or loss and then reclassified to profit or loss in the period in which the hedged item affects the profit or loss. The Company’s foreign currency risk management strategy is to hedge future export revenue in the amount of the net monetary position in U.S. dollars. The Company aligns the hedged nominal amount to the net monetary position in U.S. dollars on a periodical basis. As of December 31, 2020 and December 31, 2019 hedge instruments are not designated. The impact of foreign exchange cash flow hedges recognized in other comprehensive income is set out below: 2020 (unaudited) 2019 Before income tax Income tax Net of tax Before income tax Income tax Net of tax Total recognized in other comprehensive (loss)/income as of the beginning of the year 2 – 2 (144) 29 (115) Foreign exchange effects recognized during the year – – – – – – Foreign exchange effects reclassified to profit or loss (2) – (2) 146 (29) 117 Total recognized in other comprehensive income/(loss) for the year (2) – (2) 146 (29) 117 Total recognized in other comprehensive income/(loss) as of the end of the year – – – 2 – 2
6. Capital and financial risk management (continued) Analysis of sensitivity of financial instruments to foreign currency risk The level of currency risk is assessed on a monthly basis using mathematical modeling methods, as well as sensitivity analysis. The table below summarizes the impact on the Company’s income before income tax and equity of the depreciation/(appreciation) of the U.S. dollar and euro against the Russian ruble. U.S. dollar effect Euro effect 2020 (unaudited) 2019 2020 (unaudited) 2019 Currency rate change in % 17.00% 7.74% 17.24% 7.48% Gain/(loss) 177/(177) 34/(34) 29/(29) (6)/6 Equity (255)/255 (56)/56 13/(13) (1)/1 Interest rate risk Loans and borrowings raised at variable interest rates expose the Company to interest rate risk arising from the possible movement of variable elements of the overall interest rate. As of December 31, 2020 (unaudited), the Company’s variable rate liabilities totaled RUB 2,956 billion (net of interest payable). The Company performs analysis of its interest rate exposure on regular basis, including modeling of various scenarios of interest rates behavior. The table below summarizes the impact of a potential increase or decrease in interest rates on the Company’s profit before tax, as applied to the variable element of interest rates on loans and borrowings. The increase/ decrease is based on the management estimates of potential interest rate movements. Increase/decrease in interest rate Effect on income before income tax Basis points RUB billion 2020 (unaudited) +3 (1) -3 1 2019 +4 (1) -4 1 The sensitivity analysis is limited to variable rate loans and borrowings and is conducted with all other variables held constant. The analysis is prepared with the assumption that the amount of variable rate liability outstanding at the balance sheet date was outstanding for the whole year. The interest rate on variable rate loans and borrowings will effectively change throughout the year in response to fluctuations in market interest rates. The impact measured through the sensitivity analysis does not take into account other potential changes in economic conditions that may accompany the relevant changes in market interest rates. Credit risk The Company controls its own exposure to credit risk. All external customers and their financial guarantors, other than related parties, undergo a creditworthiness check (including sellers of goods and services who act on a prepayment basis). The Company performs an ongoing assessment and monitoring of the financial position and the risk of default. As of December 31, 2020, management assessed the impact of credit risk (if materialized) on the Company’s net profit as low. The Company’s exposure to credit risk is limited to the carrying value of financial assets recognized on the consolidated balance sheet, taking into consideration the information disclosed in Note 40 “Contingencies. Guarantees and indemnities issued”.
6. Capital and financial risk management (continued) Credit risk (continued) In addition, as part of its cash management and credit risk function, the Company regularly evaluates the creditworthiness of financial and banking institutions where it deposits cash and performs trade finance operations. The Company primarily has banking relationships with the Russian subsidiaries of large international banking institutions and certain large Russian banks. Liquidity risk The Company has mature liquidity risk management processes covering short-term, mid-term and long-term funding. Liquidity risk is controlled through maintaining sufficient reserves and the adequate amount of committed credit facilities and loan funds. Management regularly monitors projected and actual cash flow information, analyzes the repayment schedules of the existing financial assets and liabilities, including upcoming un-accrued interest payments, and performs annual detailed budgeting procedures. The contractual maturities of the Company’s financial liabilities are presented below: Year ended December 31, 2020 (unaudited) On demand < 1 year 1 to 5 years > 5 years Total Loans and borrowings and other financial liabilities – 946 3,343 826 5,115 Lease liabilities – 29 72 197 298 Accounts payable to suppliers and contractors – 422 – – 422 Salary and related benefits payable – 111 – – 111 Current operating liabilities of subsidiary banks 205 523 7 – 735 Dividends payable – 1 – – 1 Other accounts payable – 42 – – 42 Derivative financial liabilities – 13 – – 13 Year ended December 31, 2019 On demand < 1 year 1 to 5 years > 5 years Total Loans and borrowings and other financial liabilities – 952 2,724 802 4,478 Lease liabilities – 32 68 188 288 Accounts payable to suppliers and contractors – 544 – – 544 Salary and other benefits payable – 102 – – 102 Current operating liabilities of subsidiary banks 91 352 38 – 481 Dividends payable – 1 – – 1 Other accounts payable – 19 – – 19 Derivative financial liabilities – 1 – – 1
7. Acquisitions and disposals of subsidiaries and joint arrangements 2020 (unaudited) Acquisition of “Taimyrneftegas” Group In December 2020, the Company completed the acquisition of JSC Taimyrneftegaz and its subsidiaries (“TNG”). TNG owns licenses for the use of subsurface resources at Payakha, Irkinsky and a number of less significant oilfields. Simultaneously, the Company entered into a series of sale transactions with several companies controlled by LLC Independent Oil and Gas Company – Holding (“IOC”) for the sale of a number of mature oil production and service assets, including PJSC Varioganneftegaz, LLC Severovarioganskoye, JSC Nizhnevartovsk Oil and Gas Production Enterprise, LLC RN – Sakhalinmorneftegaz, LLC RN-Severnaya Neft and a number of other assets (“tail assets”). The seller of TNG and the buyers of “tail” assets are the companies under common control. These transactions are recorded in these financial statements as linked in accordance with the criteria in IFRS 10 Consolidated Financial Statements. Thus, the consideration for TNG consists of a cash component (net US$ 9.6 billion), as well as the transferred “tail” assets measured at fair value. Due to the size of the business acquired, the complexity of the valuation of the business in early development stage, as well as the timing considerations (the transaction occurred immediately before the end of the reporting period), the assessment of the fair value of the assets acquired and liabilities assumed, as well as the fair value of the consideration transferred as of December 31, 2020 has not yet been completed by the Company at the date when these financial statements were authorized for issue. Allocation of the purchase price to the fair value of the assets acquired and liabilities assumed will be completed within 12 months from the acquisition date. The provisional fair value of the assets acquired and liabilities assumed was determined using the discounted cash flow method with a pre-tax dollar discount rate of 16%. The projected cash flows were based on proved and probable reserves volumes, as defined by Petroleum Resource Management System. The long-term netback oil price applied $51 / bbl. in real terms. The forecast presumes the commencement of production from 2024. It also presumes that capital expenditures for all the necessary transport infrastructure will be duly incured. The following table summarizes the Company’s preliminary allocation of the purchase price to the fair value of assets acquired and liabilities assumed: ASSETS Current assets Other current financial assets 12 Prepayments and other current assets 2 Total current assets 14 Non-current assets Exploration and evaluation assets 1,622 Other property, plant and equipment 8 Intangible assets 1 Total current assets 1,631 Total assets 1,645 LIABILITIES Non-current liabilities Deferred tax liabilities 318 Total non-current liabilities 318 Total liabilities 318 Total identifiable net assets at fair value 1,327 Cash consideration paid in 2020, net 615 Fair value of the assets disposed of in 2020 25 Cash consideration payable in 2021 101 Obligation to transfer the assets in 2021 82 Total consideration 823 Gain on bargain purchase 504
7. Acquisitions and disposals of subsidiaries and joint arrangements (continued) 2020 (unaudited) (continued) Gain on bargain purchase was recognized mainly due to the fact, that the seller apparently had little ability to commence a full scale development of the oil fields, taking into account the size of capital investments required. The TNG Group was acquired to become a part of the Vostok Oil project. Integration of Payakha field, licences for which are held by the TNG group, into the project will enable to significantly increase the project’s resource base. Apart from TNG, the Vostok Oil LLC has the following subsidiaries: JSC Vankorneft, JSC Suzun, LLC Tagulskoe, as well as a number of less significant assets. In December 2020, the Company entered into a deal to sell a 10% stake in Vostok Oil LLC for EUR 7 billion (Note 16). Had the “TNG” acquisition taken place at the beginning of the reporting period (January 1, 2020), revenues and net profit of the combined entity for the twelve months ended December 31, 2020 would have been RUB 5,759 billion and RUB 179 billion, respectively. Sale of a share in oil producing projects in Eastern Siberia In December 2020, the Company completed the deal, whereby a Norwegian company Equinor acquired 49% in the Company’s subsidiary KrasGeoNaz LLC. KrasGeoNaz LLC holds twelve exploration and production licenses in Eastern Siberia. As a result of the deal, the Company recorded the sale of the subsidiary together with the recognition of investment in a joint venture, accounted for using equity method (Note 27). The cash consideration received from Equinor amounted to EUR 434 million (RUB 38 billion at the official exchange rate of the Central Bank on the date of cash received). As a result of retained interest remeasured at its fair value, the Company recorded a gain of RUB 7 billion in other income. The acquisition of a 100% stake in “Taimyrburservice” LLC In December 2020, the acquisition of 100% share in Taimyrburservice LLC (“TBS”) from an individual was finalized. The acquisition price amounted to USD 245 million (RUB 18.3 billion at the date of payment). The acquisition of TBS is aimed at the development of Vostok Oil project. As of December 31, 2020 the Company has not yet completed the assessment of the fair value of the assets acquired and liabilities assumed. Allocation of the purchase price to the fair value of the assets acquired and liabilities assumed will be completed within 12 months from the acquisition date.
7. Acquisitions and disposals of subsidiaries and joint arrangements (continued) 2020 (unaudited) (continued) The following table summarizes the Company’s preliminary allocation of the purchase price to the fair value of assets acquired and liabilities assumed: ASSETS Current assets Inventories 2 Total current assets 2 Non-current assets Property, plant and equipment 22 Total non-current assets 22 Total assets 24 LIABILITIES Current liabilities Accounts payable and accrued liabilities 1 Other tax liabilities 1 Total current liabilities 2 Non-current liabilities Deferred tax liabilities 4 Total non-current liabilities 4 Total liabilities 6 Identifiable net assets at fair value 18 Cash consideration transferred 18 Total consideration 18 Goodwill ‒ Had the “TBS” acquisition taken place at the beginning of the reporting period (January 1, 2020), revenues and net profit of the combined entity for the twelve months ended December 31, 2020 would have been RUB 5,758 billion and RUB 176 billion, respectively. Disposals of assets in Venezuela On April 30, 2020 the Company closed a previously announced transaction to transfer all assets in Venezuela to a company 100% owned by the Government of the Russian Federation, including interests in Petromonagas, Petroperija, Boqueron, Petromiranda and Petrovictoria exploration and production entities, as well as in oilfield services companies, commercial and trading operations. The Company’s operations in Venezuela have been completely discontinued. As a result of the transaction, a 100% subsidiary of the Company became the owner of 9.6% of the registered ordinary shares of Rosneft (Note 36). The above mentioned transaction under common control was recorded in the consolidated financial statements of the Company by charging the Statement of profit or loss with the difference between the fair market value at the date of transaction of the treasury shares received, and the carrying value of the disposed assets and investments in Venezuela at the same date.
7. Acquisitions and disposals of subsidiaries and joint arrangements (continued) 2020 (unaudited) (continued) The effects of the transaction on the Company’s financial statements are summarized below (in billions of RUB): Treasury shares (decrease in share capital) 342 Reclassification of the foreign exchange differences (decrease in equity) 23 Deferred tax on foreign exchange differences 1 366 Less: carrying amount of investments and other assets transferred (369) Net result recorded in the statement of profit or loss (3) 25% of the assets disposed of relates to Exploration and production segment, 75% – to Refining and distribution segment. The net result of the transaction is included in Other expenses in the Consolidated statement of profit or loss for the ended December 31, 2020 (Note 13). Acquisitions of 2019 Acquisition of additional interest in LLC “Sibintek” In December 2019 the Company acquired 49.5132% shares in LLC “Sibintek” (“Sibintek”). The cash consideration paid amounted to RUB 842 million. As a result of increasing its ownership interest up to 98.5% the Company obtained control over “Sibintek” as defined in IFRS 10 Consolidated Financial Statements. “Sibintek” is a provider of IT services.
7. Acquisitions and disposals of subsidiaries and joint arrangements (continued) Acquisitions of 2019 (continued) The following table summarizes the Company’s final allocation of the purchase price to the fair value of assets acquired and liabilities assumed: ASSETS Current assets Cash and cash equivalents 2 Accounts receivable 1 Inventories 5 Prepayments and other current assets 2 Total current assets 10 Non-current assets Property, plant and equipment 7 Intangible assets 2 Total non-current assets 9 Total assets 19 LIABILITIES Current liabilities Accounts payable and accrued liabilities 15 Other tax liabilities 2 Total current liabilities 17 Non-current liabilities Deferred tax liabilities 1 Total non-current liabilities 1 Total liabilities 18 Identifiable net assets at fair value 1 Fair value of cash consideration transferred 1 Investment in associate – Consideration transferred to be included for the purpose of goodwill 1 Excluding identifiable net assets (1) Goodwill – Cash flows arising on the acquisition: Cash acquired as a result of the acquisition 2 Cash paid 1 Net cash inflow 1 Had the LLC “Sibintek” acquisition taken place at the beginning of the reporting period (January 1, 2019), revenues and net income of the combined entity would have been RUB 8,678 billion and RUB 804 billion, respectively, for the year ended December 31, 2019. As of January 13, 2020 the Company acquired the additional 1.5% of Sibintek shares for RUB 25.5 mln increasing the Company’s ownership interest in Sibintek to 100%.
7. Acquisitions and disposals of subsidiaries and joint arrangements (continued) Acquisitions of 2019 (continued) Acquisition of 100% shares in the entities of “Petersburg Fuel Company” group In July 2019 Company completed the acquisition of 100% shares in “Petersburg Fuel Company” group (“PTK”). Fair value of consideration amounted to RUB 13 billion, including contingent consideration. The acquisition of PTK is in line with the Company’s strategy aimed at developing the retail business and expanding its presence in key regions of the country. As of June 30, 2020 the Company finalized the assessment of the fair values of assets acquired and liabilities assumed. The finalized allocation of the purchase price to the fair value of assets acquired and liabilities assumed is summarized below: ASSETS Current assets Accounts receivable and other assets 1 Total current assets 1 Non-current assets Property, plant and equipment 8 Total non-current assets 8 Total assets 9 LIABILITIES Current liabilities Accounts payable and accrued liabilities 1 Loans and borrowings and other financial liabilities 1 Total current liabilities 2 Non-current liabilities Loans and borrowings and other financial liabilities 1 Deferred tax liabilities 1 Total non-current liabilities 2 Total liabilities 4 Total identifiable net assets at fair value 5 Total consideration transferred 13 Goodwill 8 As a result of the PTK acquisition, the Company became the largest player in the North-West region, and a major retail network with an even geographical distribution of gas stations has been formed. Better conditions have been created for the development and synergy of the Company’s retail business in the North-West region, due to attracting large corporate clients, the effectiveness of marketing programs for individuals, as well as increasing the profitability of the related businesses. Had the PTK acquisition taken place at the beginning of the reporting period (January 1, 2019), revenues and net profit of the combined entity for the twelve months ended December 31, 2019 would have been RUB 8,680 billion and RUB 803 billion, respectively.
7. Acquisitions and disposals of subsidiaries and joint arrangements (continued) Acquisitions of 2019 (continued) The effects of final purchase price allocation to the fair value of assets acquired and liabilities assumed on the consolidated balance sheet of the Company at December 31, 2019 are summarized below: Provisional allocation December 31, 2019 Changes Final allocation December 31, 2019 ASSETS Total current assets 2,396 – 2,396 Non-current assets Property, plant and equipment 8,713 (7) 8,706 Right-of-use assets 160 – 160 Intangible assets 69 (3) 66 Other long-term financial assets 229 – 229 Investments in associates and joint ventures 803 (2) 801 Bank loans granted 291 – 291 Deferred tax assets 33 – 33 Goodwill 85 8 93 Other non-current non-financial assets 171 – 171 Total non-current assets 10,554 (4) 10,550 Total assets 12,950 (4) 12,946 LIABILITIES AND EQUITY Total current liabilities 2,755 – 2,755 Non-current liabilities Loans and borrowings and other financial liabilities 3,033 – 3,033 Deferred tax liabilities 844 (1) 843 Provisions 343 – 343 Prepayment on long-term oil and petroleum products supply agreements 750 – 750 Other non-current liabilities 73 – 73 Total non-current liabilities 5,043 (1) 5,042 Total equity 5,152 (3) 5,149 Total liabilities and equity 12,950 (4) 12,946 8. Segment information The Company determines its operating segments based on the nature of their operations. The performance of these operating segments is assessed by management on a regular basis. The Exploration and production segment is engaged in field exploration and the production of crude oil and natural gas. The Refining and distribution segment is engaged in processing crude oil and other hydrocarbons into petroleum products, as well as in the purchase, sale and transportation of crude oil and petroleum products. Corporate and other unallocated activities are not part of any operating segment and include corporate activity, activities involved in field development, the maintenance of infrastructure and the functioning of the first two segments, as well as banking and finance services, and other activities. Substantially all of the Company’s operations and assets are located in the Russian Federation. Segment performance is evaluated based on both revenues and operating income, which are measured on the same basis as in the consolidated financial statements, but with intersegment transactions revalued at market prices.
8. Segment information (continued) The performance of the operating segments in 2020 (unaudited) is shown below: Exploration and production Refining and distribution Corporate and other unallocated activities Intercompany Consolidated Total revenues and equity share in profits of associates and joint ventures 3,057 5,821 230 (3,351) 5,757 Including: equity share in profits of associates and joint ventures 23 25 4 – 52 Costs and expenses Costs and expenses other than depreciation, depletion and amortization 2,019 5,775 273 (3,351) 4,716 Including: expenses due to COVID-19 pandemic 9 1 1 – 11 Depreciation, depletion and amortization 536 110 17 – 663 Total costs and expenses 2,555 5,885 290 (3,351) 5,379 Operating income/(loss) 502 (64) (60) – 378 Finance income – – 95 – 95 Finance expenses – – (220) – (220) Total finance expenses – – (125) – (125) Other income – – 533 – 533 Other expenses – – (463) – (463) Foreign exchange differences – – (163) – (163) Realized foreign exchange differences on hedge instruments – – 2 – 2 Income/(loss) before income tax 502 (64) (276) – 162 Income tax (expense)/benefit (96) 18 97 – 19 Net income/(loss) 406 (46) (179) – 181
8. Segment information (continued) The performance of the operating segments in 2019 is shown below: Exploration and production Refining and distribution Corporate and other unallocated activities Intercompany Consolidated Total revenues and equity share in profits of associates and joint ventures 4,781 8,641 172 (4,918) 8,676 Including: equity share in profits of associates and joint ventures 64 32 4 – 100 Costs and expenses Costs and expenses other than depreciation, depletion and amortization 2,912 8,460 230 (4,918) 6,684 Depreciation, depletion and amortization 560 113 14 – 687 Total costs and expenses 3,472 8,573 244 (4,918) 7,371 Operating income/(loss) 1,309 68 (72) – 1,305 Finance income – – 143 – 143 Finance expenses – – (227) – (227) Total finance expenses – – (84) – (84) Other income – – 11 – 11 Other expenses – – (156) – (156) Foreign exchange differences – – 64 – 64 Realized foreign exchange differences on hedge instruments – – (146) – (146) Income/(loss) before income tax 1,309 68 (383) – 994 Income tax (expense)/benefit (249) (7) 64 – (192) Net income/(loss) 1,060 61 (319) – 802 Segment assets: Exploration and production Refining and distribution Corporate and other unallocated activities Intercompany Consolidated Investments in associates and joint ventures As of December 31, 2020 (unaudited) 376 446 16 – 838 As of December 31, 2019 413 375 15 – 803 Additions to non-current assets In 2020 (unaudited) 2,623 108 37 – 2,768 In 2019 895 258 57 – 1,210 Additions to non-current assets include additions of property, plant and equipment, right-of-use assets, investments in associates and joint ventures, intangible assets.
8. Segment information (continued) Oil, gas, petroleum products and petrochemicals sales comprise the following (based on the country indicated in the bill of lading): 2020 (unaudited) 2019 International sales of crude oil, petroleum products and petrochemicals – non-CIS 3,672 6,126 International sales of crude oil, petroleum products and petrochemicals – CIS, other than Russia 190 335 Domestic sales of crude oil, petroleum products and petrochemicals 1,526 1,770 Sales of gas 240 259 Total oil, gas, petroleum products and petrochemicals sales 5,628 8,490 For the years ended December 31, 2020 and 2019 the Company had two external customers accounting for at least 10% of total revenues from sales. Revenues generated from sales to these customers amounted to 10.8% (RUB 616 billion) and 10.5% (RUB 601 billion) of total revenues from sales in 2020 and to 13.5% (RUB 1,157 billion) and 10.8% (RUB 926 billion) of total revenues from sales in 2019. These revenues are recognized under the Refining and distribution segment. The Company is not dependent on any of its customers or any one particular customer as there is a liquid market for crude oil and petroleum products. 9. Taxes other than income tax Taxes other than income tax for the years ended December 31 comprise the following: 2020 (unaudited) 2019 Mineral extraction tax 1,315 2,185 Excise tax 583 260 Property tax 40 40 Insurance contributions 85 75 Tax on additional income from production of hydrocarbons 90 96 Other 8 10 Total taxes other than income tax 2,121 2,666 10. Export customs duty Export customs duty for the years ended December 31 comprises the following: 2020 (unaudited) 2019 Export customs duty on oil sales 222 583 Export customs duty on petroleum products and petrochemicals sales 112 210 Total export customs duty 334 793
11. Finance income Finance income for the years ended December 31 comprises the following: 2020 (unaudited) 2019 Interest income on Financial assets carried: - at amortized cost 53 59 - at fair value through other comprehensive income 22 24 - at fair value through profit or loss 7 7 Long-term advances issued 4 21 Total interest income 86 111 Decrease in allowance for expected credit losses on debt financial assets carried: - at fair value through other comprehensive income 1 – - at amortised cost 1 1 Change in fair value of financial assets carried at fair value through profit or loss 4 21 Net gain from operations with derivative financial instruments – 4 Gain from disposal of financial assets – 1 Other finance income 3 5 Total finance income 95 143 12. Finance expenses Finance expenses for the years ended December 31 comprised the following: 2020 (unaudited) 2019 Interest expenses on Loans and borrowings (113) (111) Lease liability (6) (6) Prepayment on long-term oil and petroleum products supply agreements (Note 33) (42) (70) Other (14) (15) Total interest expenses (175) (202) Unwinding of discount (24) (19) Increase in allowance for expected credit losses on debt financial assets: - at fair value through other comprehensive income (3) (2) - at amortised cost (5) (3) Net loss from operations with derivative financial instruments (11) – Other finance expenses (2) (1) Total finance expenses (220) (227)
13. Other income and expenses Other income for the years ended December 31 comprises the following: 2020 (unaudited) 2019 Gain on bargain purchase (Note 7) 504 – Insurance recoveries 4 2 Other 25 9 Total other income 533 11 Other expenses for the years ended December 31 comprise the following: 2020 (unaudited) 2019 Impairment of assets (371) (77) Social payments, charity, financial aid (20) (21) Sale and disposal of property, plant and equipment and intangible assets (15) (16) Impairment of goodwill (11) – Other (46) (42) Total other expenses (463) (156) Impairment of assets As a result of the prevailing conditions in the hydrocarbon market in 2020, the Company recognized a number of impairments of property, plant and equipment and other assets. In the fourth quarter of 2020, the Company recognized an impairment loss of RUB 282 billion in relation to certain CGUs and individual oilfields in the Exploration and production segment. The recoverable amounts were determined as fair values based on discounted cash flows using the after-tax USD discount rate about 16%, long-term oil price of Brent $55/bbl and the oil production up to 2040. As a part of this impairment, the goodwill allocated to these CGUs and certain assets of the Exploration and production segment of RUB 11 billion was impaired as well. In the third quarter of 2020, the Company recognized an impairment loss of RUB 15 billion, which represents the write-down of certain properties, plant and equipment in the Exploration and production segment to their recoverable amounts. The recoverable amounts were determined at the level of several CGU’s based on their fair value. Previously, the above-mentioned assets were tested for impairment using the value-in-use method, and also individual assets (oilfields) were tested within the appropriate CGU. The shift in approach is due to a change in the Company’s plans in respect of these assets. The impairment loss in the amount of RUB 46 billion relates to the Refining and distribution segment and primarily represents the partial impairment of refining assets in Germany due to the decline in refining margins forecasts following COVID-19 situation. The recoverable amount of these assets for impairment testing purposes is determined based on the value-in-use, with a pre-tax discount rate of 5.4% in euro applied to the forecasted cash flows. An impairment loss of RUB 19 billion represents a write-down of the carrying amount of a number of assets as a result of the analysis of the Company’s exploration and evaluation assets portfolio. The remaining amount of impairment relates to a decrease in the recoverable amount of investments in certain joint ventures in the Exploration and production segment. The recoverable amount was determined at the CGU level based on its fair value.
14. Personnel expenses Personnel expenses for the years ended December 31 comprise the following: 2020 (unaudited) 2019 Salary 335 294 Statutory insurance contributions 87 76 Expenses on non-statutory defined contribution plan 10 12 Other employee benefits 20 20 Total personnel expenses 452 402 Personnel expenses are included in Production and operating expenses, General and administrative expenses and Other expenses in the consolidated statement of profit or loss. Due to COVID-19 pandemic the Company incurred additional expenses for salary and social insurance contributions of RUB 6 billion associated with forced downtime and employees stay under observation. 15. Income tax Income tax for the years ended December 31 comprise the following: 2020 (unaudited) 2019 Current income tax expense (102) (184) Deferred tax benefit/(expense) due to the origination and reversal of temporary differences 121 (8) Total income tax benefit/(expense) 19 (192) In 2012 the Company created a consolidated group of taxpayers (hereinafter “CGT”) which includes Rosneft and its subsidiaries. Rosneft became the responsible taxpayer of the CGT. At present, under the terms of the agreement the number of members in the consolidated group of taxpayers is 64. In 2020 and 2019, the Company’s subsidiaries domiciled in the Russian Federation applied the standard Russian income tax rate of 20%, except for those where regional tax relief is applied. The income tax rates applicable for subsidiaries incorporated in foreign jurisdictions are based on local regulations and vary from 0% to 34%.
15. Income tax (continued) Temporary differences between these consolidated financial statements and tax records gave rise to the following deferred income tax assets and liabilities: Consolidated balance sheet as of December 31, Consolidated statement of profit or loss for the years, ended December 31, 2020 (unaudited) 2019* 2020 (unaudited) 2019 Short-term accounts receivable 16 10 6 1 Property, plant and equipment 17 18 (1) 4 Short-term accounts payable and accrued liabilities 28 18 10 3 Loans and borrowings and other financial liabilities 9 1 7 (3) Lease liabilities 31 29 2 24 Provisions 17 12 5 (1) Tax loss carry forward 148 68 79 17 Other 32 27 3 4 Less: offset with deferred tax liabilities (244) (150) – – Deferred tax assets 54 33 111 49 Inventories (9) (10) 1 3 Property, plant and equipment (653) (643) (3) (21) Right-of-use assets (30) (32) 2 (24) Mineral rights (569) (258) 11 6 Intangible assets (5) (5) – 4 Investments in associates and joint ventures (8) (8) 1 – Other (42) (37) (2) (25) Less: offset with deferred tax assets 244 150 – – Deferred tax liabilities (1,072) (843) 10 (57) Deferred income tax (expense)/benefit 121 (8) Net deferred tax liabilities (1,018) (810) Recognized in the consolidated balance sheet as following Deferred tax assets 54 33 Deferred tax liabilities (1,072) (843) Net deferred tax liabilities (1,018) (810) * Deferred tax liabilities have been restated according to final allocation of the purchase price of “Petersburg Fuel Company” group (Note 7). The reconciliation of net deferred tax liabilities is as follows: 2020 (unaudited) 2019* As of January 1 (810) (809) Deferred tax benefit/(expense) recognized in the consolidated statement of profit or loss 121 (8) Acquisition of subsidiaries and shares in joint operations (Note 7) (322) (2) Disposal of subsidiaries 5 ‒ Deferred tax (expense)/benefit recognized in other comprehensive income (12) 9 As of December 31 (1,018) (810) * Deferred tax liabilities have been restated according to final allocation of the purchase price of “Petersburg Fuel Company” group (Note 7).
15. Income tax (continued) The reconciliation between actual income tax expense and theoretical income tax expense calculated as accounting profit multiplied by the 20% tax rate for the years ended December 31 is as follows: 2020 (unaudited) 2019 Income before income tax 162 994 Income tax at statutory rate of 20% (32) (199) Increase/(decrease) resulting from: Effect of change in unrecognized deferred tax assets (41) 1 Effect of income tax rates in other jurisdictions 7 3 Effect of special tax treatments (3) (5) Effect of income tax reliefs 13 17 Effect of equity share in profits of associates and joint ventures 10 18 Effect of tax on intercompany dividends (3) (3) Effect from goodwill impairment (2) – Effect from obtaining control over a subsidiary 100 – Effect from sale of shares in subsidiaries 5 – Effect of prior period adjustments (7) (1) Effect of non-taxable income and non-deductible expenses (28) (23) Total income tax benefit/(expense) 19 (192) Unrecognized deferred tax assets in the consolidated balance sheet for the years ended December 31, 2020 and 2019 amounted to RUB 77 billion and RUB 73 billion, respectively, related to unused tax losses. In respect of recognized deferred tax assets on tax losses carried forward management considers it probable that future taxable profits will be available for the Company against which these tax losses can be utilized. The total amount of temporary differences associated with investment in subsidiaries, for which deferred tax liabilities have not been recognized, amounted to RUB 2,042 billion as of December 31, 2020. According to Russian tax legislation undistributed profit of foreign subsidiaries recognized as controlled foreign companies may form an additional tax base for Rosneft (and for certain Russian subsidiaries holding investments in foreign entities). In particular, undistributed 2020 profits of controlled foreign companies are included in the Company’s tax base as of December 31, 2020 and recorded in the tax declaration. The consequences of taxation of controlled foreign companies are considered in the determination of current and deferred tax liabilities.
16. Non-controlling interests Non-controlling interests include: As of December 31, 2020 (unaudited) 2020 (unaudited) As of December 31, 2019 2019 Non- controlling interest (%) Non- controlling interest as of the end of the year Non- controlling interest in net (loss)/ income Non- controlling interest (%) Non- controlling interest as of the end of the year Non- controlling interest in net income PJSC Bashneft Oil Company 39.67 230 (10) 39.67 248 19 JSC Taimyrneftegas 10.00 133 – – – – JSC Vankorneft 54.91 124 13 49.90 120 29 LLC Taas-Yuriakh Neftegazodobycha 49.90 120 26 49.90 121 30 JSC Verkhnechonskneftegaz 20.04 47 6 20.04 49 9 LLC Kharampurneftegas 49.00 43 (1) 49.00 35 1 LLC Sorovskneft 39.67 25 1 39.67 24 3 PJSC Ufaorgsintez 42.66 18 – 42.66 18 – LLC Tagulskoe 10.00 14 – – – – JSC Suzun 10.00 13 – – – – Non-controlling interests in other entities various 14 (1) various 20 6 Total non-controlling interests 781 34 635 97 As of December 23, 2020 the Company closed a deal to sell a 10% share in JSC “Vostok Oil” for EUR 7 billion (RUB 644 billion at the exchange rate as of the cash receipt’ date). The key subsidiaries of JSC “Vostok Oil” are JSC “Taimyrneftegas” and LLC “NGH-Nedra”, acquired in December 2020 (Note 7), JSC “Vankorneft”, JSC “Suzun” and LLC “Tagulskoe”. The difference between the 10% of consolidated balance sheet value of net assets (RUB 175 billion) and the consideration received is recognized in additional paid-in capital. Other changes in non-controlling interests recognized in the consolidated statement of changes in equity relate mainly to contributions to assets to subsidiaries with non-controlling interests. The summarized financial information of subsidiaries that have material non-controlling interests is provided below. This information is presented before intercompany eliminations. Summarized statement of profit or loss for 2020 (unaudited) PJSC Bashneft Oil Company JSC Taimyr- neftegas JSC Vankorneft LLC Taas- Yuriakh Neftegazodobycha Revenues 500 – 236 114 Costs and other income and expenses (531) – (205) (53) (Loss)/income before income tax (31) – 31 61 Income tax benefit/(expense) 6 – (5) (10) Net (loss)/income (25) – 26 51 incl. attributable to non-controlling interests (10) – 13 26
16. Non-controlling interests (continued) Summarized statement of profit or loss for 2019 PJSC Bashneft Oil Company JSC Taimyr- neftegas JSC Vankorneft LLC Taas- Yuriakh Neftegazodobycha Revenues 768 – 383 135 Costs and other income and expenses (711) – (315) (60) Income before income tax 57 – 68 75 Income tax expense (12) – (11) (13) Net income 45 – 57 62 incl. attributable to non-controlling interests 19 – 29 30 Summarized balance sheet as at December 31, 2020 (unaudited) PJSC Bashneft Oil Company JSC Taimyr- neftegas JSC Vankorneft LLC Taas- Yuriakh Neftegazodobycha Current assets 766 19 73 40 Non-current assets 822 1,635 216 222 Total assets 1,588 1,654 289 262 Current liabilities 693 4 34 9 Non-current liabilities 226 324 39 30 Equity 669 1,326 216 223 Total equity and liabilities 1,588 1,654 289 262 incl. non-controlling interests 230 133 124 120 Dividends declared to non-controlling interests 7 – 30 18 Summarized balance sheet as at December 31, 2019 PJSC Bashneft Oil Company JSC Taimyr- neftegas JSC Vankorneft LLC Taas- Yuriakh Neftegazodobycha Current assets 916 – 70 41 Non-current assets 730 – 256 223 Total assets 1,646 – 326 264 Current liabilities 713 – 41 9 Non-current liabilities 219 – 35 29 Equity 714 – 250 226 Total equity and liabilities 1,646 – 326 264 incl. non-controlling interests 248 – 120 121 Dividends declared to non-controlling interests 11 – 52 28
17. Earnings per share For the years ended December 31 basic and diluted earnings per share comprise the following: 2020 (unaudited) 2019 Net income attributable to shareholders of Rosneft 147 705 Weighted average number of issued common shares outstanding (millions) 9,876 10,598 Total basic and diluted earnings per share (RUB) 14.88 66.52 18. Cash and cash equivalents Cash and cash equivalents comprise the following: As of December 31, 2020 (unaudited) 2019 Cash on hand and in bank accounts in RUB 56 14 Cash on hand and in bank accounts in foreign currencies 468 92 Deposits 273 109 Other 9 13 Total cash and cash equivalents 806 228 Cash accounts denominated in foreign currencies primarily comprise cash in U.S. dollars and euro. Deposits are interest bearing and denominated in RUB and U.S. dollars. Restricted cash includes the obligatory reserve of subsidiary banks with the CBR in the amount of RUB 17 billion and RUB 7 billion as of December 31, 2020 and 2019, respectively. 19. Other short-term financial assets Other short-term financial assets comprise the following: As of December 31, 2020 (unaudited) 2019 Financial assets at fair value through other comprehensive income Bonds 198 158 Promissory notes 116 151 Stocks and shares 47 46 Loans granted under reverse repurchase agreements 56 55 Financial assets at amortized cost Bonds 1 1 Loans issued 20 7 Loans issued to associates and joint ventures – 19 Deposits and certificates of deposit 363 60 Financial assets at fair value through profit or loss Deposits 1 1 Bonds 15 1 Derivative financial instruments – 2 Total other short-term financial assets 817 501
19. Other short-term financial assets (continued) As of December 31, 2020 and 2019 bonds and notes at fair value through other comprehensive income comprised the following: Type of security 2020 (unaudited) 2019 Balance Interest rate p.a. Date of maturity Balance Interest rate p.a. Date of maturity State and municipal bonds 25 2.5-12.66% 2021-2033 21 2.5-12.66% 2020-2033 Corporate bonds 173 2.95-14.25% 2021-2048 137 3.15-14.25% 2020-2029 Promissory notes 116 3.8-9.0% 2021-2025 151 3.8-9.0% 2020-2023 Total 314 309 Investments in stocks and shares within other short-term financial assets are not held for trading and were designated to the FVOCI category at initial application of IFRS 9 Financial Instruments, or at their initial recognition (in respect of stocks and shares acquired after January 1, 2018). As of December 31, 2020, deposits and certificates of deposit are denominated mainly in U.S. dollars and euros and earn interest from 0.4% to 3.7% p.a. Financial assets at amortized cost are presented net of allowance for expected credit losses in the amount of RUB 4 billion as of December 31, 2020. The allowance for expected credit losses on financial assets at fair value through other comprehensive income in the amount of RUB 10 billion as of December 31, 2020 is recognized in other comprehensive income. Set out below is the movement in the allowance for expected credit losses on other short-term financial assets: As of January 1, 2020 (unaudited) Increase in allowance Decrease in allowance Reclassifica- tion As of December 31, 2020 (unaudited) Loss allowance at an amount equal to 12-month expected credit losses: - on financial assets at fair value through other comprehensive income 8 3 (1) – 10 - on financial assets at amortized cost 1 1 – – 2 Loss allowance at an amount equal to lifetime expected credit losses: - on financial assets at amortized cost 2 – – – 2 As of December 31, 2020 the Company has no financial assets, which were credit-impaired at initial recognition. 20. Accounts receivable Accounts receivable include the following: As of December 31, 2020 (unaudited) 2019 Trade receivables 497 678 Other accounts receivable 55 37 Total 552 715 Allowance for expected credit losses (84) (95) Total accounts receivable, net of allowance 468 620
20. Accounts receivable (continued) As of December 31, 2020 and 2019 accounts receivable were not pledged as collateral for loans and borrowings provided to the Company, except as discussed in Note 30. Set out below is the movement in the allowance for expected credit losses on accounts receivable: As of January 1, 2020 (unaudited) Increase in allowance Decrease in allowance As of December 31, 2020 (unaudited) Allowance at an amount equal to 12-month expected credit losses on trade receivables 47 13 (44) 16 Allowance at an amount equal to lifetime expected credit losses on trade receivables 27 13 – 40 Allowance for expected credit losses on other accounts receivable 21 19 (12) 28 Total 95 45 (56) 84 Due to overall high credit quality and short-term nature of trade receivables, the allowance for expected credit losses for significant counterparties is determined based on 12-month expected credit losses. The Company has no trade receivables that were credit impaired upon initial recognition. Allowance at the amount equal to lifetime expected credit losses was recognized during the reporting period due to occurrence of credit impairment of an asset, which was not credit impaired upon initial recognition. There was no significant deterioration in the credit quality of trade and other accounts receivable due to COVID-19 pandemic. Uncertainties due to COVID-19 pandemic may exist in the future, and as a result, actual losses may differ from expected credit losses on accounts receivable. 21. Inventories Inventories comprise the following: As of December 31, 2020 (unaudited) 2019 Crude oil and gas 86 135 Petroleum products and petrochemicals 145 186 Materials and supplies 130 117 Total inventories 361 438 Petroleum products and petrochemicals include those designated both for sale and for own use. For the years ended December 31: 2020 (unaudited) 2019 Cost of inventories recognized as an expense during the period 827 1,669 The cost of inventories recognized as expense during the period is included in Production and operating expenses, Cost of purchased oil, gas, petroleum products and refining costs and General and administrative expenses in the consolidated statement of profit or loss. As of March 31, 2020 following a significant decrease in oil prices, the cost of inventories were written down to the lower of cost or net realizable value, with the resulting expense recognized within “Production and operating expenses” in the consolidated statement of profit or loss in the amount of RUB 16 billion.
22. Prepayments and other current assets Prepayments and other current assets comprise the following: As of December 31, 2020 (unaudited) 2019 Value added tax and excise receivable 161 183 Prepayments to suppliers: 124 209 - Current portion of long-term prepayments issued 5 64 Settlements with customs 13 34 Profit and other tax payments 15 35 Other 9 8 Total prepayments and other current assets 322 469 Settlements with customs primarily represent export duties related to the export of crude oil and petroleum products (Note 10). 23. Property, plant and equipment Exploration and production Refining and distribution Corporate and other unallocated activities Total Cost as of January 1, 2019 9,709 2,334 154 12,197 Depreciation, depletion and impairment losses as of January 1, 2019 (3,176) (598) (54) (3,828) Net book value as of January 1, 2019 6,533 1,736 100 8,369 Prepayments for property, plant and equipment as of January 1, 2019 9 15 29 53 Total as of January 1, 2019 6,542 1,751 129 8,422 Cost Acquisitions of subsidiaries and shares in joint operations (Note 7) – 8 7 15 Additions 874 112 8 994 Including capitalized expenses on loans and borrowings 130 45 – 175 Disposals and other movements (43) (6) (14) (63) Foreign exchange differences (94) (29) (2) (125) Cost of asset retirement (decommissioning) obligations 94 – – 94 As of December 31, 2019 10,540 2,419 153 13,112 Depreciation, depletion and impairment losses Depreciation and depletion charge (556) (95) (9) (660) Disposals and other movements 19 6 6 31 Impairment of assets (2) (61) – (63) Foreign exchange differences 43 5 2 50 As of December 31, 2019 (3,672) (743) (55) (4,470) Net book value as of December 31, 2019 6,868 1,676 98 8,642 Prepayments for property, plant and equipment as of December 31, 2019 17 13 34 64 Total as of December 31, 2019 6,885 1,689 132 8,706
23. Property, plant and equipment (continued) Exploration and production Refining and distribution Corporate and other unallocated activities Total Cost as of January 1, 2020 (restated) (unaudited) 10,537 2,419 156 13,112 Depreciation, depletion and impairment losses as of January 1, 2020 (restated) (unaudited) (3,670) (743) (57) (4,470) Net book value as of January 1, 2020 (restated) (unaudited) 6,867 1,676 99 8,642 Prepayments for property, plant and equipment as of January 1, 2020 17 13 34 64 Total as of January 1, 2020 (restated) (unaudited) 6,884 1,689 133 8,706 Cost Acquisitions of subsidiaries (Note 7) 1,652 – – 1,652 Additions 846 92 21 959 Including capitalized expenses on loans and borrowings 124 38 – 162 Disposals and other movements (628) (17) (7) (652) Foreign exchange differences 156 61 2 219 Cost of asset retirement (decommissioning) obligations 73 – – 73 As of December 31, 2020 (unaudited) 12,636 2,555 172 15,363 Depreciation, depletion and impairment losses Depreciation and depletion charge (531) (97) (10) (638) Disposals and other movements 515 7 2 524 Impairment of assets (305) (45) – (350) Foreign exchange differences (75) (14) (2) (91) As of December 31, 2020 (unaudited) (4,066) (892) (67) (5,025) Net book value as of December 31, 2020 (unaudited) 8,570 1,663 105 10,338 Prepayments for property, plant and equipment as of December 31, 2020 21 41 1 63 Total as of December 31, 2020 (unaudited) 8,591 1,704 106 10,401 The cost of construction in progress included in property, plant and equipment was RUB 4,460 billion and RUB 2,640 billion as of December 31, 2020 and 2019, respectively. Cost, Depreciation, depletion and impairment losses, Net book value as of January 1, 2019 include the effects of the initial application of IFRS 16 Leases (Note 24). As of January 1, 2020, certain items of property, plant and equipment were reallocated between segments Exploration and production and Corporate and other activities due to the changes in the management structure. The depreciation charge includes depreciation which was capitalized as part of the construction cost of property, plant and equipment and the cost of inventory in the amount of RUB 14 billion and RUB 14 billion for the years ended December 31, 2020 and 2019, respectively. The Company capitalized RUB 162 billion (including RUB 131 billion in capitalized interest expense) and RUB 175 billion (including RUB 158 billion in capitalized interest expense) of expenses on loans and borrowings in 2020 and 2019, respectively.
23. Property, plant and equipment (continued) During 2020 and 2019 the Company received government grants for capital expenditures in the amount of RUB 3 billion and RUB 8 billion, respectively. Grants are accounted for as a reduction to the cost of additions in the Exploration and production segment. The weighted average rates used to determine the amount of borrowing costs eligible for capitalization are 5.50% and 7.00% p.a. in 2020 and 2019, respectively. Exploration and evaluation assets Exploration and evaluation assets included in the Exploration and production segment, including mineral rights to unproved properties, comprise the following: 2020 (unaudited) 2019 Cost as of January 1 420 397 Impairment losses as of January 1 (15) (17) Net book value as of January 1 405 380 Cost Disposal of subsidiaries (Note 7) (27) – Acquisition of subsidiaries (Note 7) 1,622 – Capitalized expenditures 68 53 Reclassified to development assets (15) (14) Expensed (6) (4) Foreign exchange differences 13 (12) As of December 31 2,075 420 Impairment losses Accrual of impairment reserve (22) (1) Foreign exchange differences 1 3 As of December 31 (36) (15) Net book value as of December 31 2,039 405 Provision for asset retirement (decommissioning) obligations The cost of asset retirement (decommissioning) obligations was RUB 222 billion and RUB 161 billion as of December 31, 2020 and 2019, respectively, and was included in Property, plant and equipment. Discount rate, applied for asset retirement obligations calculation decreased by 0.9%.
24. Lease agreements Set out below is the movement in the right-of-use assets for 2019: Exploration and production Refining and distribution Corporate and other unallocated activities Total Cost as of January 1, 2019 67 82 37 186 Depreciation and impairment losses as of January 1, 2019 (27) (14) (1) (42) Net book value as of January 1, 2019 40 68 36 144 Cost Acquisitions of subsidiaries and shares in joint operations (Note 7) – – – – Additions 15 5 28 48 Disposals and other movements (2) (2) (1) (5) Foreign exchange differences (1) – – (1) Cost of asset retirement (decommissioning) obligations – – – – As of December 31, 2019 79 85 64 228 Depreciation and impairment losses Depreciation charge (15) (8) (4) (27) Disposals and other movements 1 (2) 1 – Impairment of assets – – – – Foreign exchange differences 1 – – 1 As of December 31, 2019 (40) (24) (4) (68) Net book value as of December 31, 2019 39 61 60 160 Set out below is the movement in the right-of-use assets for 2020 (unaudited): Exploration and production Refining and distribution Corporate and other unallocated activities Total Cost as of December 31, 2019 79 85 64 228 Depreciation and impairment losses as of January 1, 2020 (40) (24) (4) (68) Net book value as of December 31, 2019 39 61 60 160 Cost Acquisitions of subsidiaries and shares in joint operations (Note 7) – – – – Additions 26 7 5 38 Disposals and other movements (10) (4) (2) (16) Foreign exchange differences 2 1 1 4 Cost of asset retirement (decommissioning) obligations – – – – As of December 31, 2020 97 89 68 254 Depreciation and impairment losses Depreciation charge (19) (10) (5) (34) Disposals and other movements 4 1 – 5 Impairment of assets – – – – Foreign exchange differences (1) (1) – (2) As of December 31, 2020 (56) (34) (9) (99) Net book value as of December 31, 2020 41 55 59 155
24. Lease agreements (continued) Set out below is the movement of lease liabilities for 2019 and 2020 (unaudited): As of January 1, 2019 Additions and other movements Interest expense Foreign exchange differences Payments As of December 31, 2019 Lease liabilities 130 46 12 (5) (37) 146 As of December 31, 2019 Additions and other movements Interest expense Foreign exchange differences Payments As of December 31, 2020 Lease liabilities 146 27 12 12 (40) 157 Within the income statement for 2020 the following expenses were recognized: expenses related to land leases for exploration and production purposes as well as leases of wells (RUB 2 billion), short-term lease expenses (RUB 7 billion), low value lease expenses and non-lease components of leases (RUB 1 billion). Variable lease payment expenses for the period were not material. The range of discount rates applied in calculating right-of-use assets and related lease liabilities, depending on the lease term, is presented below for the main contracting currencies: As of December 31, 2019 As of December 31, 2020 (unaudited) Ruble 6.46-7.77% 5.04-6.99% US dollar 2.66-5.11% 1.52-3.40% The total cash outflow under leases, including cash payments under contracts outside the scope of IFRS 16 (exceptions and practical expedients listed above) amounted to RUB 50 billion in 2020 (unaudited). The future cash outflows relating to leases that have not yet commenced are disclosed in Note 40.
25. Intangible assets and goodwill Intangible assets and goodwill comprise the following: Development cost Сomputer software Other intangible assets Total intangible assets Goodwill Cost as of January 1, 2019 8 32 44 84 85 Amortization as of January 1, 2019 (1) (15) (11) (27) – Net book value as of January 1, 2019 7 17 33 57 85 Cost Additions – 15 6 21 – Additions – internal developments 2 – – 2 – Acquisition of subsidiaries (Note 7) – 2 – 2 8 Disposals – (1) – (1) – Foreign exchange differences – – (1) (1) – As of December 31, 2019 10 48 49 107 93 Amortization Amortization charge – (5) (10) (15) – Disposal of amortization – – 1 1 – Foreign exchange differences – – – – – As of December 31, 2019 (1) (20) (20) (41) – Net book value as of December 31, 2019 9 28 29 66 93 Cost as of January 1, 2020 10 48 49 107 93 Amortization as of January 1, 2020 (1) (20) (20) (41) – Net book value as of January 1, 2020 (unaudited) 9 28 29 66 93 Cost Additions – 6 11 17 – Additions – internal developments 3 – 4 7 – Acquisition of subsidiaries (Note 7) – – 1 1 – Disposals (1) – (1) (2) (11) Foreign exchange differences – – 1 1 – As of December 31, 2020 (unaudited) 12 54 65 131 82 Amortization Amortization charge – (2) (8) (10) – Disposal of amortization – – – – – Foreign exchange differences – – – – – As of December 31, 2020(unaudited) (1) (22) (28) (51) – Net book value as of December 31, 2020 (unaudited) 11 32 37 80 82
25. Intangible assets and goodwill (continued) December 31, 2020 (unaudited) December 31, 2019 Goodwill Exploration and production 74 85 Refining and distribution 8 8 Total 82 93 The Company performs its annual goodwill impairment test as of October 1 of each year. The impairment test was carried out at the beginning of the fourth quarter of each year using the data that was appropriate at that time. Due to the excess of value in use over identified net assets for both the Exploration and production segment and the Refining and distribution segment no impairment of goodwill was identified in 2020. The Company estimates the value in use of the operating segments using a discounted cash flow model. Future cash flows are adjusted for risks specific to each segment and discounted using a rate that reflects current market assessments of the time value of money and the risks specific to each segment, for which the future cash flow estimates have not been adjusted. The Company’s business plan, approved by the Company’s Board of Directors, is the primary source of information for the determination of the operating segments’ value in use. The business plan contains internal forecasts of oil and gas production, refinery throughputs, revenues, operating and capital expenditures. As an initial step in the preparation of these plans, various assumptions, such as concerning crude oil and natural gas prices, ruble exchange rate and cost inflation rates, are set. These assumptions take into account the current prices, U.S. dollar and RUB inflation rates, other macroeconomic factors and historical trends, as well as market volatility. In determining the value in use for the Exploration and production operating segment, twelve-year period cash flows calculated on the basis of the Company management’s forecasts are discounted and aggregated with the segment’s terminal value. The use of a forecast period longer than five years originates from the industry’s average investment cycle. In determining the value in use for the Refining and distribution operating segment, five-year period cash flows calculated on the basis of the Company management’s forecasts are discounted and aggregated with the segment’s terminal value. For the calculation of the terminal value of the Company’s segments in the post-outlook period the Gordon model is used. Key assumptions applied to the calculation of value in use Discounted cash flows are most sensitive to changes in the following factors: • Oil prices. For the purposes of the impairment testing the Urals oil price was forecasted as follows: RUB 3.3 thousand per barrel, RUB 3.4 thousand per barrel, RUB 3.5 thousand per barrel for 2021, 2022 and 2023, respectively, and RUB 3.6 per barrel from 2024 onwards. • Production and sales volumes. Estimated production and sales volumes were based on the business plan. • The discount rates. The discount rate calculation is based on the Company’s weighted average cost of capital adjusted to reflect the pre-tax discount rate and the discount rate was 8.6% p.a. and 6.4% p.a. for the Exploration and production segment and for the Refining and distribution segment, respectively. In 2020 a part of goodwill relating to the impaired properties, plant and equipment of the Exploration and production segment was written off (Note 13). As of December 31, 2020 and 2019 the Company did not have any intangible assets with indefinite useful lives. As of December 31, 2020 and 2019 no intangible assets have been pledged as collateral.
26. Other long-term financial assets Other long-term financial assets comprise the following: As of December 31, 2020 (unaudited) 2019 Financial assets at fair value through other comprehensive income Shares and participating interests 37 21 Financial assets at amortized cost Bonds 26 26 Loans granted 22 18 Loans granted to associates and joint ventures 6 12 Deposits and certificates of deposit 25 20 Other accounts receivable 13 10 Financial assets at fair value through profit or loss Deposits 144 122 Other 2 – Total other long-term financial assets 275 229 Bank deposits are denominated in rubles, U.S. dollars and euros and earn interest from 1.5% to 8.75% p.a. Bonds mainly include federal loan bonds. No long-term financial assets were pledged as collateral as of December 31, 2020 and 2019. Set out below is the movement in the allowance for expected credit losses on other long-term financial assets: As of January 1, 2020 (unaudited) Increase in allowance Decrease in allowance Reclas- sification As of December 31, 2020 (unaudited) Allowance at an amount equal to 12-month expected credit losses: - on financial assets at amortized cost 1 – (1) – – Allowance at an amount equal to lifetime expected credit losses: - on financial assets at amortized cost 15 4 – – 19 As of December 31, 2020 the Company has no financial assets, which were credit-impaired at initial recognition.
27. Investments in associates and joint ventures Investments in associates and joint ventures comprise the following: Core activity Company’s share as of December 31, 2020, % As of December 31, Name of investee Country 2020 (unaudited) 2019 Joint ventures PJSC NGK Slavneft Russia Exploration and production 49.96 172 175 Kurdistan Pipeline Company Pte. Ltd Singapore Logistics 60.00 152 123 Petromonagas S.A. Venezuela Exploration and production – – 24 Taihu Ltd (OJSC Udmurtneft) Cyprus Exploration and production 51.00 84 75 Messoyahaneftegaz JSC Russia Exploration and production 50.00 57 50 KrasGeoNaz LLC (note 7) Russia Exploration and production 51.00 35 – Petrovictoria S.A. Venezuela Exploration and production – – 28 National Oil Consortium LLC Venezuela Exploration and production – – 25 TZK Vnukovo Russia Distribution 50.00 18 17 Arktikshelfneftegaz JSC Russia Exploration and production 50.00 1 2 SIA ITERA Latvija Latvia Holding company 66.00 3 2 Other various various 18 16 Associates Nayara Energy Limited India Refining and distribution 49.13 255 219 Purgaz CJSC Russia Exploration and production 49.00 28 27 Petrocas Energy International Ltd Cyprus Logistics 49.00 11 10 Nizhnevartovskaya TPP JSC Russia Power plant 25.01 4 3 Other various various 8 5 Total associates and joint ventures 846 801 In respect of associates and joint ventures, where the Company’s share exceeds 50%, the Company does not have an ability to solely direct their relevant activities. Set out below is the movement in the investments in associates and joint ventures: Joint ventures Associates Total As of January 1, 2020 537 264 801 Equity share in profits of associates and joint ventures 50 2 52 Dispose of investments (74) – (74) Dividends accrued (32) – (32) Impairment (19) – (19) Decrease of interest in subsidiary 35 – 35 Acquisition of interest and additional capital contribution to the associates and joint ventures 2 2 4 Foreign exchange differences on translation of foreign operations 41 39 80 Equity share in other comprehensive loss of associates – (1) (1) As of December 31, 2020 (unaudited) 540 306 846
27. Investments in associates and joint ventures (continued) The equity share in profits/(losses) of associates and joint ventures comprised the following: Company’s share as of December 31, 2019, % Share in income/(loss) of equity investees 2020 (unaudited) 2019 Messoyahaneftegaz JSC 50.00 17 30 Petromonagas S.A. – 1 5 PJSC NGK Slavneft 49.96 (3) 8 Taihu Ltd 51.00 9 19 Kurdistan Pipeline Company Pte. Ltd 60.00 23 25 Other various 5 13 Total equity share in profits of associates and joint ventures 52 100 The unrecognized share of losses of associates and joint ventures comprised the following: Name of investee As of December 31, 2020 (unaudited) 2019 LLC Veninneft 2 2 LLP Adai Petroleum Company 9 8 Boqueron S.A. – 2 Petroperija S.A. – 4 Total unrecognized share of losses of associates and joint ventures 11 16 Summarized financial information of significant associates and joint ventures as of December 31, 2020 and 2019 is presented below: Nayara Energy Limited As of December 31, 2020 (unaudited) 2019 Cash 62 28 Other current assets 119 105 Non-current assets 404 369 Total assets 585 502 Current financial liabilities (68) (34) Other current liabilities (236) (161) Non-current financial liabilities (75) (87) Other non-current liabilities (175) (191) Total liabilities (554) (473) Net assets 31 29 The Company’s share, % 49.13 49.13 The Company’s total share in net assets 15 14 Goodwill 240 205 Total 255 219
27. Investments in associates and joint ventures (continued) Nayara Energy Limited 2020 (unaudited) 2019 Revenues 855 923 Finance expenses (22) (26) Depreciation, depletion and amortization (24) (23) Other expenses (815) (873) (Loss)/income before tax (6) 1 Income tax 7 8 Net income 1 9 The Company’s share, % 49.13 49.13 The Company’s total share in net income – 4 The Company’s total share in other comprehensive loss (1) (4) The Company’s share in total comprehensive loss (1) – 2020 (unaudited) 2019 As of January 1 219 251 Equity share in net income – 4 Foreign exchange differences on translation of foreign operations 37 (32) Equity share in other comprehensive loss (1) (4) As of December 31 255 219 The Company’s share in contingent liabilities as of December 31, 2020 amounted to RUB 29 billion. As of December 31, PJSC NGK Slavneft 2020 (unaudited) 2019 Cash 2 3 Other current assets 48 97 Non-current assets 559 513 Total assets 609 613 Current financial liabilities (30) (21) Other current liabilities (48) (67) Non-current financial liabilities (119) (122) Other non-current liabilities (68) (53) Total liabilities (265) (263) Net assets 344 350 The Company’s share, % 49.96 49.96 The Company’s total share in net assets 172 175
27. Investments in associates and joint ventures (continued) PJSC NGK Slavneft 2020 (unaudited) 2019 Revenues 175 316 Finance income – 1 Finance expenses (13) (12) Depreciation, depletion and amortization (44) (48) Other expenses (124) (232) (Loss)/income before tax (6) 25 Income tax – (9) Net (loss)/income (6) 16 The Company’s share, % 49.96 49.96 The Company’s total share in net (loss)/income (3) 8 The Company’s share in total comprehensive (loss)/income (3) 8 2020 (unaudited) 2019 As of January 1 175 167 Equity share in net (loss)/income (3) 8 As of December 31 172 175 As of December 31, Messoyahaneftegaz JSC 2020 (unaudited) 2019 Current assets 32 27 Non-current assets 223 204 Total assets 255 231 Current financial liabilities (17) (99) Other current liabilities (21) (16) Non-current financial liabilities (85) – Other non-current liabilities (18) (16) Total liabilities (141) (131) Net assets 114 100 The Company’s share, % 50.00 50.00 The Company’s total share in net assets 57 50 Messoyahaneftegaz JSC 2020 (unaudited) 2019 Revenues 98 141 Finance expenses (5) (7) Depreciation, depletion and amortization (21) (16) Other expenses (30) (47) Income before tax 42 71 Income tax (7) (12) Net income 35 59 The Company’s share, % 50.00 50.00 The Company’s total share in net income 17 30 The Company’s share in total comprehensive income 17 30
27. Investments in associates and joint ventures (continued) 2020 (unaudited) 2019 As of January 1 50 37 Equity share in net income 17 30 Accrued dividends (10) (17) As of December 31 57 50 As of December 31, Kurdistan Pipeline Company Pte. Ltd 2020 (unaudited) 2019 Current assets 31 17 Non-current assets 223 196 Total assets 254 213 Current liabilities (1) (8) Non-current liabilities – – Total liabilities (1) (8) Net assets 253 205 The Company’s share, % 60.00 60.00 The Company’s total share in net assets 152 123 Kurdistan Pipeline Company Pte. Ltd 2020 (unaudited) 2019 Revenues 15 11 Finance income 27 44 Finance expenses – – Depreciation, depletion and amortization – – Other expenses (3) (2) Income before tax 39 53 Income tax – – Net income 39 53 The Company’s share, % 60.00 60.00 The Company’s total share in net income 23 32 The Company’s share in total comprehensive income 23 32 2020 (unaudited) 2019 As of January 1 123 – Acquisition of interest and additional capital contribution – 128 Equity share in net income 23 25 Accrued dividends (20) (19) Foreign exchange differences on translation of foreign operations 26 (11) As of December 31 152 123
27. Investments in associates and joint ventures (continued) In January 2019 part of the long-term advances issued in 2017 amounting to RUB 128 billion (including accrued interest) was reclassified as the Company’s capital contribution to the joint venture, which operates the oil pipeline in Iraqi Kurdistan. As of December 31, Taihu Ltd 2020 (unaudited) 2019 Cash 10 41 Other current assets 15 19 Non-current assets 177 127 Total assets 202 187 Current liabilities (14) (20) Non-current financial liabilities – (1) Other non-current liabilities (23) (19) Total liabilities (37) (40) Net assets 165 147 The Company’s share, % 51.00 51.00 The Company’s total share in net assets 84 75 Taihu Ltd 2020 (unaudited) 2019 Revenues 89 145 Finance income 5 4 Finance expenses (1) (2) Depreciation, depletion and amortization (6) (6) Other expenses (67) (110) Income before tax 20 31 Income tax (3) (6) Net income 17 25 The Company’s share, % 51.00 51.00 The Company’s total share in net income 9 13 The Company’s share in total comprehensive income 9 13 2020 (unaudited) 2019 As of January 1 75 58 Equity share in net income 9 19 Foreign exchange differences on translation of foreign operations – (2) As of December 31 84 75
28. Other non-current non-financial assets Other non-current non-financial assets comprise the following: As of December 31, 2020 (unaudited) 2019 Long-term advances issued 170 169 Other 2 2 Total other non-current non-financial assets 172 171 Long-term advances issued represent primarily advance payments under contracts for future crude oil purchases. 29. Accounts payable and accrued liabilities Accounts payable and accrued liabilities comprise the following: As of December 31, 2020 (unaudited) 2019 Financial liabilities Accounts payable to suppliers and contractors 422 544 Current operating liabilities of subsidiary banks 724 438 Salary and related benefits payable 111 102 Dividends payable 1 1 Cash consideration payable (Note 7) 100 – Obligation to transfer the assets (Note 7) 82 – Other accounts payable 42 19 Total financial liabilities 1,482 1,104 Non-financial liabilities Short-term advances received 64 58 Total accounts payable and accrued liabilities 1,546 1,162 Trade and other payables are non-interest bearing.
30. Loans and borrowings and other financial liabilities Loans and borrowings and other financial liabilities comprise the following: As of December 31, Currency 2020 (unaudited) 2019 Long-term Bank loans RUB 807 397 Bank loans US$, euro 913 745 Bonds RUB 581 548 Eurobonds US$ 150 157 Borrowings RUB 122 111 Other borrowings RUB 744 503 Other borrowings US$ 750 643 Less: current portion of long-term loans and borrowings (452) (315) Total long-term loans and borrowings 3,615 2,789 Lease liabilities 157 146 Other long-term financial liabilities 56 116 Less: current portion of long-term lease liabilities (18) (18) Total long-term loans and borrowings and other financial liabilities 3,810 3,033 Short-term Bank loans RUB 90 87 Bank loans US$, euro 6 36 Borrowings RUB – 1 Borrowings US$ 16 7 Other borrowings RUB 49 159 Other borrowings US$ 7 3 Current portion of long-term loans and borrowings 452 315 Total short-term loans and borrowings and current portion of long-term loans and borrowings 620 608 Current portion of long-term lease liabilities 18 18 Other short-term financial liabilities 147 168 Short-term liabilities related to derivative financial instruments 13 1 Total short-term loans and borrowings and other financial liabilities 798 795 Total loans and borrowings and other financial liabilities 4,608 3,828 Long-term loans and borrowings Long-term bank loans comprise the following: Currency Interest rate p.a. Maturity date As of December 31, 2020 (unaudited) 2019 US$ LIBOR + 2.60% – 4.40% 2024-2029 801 743 EUR 2.00% – 2.55% 2022 112 2 RUB CBKR + 0.50% – 8.50% 2021-2025 807 397 Total 1,720 1,142 Debt issue costs – – Total long-term bank loans 1,720 1,142 Long-term bank loans from a foreign bank denominated in U.S. dollars are partially secured by oil export contracts. If the Company fails to make timely debt repayments, the terms of such contracts normally provide the lender with the express right of claim to contractual revenue in the amount of the late loan repayments, which the purchaser generally remits directly through transit currency accounts with the lender banks. The outstanding balance of Accounts receivable arising from such contracts amounts to RUB 22 billion and RUB 32 billion as of December 31, 2020 and 2019, respectively, and is included in Trade receivables.
30. Loans and borrowings and other financial liabilities (continued) Long-term loans and borrowings (continued) In 2020 the Company drew down funds under long-term fixed and floating rates loans from Russian banks. Interest-bearing RUB denominated bearer bonds in circulation comprise the following: Security ID Date of issue Date of maturity Total volume in RUB billions Coupon (%) As of December 31, 2020 (unaudited) 2019 Bonds 04,05 10.2012 10.20221 20 7.90% 20 20 Bonds 07,08 03.2013 03.20231 30 7.30% 31 31 Bonds 066,096,106 06.2013 05.20231 40 7.00% 5 1 SE Bonds БО-05, БО-06 12.2013 12.2023 40 6.65%5 26 10 SE Bonds БО-01, БО-07 02.2014 02.2024 35 8.90% 36 36 SE Bonds БО-02, БО-03, БО-04 БО-094 12.2014 11.20241 65 9.40% 55 55 SE Bonds4 БО-08, БО-10 БО-11, БО-12, БО-13 БО-14 12.2014 11.20241 160 9.40%5 – – SE Bonds2 БО-15, БО-16 БО-17, БО-24 12.20142 12.20201 400 7.85% – – SE Bonds БО-18, БО-19, БО-20 БО-21, БО-22, БО-23 БО-25, БО-26 01.20152 01.2021 400 6.30%5 – – SE Bonds4 001Р-01 12.20162 11.2026 600 4.35%5 – – SE Bonds 001Р-02 12.2016 12.2026 30 9.39%5 30 30 SE Bonds 001Р-03 12.2016 12.20261 20 9.50%5 20 20 SE Bonds 001Р-04 05.2017 04.2027 40 8.65%5 41 41 SE Bonds 001Р-05 05.20172 05.20251 15 8.60%5 15 15 SE Bonds4 001Р-06, 001Р-07 07.2017 07.2027 266 8.50%5 – – SE Bonds4 001Р-08 10.2017 09.2027 100 4.35%5 – – SE Bonds4 002Р-01, 002Р-02 12.2017 11.2027 600 4.35%5 – – SE Bonds 002Р-03 12.2017 12.2027 30 7.75%5 30 30 SE Bonds 002Р-04 02.2018 02.2028 50 7.50%5 51 51 SE Bonds 002Р-05 03.2018 02.2028 20 7.30 %5 20 21 SE Bonds 002Р-06, 002Р-07 04.20192 03.2029 30 8.70%5 31 31 SE Bonds 002Р-08 07.2019 07.2029 25 7.95%5 26 26 SE Bonds 002Р-09 10.20192 10.2029 25 7.10%5 25 25 SE Bonds 002Р-10 06.20202 05.2030 15 5.80%5 14 – SE Bonds 003Р-01, 003Р-02 11.2020 11.2030 800 4.35%5 – – Bonds of subsidiary banks: SE Bonds7 001Р-01 10.2017 10.20201 10 8.50% – 10 SE Bonds 001Р-02 02.2018 07.20211 5 7.80%5 5 5 SE Bonds 001Р-03 03.20192 03.2024 5 8.85%5 5 5 SE Bonds 001Р-04 05.20202 05.2025 5 6.50%5 5 – SE Bonds 001Р-05 09.20202 09.2025 5 5.80%5 5 – SE Bonds БО-026 08.20143 08.20341 3 0.51%5 – – SE Bonds БО-036 07.20153 06.20351 4 0.51%5 – – SE Bonds БО-П01 09.20153 08.20351 5 0.51%5 – – SE Bonds БО-П02 10.20153 09.20351 4 0.51%5 1 1 SE Bonds БО-П03 11.20153 10.20351 1 0.51%5 – – SE Bonds БО-П05 06.20163 06.20361 5 0.51%5 – – Convertible Bonds С-01 02.20173 02.20321 69 0.51%5 2 2 PJSC Bashneft SE Bonds: Bonds 046 02.2012 02.2022 10 7.00%5 – – Bonds 06, 08 02.2013 01.20231 15 7.70%5 15 15 Bonds 07, 09 02.2013 01.2023 15 6.30%5 16 16 SE Bonds БО-06, БО-08 05.2016 04.2026 15 10.90%5 16 16 SE Bonds БО-09 10.2016 10.2026 5 9.30%5 5 5 SE Bonds БО-10 12.2016 12.2026 5 9.50%5 5 5 SE Bonds 001P-01R 12.2016 12.20241 10 9.50%5 10 10 SE Bonds 001P-02R 12.2016 12.20231 10 9.50%5 10 10 SE Bonds 001P-03R 01.2017 01.20241 5 9.40%5 5 5 Total long-term RUB bonds 581 548 1 Early repurchase at the request of the bond holder is not allowed. 2 Coupon payments every three months. 3 Coupon payments at the maturity day. 4 On the reporting date these issues are fully or partially used as an instrument for other borrowings under repurchasing agreement operations. 5 For the coupon period effective as of December 31, 2020. 6 As of December 31, 2020 part of issue early repurchased. 7 As of December 31, 2020 bonds are matured.
30. Loans and borrowings and other financial liabilities (continued) Long-term loans and borrowings (continued) In 2020 the Company placed documentary fixed interest-bearing non-convertible long-term bonds with total value of RUB 43 billion. All of the bonds, excluding certain issues, allow early repurchase at the request of the bond holder as set in the respective offering documents. In addition, the issuer, at any time and at its discretion, may purchase/repay the bonds early with the possibility of subsequently placing the bonds in the market. Such purchase/repayment of the bonds does not constitute an early redemption. Corporate Eurobonds comprise the following: Coupon rate (%) Currency Maturity As of December 31, 2020 (unaudited) 2019 Eurobonds (Series 2) 4.199% US$ 2022 150 125 Eurobonds (Series 8) 7.250% US$ 2020 – 32 Total long-term Eurobonds 150 157 In 2020, the Company fully repaid Eurobonds (Series 8) of US$ 0.5 billion (RUB 31.6 billion at the CBR official exchange rate at the transaction date) assumed through the TNK-BP acquisition. In 2020 the Company continued to settle other long-term borrowings under repurchasing agreement operations and entered into new transactions. As of December 31, 2020, the liabilities of the Company under those operations amounted to the equivalent of RUB 1,494 billion at the CBR official exchange rate as of December 31, 2020. The Company’s own corporate bonds were used as an instrument for those operations. The Company is obliged to comply with a number of restrictive financial and other covenants contained in several of its loan agreements. Such covenants include maintaining certain financial ratios. As of December 31, 2020 and December 31, 2019 the Company was in compliance with all restrictive financial and other covenants contained in its loan agreements. Short-term loans and borrowings In 2020 the Company drew down funds under short-term fixed and floating rates loans from Russian and foreign banks. In 2020 the Company continued to meet its obligations in relation to other short-term borrowings in the form of repurchase operations and entered into new transactions. As of December 31, 2020 the liabilities of the Company under those transactions amounted to the equivalent of RUB 56 billion (at the CBR official exchange rate as of December 31, 2020). Own corporate bonds were used as an instrument for those transactions. In 2020 the Company was current on all payments under loan agreements and interest payments. Liabilities related to derivative financial instruments Short-term liabilities related to derivative financial instruments mainly include liabilities related to cross-currency rate swaps. The Company enters into cross-currency rate swaps to sell US$. The transactions balance the currency of revenues and liabilities and reduce the overall interest rates on borrowings.
30. Loans and borrowings and other financial liabilities (continued) Liabilities related to derivative financial instruments (continued) The cross-currency rate swaps are recorded in the consolidated balance sheet at fair value. The measurement of the fair value of the transactions is based on a discounted cash flow model and consensus forecasts of foreign currency rates. The consensus forecasts include forecasts of the major international banks and agencies. The Bloomberg system is the main information source for the model. Reconciliation of changes in liabilities arising from financing activities: Long-term loans and borrowings Short-term loans and borrowings Lease liabilities Other long-term financial liabilities Other short-term financial liabilities Short-term liabilities related to derivative financial instruments Total As of January 1, 2019, including 3,252 778 27 139 162 33 4,391 Financing activities (cash flow) Proceeds/repayment of loans and borrowings (147) (288) – 185 – – (250) Interest paid (221) (19) (12) (8) – – (260) Repayment of other financial liabilities – – (25) – (3) (29) (57) Operating and investing activities (non-cash flow) Foreign exchange (gain)/loss (204) 6 (5) (29) (1) – (233) Offset of other financial liabilities – – – (160) (12) – (172) Acquisition of subsidiaries net of cash – 2 – – – – 2 Effect of initial application of IFRS 16 Leases as of January 1, 2019 – – 103 – – – 103 Increase in lease liabilities – – 46 – – – 46 Finance expenses 222 16 12 11 – – 261 Finance income – – – – – (3) (3) Reclassification (113) 113 – (22) 22 – – As of December 31, 2019 2,789 608 146 116 168 1 3,828 Financing activities (cash flow) Proceeds/repayment of loans and borrowings 630 (174) – – – – 456 Proceeds of other financial liabilities – – 54 – 3 57 Interest paid (197) (15) (12) (10) – – (234) Repayment of other financial liabilities – – (28) (44) (31) – (103) Operating and investing activities (non-cash flow) Foreign exchange (gain)/loss 295 16 12 67 3 – 393 Offset of other financial liabilities – – – (160) – – (160) Acquisition of interest in subsidiaries, net of cash acquired 31 36 – – – – 67 Effect of initial application of IFRS 16 Leases as of January 1, 2019 – – 27 – – – 27 Increase in lease liabilities 204 12 12 12 – 11 251 Finance expenses – – – – – (2) (2) Finance income – – – – 28 – 28 Reclassification (137) 137 – 21 (21) – – As of December 31, 2020 (unaudited) 3,615 620 157 56 147 13 4,608
31. Other current tax liabilities Other short-term tax liabilities comprise the following: As of December 31, 2020 (unaudited) 2019 Mineral extraction tax 133 181 VAT 99 123 Excise duties 32 30 Property tax 9 9 Tax on additional income from production of hydrocarbons 24 31 Personal income tax 2 3 Other 2 2 Total other tax liabilities 301 379 32. Provisions Asset retirement obligations Environmental remediation provision Legal and tax claims and other provisions Total As of January 1, 2019, including 213 44 30 287 Non-current 207 29 8 244 Current 6 15 22 43 Provisions charged during the year (Note 40) 14 8 7 29 Increase/(decrease) in the liability resulting from: Changes in estimates (1) (2) 13 10 Change in the discount rate 81 1 – 82 Foreign exchange differences (6) – (2) (8) Unwinding of discount 17 2 19 Utilization (3) (6) (12) (21) As of December 31, 2019, including 315 47 36 398 Non-current 309 31 3 343 Current 6 16 33 55 Provisions charged during the year (Note 40) 5 9 15 29 Increase/(decrease) in the liability resulting from: Acquisition/(disposal) of subsidiaries (Note 7) (13) (1) (2) (16) Changes in estimates (15) 1 (14) Changes in the discount rate 83 – – 83 Foreign exchange differences 13 – 6 19 Unwinding of discount 22 2 24 Utilization (4) (6) (8) (18) As of December 31, 2020 (unaudited), including 406 51 48 505 Non-current 400 33 4 437 Current 6 18 44 68 Asset retirement (decommissioning) obligations and Environmental remediation provision represent an estimate of the costs of liquidating oil and gas assets, the reclamation of sand pits, slurry ponds, and disturbed lands, and the dismantling of pipelines and power transmission lines. The budget for payments under asset retirement obligations is prepared on an annual basis. Depending on the current economic environment the Company’s actual expenditures may vary from the budgeted amounts.
33. Prepayment on long-term oil and petroleum products supply agreements During 2013-2014 the Company entered into a number of long-term crude oil and petroleum products supply contracts which require the buyer to make a prepayment. The total minimum delivery volume under those contracts at inception approximated 400 million tonnes. The crude oil and petroleum product prices are based on current market prices. The prepayments are settled through physical deliveries of crude oil and petroleum products. Deliveries of oil and petroleum products that reduce the prepayment amounts commenced in 2015. The Company considers these contracts to be regular-way contracts. 2020 (unaudited) 2019 As of January 1 1,082 1,426 Received 1,004 – Reclassified (28) – Settled (300) (344) Total prepayment on long-term oil and petroleum products supply agreements 1,758 1,082 Less current portion (357) (332) Long-term prepayment as of December 31 1,401 750 The amounts settled under these contracts were RUB 300 billion and RUB 344 billion (US$ 6.23 billion and US$ 7.08 billion at the CBR official exchange rate at the prepayment dates, the prepayments are not revalued at each balance sheet date) for 2020 and 2019, respectively. 34. Other non-current liabilities Other non-current liabilities comprise the following: As of December 31, 2020 (unaudited) 2019 Joint project liabilities 2 1 Liabilities for investing activities 3 3 Liabilities for joint operation contracts in Germany 32 25 Operating liabilities of subsidiary banks 7 38 Other 7 6 Total other non-current liabilities 51 73 35. Pension benefit obligations Defined contribution plans The Company makes payments to the State Pension Fund of the Russian Federation. These payments are calculated by the employer as a percentage of salary expense and are expensed as accrued. The Company also maintains a defined contribution corporate pension plan to finance the non-state pensions of its employees.
35. Pension benefit obligations (continued) Defined contribution plans (continued) Pension contributions recognized in the consolidated statement of profit or loss were as follows: 2020 (unaudited) 2019 State Pension Fund 73 63 JSC NPF Evolution 11 12 Total pension contributions 84 75 36. Shareholders’ equity Ordinary shares As of December 31, 2020 (unaudited) As of December 31, 2019 mln shares bln RUB mln shares bln RUB Issued and fully paid shares with par value of RUB 0.01 each 10,598 0.6 10,598 0.6 Treasury shares (1,098) (370) – – Outstanding shares 9,500 10,598 During 2020 the Company acquired 80,988,983 treasury shares (including in form of global depositary receipts) in the amount of RUB 28.1 billion under the share buyback program. As a part of the transaction on disposal of assets in Venezuela (Note 7) the Company received 1,017,425,000 treasury shares valued at quoted price on the transaction date (April 30, 2020) in the amount of RUB 341.5 billion. Dividends The dividends are distributed from the net profit of PJSC Rosneft Oil Company calculated in compliance with the current legislation of the Russian Federation. On June 4, 2019 the Annual General Shareholders’ Meeting approved dividends on the Company’s common shares for 2018 in the amount of RUB 11.33 per share. On September 30, 2019 the Extraordinary Shareholders’ Meeting approved interim dividends on the Company’s common shares for the first half of 2019 in the amount of RUB 15.34 per share. Dividends to third party shareholders of Rosneft Dividends to non-controlling shareholders of subsidiaries Total Dividends payable as of January 1, 2019 1 – 1 Dividends declared for 2018 120 73 193 Interim dividends declared for the first half of 2019 163 26 189 Dividends paid during the year (283) (99) (382) Dividends payable as of December 31, 2019 1 – 1
36. Shareholders’ equity (continued) Dividends (continued) On June 2, 2020 the Annual General Shareholders’ Meeting approved dividends on the Company’s common shares for 2019 in the amount of RUB 18.07 per share. Dividends to third party shareholders of Rosneft Dividends to non-controlling shareholders of subsidiaries Total Dividends payable as of January 1, 2020 (unaudited) 1 – 1 Dividends declared for 2019 172* 52 224 Interim dividends declared for the first half of 2020 – 11 11 Dividends paid during the year (172) (63) (235) Dividends payable as of December 31, 2020 (unaudited) 1 – 1 * Including dividends declared to shareholders which are Rosneft subsidiaries, the amount was RUB 192 billion. 37. Fair value of financial instruments The fair value of financial assets and liabilities is determined as follows: • The fair value of financial assets and liabilities quoted on active liquid markets is determined in accordance with market prices; • The fair value of other financial assets and liabilities is determined in accordance with generally accepted models and is based on discounted cash flow analysis that relies on prices used for existing transactions in the current market; • The fair value of derivative financial instruments is based on market quotes. In illiquid and highly volatile markets fair value is determined on the basis of valuation models that rely on assumptions confirmed by observable market prices or rates as of the reporting date. The Company uses the following hierarchy to determine and disclose the fair value of financial instruments, depending on the valuation methodology • Level 1: quoted (unadjusted) prices in active markets for identical assets and liabilities; • Level 2: methodologies in which all inputs that significantly affect the fair value are directly or indirectly observable in the open market; • Level 3: techniques which use inputs which have a significant effect on the fair value that are not based on the data observable in the open market.
37. Fair value of financial instruments (continued) Assets and liabilities of the Company that are measured at fair value on a recurring basis in accordance with the fair value hierarchy are presented in the table below. Fair value measurement as of December 31, 2020 (unaudited) Level 1 Level 2 Level 3 Total Assets Current assets Financial assets at fair value through other comprehensive income 80 304 33 417 Financial assets at fair value recognized in profit or loss – 16 – 16 Derivative financial instruments – – – – Non-current assets Financial assets at fair value through other comprehensive income 10 – 27 37 Financial assets at fair value recognized in profit or loss – 145 1 146 Total assets measured at fair value 90 465 61 616 Liabilities Derivative financial instruments – (13) – (13) Total liabilities measured at fair value – (13) – (13) The fair value of financial assets at fair value through other comprehensive income, financial assets at fair value through profit or loss and derivative financial instruments included in Level 2 is measured at the present value of future estimated cash flows, using inputs such as market interest rates and market quotes of forward exchange rates. The carrying value of cash and cash equivalents and derivative financial instruments recognized in these consolidated financial statements equals their fair value. The carrying value of accounts receivable and accounts payable, loans issued, other financial assets and other financial liabilities recognized in these consolidated financial statements approximates their fair value. Financial assets measured at fair value through other comprehensive income in Level 3 are investments in shares of non-listed companies that are measured on the basis of information not observable in the market. The fair value of investments in unquoted equity instruments was determined using the adjusted net assets method. There were no significant changes in fair value during the reporting period. There were no transfers of financial assets and liabilities between levels during the reporting period. Carrying value Fair value (Level 2) As of December 31, As of December 31, 2020 (unaudited) 2019 2020 (unaudited) 2019 Financial liabilities Financial liabilities at amortized cost: Loans and borrowings with a variable interest rate (2,964) (2,230) (2,876) (2,148) Loans and borrowings with a fixed interest rate (1,271) (1,167) (1,313) (1,170) Lease liabilities (157) (146) (169) (143)
38. Related party transactions For the purpose of these consolidated financial statements, parties are considered to be related if one party has the ability to control the other party or exercise significant influence over the other party in making financial or operational decisions. Related parties comprise major shareholders and companies under their control (including enterprises directly or indirectly controlled by the Russian Government), associates and joint ventures, key management and pension funds (Note 35). Related parties may enter into transactions which unrelated parties might not, and transactions between related parties may not be entered on the same terms as transactions between unrelated parties. The disclosure of related party transactions is presented on an aggregate basis for major shareholders and companies under their control, joint ventures and associates, and non-state pension funds. In addition, there may be additional disclosures of certain significant transactions (balances and turnovers) with certain related parties. In the course of its ordinary business, the Company enters into transactions with other companies controlled by the Russian Government. In the Russian Federation, electricity and transport tariffs are regulated by the Federal Antimonopoly Service, an authorized governmental agency of the Russian Federation. Bank loans are recorded based on market interest rates. Taxes are accrued and paid in accordance with applicable tax law. The Company sells crude oil and petroleum products to and purchases crude oil and petroleum products from related parties in the ordinary course of business at prices close to average market prices. Transactions with major shareholders and companies under their control Revenues and income 2020 (unaudited) 2019 Oil, gas, petroleum products and petrochemicals sales 603 732 Support services and other revenues 2 2 Finance income 19 21 Other income 8 4 632 759 Costs and expenses 2020 (unaudited) 2019 Production and operating expenses 23 17 Cost of purchased oil, gas, petroleum products and refining costs 52 58 Transportation costs and other commercial expenses 435 481 Other expenses 10* 9 Financial expenses 52 52 572 617 * Including effect of acquisitions and disposals of subsidiaries and shares in joint operations (Note 7).
38. Related party transactions (continued) Transactions with major shareholders and companies under their control (continued) Other operations 2020 (unaudited) 2019 Acquisition of subsidiaries and interest in associates (Note 7) (8) (1) Purchase of other long-term financial assets (30) – Loans received 922 140 Loans repaid (470) (412) Loans and borrowings issued (2) (42) Repayment of loans and borrowings issued 2 37 Deposits placed (92) (33) Deposits repaid – 96 Settlement balances As of December 31, 2020 (unaudited) 2019 Assets Cash and cash equivalents 467 88 Accounts receivable 166 100 Prepayments and other current assets 44 44 Other financial assets 376 225 1,053 457 Liabilities Accounts payable and accrued liabilities 372 279 Loans and borrowings and other financial liabilities 858 443 1,230 722 Transactions with joint ventures Revenues and income 2020 (unaudited) 2019 Oil, gas, petroleum products and petrochemicals sales 19 18 Support services and other revenues 4 4 Finance income 3 21 Other income 2 12 28 55 Costs and expenses 2020 (unaudited) 2019 Production and operating expenses 2 5 Cost of purchased oil, gas, petroleum products and refining costs 181 312 Transportation costs and other commercial expenses 15 8 Other expenses 1 – Finance expenses 2 1 201 326
38. Related party transactions (continued) Transactions with joint ventures (continued) Other operations 2020 (unaudited) 2019 Loans received 36 54 Loans repaid (22) (25) Loans and borrowing issued (6) (9) Repayment of loans and borrowings issued 2 5 Settlement balances As of December 31, 2020 (unaudited) 2019 Assets Accounts receivable 9 9 Prepayments and other current assets 2 1 Other financial assets 3 21 14 31 Liabilities Accounts payable and accrued liabilities 110 244 Loans and borrowings and other financial liabilities 54 23 164 267 Transactions with associates Revenues and income 2020 (unaudited) 2019 Oil, gas, petroleum products and petrochemicals sales 316 354 Support services and other revenues 1 4 Finance income 3 3 Other income 5 – 325 361 Costs and expenses 2020 (unaudited) 2019 Production and operating expenses 2 22 Cost of purchased oil, gas, petroleum products and refining costs 23 108 Transportation costs and other commercial expenses 2 2 Other expenses – 3 Finance expenses 8 7 35 142
38. Related party transactions (continued) Transactions with associates (continued) Other operations 2020 (unaudited) 2019 Loans received 63 122 Loans repaid (183) (168) Loans and borrowing issued – (43) Repayment of loans and borrowings issued – 41 Settlement balances As of December 31, 2020 (unaudited) 2019 Assets Accounts receivable 71 91 Prepayments and other current assets 1 – Other financial assets 3 11 75 102 Liabilities Accounts payable and accrued liabilities 22 35 Loans and borrowings and other financial liabilities 159 232 181 267 Transactions with non-state pension funds Costs and expenses 2020 (unaudited) 2019 Other expenses 11 12 Settlement balances As of December 31, 2020 (unaudited) 2019 Liabilities Accounts payable and accrued liabilities 1 2 1 2 Compensation to key management personnel For the purpose of these consolidated financial statements key management personnel include members of the Management Board of PJSC Rosneft Oil Company and members of the Board of Directors. Short-term gross benefits of the Management Board members, taking into account personnel rotation, including payroll, bonuses, compensation payments and personal income tax totaled RUB 3,531 million and RUB 3,570 million in 2020 and 2019, respectively (social security fund contributions, which are not Management Board members’ income, totaled RUB 520 million and RUB 513 million, respectively). Short-term gross benefits for 2020 are disclosed in accordance with the Russian securities law on information disclosure.
38. Related party transactions (continued) Compensation to key management personnel (continued) On June 2, 2020, the Annual General Shareholders Meeting approved remuneration to the following members of the Company’s Board of Directors for the period of their service in the following amounts: Mr. Gerhard Schröder – US$ 600,000 (RUB 41.8 million at the CBR official exchange rate on June 2, 2020); Mr. Hamad Rashid Al-Mohannadi – US$ 530,000 (RUB 36.9 million at the CBR official exchange rate on June 2, 2020); Mr. Faisal Alsuwaidi – US$ 530,000 (RUB 36.9 million at the CBR official exchange rate on June 2, 2020); Mr. Matthias Warnig – US$ 580,000 (RUB 40.4 million at the CBR official exchange rate on June 2, 2020); Mr. Oleg Viyugin – US$ 560,000 (RUB 39.0 million at the CBR official exchange rate on June 2, 2020); Mr. Rudloff Hans-Joerg – US$ 580,000 (RUB 40.4 million at the CBR official exchange rate on June 2, 2020). Remuneration does not include compensation of travel expenses. No remuneration was paid to members of the Board of Directors who are state officials (Andrey Belousov and Alexander Novak) or to Mr. Igor Sechin, the Chairman of the Management Board, for their Board of Directors service. On June 4, 2019, the Annual General Shareholders Meeting approved remuneration to the following members of the Company’s Board of Directors for the period of their service in the following amounts: Mr. Gerhard Schröder – US$ 600,000 (RUB 39.3 million at the CBR official exchange rate on June 4, 2019); Mr. Faisal Alsuwaidi – US$ 530,000 (RUB 34.7 million at the CBR official exchange rate on June 4, 2019); Mr. Matthias Warnig – US$ 580,000 (RUB 38.0 million at the CBR official exchange rate on June 4, 2019); Mr. Oleg Viyugin – US$ 560,000 (RUB 36.7 million at the CBR official exchange rate on June 4, 2019); Mr. Ivan Glasenberg – US$ 530,000 (RUB 34.7 million at the CBR official exchange rate on June 4, 2019); Mr. Rudloff Hans-Joerg – US$ 580,000 (RUB 38.0 million at the CBR official exchange rate on June 4, 2019). Remuneration does not include compensation of travel expenses. No remuneration was paid to members of the Board of Directors who are state officials (Andrey Belousov and Alexander Novak) or to Mr. Igor Sechin, the Chairman of the Management Board, for their Board of Directors service. 39. Key subsidiaries Name Country of incorporation Core activity 2020 (unaudited) 2019 Total shares Voting shares Total shares Voting shares % % % % Exploration and production JSC Samotlorneftegaz Russia Oil and gas development and production 100.00 100.00 100.00 100.00 LLC RN-Yuganskneftegaz Russia Oil and gas production operator services 100.00 100.00 100.00 100.00 PJSOC Bashneft Russia Oil and gas development and production 60.33 70.93 60.33 70.93 JSC Taymyrneftegaz Russia Oil and gas development and production 90.00 90.00 – – Vostok Oil LLC Russia Oil and gas development and production 90.00 90.00 – – Refining, marketing and distribution JSC RORC Russia Petroleum refining 100.00 100.00 100.00 100.00 JSC ANKHK Russia Petroleum refining 100.00 100.00 100.00 100.00 JSC NK NPZ Russia Petroleum refining 100.00 100.00 100.00 100.00 LLC RN-Komsomolskiy NPZ Russia Petroleum refining 100.00 100.00 100.00 100.00 JSC SNPZ Russia Petroleum refining 100.00 100.00 100.00 100.00 JSC ANPZ VNK Russia Petroleum refining 100.00 100.00 100.00 100.00 JSC KNPZ Russia Petroleum refining 100.00 100.00 100.00 100.00 LLC RN-Tuapse OR Russia Petroleum refining 100.00 100.00 100.00 100.00 LLC RN-Bunker Russia Marketing and distribution 100.00 100.00 100.00 100.00 LLC RN-Aero Russia Marketing and distribution 100.00 100.00 100.00 100.00 LLC RN-Commerce Russia Marketing and distribution 100.00 100.00 100.00 100.00 LLC RN-Trade Russia Investing activity 100.00 100.00 100.00 100.00 Rosneft Deutschland GmbH Germany Marketing and distribution 100.00 100.00 100.00 100.00 Other JSC RN Holding Russia Holding company 100.00 100.00 100.00 100.00 Bank RRDB (JSC) Russia Banking 98.34 98.34 98.34 98.34 LLC RN-GAZ Russia Holding company 100.00 100.00 100.00 100.00 Rosneft Singapore Pte. Ltd. Singapore Holding company 100.00 100.00 100.00 100.00 LLC RN-Foreign Projects Russia Holding company 100.00 100.00 100.00 100.00 Rosneft Holdings LTD S.A. Luxemburg Holding company 100.00 100.00 100.00 100.00 TOC Investments Corporation Limited Cyprus Other services 100.00 100.00 100.00 100.00
40. Contingencies Russian business environment Despite of the measures undertaken by the Government of Russian Federation aimed at supporting liquidity and facilitating refinancing of foreign loans of Russian banks and companies, uncertainty in relation to the access to capital markets and cost of capital for the Company continues. This uncertainty can influence financial condition, results of operations and economic perspectives of the Company. The Company is not able to significantly influence overall economic situation in the country. However in the case of negative impact driven by changes of the situation in the country, it will undertake all the necessary measures to minimize negative consequences on its financial condition and operating results. The Company also has investments in subsidiaries, associates and joint ventures and advances issued to counterparties operating in foreign jurisdictions. Besides commercial risks being a part of any investment operation, assets in a number of regions of the Company’s activities also bear political, economic and tax risks which are analyzed by the Company on a regular basis. Since the beginning of March 2020, the world markets are experiencing a significant decline in oil demand and oil prices, in particular as a result of COVID-19 pandemic. Russian ruble value has fallen significantly against the major world currencies. Should these factors continue in the long-term, it will continue to have a significant impact on the Company’s financial position, cash flows and results of operations. Guarantees and indemnities issued An unconditional unlimited guarantee issued in 2013 in favor of the Government and municipal authorities of Norway is effective in respect of the Company’s operations on the Norwegian continental shelf. That guarantee fully covers all potential ongoing environmental liabilities of RN Nordic Oil AS. A parent company guarantee is required by Norwegian legislation and is an essential condition for licensing the operations of RN Nordic Oil AS on the Norwegian continental shelf jointly with Equinor (until July 2018 – Statoil ASA). The Company’s agreements with Eni S.p.A and Equinor (until July 2018 – Statoil ASA) under the Russian Federation shelf exploration program contain mutual guarantees provided in 2013 that are unconditional, unlimited and open-ended. In 2015 in accordance with the cooperation agreement on difficult to extract oil reserves with Equinor (until July 2018 – Statoil ASA), both parties issued parent guarantees on the discharging of the mutual liabilities of their related parties. These guarantees are unconditional, unlimited and open-ended. In 2018, as part of the operating activities of Rosneft, unconditional irrevocable guarantees were issued in favor of the Government of the Republic of Mozambique providing the coverage of potential liabilities for geological exploration on the Mozambique continental shelf (4 years). Legal claims Rosneft and its subsidiaries are involved in litigations which arise from time to time in the course of their business activities. Management believes that the ultimate results of these litigations will not materially affect the performance or financial position of the Company. Reliably estimated probable obligations were recognized within provisions in the Consolidated financial statements of the Company (Note 32).
40. Contingencies (continued) Taxation Legislation and regulations regarding taxation in Russia continue to evolve. Various legislative acts and regulations are not always clearly written, and their interpretation is subject to the opinions of the taxpayers, and local, regional, and national tax authorities, and the Ministry of Finance of the Russian Federation. Instances of inconsistent opinions are not unusual. In Russia, tax returns remain open and subject to inspection for a period of up to three years. The fact that a year has been reviewed does not close that year, or any tax return applicable to that year, from further review during the period of three calendar years preceding the year when the inspection started. In accordance with Russian tax legislation, if an understatement of a tax liability is detected as a result of an inspection, penalties and fines to be paid might be material in respect of the tax liability misstatement. During the reporting period, the tax authorities continued their inspections of some of Rosneft subsidiaries for 2015-2019. The Company’s management does not expect the outcome of the inspections to have a material impact on the Company’s consolidated financial position or results of operations. As part of the new regime for fiscal control over the pricing of related party transactions, the Company and the Federal Tax Service signed a number of pricing agreements from 2012 to 2020 with respect to the taxation of oil sales and refining transactions in Russia. The Company believes that transfer pricing risks in relation to intragroup transactions during the twelve months ended December 31, 2020 and earlier will not have a material effect on its financial position or results of operations. The Company follows the rules of tax legislation on de-offshorization, including income tax rules for controlled foreign companies to calculate its current and deferred income tax estimates. Overall, management believes that the Company has paid and accrued all taxes that are applicable. For taxes where uncertainty exists, the Company has accrued tax liabilities based on management’s best estimate of the probable outflow of resources that will be required to settle these liabilities. Capital commitments The Company and its subsidiaries are engaged in ongoing capital projects for the exploration and development of production facilities and the modernization of refineries and the distribution network. The budgets for these projects are generally set on an annual basis. The total amount of contracted but not yet delivered goods and services related to the construction and acquisition of property, plant and equipment amounted to RUB 668 billion and RUB 762 billion as of December 31, 2020 (unaudited) and 2019, respectively. Commitments of the Company that it has relating to its joint ventures amount up to RUB 20 billion and RUB 15 billion as of December 31, 2020 (unaudited) and 2019, respectively. The Company has various lease contracts that have not yet commenced as at December 31, 2020. The future lease payments for these non-cancellable lease contracts are RUB 1 billion within one year, RUB 18 billion within five years and RUB 63 billion thereafter.
40. Contingencies (continued) Environmental liabilities The Company periodically evaluates its environmental liabilities pursuant to environmental regulations. Such liabilities are recognized in the consolidated financial statements as and when identified. Potential liabilities, which could arise as a result of changes in existing regulations or the settlement of civil litigation, or as a result of changes in environmental standards, cannot be reliably estimated but may be material. With the existing system of control, management believes that there are no material liabilities for environmental damage other than those recorded in these consolidated financial statements. Risks and opportunities associated with climate change Within the framework of its corporate risk management and internal control systems, the Company on an annual basis identifies and evaluates risks and opportunities related to climate change impact on its business activities. In the process of investment decision making, the risks associated with health, safety and environment (HSE), ecology, and climate change are analyzed. For large projects, the analysis of the alignment with the Company’s strategic goals, environmental standards and requirements of the Russian and international legislation is performed, as well as the analysis and assessment of external risks related to the impact on the environment (changes in legislation, changes in technologies, market risks, reputation risks, etc.). In addition, the risks and opportunities associated with climate change and the transition to low-carbon energy are considered in the Company’s strategic management and business planning processes (especially for projects located in climate-sensitive regions: marine projects, Arctic projects, etc.) as well as for of the global energy developments scenario planning. Other matters Due to the pollution of oil in the trunk pipeline “Druzhba” in April 2019 a number of claims from the customers were submitted to PJSC “Rosneft Oil Company”, stating that the supplied oil contains substantially exceeded maximum permitted levels of organochlorine compounds (compared to levels determined by the relevant technical regulations and standards). At the same time, PJSC “Rosneft Oil Company” delivered oil to the system of oil trunk pipelines of PJSC “Transneft” in compliance with the requirements of technical regulations and standards. Also, the Company received claims from the customers who were not delivered the contracted amounts of oil due to the oil pumping interruption in the trunk oil pipeline “Druzhba” resulting from the contamination. Currently the Company is working with foreign customers and PJSC “Transneft” on the settlement of claims. Calculation of losses incurred by PJSC “Rosneft Oil Company” can be finalized after the completion of the comprehensive assessment of the impact of the incident on the Company’s activities (including the forced reduction in oil production due to the reduced oil intake into the system of PJSC “Transneft”), obtaining a complete and documentary supported claims from all counterparties and their re-submission to PJSC “Transneft” for compensation.
Consolidated Financial Statements of Rosneft Oil Company as at and for the years ended 31 December 2018 (unaudited) and 2017 (unaudited) EXHIBIT 99.2
Rosneft Oil Company The accompanying notes to the consolidated financial statements are an integral part of these statements. Consolidated balance sheet (unaudited) (in billions of Russian rubles) As of December 31, Notes 2018 2017 (restated) ASSETS Current assets Cash and cash equivalents 19 832 322 Restricted cash 19 12 13 Other short-term financial assets 20 633 336 Accounts receivable 21 642 843 Inventories 22 393 324 Prepayments and other current assets 23 510 454 Total current assets 3,022 2,292 Non-current assets Property, plant and equipment 24 8,445 7,923 Intangible assets 25 75 75 Other long-term financial assets 26 239 606 Investments in associates and joint ventures 27 735 635 Bank loans granted 239 121 Deferred tax assets 16 28 26 Goodwill 25 85 265 Other non-current non-financial assets 28 295 285 Total non-current assets 10,141 9,936 Total assets 13,163 12,228 LIABILITIES AND EQUITY Current liabilities Accounts payable and accrued liabilities 29 1,130 971 Loans and borrowings and other financial liabilities 30 978 2,229 Income tax liabilities 23 39 Other tax liabilities 31 327 278 Provisions 32 43 29 Prepayment on long-term oil and petroleum products supply agreements 33 354 264 Other current liabilities 19 26 Total current liabilities 2,874 3,836 Non-current liabilities Loans and borrowings and other financial liabilities 30 3,413 1,783 Deferred tax liabilities 16 837 814 Provisions 32 244 245 Prepayment on long-term oil and petroleum products supply agreements 33 1,072 1,322 Other non-current liabilities 34 46 45 Total non-current liabilities 5,612 4,209 Equity Share capital 36 1 1 Additional paid-in capital 36 633 627 Other funds and reserves (191) (322) Retained earnings 3,610 3,313 Rosneft shareholders’ equity 4,053 3,619 Non-controlling interests 17 624 564 Total equity 4,677 4,183 Total liabilities and equity 13,163 12,228
Rosneft Oil Company The accompanying notes to the consolidated financial statements are an integral part of these statements. Consolidated statement of profit or loss (unaudited) (in billions of Russian rubles, except earnings per share data, and share amounts) For the years ended December 31, Notes 2018 2017 (restated)* Revenues and equity share in profits of associates and joint ventures Oil, gas, petroleum products and petrochemicals sales 8 8,076 5,877 Support services and other revenues 80 77 Equity share in profits of associates and joint ventures 27 82 57 Total revenues and equity share in profits of associates and joint ventures 8,238 6,011 Costs and expenses Production and operating expenses 642 607 Cost of purchased oil, gas, petroleum products and refining costs 1,099 837 General and administrative expenses 167 172 Pipeline tariffs and transportation costs 638 596 Exploration expenses 11 15 Depreciation, depletion and amortization 24, 25 635 586 Taxes other than income tax 9 2,701 1,919 Export customs duty 10 1,061 658 Total costs and expenses 6,954 5,390 Operating income 1,284 621 Finance income 11 122 107 Finance expenses 12 (290) (225) Other income 13 49 110 Other expenses 13 (294) (75) Foreign exchange differences 107 3 Cash flow hedges reclassified to profit or loss 6 (146) (146) Income before income tax 832 395 Income tax expense 16 (183) (98) Net income 649 297 Net income attributable to: - Rosneft shareholders 549 222 - non-controlling interests 17 100 75 Net income attributable to Rosneft per common share (in RUB) – basic and diluted 18 51.80 20.95 Weighted average number of shares outstanding (millions) 10,598 10,598 * Some amounts for the twelve months ended December 31, 2017 have been restated – see Note 7.
Rosneft Oil Company The accompanying notes to the consolidated financial statements are an integral part of these statements. Consolidated statement of other comprehensive income (unaudited) (in billions of Russian rubles) For the years ended December 31, Notes 2018 2017 Net income 649 297 Other comprehensive income – to be reclassified to profit or loss in subsequent periods Foreign exchange differences on translation of foreign operations 4 51 Foreign exchange cash flow hedges 6 146 145 (Loss)/income from changes in fair value of debt financial assets at fair value through other comprehensive income (2) 10 Increase in loss allowance for expected credit losses on debt financial assets at fair value through other comprehensive income 7 – Equity share in other comprehensive loss of associates and joint ventures 1 – Income tax related to other comprehensive income – to be reclassified to profit or loss in subsequent periods 6 (30) (31) Total other comprehensive income – to be reclassified to profit or loss in subsequent periods, net of tax 126 175 Other comprehensive income – not to be reclassified to profit or loss in subsequent periods Income from changes in fair value of equity financial assets at fair value through other comprehensive income 6 – Income tax related to other comprehensive income – not to be reclassified to profit or loss in subsequent periods (1) – Total comprehensive income – not to be reclassified to profit or loss in subsequent periods, net of tax 5 – Total comprehensive income, net of tax 780 472 Total comprehensive income, net of tax, attributable to: - Rosneft shareholders 680 397 - non-controlling interests 100 75
Rosneft Oil Company The accompanying notes to the consolidated financial statements are an integral part of these statements. Consolidated statement of changes in shareholders’ equity (unaudited) (in billions of Russian rubles, except share amounts) Number of shares (millions) Share capital Additional paid-in capital Other funds and reserves Retained earnings Rosneft share- holders’ equity Non- controlling interests Total equity Balance at January 1, 2017 10,598 1 603 (497) 3,195 3,302 480 3,782 Net income – – – – 222 222 75 297 Other comprehensive income – – – 175 – 175 – 175 Total comprehensive income – – – 175 222 397 75 472 Dividends declared (Note 36) – – – – (104) (104) (43) (147) Change of interests in subsidiaries (Note 17) – – 24 – – 24 44 68 Disposal of subsidiaries – – – – – – (1) (1) Other movements – – – – – – 9 9 Balance at December 31, 2017 10,598 1 627 (322) 3,313 3,619 564 4,183 Adjustment on initial application of IFRS 9 – – – – (27) (27) (1) (28) Balance at January 1, 2018 adjusted for the effect of IFRS 9 10,598 1 627 (322) 3,286 3,592 563 4,155 Net income – – – – 549 549 100 649 Other comprehensive income – – – 131 – 131 – 131 Total comprehensive income – – – 131 549 680 100 780 Dividends declared (Note 36) – – – – (225) (225) (61) (286) Change of interests in subsidiaries (Note 17) – – 5 – – 5 21 26 Other movements – – 1 – – 1 1 2 Balance at December 31, 2018 10,598 1 633 (191) 3,610 4,053 624 4,677
Rosneft Oil Company The accompanying notes to the consolidated financial statements are an integral part of these statements. Consolidated statement of cash flows (unaudited) (in billions of Russian rubles) For the years ended December 31, Notes 2018 2017 (restated) Operating activities Net income 649 297 Adjustments to reconcile net income to net cash provided by operating activities Depreciation, depletion and amortization 24, 25 635 586 Loss on disposal of non-current assets 13 14 13 Dry hole costs 3 3 Offset of prepayments received on oil and petroleum products long term supply agreements 33 (283) (255) Offset of prepayments made on oil and petroleum products long term supply agreements 205 – Foreign exchange gain on non-operating activities (77) (24) Cash flow hedges reclassified to profit or loss 6 146 146 Offset of other financial liabilities (164) (105) Equity share in profits of associates and joint ventures 27 (82) (57) Non-cash income from acquisitions, net 13 (26) (1) Gain on out-of-court settlement 13 – (100) Loss from disposal of non-production assets 13 1 3 Changes in provisions for financial assets 6 16 Loss from changes in estimates and impairment of assets 238 23 Finance expenses 12 290 225 Finance income 11 (122) (107) Income tax expense 16 183 98 Changes in operating assets and liabilities Decrease/(increase) in accounts receivable, gross 215 (184) Increase in inventories (68) (41) Decrease/(increase) in restricted cash 5 (10) Increase in prepayments and other current assets (74) (27) Increase in long-term prepayments made on oil and petroleum products supply agreements (72) (207) (Decrease)/increase in accounts payable and accrued liabilities (29) 24 Increase in other tax liabilities 48 56 Decrease in other current liabilities (8) – Increase in other non-current liabilities 8 – Interest paid on long-term prepayment received on oil and petroleum products supply agreements (6) (10) Net increase in operating assets of subsidiary banks (139) (144) Net increase in operating liabilities of subsidiary banks 144 170 Proceeds from sale of trading securities – 3 Net cash provided by operating activities before income tax and interest 1,640 391 Income tax payments (221) (112) Interest received 67 37 Dividends received 16 21 Net cash provided by operating activities 1,502 337
Rosneft Oil Company The accompanying notes to the consolidated financial statements are an integral part of these statements. Consolidated statement of cash flows (unaudited) (continued) (in billions of Russian rubles) For the years ended December 31, Notes 2018 2017 (restated) Investing activities Capital expenditures (936) (922) Acquisition of licenses and auction fee payments (3) (34) Acquisition of short-term financial assets (419) (103) Proceeds from sale of short-term financial assets 189 258 Acquisition of long-term financial assets 26 (71) (58) Proceeds from sale of long-term financial assets 466 127 Financing of joint ventures (2) (2) Acquisition of interest in associates and joint ventures 27 (2) (219) Proceeds from sale of investments in joint ventures 7 – Acquisition of interest in subsidiaries, net of cash acquired, and joint arrangements 7 (35) (215) Proceeds from sale of property, plant and equipment 7 5 Placements under reverse REPO agreements – (1) Receipts under reverse REPO agreements – 2 Net cash used in investing activities (799) (1,162) Financing activities Proceeds from short-term loans and borrowings 30 429 1,431 Repayment of short-term loans and borrowings (1,366) (787) Proceeds from long-term loans and borrowings 30 1,311 508 Repayment of long-term loans and borrowings (289) (806) Proceeds from other financial liabilities 338 336 Repayment of other financial liabilities (64) (22) Interest paid (284) (219) Repurchase of bonds (40) – Proceeds from sale of non-controlling share in subsidiary 23 73 Other financing 4 9 Dividends paid to Rosneft shareholders 36 (225) (104) Dividends paid to non-controlling shareholders (65) (38) Net cash (used in) / provided by financing activities (228) 381 Net increase/(decrease) in cash and cash equivalents 475 (444) Cash and cash equivalents at the beginning of the year 19 322 790 Effect of foreign exchange on cash and cash equivalents 35 (24) Cash and cash equivalents at the end of the year 19 832 322
Rosneft Oil Company Notes to the consolidated financial statements (unaudited) December 31, 2018 (all amounts in tables are in billions of Russian rubles, except as noted otherwise) 1. General Public Joint Stock Company (“PJSC”) Rosneft Oil Company (“Rosneft”) and its subsidiaries (collectively, the “Company”) are principally engaged in exploration, development, production and sale of crude oil and gas and refining, transportation and sale of petroleum products in the Russian Federation and in certain international markets. Rosneft State Enterprise was incorporated as an open joint stock company on December 7, 1995. All assets and liabilities previously managed by Rosneft State Enterprise were transferred to the Company at their book value effective on that date together with ownership rights to other privatized oil and gas companies belonging to the Government of the Russian Federation (the “State”). The transfer of assets and liabilities was made in accordance with Russian Government Resolution No. 971 dated September 29, 1995, On the Transformation of Rosneft State Enterprise into Open Joint Stock Company “Oil Company Rosneft”. These transfers involved the reorganization of assets under the common control of the State and, accordingly, were accounted for at their book value. In 2005, the State contributed the shares of Rosneft to the share capital of JSC ROSNEFTEGAS. As of December 31, 2005, 100% of the shares of Rosneft less one share were owned by JSC ROSNEFTEGAS and one share was owned by the Russian Federation Federal Agency for the Management of Federal Property. Subsequently, JSC ROSNEFTEGAS’s ownership interest decreased through the additional issue of shares during Rosneft’s Initial Public Offering (“IPO”) in Russia, an issue of Global Depository Receipts (“GDR”) for shares on the London Stock Exchange and the share swap completed during the merger of Rosneft and certain subsidiaries in 2006. In March 2013 in the course of the acquisition of TNK-BP Limited and TNK Industrial Holdings Limited, its subsidiary (collectively with their subsidiaries, “TNK-BP”), JSC ROSNEFTEGAS sold 5.66% of Rosneft shares to BP plc. (“BP”). In December 2016 JSC ROSNEFTEGAS signed an agreement to sell 19.5% of Rosneft shares to a consortium of foreign investors. As of December 31, 2018 JSC ROSNEFTEGAS’s ownership interest in Rosneft amounted to 50% plus one share. Under Russian legislation, natural resources, including oil, gas, precious metals and minerals and other commercial minerals situated in the territory of the Russian Federation, are the property of the State until they are extracted. Law of the Russian Federation No. 2395-1, On Subsurface Resources, regulates relations arising in connection with the geological study, use and protection of subsurface resources in the territory of the Russian Federation. Pursuant to the law, subsurface resources may be developed only on the basis of a license. A license is issued by the regional governmental body and contains information on the site to be developed and the period of activity, as well as financial and other conditions. The Company holds licenses issued by competent authorities for the geological study, exploration and development of oil and gas blocks, fields, and shelf in areas where its subsidiaries are located. The Company is subject to export quotas set by the Russian Federation State Pipeline Commission to allow equal access to the limited capacity of the oil pipeline system owned and operated by PJSC AK Transneft. The Company exports certain quantities of crude oil through bypassing the PJSC AK Transneft system thus achieving higher export capacity. The remaining production is processed at the Company’s and third parties’ refineries for further sale on domestic and international markets.
2. Basis of preparation These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards, including all International Financial Reporting Standards (“IFRS”) and Interpretations issued by the International Accounting Standards Board (“IASB”) and effective in the reporting period, and are fully compliant therewith. These consolidated financial statements have been prepared on a historical cost basis, except certain financial assets and liabilities measured at fair value (Note 37). Rosneft and its subsidiaries maintain their books and records in accordance with statutory accounting and taxation principles and practices applicable in respective jurisdictions. These consolidated financial statements were derived from the Company’s statutory books and records. The Company’s consolidated financial statements are presented in billions of Russian rubles (“RUB”), unless otherwise indicated. The consolidated financial statements were approved and authorized for issue by the Chief Executive Officer of the Company on February 5, 2019. Subsequent events have been evaluated through February 5, 2019, the date these consolidated financial statements were issued. 3. Significant accounting policies The accompanying consolidated financial statements differ from the financial statements issued for statutory purposes in that they reflect certain adjustments, not recorded in the Company’s statutory books, which are appropriate for presenting the financial position, results of operations and cash flows in accordance with IFRS. The principal adjustments relate to: (1) recognition of certain expenses; (2) valuation and depreciation of property, plant and equipment; (3) deferred income taxes; (4) impairment of assets; (5) accounting for the time value of money; (6) accounting for investments in oil and gas property and conveyances; (7) consolidation principles; (8) recognition and disclosure of guarantees, contingencies, commitments and certain other assets and liabilities; (9) business combinations and goodwill; (10) accounting for derivative instruments; (11) purchase price allocation to the identifiable assets acquired and the liabilities assumed. The consolidated financial statements include the accounts of majority-owned, controlled subsidiaries and special-purpose entities where the Company holds a beneficial interest. All significant intercompany transactions and balances have been eliminated. The equity method is used to account for investments in associates in which the Company has the ability to exert significant influence over the associates’ operating and financial policies. Investments in entities where the Company holds the majority of shares, but does not exercise control, are also accounted for using the equity method. Investments in other companies are accounted for at fair value or cost adjusted for impairment, if any. Determination of the level of control or influence in the entities where the Company holds a share is carried out taking into account the powers established by the agreement in respect of the investment and the existing rights that provide the Company with the opportunity to manage significant activities at the present time.
3. Significant accounting policies (continued) Business combinations, goodwill and other intangible assets Acquisitions by the Company of controlling interests in third parties (or interest in their charter capital) are accounted for using the acquisition method. The date of acquisition is the date when effective control over the acquiree passes to the Company. The cost of an acquisition is measured as an aggregate of the consideration transferred, measured at acquisition date fair value, and the amount of any non-controlling interest in the acquiree. For each business combination, the Company elects whether it measures the non-controlling interest in the acquiree either at fair value or at the proportionate share of the acquiree’s identifiable net assets. Acquisition costs incurred are expensed and included in administrative expenses. Any contingent consideration to be transferred by the acquirer is recognized at fair value at the acquisition date. Subsequent changes to the fair value of the contingent consideration which is deemed to be an asset or a liability should be recognized within profit or loss for the period if they do not represent measurement-period adjustments. If the contingent consideration is classified as equity, it should not be re-measured. Goodwill is initially measured at cost being the excess of the aggregate of the consideration transferred and the amount recognized for non-controlling interests over the fair value of net identifiable assets acquired and liabilities assumed. If the aggregate of the consideration transferred and the amount of non-controlling interest is lower than the fair value of the net assets of the subsidiary acquired and liabilities assumed, the difference is recognized in profit or loss for the period. Associates Investments in associates are accounted for using the equity method unless they are classified as non-current assets held for sale. Under this method, the carrying value of investments in associates is initially recognized at the acquisition cost. The carrying value of investments in associates is increased or decreased by the Company’s reported share in the profit or loss and other comprehensive income of the investee after the acquisition date. The Company’s share in the profit or loss and other comprehensive income of an associate is recognized in the Company’s consolidated statement of profit or loss or in the consolidated statement of other comprehensive income, respectively. Dividends paid by the associate are accounted for as a reduction of the carrying value of investments. The Company’s net investments in associates include the carrying value of the investments in these associates as well as other long-term investments that are, in substance, investments in associates, such as loans. If the share in losses exceeds the carrying value of the investments in associates and the value of other long-term investments related to investments in these associates, the Company ceases to recognize its share in losses when the carrying value reaches zero. Any additional losses are provided for and liabilities are recognized only to the extent that the Company has legal or constructive obligations or has made payments on behalf of the associate. If the associate subsequently makes profits, the Company resumes recognizing its share in these profits only after its share of the profits equals the share of losses not recognized. The carrying value of investments in associates is tested for impairment by reconciling its recoverable amount (the higher of its value in use and fair value less costs to sell) to its carrying value, whenever impairment indicators are identified.
3. Significant accounting policies (continued) Joint arrangements The Company participates in joint arrangements either in the form of joint ventures or joint operations. A joint venture implies that the parties that have joint control of the arrangement have rights to the net assets of the arrangement. A joint venture involves establishing a legal entity where the Company and other participants have respective equity interests. Equity interests in joint ventures are accounted for under the equity method. The Company’s share in net profit or loss and in other comprehensive income of joint ventures is recognized in the consolidated statement of profit or loss and in the consolidated statement of other comprehensive income, respectively, from the date when joint control commences until the date when joint control ceases. A joint operation implies that the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement. In relation to its interest in a joint operation the Company recognizes its assets, including its share of any assets held jointly, its liabilities, including its share of any liabilities incurred jointly, its revenue from the sale of its share of the output arising from the joint operation, its share of the revenue from the sale of the output by the joint operation, and expenses, including its share of any expenses incurred jointly. Cash and cash equivalents Cash represents cash on hand, in the Company’s bank accounts, in transit and interest bearing deposits which can be effectively withdrawn at any time without prior notice or any penalties reducing the principal amount of the deposit. Cash equivalents are highly liquid, short-term investments that are readily convertible to known amounts of cash and have original maturities of three months or less from their date of purchase. They are carried at cost plus accrued interest, which approximates fair value. Restricted cash is presented separately in the consolidated balance sheet if its amount is significant. Financial assets The Company recognizes financial assets in its balance sheet when, and only when, it becomes a party to the contractual provisions of the financial instrument. When financial assets are recognized initially, they are measured at fair value, which is usually the price of the transaction, i.e. the fair value of consideration paid or received. When financial assets are recognized initially, they are classified as one of the following, as appropriate: (1) financial assets at fair value through profit or loss, (2) financial assets at fair value through other comprehensive income, or (3) financial assets at amortised cost. The Company classifies financial assets on the basis of both: the Company’s business model for managing the financial assets, as well as the contractual cash flow characteristics of the financial assets. A financial asset shall be measured at fair value through profit or loss unless it is measured at amortised cost or at fair value through other comprehensive income. However the Company may make an irrevocable election at initial recognition for particular instruments in equity instruments that would otherwise be measured at fair value through profit or loss to present subsequent changes in fair value in other comprehensive income. All derivative instruments are recorded in the consolidated balance sheet at fair value in either current financial assets, non-current financial assets, current liabilities related to derivative instruments, or non-current liabilities related to derivative instruments. The recognition and classification of a gain or loss that results from recognition of an adjustment of a derivative instrument at fair value depends on the purpose for issuing or holding the derivative instrument. Gains and losses from derivatives that are not accounted for as hedges under International Financial Reporting Standard (“IFRS”) 9 Financial Instruments are recognized immediately in the profit or loss for the period.
3. Significant accounting policies (continued) Financial assets (continued) Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Subsequent to initial recognition, the fair value of financial assets at fair value that are quoted in an active market is defined as bid prices for assets and ask prices for issued liabilities as of the measurement date. If no active market exists for financial assets, the Company measures the fair value using the following methods: analysis of recent transactions with peer instruments between independent parties; current fair value of similar financial instruments; discounting future cash flows. The discount rate reflects the minimum return on investment an investor is willing to accept before starting an alternative project, given its risk and the opportunity cost of forgoing other projects. A financial asset shall be measured at amortised cost if both of the following conditions are met: (a) the financial asset is held within a business model whose objective is to hold financial assets in order to collect contractual cash flows and (b) the contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding. Examples of financial assets that may fall into this category are loans given, accounts receivable, bonds and notes issued by 3rd parties, which are not quoted at active market – if they fulfill the requirements set above. A financial asset shall be measured at fair value through other comprehensive income if both of the following conditions are met: (a) the financial asset is held within a business model whose objective is achieved by both collecting contractual cash flows and selling financial assets and (b) the contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding. In particular, this category includes shares of other companies, which are not included in the category of measured at fair value through profit or loss. Dividends and interest income are recognized in the consolidated statement of profit or loss on an accrual basis. The amount of accrued interest income is calculated using the effective interest rate. Upon de-recognition of debt financial assets (bonds, notes etc.) classified as financial instruments at fair value through other comprehensive income, cumulative gains or losses previously recognized in other comprehensive income are reclassified to profit or loss. In case of equity financial assets (shares, stocks etc.), classified as financial instruments at fair value through other comprehensive income, such cumulative gain or loss shall never be subsequently transferred to profit or loss. Interest income as a component of finance income is disclosed in the notes to financial statements separately for each category of financial assets. Regular way purchases and sales of financial assets are accounted for at trade date.
3. Significant accounting policies (continued) Financial liabilities The Company recognizes financial liabilities on its balance sheet when, and only when, it becomes a party to the contractual provisions of the financial instrument. When financial liabilities are recognized initially, they are measured at fair value, which is usually the price of the transaction, i.e. the fair value of consideration paid or received. When financial liabilities are recognized initially, they are classified as one of the following: financial liabilities at fair value through profit or loss; other financial liabilities. Financial liabilities at fair value through profit or loss are financial liabilities held for trading unless such liabilities are linked to the delivery of unquoted equity instruments. At the initial recognition, the Company may include in this category any financial liability, except for equity instruments that are not quoted in an active market and whose fair value cannot be reliably measured. After initial recognition, however, the liability cannot be reclassified. Financial liabilities not classified as financial liabilities at fair value through profit or loss are designated as other financial liabilities. Other financial liabilities include, inter alia, trade and other accounts payable, and loans and borrowings payable. Subsequent to initial recognition, financial liabilities at fair value through profit or loss are measured at fair value, with changes in fair value recognized in profit or loss in the consolidated statement of profit or loss. Other financial liabilities are carried at amortized cost. The Company writes off a financial liability (or part of a financial liability) from its balance sheet when, and only when, it is extinguished – i.e. when the obligation specified in the contract is discharged, cancelled or expires. The difference between the carrying value of a financial liability (or a part of a financial liability) extinguished or transferred to another party and the redemption value, including any transferred non-monetary assets and assumed liabilities, is recognized in profit or loss. Any previously recognized components of other comprehensive income pertaining to this financial liability are also included in the financial result and are recognized as gains and losses for the period. Certain prior period indicators have been reclassified to conform to the current year presentation. In particular, due to significant increase in the operating activities of subsidiary banks of the Company and the need for reliable and consistent reporting in the consolidated financial statements, the presentation of cash flows from the operating activities of subsidiary banks was revised. Such activities are now included within operating activities of the Consolidated Statement of Cash Flows. Further, the operating assets of the subsidiary banks, including short-term interbank deposits placed, were reclassified to Accounts Receivable, operating liabilities, including interbank loans, customer deposits, promissory notes and REPO obligations reclassified from Loans and borrowings and other financial liabilities to Accounts payable and accrued liabilities. Earnings per share Basic earnings per share is calculated by dividing net earnings attributable to common shares by the weighted average number of common shares outstanding during the corresponding period. In the absence of any securities-to-shares conversion transactions, the amount of basic earnings per share stated in these consolidated financial statements is equal to the amount of diluted earnings per share.
3. Significant accounting policies (continued) Treasury shares Treasury shares are outstanding Treasury shares purchased from the shareholders. The Company acquires shares of Rosneft in accordance with the program of acquisition of shares in the open market (Note 36). Treasury shares are presented in the consolidated balance sheet as a deduction from equity at cost of repurchase. Inventories Inventories consisting primarily of crude oil, petroleum products, petrochemicals and materials and supplies are accounted for at the weighted average cost unless net realizable value is less than cost. Materials that are used in production are not written down below cost if the finished products into which they will be incorporated are expected to be sold above cost. Repurchase and resale agreements Securities sold under repurchase agreements (“REPO”) and securities purchased under agreements to resell (“reverse REPO”) generally do not constitute a sale of the underlying securities for accounting purposes, and so are treated as collateralized financing transactions. Interest paid or received on all REPO and reverse REPO transactions is recorded in Finance expense or Finance income, respectively, at the contractually specified rate using the effective interest method. Exploration and production assets Exploration and production assets include exploration and evaluation assets, mineral rights and oil and gas properties (development assets and production assets). Exploration and evaluation costs The Company recognizes exploration and evaluation costs using the successful efforts method as permitted by IFRS 6 Exploration for and Evaluation of Mineral Resources. Under this method, costs related to exploration and evaluation (license acquisition costs, exploration and appraisal drilling) are temporarily capitalized in cost centers by field (well) until the drilling program results in the discovery of economically feasible oil and gas reserves. The length of time necessary for this determination depends on the specific technical or economic difficulties in assessing the recoverability of the reserves. If a determination is made that the well did not encounter oil and gas in economically viable quantities, the well costs are expensed to Exploration expenses in the consolidated statement of profit or loss. Exploration and evaluation costs, except for costs associated with seismic, topographical, geological, and geophysical surveys, are initially capitalized as exploration and evaluation assets. Exploration and evaluation assets are recognized at cost less impairment, if any, as property, plant and equipment until the existence (or absence) of commercial reserves has been established. The initial cost of exploration and evaluation assets acquired through a business combination is formed as a result of purchase price allocation. The cost allocation to mineral rights to proved properties and mineral rights to unproved properties is performed based on the respective oil and gas reserves information. Exploration and evaluation assets are subject to technical, commercial and management review as well as review for indicators of impairment at least once a year. This is to confirm the continued intent to develop or otherwise extract value from the discovery. When indicators of impairment are present, an impairment test is performed. If, subsequently, commercial reserves are discovered, the carrying value, less losses from impairment of the respective exploration and evaluation assets, is classified as oil and gas properties (development assets). However, if no commercial reserves are discovered, such costs are expensed after exploration and evaluation activities have been completed.
3. Significant accounting policies (continued) Development and production Oil and gas properties (development assets) are accounted for on a field-by-field basis and represent (1) capitalized costs to develop discovered commercial reserves and to put fields into production, and (2) exploration and evaluation costs incurred to discover commercial reserves reclassified from exploration and evaluation assets to oil and gas properties (development assets) following the discovery of commercial reserves. The cost of oil and gas properties (development assets) also includes the expenditures to acquire such assets, directly identifiable overhead expenses, capitalized financing costs and related asset retirement (decommissioning) obligation costs. Oil and gas properties (development assets) are generally recognized as construction in progress. Following the commencement of commercial production, oil and gas properties (development assets) are reclassified as oil and gas properties (production assets). Other property, plant and equipment Other property, plant and equipment is stated at historical cost as of the acquisition date, except for property, plant and equipment acquired prior to January 1, 2009, which is stated at deemed cost, net of accumulated depreciation and impairment. The cost of maintenance, repairs, and the replacement of minor items of property is charged to operating expenses. Renewals and betterments of assets are capitalized. Upon the sale or retirement of property, plant and equipment, the cost and related accumulated depreciation are eliminated from the accounts. Any resulting gains or losses are included in profit or loss. Depreciation, depletion and amortization Oil and gas properties are depleted using the unit-of-production method on a field-by-field basis starting from the commencement of commercial production. In applying the unit-of-production method to mineral licenses, the depletion rate is based on total proved reserves. In applying the unit-of-production method to producing wells and the related oil and gas infrastructure, the depletion rate is based on proved developed reserves. Other property, plant and equipment are depreciated using the straight-line method over their estimated useful lives from the time they are ready for use, except for catalysts which are amortized using the unit-of-production method. Components of other property, plant and equipment and their respective estimated useful lives are as follows: Property, plant and equipment Useful life, not more than Buildings and structures 30-45 years Plant and machinery 5-25 years Vehicles and other property, plant and equipment 6-10 years Service vessels 20 years Offshore drilling assets 20 years Land generally has an indefinite useful life and is therefore not depreciated. Land leasehold rights are amortized on a straight-line basis over their expected useful life, which averages 20 years.
3. Significant accounting policies (continued) Construction grants The Company recognizes construction grants from local governments when there is a reasonable assurance that the Company will comply with the conditions attached and that the grant will be received. The construction grants are accounted for as a reduction of the cost of the asset for which the grant is received. Impairment of non-current assets The Company assesses at each balance sheet date whether there is any indication that an asset or cash- generating unit may be impaired. If any such indication exists, the Company estimates the recoverable amount of the asset or cash-generating unit. In assessing whether there is any indication that an asset may be impaired, the Company considers internal and external sources of information. It considers at least the following: External sources of information: during the period, an asset’s market value has declined significantly more than would be expected as a result of the passage of time or normal use; significant changes with an adverse effect on the Company have taken place during the period, or will take place in the near future, in the technological, market, economic or legal environment in which the Company operates or in the market to which an asset is dedicated; market interest rates or other market rates of return on investments have increased during the period, and those increases are likely to affect the discount rate used in calculating an asset’s value in use and decrease the asset’s recoverable amount materially; the carrying amount of the net assets of the Company is more than its market capitalization. Internal sources of information: evidence is available of obsolescence or physical damage of an asset; significant changes with an adverse effect on the Company have taken place during the period, or are expected to take place in the near future, in the extent to which, or manner in which, an asset is used or is expected to be used (e.g., the asset becoming idle, or the useful life of an asset is reassessed as finite rather than indefinite); information on dividends from a subsidiary, joint venture or associate; evidence is available from internal reporting that indicates that the economic performance of an asset is, or will be, worse than expected. Such evidence includes the existence of: cash flows on acquiring the asset, or subsequent cash needs for operating or maintaining it, that are significantly higher than those originally budgeted; actual net cash flows or operating profit or loss flowing from the asset that are significantly worse than those budgeted; a significant decline in budgeted net cash flows or operating profit, or a significant increase in budgeted losses, flowing from the asset; operating losses or net cash outflows for the asset, when current period amounts are aggregated with budgeted amounts for the future.
3. Significant accounting policies (continued) Impairment of non-current assets (continued) The following factors indicate that exploration and evaluation assets may be impaired: the period for which the Company has the right to explore in the specific area has expired during the period or will expire in the near future, and is not expected to be renewed; substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is neither budgeted nor planned; exploration for and evaluation of mineral resources in the specific area have not led to the discovery of commercially viable quantities of mineral resources and the Company has decided to discontinue such activities in the specific area; sufficient data exist to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale. The recoverable amount of an asset or a cash-generating unit is the higher of: the value in use of an asset (cash-generating unit); and the fair value of an asset (cash-generating unit) less costs to sell. If the asset does not generate cash inflows that are largely independent of those from other assets, its recoverable amount is determined for the asset’s cash-generating unit. The Company initially measures the value in use of a cash-generating unit. When the carrying amount of a cash-generating unit is greater than its value in use, the Company measures the unit’s fair value for the purpose of measuring the recoverable amount. When the fair value is less than the carrying value an impairment loss is recognized. Value in use is determined by discounting the estimated value of the future cash inflows expected to be derived from the asset or cash-generating unit, including cash inflows from its sale. The value of the future cash inflows from a cash-generating unit is determined based on the forecast approved by management of the business unit to which the unit in question pertains. Impairment of financial assets At each balance sheet date the Company recognizes a loss allowance for expected credit losses on a financial asset measured at amortised cost, and at fair value through other comprehensive income, a lease receivable, a contract asset or a loan commitment and a financial guarantee contract to which the impairment requirements apply. Requirements of IFRS 9 concerning impairment do not apply to equity instruments of any category as well as to the instruments at fair value though profit or loss. The loss allowance for financial asset at amortised cost is recognized in profit or loss in correspondence with a balance sheet account reducing the carrying amount of the financial asset. The loss allowance for financial assets at fair value through other comprehensive income shall be recognized in other comprehensive income and shall not reduce the carrying amount of the financial asset in the statement of financial position. Expected credit losses for significant counterparties, including banks, are determined based on credit rating of particular counterparty and relevant probability of default.
3. Significant accounting policies (continued) Capitalized interest Interest expense on borrowed funds used for capital construction projects and the acquisition of property, plant and equipment is capitalized provided that the interest expense could have been avoided if the Company had not made capital investments. Interest is capitalized only during the period when construction activities are actually in progress and until the resulting properties are put into operation. Capitalized borrowing costs include exchange differences arising from foreign currency borrowings to the extent that they are regarded as an adjustment to interest costs. Leasing agreements Leases, which transfer to the Company substantially all the risks and benefits incidental to ownership of the asset, are classified as financial leases and are capitalized at the commencement of the lease at the fair value of the leased property or, if lower, at the present value of the minimum lease payments. Lease payments are apportioned between the finance expenses and reduction of the lease liability in order to achieve a constant rate of interest on the remaining balance of the liabilities. Finance expenses are charged directly to the consolidated statement of profit or loss. Leased property, plant and equipment are accounted for using the same policies applied to the Company’s own assets. In determining the useful life of a leased item of property, plant and equipment, consideration is given to the probability of the title being transferred to the lessee at the end of the lease term. If there is no reasonable certainty that the lessee will obtain ownership by the end of the lease term, the asset shall be fully depreciated over the shorter of the lease term and its useful life. Where such certainty exists, the asset is depreciated over its useful life. Leases where the lessor retains substantially all the risks and benefits of ownership of the asset are classified as operating leases. Operating lease payments are recognized as an expense in the consolidated statement of profit or loss on a straight-line basis over the lease term. Asset retirement (decommissioning) obligations The Company has asset retirement (decommissioning) obligations associated with its core business activities. The nature of the assets and potential obligations are as follows: The Company’s exploration, development and production activities involve the use of wells, related equipment and operating sites, oil gathering and treatment facilities, tank farms and in-field pipelines. Generally, licenses and other regulatory acts require that such assets be decommissioned upon the completion of production. According to these requirements, the Company is obliged to decommission wells, dismantle equipment, restore the sites and perform other related activities. The Company’s estimates of these obligations are based on current regulatory or license requirements, as well as actual dismantling and other related costs. These liabilities are measured by the Company using the present value of the estimated future costs of decommissioning of these assets. The discount rate is reviewed at each reporting date and reflects current market assessments of the time value of money and the risks specific to the liability.
3. Significant accounting policies (continued) Asset retirement (decommissioning) obligations (continued) In accordance with IFRS Interpretations Committee (“IFRIC”) Interpretation 1 Changes in Existing Decommissioning, Restoration and Similar Liabilities, the provision is reviewed at each balance sheet date as follows: upon changes in the estimates of future cash flows (e.g., the costs of and timeframe for abandoning one well) or the discount rate, changes in the amount of the liability are included in the cost of the item of property, plant, and equipment, whereby such cost may not be negative and may not exceed the recoverable value of the item of property, plant, and equipment; any changes in the liability due to its nearing maturity (change in the discount) are recognized in Finance expenses. The Company’s refining and distribution activities involve refining operations, marine and other distribution terminals, and retail sales. The Company’s refining operations consist of major petrochemical operations and industrial complexes. Legal or contractual asset retirement (decommissioning) obligations related to petrochemical, oil refining and distribution activities are not recognized due to the limited history of such activities in these segments, the lack of clear legal requirements as to the recognition of obligations, as well as the fact that decommissioning periods for such assets are not determinable. Because of the reasons described above, the fair value of an asset retirement (decommissioning) obligation in the refining and distribution segment cannot be reasonably estimated. Due to continuous changes in the Russian regulatory and legal environment, there could be future changes to the requirements and contingencies associated with the retirement of long-lived assets. Income tax Since 2012 Russian tax legislation has allowed income taxes to be calculated on a consolidated basis. The main subsidiaries of the Company were therefore combined into a consolidated group of taxpayers (Note 40). For subsidiaries which are not included in the consolidated group of taxpayers, income tax is calculated on an individual subsidiary basis. Deferred income tax assets and liabilities are recognized in the accompanying consolidated financial statements in the amount determined by the Company in accordance with IAS 12 Income Taxes. Deferred tax is provided using the liability method on temporary differences at the reporting date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. A deferred tax liability is recognized for all taxable temporary differences, except to the extent that the deferred tax liability arises from: the initial recognition of goodwill; the initial recognition of an asset or liability in a transaction which: is not a business combination; and affects neither accounting profit, nor taxable profit; investments in subsidiaries when the Company is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future.
3. Significant accounting policies (continued) Income tax (continued) A prior period tax loss planned to be used to reduce the current or future amount of income tax is recognized as a deferred tax asset. A deferred tax asset is recognized only to the extent that it is probable that taxable profit will be available against which the deductible temporary differences can be utilized, unless the deferred tax asset arises from the initial recognition of an asset or liability in a transaction that: is not a business combination; and at the time of the transaction, affects neither accounting profit nor taxable profit (tax loss). The Company recognizes deferred tax assets for all deductible temporary differences arising from investments in subsidiaries and associates, and interests in joint ventures, to the extent that the following two conditions are met: the temporary difference will reverse in the foreseeable future; and taxable profit will be available against which the temporary difference can be utilized. Deferred tax assets and liabilities shall be measured at the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted by the end of the reporting period. The measurement of deferred tax assets and liabilities reflects the tax consequences that would follow from the manner in which the Company expects, at the end of the reporting period, to recover or settle the carrying amount of its assets and liabilities. Deferred tax assets and liabilities are offset when there is a legally enforceable right to set off current tax assets against current tax liabilities and when they relate to income taxes levied by the taxation authority of the same jurisdiction and the Company intends to settle its current tax assets and liabilities on a net basis. The carrying amount of a deferred tax asset is reviewed at each balance sheet date. The Company reduces the carrying amount of a deferred tax asset to the extent that it is no longer probable that sufficient taxable profit will be available to allow the benefit of part or all of that deferred tax asset to be utilized. Deferred tax assets and liabilities are classified as Non-current Deferred tax assets and Non-current Deferred tax liabilities, respectively. Deferred tax assets and liabilities are not discounted. Recognition of revenues Revenues are recognized when (or as) the Company satisfies a performance obligation by transferring a promised good or service (i.e. an asset) to a customer. An asset is transferred when (or as) the customer obtains control of that asset, which usually occurs when the title is passed, provided that the contract price is fixed or determinable and collectability of the receivable is reasonably assured. Specifically, domestic sales of crude oil and gas, as well as petroleum products and materials are usually recognized when title passes. For export sales, title generally passes at the border of the Russian Federation. Revenue is measured at the fair value of the consideration received or receivable taking into account the amount of any trade discounts, volume rebates and reimbursable taxes. Sales of support services are recognized as services are performed provided that the service price can be determined and no significant uncertainties regarding the receipt of revenues exist.
3. Significant accounting policies (continued) Transportation expenses Transportation expenses recognized in the consolidated statement of profit or loss represent all expenses incurred by the Company to transport crude oil for refining and to end customers, and to deliver petroleum products from refineries to end customers (these may include pipeline tariffs and any additional railroad transportation costs, handling costs, port fees, sea freight and other costs). Refinery maintenance costs The Company recognizes the costs of overhauls and preventive maintenance performed with respect to oil refining assets as expenses when incurred. Environmental liabilities Expenditures that relate to an existing condition caused by past operations, and do not have a future economic benefit, are expensed. Liabilities for these expenditures are recorded when environmental assessments or clean- ups are probable and the costs can be reasonably estimated. Accounting for contingencies Certain conditions may exist as of the date of these consolidated financial statements which may further result in a loss to the Company, but which will only be resolved when one or more future events occur or fail to occur. The Company’s management makes an assessment of such contingent liabilities which is based on assumptions and is a matter of opinion. In assessing loss contingencies relating to legal or tax proceedings that involve the Company or unasserted claims that may result in such proceedings, the Company, after consultation with legal or tax advisors, evaluates the perceived merits of any legal or tax proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. If the assessment of a contingency indicates that it is probable that a loss will be incurred and the amount of the liability can be estimated, then the estimated liability is accrued in the Company’s consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable, but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, would be disclosed. Loss contingencies considered remote are generally not disclosed unless they involve financial guarantees, in which case the nature of the guarantee would be disclosed. However, in some instances in which disclosure is not otherwise required, the Company may disclose contingent liabilities or other uncertainties of an unusual nature which, in the judgment of management after consultation with its legal or tax counsel, may be of interest to shareholders or others. Taxes collected from customers and remitted to governmental authorities Refundable taxes (excise and value-added tax (“VAT”)) are deducted from revenues. Other taxes and duties are not deducted from revenues and are recognized as expenses in Taxes other than income tax in the consolidated statement of profit or loss. VAT and excise receivable and payable are recognized as Prepayments and other current assets and Other tax liabilities in the consolidated balance sheet, respectively.
3. Significant accounting policies (continued) Functional and presentation currency The consolidated financial statements are presented in Russian rubles, which is the functional currency of Rosneft Oil Company and all of its subsidiaries operating in the Russian Federation. The functional currency of the foreign subsidiaries is generally the U.S. dollar. Transactions and balances Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of these transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation of monetary assets and liabilities denominated in foreign currencies at year-end exchange rates are recognized in the profit or loss for the period. Foreign exchange gains and losses resulting from the translation of monetary assets and liabilities designated as foreign currency cash flow hedging instruments are recognized within other comprehensive income and reclassified to profit or loss in the period when the hedged item affects profit or loss. Non-monetary items that are measured in terms of historical cost in a foreign currency are translated using the exchange rates as at the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value is determined. The Company’s subsidiaries The results and financial position of all of the Company’s subsidiaries, joint ventures and associates that have a functional currency which is different from the presentation currency are translated into the presentation currency as follows: assets and liabilities for each balance sheet presented are translated at the closing rate at that reporting date; income and expenses for each statement of profit or loss and each statement of other comprehensive income are translated at average exchange rates (unless this average is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the rate on the dates of the transactions); and all resulting exchange differences are recognized as a separate component of other comprehensive income. Prepayment on oil and petroleum products supply agreements In the ordinary course of business, the Company enters into long-term oil supply contracts. The contract terms may require the buyer to make a prepayment. The Company considers long-term oil supply contracts to be regular-way sale contracts entered into and continued to be held for the purpose of the receipt or delivery of non-financial items in accordance with the Company’s expected purchase, sale or usage requirements. Regular-way sale contracts are exempted from the scope of IAS 32 Financial Instruments: Presentation and IFRS 9 Financial Instruments.
3. Significant accounting policies (continued) Prepayment on oil and petroleum products supply agreements (continued) Conditions for meeting the definition of a regular-way sale are not met if either of the following applies: the ability to settle net in cash or another financial instrument, or by exchanging financial instruments, is not explicit in the terms of the contract, but the Company has a practice of settling similar contracts net in cash or via another financial instrument or by exchanging financial instruments (whether with the counterparty, by entering into offsetting contracts or by selling the contract before its exercise or lapse); for similar contracts, the Company has a practice of taking delivery of the underlying goods and selling them within a short period after delivery for the purpose of generating a profit from short-term fluctuations in price or from a dealer’s margin. Prepayments received for the delivery of goods or respective deferred revenue are accounted for as non- financial liabilities because the outflow of economic benefits associated with them is the delivery of goods and services rather than a contractual obligation to pay cash or another financial asset. Changes in accounting policies and disclosures The accounting policies adopted are consistent with those of the previous financial year except for the adoption of new standards, interpretations and amendments to standards effective as of January 1, 2018. The following standards were applied for the first time in 2018: IFRS 9 Financial Instruments. The final version of IFRS 9 issued in 2014 replaces IAS 39 Financial Instruments: Recognition and Measurement, as well as all previous versions of IFRS 9. IFRS 9 brings together the requirements for the classification and measurement, impairment and hedge accounting of financial instruments. In respect of impairment, IFRS 9 replaces the “incurred loss” model used in IAS 39 with a new “expected credit loss” model that will require a more timely recognition of expected credit losses. According to the new standard, expected credit losses for significant debt balances were estimated based on the credit risk of the debtors. Also due to the new requirements, certain of the financial instruments of the Company were measured to their fair value as a consequence of the change in classification category from measured at amortized cost to measured at fair value through profit or loss. Together with IFRS 9 the Company early adopted amendments to IAS 28 Investments in Associates and Joint Ventures effective for annual periods beginning on or after January 1, 2019. These amendments clarify that the companies should apply IFRS 9, including impairment requirements, for the long-term investments in associates and joint ventures, which are accounted for otherwise than using the equity method, including long-term loans given to associates and joint ventures. IFRS 15 Revenue from Contracts with Customers. IFRS 15 establishes a single framework for revenue recognition and contains requirements for related disclosures. The new standard replaces IAS 18 Revenue, IAS 11 Construction Contracts, and the related interpretations on Revenue recognition. As a result of the analysis performed by the Company, the conclusion was made that the standard has no significant impact on the consolidated financial statements. Amendments to IFRS 2 Share-based Payment entitled Classification and Measurement of Share-based Payment Transactions. The amendments provide requirements for the accounting for the effects of vesting and non-vesting conditions on the measurement of cash-settled share-based payments; share- based payment transactions with a net settlement feature for withholding tax obligations; a modification to the terms and conditions of a share-based payment that changes the classification of the transaction from cash-settled to equity-settled. The amendments did not have a material impact on the consolidated financial statements.
3. Significant accounting policies (continued) Changes in accounting policies and disclosures (continued) Amendments to IFRS 4 Insurance Contracts entitled Applying IFRS 9 Financial Instruments with IFRS 4 Insurance Contracts. The amendments address concerns arising from implementing the new financial instruments Standard, IFRS 9, before implementing the replacement. Standard that the Board is developing for IFRS 4. The amendments introduce two approaches, which should reconcile the timing of the application of the two new standards. Under the first approach, the amendments become effective on the date of first-time adoption of IFRS 9; under the second, the amendments become effective for annual periods beginning on or after January 1, 2018. The amendments did not have a material impact on the consolidated financial statements. Amendments to IAS 40 Investment Property entitled Transfers of Investment Property. The amendments clarify the requirements for transfers to, or from, investment property. The amendments did not have a material impact on the consolidated financial statements. IFRIC 22 Interpretation entitled Foreign Currency Transactions and Advance Consideration. The IFRIC addresses how to determine the date of the transaction for the purpose of determining the exchange rate to use on initial recognition of the related asset, expense or income (or part of it) on the de-recognition of a non-monetary asset or non-monetary liability arising from the payment or receipt of advance consideration in a foreign currency. The interpretation did not have a material impact on the consolidated financial statements as its requirements were already previously incorporated in the accounting policy of the Company. Effect of the first application of IFRS 9 Financial Instruments Financial assets by categories Carrying amount as of December 31, 2017 Remeasure- ment due to reclassifica- tion Total as of January 1, 2018 Loss allowance per IAS 39 as at January 1, 2018 Increase in allowance Loss allowance per IFRS 9 as at January 1, 2018 I. Cash and cash equivalents Cash on hand and in bank accounts in RUB 44 – 44 – (1) (1) Cash on hand and in bank accounts in foreign currencies 124 – 124 – – – Deposits and other cash equivalents in RUB 142 – 142 – – – Other 12 – 12 – – – Total Cash and cash equivalents 322 – 322 – (1) (1) II. Other short-term financial assets Financial assets at fair value through other comprehensive income Notes from Loans and receivables 66 – 66 – (2) (2) Notes from Available for Sale 19 – 19 – – – Bonds from Available for Sale 116 – 116 – – – Government bonds from Held to Maturity 1 – 1 – – – Stocks and shares from Available for Sale 44 – 44 – – – Financial assets at amortized cost Loans given from Loans and receivables 13 – 13 – – – Loans given to associates from Loans and receivables 32 – 32 – (6) (6) Deposits and certificates of deposit from Loans and receivables 43 – 43 – – – Bonds from Held to Maturity 1 – 1 – – – Financial assets at fair value through profit or loss Deposits and certificates of deposit from Loans and receivables 1 – 1 – – – Total Other short-term financial assets 336 – 336 – (8) (8)
3. Significant accounting policies (continued) Effect of the first application of IFRS 9 Financial Instruments (continued) Financial assets by categories Carrying amount as of December 31, 2017 Remeasure- ment due to reclassifica- tion Total as of January 1, 2018 Loss allowance per IAS 39 as at January 1, 2018 Increase in allowance Loss allowance per IFRS 9 as at January 1, 2018 III. Accounts receivable Trade receivables 658 – 658 (26) (9) (35) Bank loans to customers 108 – 108 – – – Other accounts receivable 116 – 116 (13) (2) (15) Total Accounts receivable 882 – 882 (39) (11) (50) IV. Other long-term financial assets Financial assets at fair value through profit or loss Bank deposits from Held to Maturity 493 (5) 488 – – – Financial assets at amortized cost Bonds from Held to Maturity 13 – 13 – – – Bank deposits from Held to Maturity 49 – 49 – – – Loans given to associates and joint ventures from Loans and receivables 26 – 26 – (8) (8) Long-term loans given from Loans and receivables 4 – 4 – – – Other accounts receivable 3 – 3 – Financial assets at fair value through other comprehensive income Shares of PJSC INTER RAO UES 4 – 4 – – – Shares of PJSC Russian Grids 1 – 1 – – – Shares of JSC Modern Shipbuilding Technology 11 – 11 – – – Other shares 2 – 2 – – – Total Other long-term financial assets 606 (5) 601 – (8) (8) Subtotal 2,146 (5) 2,141 (39) (28) (67) Pre-tax effect on retained earnings (33) After-tax effect on retained earnings (28) 4. Significant accounting judgments, estimates and assumptions The preparation of consolidated financial statements requires management to make a number of accounting estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities. The actual results, however, could differ from those estimates. The most significant accounting estimates and assumptions used by the Company’s management in preparing the consolidated financial statements include: estimation of oil and gas reserves; estimation of rights to, recoverability and useful lives of non-current assets; impairment of goodwill and fixed assets (Note 25 “Intangible assets and goodwill” and Note 24 “Property, plant and equipment and construction in progress”); estimated credit losses for accounts receivable (Note 21 “Accounts receivable”); assessment of asset retirement (decommissioning) obligations (Note 3 “Significant accounting policies”, section: “Asset retirement (decommissioning) obligations”, and Note 32 “Provisions”); assessment of legal and tax contingencies, recognition and disclosure of contingent liabilities (Note 40 “Contingencies”);
4. Significant accounting judgments, estimates and assumptions (continued) assessment of deferred income tax assets and liabilities (Note 3 “Significant accounting policies”, section: “Income tax”, and Note 16 “Income tax”); assessment of environmental remediation obligations (Note 32 “Provisions” and Note 40 “Contingencies”); fair value measurements (Note 37 “Fair value of financial instruments”); assessment of the Company’s ability to renew operating leases and to enter into new lease agreements; purchase price allocation to the identifiable assets acquired and the liabilities assumed (Note 7 “Acquisition of subsidiaries and shares in joint operations”). Significant estimates and assumptions affecting the reported amounts are those used in determining the economic recoverability of reserves. Such estimates and assumptions may change over time when new information becomes available, e.g.: more detailed information on reserves was obtained (either as a result of more detailed engineering calculations or additional exploration drilling activities); supplemental activities to enhance oil recovery were conducted; changes were made in economic estimates and assumptions (e.g. a change in pricing factors). 5. New and amended standards and interpretations issued but not yet effective In January 2016, the IASB issued IFRS 16 Leases. IFRS 16 eliminates the classification of leases as either operating leases or finance leases and establishes a single lessee accounting model. The most significant effect of the new requirements for the lessee will be an increase in right-of-use assets and financial liabilities. The new standard replaces the previous leases standard, IAS 17 Leases, and the related interpretations. The standard is effective for annual periods beginning on or after January 1, 2019. The Company will apply the Standard using modified retrospective approach which presumes recognition of cumulative effect of initial application at the date of the initial application i.e. January 1, 2019. According to preliminary estimates made by the Company, one-off recognition of non-current assets and financial liabilities will total 220-300 bln RUR as of January 1, 2019. In May 2017, the IASB issued IFRS 17 Insurance Contracts. IFRS 17 establishes a single framework for the accounting for insurance contracts and contains requirements for related disclosures. The new standard replaces IFRS 4 Insurance Contracts. The standard is effective for annual periods beginning on or after January 1, 2021. The Company does not expect the standard to have a material impact on the consolidated financial statements. In June 2017, the IASB issued IFRIC 23 Interpretation entitled Uncertainty over Income Tax Treatments. The IFRIC clarifies that for the purposes of calculating current and deferred tax, companies should use a tax treatment of uncertainties, which will probably be accepted by the tax authorities. IFRIC 23 is effective for annual periods beginning on or after January 1, 2019. The Company does not expect the interpretation to have a material impact on the consolidated financial statements. In October 2017, the IASB issued amendments to IFRS 9 Financial instruments named Prepayment Features with Negative Compensation. The amendments relate to financial assets with an option of early prepayment, the conditions of which allow early prepayment in a variable amount, which in turn may exceed as well as may be lower than remaining outstanding cash flows. The amendments allow to measure such prepayable financial assets with so-called negative compensation at amortized cost or at fair value through other comprehensive income if a specified condition is met – instead of at fair value through profit or loss. The amendments are effective for annual periods beginning on or after January, 2019. The Company does not expect the amendments to have a material impact on the consolidated financial statements.
5. New and amended standards and interpretations issued but not yet effective (continued) In February 2018, the IASB issued amendments to IAS 19 Employee benefits named Plan Amendment, Curtailment or Settlement. The amendments specifies how companies determine pension expenses when changes to a defined benefit pension plan occur. The amendments are effective for annual periods beginning on or after January, 2019. The Company does not expect the amendments to have a material impact on the consolidated financial statements. In March 2018, the IASB issued a revised version of Conceptual Framework for Financial Reporting. In particular, the revised version introduces new definitions of assets and liabilities, as well as amended definitions of income and expenses. The new version is effective for annual periods beginning on or after January, 2020. The Company is currently assessing the impact of the revised version of Conceptual Framework on the consolidated financial statements. In October 2018, the IASB issued amendments to IFRS 3 Business Combinations. The amendments enhance definition of a business set out by the standard. The amendments are effective for acquisitions to occur on or after January 1, 2020; earlier application is permitted. Possible impact of the amendments on the consolidated financial statements as well as the necessity of early adoption will be assessed in course of accounting support for future significant transactions. In October 2018, the IASB issued amendments to IAS 1 Presentation of Financial Statements and IAS 8 Accounting policies, Changes in Accounting Estimates and Errors. The amendments to IAS 1 and IAS 8 introduce new definition of material. The amendments are effective on or after January 1, 2020; earlier application is permitted. The Company does not expect the amendments to have a material impact on the consolidated financial statements. 6. Capital and financial risk management Capital management The Company’s capital management objectives are to ensure its ability to continue as a going concern and to optimize the cost of capital in order to enhance value to shareholders. Total capital employed and financial liabilities less liquid financial assets are non-IFRS measures. The Company’s management performs a regular assessment of the financial liabilities less liquid financial assets to capital employed ratio to ensure it meets the Company’s requirements to fulfil the Company’s commitments and to retain strong financial stability. The Company’s employed capital is calculated as the sum of equity attributable to equity holders of Rosneft: share capital, reserves, retained earnings and non-controlling interests; financial liabilities, which include long and short-term loans and borrowings, other financial liabilities, as reported in the consolidated balance sheet, less liquid financial assets, including cash and cash equivalents, other short-term financial assets and certain long-term deposits. The Company’s financial liabilities less liquid financial assets to capital employed ratio was as follows: As of December 31, 2018 2017 (restated) Financial liabilities less liquid financial assets to capital employed ratio, % 37.9% 40.8%
6. Capital and financial risk management (continued) Financial risk management In the normal course of business the Company is exposed to the following financial risks: market risk (including foreign currency risk, interest rate risk and commodity price risk), credit risk and liquidity risk. The Company has introduced a risk management system and developed a number of procedures to measure, assess and monitor risks and select the relevant risk management techniques. The Company has developed, documented and approved the relevant policies pertaining to market, credit and liquidity risks and the use of derivative financial instruments. Foreign currency risk The Company undertakes transactions denominated in foreign currencies and is exposed to foreign exchange risk arising from various currency exposures, primarily with respect to the U.S. dollar and euro. Foreign exchange risk arises from assets, liabilities, commercial transactions and financing denominated in foreign currencies. The carrying values of monetary assets and liabilities denominated in foreign currencies are presented in the table below: Assets Liabilities As of December 31, As of December 31, 2018 2017 2018 2017 US$ 864 903 (1,969) (1,885) EUR 684 425 (340) (67) Total 1,548 1,328 (2,309) (1,952) The Company seeks to identify and manage foreign exchange rate risk in a comprehensive manner, including an integrated analysis of natural economic hedges, in order to benefit from the correlation between income and expenses. The Company chooses the currency in which to hold cash, such as the Russian ruble, U.S. dollar or other currency for short-term risk management purposes. The long-term risk management strategy of the Company may involve the use of derivative or non-derivative financial instruments in order to minimize foreign exchange rate risk exposure. Cash flow hedging of the Company’s future exports The Company designated certain U.S. dollar-denominated borrowings as a hedge of the expected highly probable U.S. dollar-denominated export revenue stream in accordance with IFRS 9 Financial Instruments. A portion of future monthly export revenues expected to be received in U.S. dollars was designated as a hedged item. The nominal amounts of the hedged item and the hedging instruments were equal. To the extent that a change in the foreign currency rate impacts the fair value of the hedging instrument, the effects are recognized in other comprehensive income or loss and then reclassified to profit or loss in the period in which the hedged item affects the profit or loss. The Company’s foreign currency risk management strategy is to hedge future export revenue in the amount of the net monetary position in U.S. dollars. The Company aligns the hedged nominal amount to the net monetary position in U.S. dollars on a periodical basis.
6. Capital and financial risk management (continued) Cash flow hedging of the Company’s future exports (continued) Changes in the nominal hedging amount during 2018 are presented in the table below: US$ million The equivalent amount at the CBR exchange rate as of December 31, 2018, RUB billion Nominal amount as of December 31, 2017 873 61 Hedging instruments designated – – Realized cash flow foreign exchange hedges (55) (4) Hedging instruments de-designated (818) (57) Nominal amount as of December 31, 2018 – – The impact of foreign exchange cash flow hedges recognized in other comprehensive income is set out below: 2018 2017 Before income tax Income tax Net of tax Before income tax Income tax Net of tax Total recognized in other comprehensive (loss)/income as of the beginning of the year (290) 58 (232) (435) 87 (348) Foreign exchange effects recognized during the year – – – (1) – (1) Foreign exchange effects reclassified to profit or loss 146 (29) 117 146 (29) 117 Total recognized in other comprehensive (loss)/income for the year 146 (29) 117 145 (29) 116 Total recognized in other comprehensive (loss)/income as of the end of the year (144) 29 (115) (290) 58 (232) The schedule of the expected reclassification of the accumulated foreign exchange loss from other comprehensive income to profit or loss, as of December 31, 2018, is presented below: Year 2019 2020 2021 Total Reclassification (146) 2 – (144) Income tax 29 – – 29 Total, net of tax (117) 2 – (115)
6. Capital and financial risk management (continued) Analysis of sensitivity of financial instruments to foreign exchange risk The level of currency risk is assessed on a monthly basis using mathematical modeling methods (Monte Carlo method), as well as sensitivity analysis and is maintained within the limits adopted in line with the Company’s policy. The table below summarizes the impact on the Company’s income before income tax and equity of the depreciation/(appreciation) of the Russian ruble against the U.S. dollar and euro. U.S. dollar effect Euro effect 2018 2017 2018 2017 Currency rate change in % 13.97% 10.09% 13.64% 11.34% Gain/(loss) 85/(85) 72/(72) 42/(42) 19/(19) Equity (112)/112 (91)/91 (3)/3 2/(2) Interest rate risk Loans and borrowings raised at variable interest rates expose the Company to interest rate risk arising from the possible movement of variable elements of the overall interest rate. As of December 31, 2018, the Company’s variable rate liabilities totaled RUB 2,656 billion (net of interest payable). The Company analyzes its interest rate exposure, including by performing scenario analysis to measure the impact of an interest rate shift on annual income before income tax. The table below summarizes the impact of a potential increase or decrease in interest rates on the Company’s profit before tax, as applied to the variable element of interest rates on loans and borrowings. The increase/decrease is based on the management estimates of potential interest rate movements. Increase/decrease in interest rate Effect on income before income tax basis points RUB billion 2018 +5 (1) -5 1 2017 +6 (1) -6 1 The sensitivity analysis is limited to variable rate loans and borrowings and is conducted with all other variables held constant. The analysis is prepared with the assumption that the amount of variable rate liability outstanding at the balance sheet date was outstanding for the whole year. The interest rate on variable rate loans and borrowings will effectively change throughout the year in response to fluctuations in market interest rates. The impact measured through the sensitivity analysis does not take into account other potential changes in economic conditions that may accompany the relevant changes in market interest rates. Credit risk The Company controls its own exposure to credit risk. All external customers and their financial guarantors, other than related parties, undergo a creditworthiness check (including sellers of goods and services who act on a prepayment basis). The Company performs an ongoing assessment and monitoring of the financial position and the risk of default. As of December 31, 2018, management assessed the impact of credit risk (if materialized) on the Company’s financial indicators as low. The Company’s exposure to credit risk is limited to the carrying value of financial assets recognized on the consolidated balance sheet, taking into consideration the information disclosed in Note 40 “Contingencies. Guarantees and indemnities issued”. 6. Capital and financial risk management (continued) Credit risk (continued)
In addition, as part of its cash management and credit risk function, the Company regularly evaluates the creditworthiness of financial and banking institutions where it deposits cash and performs trade finance operations. The Company primarily has banking relationships with the Russian subsidiaries of large international banking institutions and certain large Russian banks. Liquidity risk The Company has mature liquidity risk management processes covering short-term, mid-term and long-term funding. Liquidity risk is controlled through maintaining sufficient reserves and the adequate amount of committed credit facilities and loan funds. Management regularly monitors projected and actual cash flow information, analyzes the repayment schedules of the existing financial assets and liabilities, including upcoming un-accrued interest payments, and performs annual detailed budgeting procedures. The contractual maturities of the Company’s financial liabilities are presented below: Year ended December 31, 2018 On demand < 1 year 1 to 5 years > 5 years Total Loans and borrowings and other financial liabilities – 1,169 3,379 752 5,300 Finance lease liabilities – 9 19 18 46 Accounts payable to suppliers and contractors – 452 – – 452 Salary and other benefits payable – 88 – – 88 Current operating liabilities of subsidiary banks 77 376 17 – 470 Dividends payable – 1 – – 1 Other accounts payable – 63 – – 63 Derivative financial liabilities – 33 – – 33 Year ended December 31, 2017 On demand < 1 year 1 to 5 years > 5 years Total Loans and borrowings and other financial liabilities – 2,247 1,407 814 4,468 Finance lease liabilities – 9 24 21 54 Accounts payable to suppliers and contractors – 451 – – 451 Salary and other benefits payable – 81 – – 81 Current operating liabilities of subsidiary banks 89 247 – – 336 Dividends payable – 5 – – 5 Other accounts payable – 46 – – 46 Derivative financial liabilities – 74 – – 74
7. Acquisitions of subsidiaries and shares in joint operations Acquisitions of 2018 Acquisition of a share in a joint venture In the third quarter of 2018, the Company completed acquisition of a share in a joint venture engaged in exploration and evaluation activities. The following table summarizes the Company’s allocation of the purchase price to the fair value of assets acquired and liabilities assumed: ASSETS Current assets Cash and cash equivalents 1 Accounts receivable 2 Inventories 1 Total current assets 4 Total assets 4 LIABILITIES Current liabilities Accounts payable and accrued liabilities 1 Other current liabilities 1 Total current liabilities 2 Total liabilities 2 Identifiable net assets excluding intercompany liabilities and claims existing prior to the acquisition 2 Fair value of cash consideration transferred – Fair value of the Company’s investment in the joint venture 1 Intercompany liabilities existing prior to the acquisition (5) Total gain on bargain purchase 6 The gain on re-measurement of the Company’s investment in the joint venture to the fair value at acquisition date amounted to RUB 1 billion and is included in Other income.
7. Acquisitions of subsidiaries and shares in joint operations (continued) Acquisitions of 2018 (continued) Acquisition of interests in joint ventures with ExxonMobil During the second quarter of 2018, following ExxonMobil withdrawal from several joint projects, the Company completed acquisition of interests in the joint ventures with ExxonMobil and obtained control. As of June 30, 2018 the Company prepared preliminary allocation of the purchase price to the fair value of assets acquired and liabilities assumed. The purchase price allocation was finalized in December 2018. The following table summarizes the Company’s allocation of the purchase price to the fair value of assets acquired and liabilities assumed: ASSETS Current assets Cash and cash equivalents 1 Restricted cash 4 Other current assets 2 Total current assets 7 Non-current assets Property, plant and equipment 2 Total non-current assets 2 Total assets 9 Identifiable net assets excluding intercompany liabilities and claims existing prior to the acquisition 9 Fair value of cash consideration transferred – Fair value of the Company’s investments in joint ventures 6 Changes in the Company’s liabilities as a result of acquisition of control (11) Total gain on bargain purchase 14 The gain on re-measurement of the Company’s investments in joint ventures to the fair value at acquisition date amounted to RUB 5 billion and is included in Other income. Acquisition of shares in research and development institutions In June 2018 the Company acquired controlling interests in a number of institutions engaged in research, development and engineering services in oil and gas industry in line with the program of the federal and municipal property privatization. The cost of acquisition amounted to RUB 2 billion. Acquisitions of 2017 Acquisition of a 30% interest in the concession agreement for the development of the Zohr field In October 2017 the Company finalized the acquisition of a 30% stake in the concession agreement for the development of the Zohr field from Eni S.p.A. Participation in the exploration of this deep-water gas field in offshore Egypt allows the Company to substantially increase its gas production abroad within a short timeframe and strengthen its positions in this promising and strategically significant region. The acquisition price amounted to US$ 1.1 billion, while the compensation of the 30% share of past project costs to Eni S.p.A., which is subject to reimbursement according to the terms of the concession agreement, amounted to US$ 1.2 billion.
7. Acquisitions of subsidiaries and shares in joint operations (continued) Acquisitions of 2017 (continued) The acquired interest in the concession agreement was classified as a joint operation, and was accounted for through the recognition of assets, liabilities, income and expenses in respect of the Company’s interests in accordance with IFRS 11, Joint Arrangements. Allocation of purchase price to the fair value of assets acquired and liabilities assumed is finalized. Fair value of assets acquired was property, plant and equipment in amount of US$ 2.3 billion. Finalization of the purchase price allocation of JSCB Peresvet acquisition In June 2017, the Company acquired a 99.9% share in JSCB Peresvet, a financial institution engaged in banking services. As of December 31, 2017, the purchase price allocation of the acquisition to the fair value of assets acquired and liabilities assumed was preliminary and was finalized in the third quarter of 2018. The following table summarizes the Company’s finalized allocation of the purchase price to the fair value of assets acquired and liabilities assumed: ASSETS Cash and cash equivalents 1 Obligatory reserves with the Bank of Russia 1 Loans to customers 27 Investment securities available for sale 21 Investment securities held to maturity 13 Expected future benefits from DIA’s financial aid in the form of a reduced rate loan 19 Investment property 3 Current profit tax assets 2 Total assets 87 LIABILITIES Amounts due to credit institutions 18 Amounts due to customers 15 Debt securities issued 7 Other borrowings 32 Other liabilities 15 Other provisions 2 Total liabilities 89 Total identifiable net assets at fair value (2) JSCB Peresvet’s liabilities to the Company existing prior to the acquisition 16 Identifiable net assets excluding intercompany liabilities and claims existing prior to the acquisition 14 Fair value of cash consideration transferred – Intercompany liabilities and claims existing prior to the acquisition 16 Consideration transferred to be included for the purpose of goodwill 16 Excluding identifiable net assets of JSCB Peresvet (14) Goodwill 2 As of December 31, 2017, the Company recognized impairment of goodwill arising from the JSCB Peresvet acquisition. The loss of RUB 2 billion is recognized in Other expenses of the Company’s consolidated statement of profit or loss for the year ended December 31, 2017 (Note 13). The estimated equity component of convertible bonds representing a non-controlling interest is zero.
7. Acquisitions of subsidiaries and shares in joint operations (continued) Acquisitions of 2017 (continued) The fair value of the cash consideration transferred at the acquisition date was RUB 10 million. Cash flows arising from the JSCB Peresvet acquisition: Cash acquired as a result of the JSCB Peresvet acquisition 1 Cash paid – Net cash inflow 1 The carrying value of the loans to customers approximates the fair value as of the date of the acquisition. Had the JSCB Peresvet acquisition taken place at the beginning of the reporting period (January 1, 2017), revenues and net income of the combined entity would have been RUB 6,016 billion and RUB 312 billion, respectively, for the year ended December 31, 2017. Acquisition of LLC Independent Petroleum Company – Projects and LLC Drilling Service Technology In April, 2017 the Company completed the acquisition of 100% of shares in LLC Independent Petroleum Company – Projects, engaged in the development of the Kondinsky, Zapadno-Erginsky, Chaprovsky and Novo-Endyrsky license areas in the Khanty-Mansiysk Autonomous District and of 100% of shares in LLC Drilling Service Technology, engaged in the provision of drilling services in the Khanty-Mansiysk region. The consideration amounted to RUB 49 billion, net of cash acquired. The following table summarizes the Company’s allocation of the purchase price to the fair value of assets acquired and liabilities assumed: ASSETS Current assets Cash and cash equivalents 5 Other current assets 5 Total current assets 10 Non-current assets Property, plant and equipment 101 Deferred tax assets 2 Total non-current assets 103 Total assets 113 LIABILITIES Current liabilities Other current liabilities 9 Total current liabilities 9 Non-current liabilities Deferred tax liabilities 15 Loans and borrowings 44 Total non-current liabilities 59 Total liabilities 68 Total identifiable net assets at fair value 45 Goodwill 9 Total consideration transferred 54 7. Acquisitions of subsidiaries and shares in joint operations (continued) Acquisitions of 2017 (continued)
Acquisition of TNK Trading International S.A. In December 2017, the Company obtained control over TNK Trading International S.A. (“TTI”) through concluding a number of agreements. Until December 2017 the Company considered its interest in TTI to be a part of investments in joint operations and accounted for it using the equity method. The following table summarizes the Company’s allocation of the purchase price to the fair value of assets acquired and liabilities assumed: ASSETS Current assets Cash and cash equivalents 11 Prepayments and other current assets 130 Accounts receivable 13 Other current financial assets 9 Total current assets 163 Non-current assets Intangible assets 11 Total non-current assets 11 Total assets 174 LIABILITIES Current liabilities Accounts payable and accrued liabilities 12 Profit tax payable 2 Total current liabilities 14 Non-current liabilities Loans and borrowings and other financial liabilities 130 Deferred tax liabilities 1 Total non-current liabilities 131 Total liabilities 145 Total identifiable net assets at fair value 29 Intercompany liabilities and claims existing prior to the acquisition (net payable from TTI ) 120 Identifiable net assets excluding intercompany liabilities and claims existing prior to the acquisition 149 Fair value of cash consideration transferred – Fair value of the Company’s investment in joint operations 14 Intercompany liabilities and claims existing prior to the acquisition 120 Consideration transferred to be included for the purpose of goodwill 134 Finance liability to the bank 19 Excluding identifiable net assets of TTI (149) Goodwill 4 No cash consideration was paid. As of December 31, 2017, the Company recognized an impairment of goodwill arising on TTI acquisition due to the existence of significant impairment indicators. Net effect recognized from the loss on impairment of goodwill arising on the acquisition and the gain on re-measurement of the Company’s investments in joint ventures to the fair value at acquisition date amounted to RUB 1 billion and is included in Other income of the Consolidated Statement of profit or loss.
7. Acquisitions of subsidiaries and shares in joint operations (continued) Acquisitions of 2017 (continued) The identifiable intangible asset amounting to RUB 11 billion represents an estimate of the future benefits arising from the oil trading agreements between TTI and its major oil supplier. Cash flows arising from the TTI acquisition: Cash acquired as a result of the TTI acquisition 11 Cash paid – Net cash inflow 11 The book value of the accounts receivable approximates their fair value as of the date of acquisition. There are no accounts receivable that are not expected to be collected. Had TTI’s acquisition taken place at the beginning of the reporting period (January 1, 2017), revenues and net income of the combined entity would have been RUB 6,043 billion and RUB 305 billion, respectively, for the twelve month period ended December 31, 2017. In 2017 the Company completed several acquisitions, including a 99.9% share in JSCB Peresvet, a 30% stake in the Zohr field and obtained control over TNK Trading International S.A. At the date of the issuance of the consolidated financial statements for the year ended December 31, 2017 the Company made a preliminary allocation of the purchase price of these acquisitions. The allocation of the purchase prices of these acquisitions was finalized during 2018. The following table summarizes the effect from the finalized purchase price allocations on the consolidated balance sheet as of December 31, 2017: Preliminary allocation Effects from final allocation Final allocation JSCB Peresvet TTI Other acquisitions ASSETS Total current assets 2,292 – – – 2,292 Non-current assets Property, plant and equipment 7,923 – – – 7,923 Intangible assets 71 2 2 – 75 Other long-term financial assets 606 – – – 606 Investments in associates and joint ventures 638 – – (3) 635 Bank loans granted 121 – – – 121 Deferred tax assets 26 – – – 26 Goodwill 265 – – – 265 Other non-current non-financial assets 285 – – – 285 Total non-current assets 9,935 2 2 (3) 9,936 Total assets 12,227 2 2 (3) 12,228 LIABILITIES AND EQUITY Total current liabilities 3,836 – – – 3,836 Total non-current liabilities 4,208 – 1 – 4,209 Equity Share capital 1 – – – 1 Additional paid-in capital 627 – – – 627 Other funds and reserves (322) – – – (322) Retained earnings 3,313 2 1 (3) 3,313 Rosneft shareholders’ equity 3,619 2 1 (3) 3,619 Non-controlling interests 564 – – – 564 Total equity 4,183 2 1 (3) 4,183 Total liabilities and equity 12,227 2 2 (3) 12,228
7. Acquisitions of subsidiaries and shares in joint operations (continued) Acquisitions of 2017 (continued) The following table summarizes the effect from the finalized estimations on the consolidated statement of profit or loss for the year ended December 31, 2017: Before finalized estimation Effect from finalized estimation After finalized estimation JSCB Peresvet TTI Other acquisitions Revenues and equity share in profits of associates and joint ventures Oil, gas, petroleum products and petrochemicals sales 5,877 – – – 5,877 Support services and other revenues 77 – – – 77 Equity share in profits of associates and joint ventures 60 – – (3) 57 Total revenues and equity share in profits of associates and joint ventures 6,014 – – (3) 6,011 Total costs and expenses 5,390 – – – 5,390 Operating income 624 – – (3) 621 Finance income 107 – – – 107 Finance expenses (225) – – – (225) Other income 109 – 1 – 110 Other expenses (77) 2 – – (75) Foreign exchange differences 3 – – – 3 Cash flow hedges reclassified to profit or loss (146) – – – (146) Income before income tax 395 2 1 (3) 395 Income tax expense (98) – – – (98) Net income 297 2 1 (3) 297 Net income attributable to: - Rosneft shareholders 222 2 1 (3) 222 - non-controlling interests 75 – – – 75 Net income attributable to Rosneft per common share (in RUB) – basic and diluted 20.95 – – – 20.95 Weighted average number of shares outstanding (millions) 10,598 – – – 10,598
8. Segment information The Company determines its operating segments based on the nature of their operations. The performance of these operating segments is assessed by management on a regular basis. The Exploration and production segment is engaged in field exploration and the production of crude oil and natural gas. The Refining and distribution segment is engaged in processing crude oil and other hydrocarbons into petroleum products, as well as in the purchase, sale and transportation of crude oil and petroleum products. Corporate and other unallocated activities are not part of any operating segment and include corporate activity, activities involved in field development, the maintenance of infrastructure and the functioning of the first two segments, as well as banking and finance services, and other activities. Substantially all of the Company’s operations and assets are located in the Russian Federation. Segment performance is evaluated based on both revenues and operating income, which are measured on the same basis as in the consolidated financial statements, but with intersegment transactions revalued at market prices. The performance of the operating segments in 2018 is shown below: Exploration and production Refining and distribution Corporate and other unallocated activities Adjustments Consolidated Total revenues and equity share in profits of associates and joint ventures 4,679 8,255 136 (4,832) 8,238 Including: equity share in profits of associates and joint ventures 76 5 1 – 82 Costs and expenses Costs and expenses other than depreciation, depletion and amortization 2,863 8,092 196 (4,832) 6,319 Depreciation, depletion and amortization 504 123 8 – 635 Total costs and expenses 3,367 8,215 204 (4,832) 6,954 Operating income 1,312 40 (68) – 1,284 Finance income – – 122 – 122 Finance expenses – – (290) – (290) Total finance expenses – – (168) – (168) Other income – – 49 – 49 Other expenses – – (294) – (294) Foreign exchange differences – – 107 – 107 Cash flow hedges reclassified to profit or loss – – (146) – (146) Income before income tax 1,312 40 (520) – 832 Income tax expense (246) (8) 71 – (183) Net income 1,066 32 (449) – 649
8. Segment information (continued) The performance of the operating segments in 2017 (restated) is shown below: Exploration and production Refining and distribution Corporate and other unallocated activities Adjustments Consolidated Total revenues and equity share in profits of associates and joint ventures 3,180 6,096 123 (3,388) 6,011 Including: equity share in profits of associates and joint ventures 42 13 2 – 57 Costs and expenses Costs and expenses other than depreciation, depletion and amortization 2,076 5,919 197 (3,388) 4,804 Depreciation, depletion and amortization 462 116 8 – 586 Total costs and expenses 2,538 6,035 205 (3,388) 5,390 Operating income 642 61 (82) – 621 Finance income – – 107 – 107 Finance expenses – – (225) – (225) Total finance expenses – – (118) – (118) Other income – – 110 – 110 Other expenses – – (75) – (75) Foreign exchange differences – – 3 – 3 Cash flow hedges reclassified to profit or loss – – (146) – (146) Income before income tax 642 61 (308) – 395 Income tax expense (120) (10) 32 – (98) Net income 522 51 (276) – 297 Oil, gas, petroleum products and petrochemicals sales comprise the following (based on the country indicated in the bill of lading): 2018 2017 International sales of crude oil, petroleum products and petrochemicals 5,791 3,986 International sales of crude oil, petroleum products and petrochemicals – CIS, other than Russia 357 262 Domestic sales of crude oil, petroleum products and petrochemicals 1,694 1,414 Sales of gas 234 215 Total oil, gas, petroleum products and petrochemicals sales 8,076 5,877 The Company is not dependent on any of its major customers or any one particular customer, as there is a liquid market for crude oil and petroleum products.
9. Taxes other than income tax Taxes other than income tax for the years ended December 31 comprise the following: 2018 2017 Mineral extraction tax 2,258 1,488 Excise tax 327 326 Property tax 42 38 Social charges 67 61 Other 7 6 Total taxes 2,701 1,919 10. Export customs duty Export customs duty for the years ended December 31 comprises the following: 2018 2017 Export customs duty on oil sales 777 480 Export customs duty on petroleum products and petrochemicals sales 284 178 Total export customs duty 1,061 658 11. Finance income Finance income for the years ended December 31 comprises the following: 2018 2017 Interest income on Financial assets* measured: - at amortized cost 46 44 - at fair value through other comprehensive income 14 13 - at fair value through profit or loss 9 8 Long-term advances issued (Note 28) 41 29 Total interest income 110 94 Decrease in loss allowance for expected credit losses on debt financial assets at amortized cost 1 – Change in fair value of financial assets measured at fair value through profit or loss 2 – Net gain from operations with derivative financial instruments 1 10 Gain from disposal of financial assets 3 3 Other finance income 5 – Total finance income 122 107 * Comparative information is presented in accordance with the classification of financial assets according to IFRS 9 Financial Instruments, applied from January 1, 2018, for similar types of financial assets.
12. Finance expenses Finance expenses for the years ended December 31 comprise the following: 2018 2017 Interest expenses on Loans and borrowings (133) (113) Prepayment on long-term oil and petroleum products supply agreements (Note 33) (91) (81) Other interest expenses (10) (5) Total interest expenses (234) (199) Increase in provision due to the unwinding of a discount (19) (17) Increase in loss allowance for expected credit losses on debt financial assets: - at fair value through other comprehensive income (4) – - at amortized cost (3) – Change in fair value of financial assets measured at fair value through profit or loss (12) – Net loss from operations with derivative financial instruments (17) – Loss from disposal of financial assets – (8) Other finance expenses (1) (1) Total finance expenses (290) (225) 13. Other income and expenses Other income for the years ended December 31 comprises the following: 2018 2017 (restated) Compensation payment for licenses from joint venture parties 1 1 Insurance indemnity 3 – Gain on re-measurement of fair value of the Company’s investments in joint ventures 6 – Gain on bargain purchase 20 1 Gain on out-of-court settlement 13 100 Other 6 8 Total other income 49 110 Other expenses for the years ended December 31 comprise the following: 2018 2017 (restated) Sale and disposal of property, plant and equipment and intangible assets (14) (13) Impairment of assets (219) (24) Disposal of non-production assets (1) (3) Provision for legal claims (13) – Social payments, charity, financial aid (23) (20) Other (24) (15) Total other expenses (294) (75)
14. Personnel expenses Personnel expenses for the years ended December 31 comprise the following: 2018 2017 Salary 271 249 Statutory insurance contributions 68 62 Expenses on non-statutory defined contribution plan 12 7 Other employee benefits 15 13 Total personnel expenses 366 331 Personnel expenses are included in Production and operating expenses, General and administrative expenses and Other expenses in the consolidated statement of profit or loss. 15. Operating leases Operating lease agreements have various terms and conditions and primarily consist of indefinite tenancy agreements for the lease of land plots under oilfield pipelines and petrol stations, agreements for the lease of rail cars and rail tank cars for periods over 12 months, and agreements for the lease of land plots for industrial sites of the Company’s oil refining plants. The agreements provide for an annual revision of the rental rates and contractual terms and conditions. Total operating lease expenses for the years ended December 31, 2018 and 2017 amounted to RUB 29 billion and RUB 28 billion, respectively. The expenses were recognized within Production and operating expenses, General and administrative expenses and Other expenses in the consolidated statement of profit or loss. Future minimum lease payments under the above operating lease agreements as of December 31 are as follows: 2018 2017 Less than 1 year 35 29 From 1 to 5 years 78 82 Over 5 years 199 198 Total future minimum lease payments 312 309 16. Income tax Income tax expenses for the years ended December 31 comprise the following: 2018 2017 Current income tax expense 175 120 Deferred tax expense /(benefit) due to the origination and reversal of temporary differences 8 (22) Total income tax expense 183 98 In 2018 and 2017, the Company’s subsidiaries domiciled in the Russian Federation applied the standard Russian income tax rate of 20%, except for applicable regional tax relief. The income tax rates applicable for subsidiaries incorporated in foreign jurisdictions are based on local regulations and vary from 0% to 34%.
16. Income tax (continued) Temporary differences between these consolidated financial statements and tax records gave rise to the following deferred income tax assets and liabilities: Consolidated balance sheet as of December 31, Consolidated statement of profit or loss for the years, ended December 31, 2018 2017 (restated) 2018 2017 Short-term accounts receivable 9 7 – – Property, plant and equipment 14 14 – 4 Short-term accounts payable and accrued liabilities 15 13 2 4 Loans and borrowings and other financial liabilities 9 20 (11) (5) Provisions 13 9 4 (1) Tax loss carry forward 51 58 (7) 28 Other 23 11 11 (1) Less: deferred tax liabilities offset (106) (106) – – Deferred tax assets 28 26 (1) 29 Inventories (13) (13) – (3) Property, plant and equipment (637) (615) (11) (15) Mineral rights (264) (267) 3 7 Intangible assets (9) (5) (4) 1 Investments in associates and joint ventures (8) (12) – (2) Other (12) (8) 5 5 Less: deferred tax assets offset 106 106 – – Deferred tax liabilities (837) (814) (7) (7) Deferred income tax (expense)/benefit (8) 22 Net deferred tax liabilities (809) (788) Recognized in the consolidated balance sheet as following Deferred tax assets 28 26 Deferred tax liabilities (837) (814) Net deferred tax liabilities (809) (788) The reconciliation of net deferred tax liabilities is as follows: 2018 2017 (restated) As of January 1 (788) (791) Adjustment on initial application of IFRS 9 5 – Deferred income tax (expense)/benefit, recognized in the consolidated statement of profit or loss (8) 22 Acquisition of subsidiaries and shares in joint operations (Note 7) (9) (14) Deferred tax expenses recognized in other comprehensive income (9) (5) As of December 31 (809) (788)
16. Income tax (continued) The reconciliation between actual income tax expense and theoretical income tax expense calculated as accounting profit multiplied by the 20% tax rate for the years ended December 31 is as follows: 2018 2017 (restated) Income before income tax 832 395 Income tax at statutory rate of 20% 166 79 Increase/(decrease) resulting from: Effect of change in unrecognized deferred tax assets 13 4 Effect of income tax rates in other jurisdictions – 2 Effect of special tax treatments 3 2 Effect of income tax relief (24) (12) Effect of equity share in profits of associates and joint ventures (14) (8) Effect of tax on intercompany dividends 6 1 Effect of tax on controlled investments in foreign subsidiaries (3) 2 Effect from goodwill write-off 36 2 Effect from acquisition of interests in joint ventures (8) – Effect from obtaining control over a subsidiary – (1) Effect from disposal of subsidiaries – (1) Effect from sale of shares in subsidiaries 1 – Effect of prior period adjustments (10) 1 Effect of non-taxable income and non-deductible expenses 17 27 Income tax 183 98 Unrecognized deferred tax assets in the consolidated balance sheet for the years ended December 31, 2018 and 2017 amounted to RUB 72 billion and RUB 55 billion, respectively, related to unused tax losses. In respect of recognized deferred tax assets on tax losses carried forward management considers it probable that future taxable profits will be available for the Company against which these tax losses can be utilized. The total amount of temporary differences associated with investment in subsidiaries, for which deferred tax liabilities have not been recognized, amounted to RUB 849 billion as of December 31, 2018. According to Russian tax legislation undistributed profit of foreign subsidiaries recognized as controlled foreign companies may form an additional tax base for Rosneft (and for certain Russian subsidiaries holding investments in foreign entities). In particular, undistributed 2018 profits of controlled foreign companies are included in the Company’s tax base as of December 31, 2019 and recorded in the tax declaration. The consequences of taxation of controlled foreign companies are considered in the determination of current and deferred tax liabilities.
17. Non-controlling interests Non-controlling interests include: As of December 31, 2018 2018 As of December 31, 2017 2017 Non- controlling interest (%) Non- controlling interest as of the end of the year Non- controlling interest in net income Non- controlling interest (%) Non- controlling interest as of the end of the year (restated) Non- controlling interest in net income (restated) PJSC Bashneft Oil Company 39.67 240 30 39.67 221 40 JSC Vankorneft 49.90 143 38 49.90 140 28 LLC Taas-Yuriakh Neftegazodobycha 49.90 119 24 49.90 104 3 JSC Verkhnechonskneftegaz 20.05 48 10 20.05 43 3 LLC Kharampurneftegas 49.00 24 – – – – LLC Sorovskneft 39.67 21 1 39.67 20 1 PJSC Ufaorgsintez 42.66 18 – 42.66 19 1 LLC Bashneft-Dobycha 39.67 7 1 39.67 7 1 Non-controlling interests in other entities various 4 (4) various 10 (2) Total non-controlling interests 624 100 564 75 In December 2017, the Company and BP have entered into an agreement to develop certain subsoil resources. In accordance with the agreement the parties have commenced project activities in LLC Kharampurneftegas, subsidiary of the Company (BP share – 49%), in the second quarter of 2018. On June 29, 2017 the Company completed the sale of a 20% share in JSC Verkhnechonskneftegaz, a subsidiary, to Beijing Gas Singapore Private Limited, a subsidiary of Beijing Gas Group Co., Ltd. for a consideration of US$ 1.1 billion (RUB 65 billion at the CBR official exchange rate at the transaction closing date). The summarized financial information of subsidiaries that have material non-controlling interests is provided below. This information is presented before intercompany eliminations. Summarized statement of profit or loss for 2018 PJSC Bashneft Oil Company JSC Vankorneft LLC Taas-Yuriakh Neftegazodobycha Revenues 803 426 99 Costs and other income and expenses (707) (335) (41) Income before income tax 96 91 58 Income tax expense (19) (15) (10) Net income 77 76 48 incl. attributable to non-controlling interests 30 38 24
17. Non-controlling interests (continued) Summarized statement of profit or loss for 2017 PJSC Bashneft Oil Company JSC Vankorneft LLC Taas-Yuriakh Neftegazodobycha Revenues 614 330 29 Costs and other income and expenses (486) (260) (21) Income before income tax 128 70 8 Income tax expense (27) (12) (2) Net income 101 58 6 incl. attributable to non-controlling interests 40 28 3 Summarized balance sheet as at December 31, 2018 PJSC Bashneft Oil Company JSC Vankorneft LLC Taas-Yuriakh Neftegazodobycha Current assets 849 70 33 Non-current assets 768 302 223 Total assets 1,617 372 256 Current liabilities 698 43 8 Non-current liabilities 222 32 27 Equity 697 297 221 Total equity and liabilities 1,617 372 256 incl. non-controlling interests 240 143 119 Summarized balance sheet as at December 31, 2017 PJSC Bashneft Oil Company JSC Vankorneft LLC Taas-Yuriakh Neftegazodobycha Current assets 324 71 11 Non-current assets 792 292 215 Total assets 1,116 363 226 Current liabilities 234 36 7 Non-current liabilities 234 35 28 Equity 648 292 191 Total equity and liabilities 1,116 363 226 incl. non-controlling interests 221 140 104 18. Earnings per share For the years ended December 31 basic and diluted earnings per share comprise the following: 2018 2017 Net income attributable to shareholders of Rosneft 549 222 Weighted average number of issued common shares outstanding (millions) 10,598 10,598 Total basic and diluted earnings per share (RUB) 51.80 20.95
19. Cash and cash equivalents Cash and cash equivalents comprise the following: As of December 31, 2018 2017 Cash on hand and in bank accounts in RUB 30 44 Cash on hand and in bank accounts in foreign currencies 572 124 Deposits 221 142 Other 9 12 Total cash and cash equivalents 832 322 Cash accounts denominated in foreign currencies primarily comprise cash in euro and U.S. dollars. Deposits are interest bearing and denominated in U.S. dollars, RUB, and euro. Restricted cash includes the obligatory reserve of subsidiary banks with the CBR in the amount of RUB 6 billion and RUB 4 billion as of December 31, 2018 and 2017, respectively. 20. Other short-term financial assets Other short-term financial assets comprise the following: As of December 31, 2018 2017 Financial assets at fair value through other comprehensive income Bonds 162 117 Promissory notes 151 85 Stocks and shares 42 44 Loans granted under reverse repurchase agreements 56 – Financial assets at amortized cost Bonds 1 1 Loans granted – 13 Loans issued to associates 2 32 Deposits and certificates of deposit 218 43 Financial assets at fair value through profit or loss Deposits 1 1 Total other short-term financial assets 633 336 As of December 31, 2018 and 2017 bonds and notes at fair value through other comprehensive income comprise the following: Type of security 2018 2017 Balance Interest rate p.a. Date of maturity Balance Interest rate p.a. Date of maturity State and municipal bonds 18 2.5-14.15% May 2019 – March 2033 34 5.0-14.15% January 2018 – March 2033 Corporate bonds 144 2.95-14.25% January 2019 – September 2032 79 3.08-14.25% January 2018 – September 2032 Bank of Russia bonds – 4 7.75% January 2018 Promissory notes 151 3.8-9.0% January 2019 – December 2023 85 3.8-4.5% February 2018 – January 2022 Total 313 202 As of December 31, 2018, deposits and certificates of deposit are denominated mainly in U.S. dollars and earn interest from 3.7% to 6.05% p.a.
20. Other short-term financial assets (continued) Financial assets at amortized cost are presented net of allowance for expected credit losses in the amount of RUB 3 billion as of December 31, 2018. The allowance for expected credit losses on financial assets at fair value through other comprehensive income in the amount of RUB 7 billion as of December 31, 2018 is recognized in other comprehensive income. Set out below is the movement in the loss allowance for expected credit losses on other short-term financial assets: As of January 1, 2018 Increase in allowance Decrease in allowance Reclassifica- tion As of December 31, 2018 Loss allowance at an amount equal to 12-month expected credit losses: - on financial assets at fair value through other comprehensive income 2 5 – – 7 - on financial assets at amortized cost 1 – – – 1 Loss allowance at an amount equal to lifetime expected credit losses: - on financial assets at amortized cost 5 1 – (4) 2 As of December 31, 2018 the Company has no financial assets, which were credit-impaired at initial recognition. 21. Accounts receivable Accounts receivable include the following: As of December 31, 2018 2017 Trade receivables 523 658 Bank loans to customers 124 108 Other accounts receivable 51 116 Total 698 882 Allowance for expected credit losses (56) (39)* Total accounts receivable, net of allowance 642 843 * In accordance with the requirements of IAS 39 Reconciliation of allowance balances from IAS 39 to IFRS 9 at January 1, 2018 is presented in Note 3 “Significant accounting policies” As of December 31, 2018 and 2017 accounts receivable were not pledged as collateral for loans and borrowings provided to the Company. Set out below is the movement in the loss allowance for expected credit losses on accounts receivable: As of January 1, 2018 Increase in allowance Decrease in allowance As of December 31, 2018 Loss allowance at an amount equal to 12-month expected credit losses on trade receivables 35 13 (11) 37 Allowance for expected credit losses on other accounts receivable 15 7 (3) 19 Total 50 20 (14) 56
21. Accounts receivable (continued) Due to the high credit quality and short term-nature of trade receivables, the loss allowance for expected credit losses for significant counterparties is determined based on 12-month expected credit losses. The Company has no trade receivables assets of buyers and customers that are credit impaired upon initial recognition. 22. Inventories Inventories comprise the following: As of December 31, 2018 2017 Crude oil and gas 91 88 Petroleum products and petrochemicals 205 158 Materials and supplies 97 78 Total inventories 393 324 Petroleum products and petrochemicals include those designated both for sale and for own use. For the years ended December 31: 2018 2017 Cost of inventories recognized as an expense during the period 1,306 977 The cost of inventories recognized as expense during the period is included in Production and operating expenses, Cost of purchased oil, gas, petroleum products and refining costs and General and administrative expenses in the consolidated statement of profit or loss. 23. Prepayments and other current assets Prepayments and other current assets comprise the following: As of December 31, 2018 2017 Value added tax and excise receivable 221 180 Prepayments to suppliers: 217 210 Current portion of long-term prepayments issued 148 154 Settlements with customs 41 37 Profit and other tax payments 20 19 Other 11 8 Total prepayments and other current assets 510 454 Settlements with customs primarily represent export duties related to the export of crude oil and petroleum products (Note 10).
24. Property, plant and equipment and construction in progress Exploration and production Refining and distribution Corporate and other unallocated activities Total Cost as of January 1, 2017 7,513 2,052 119 9,684 Depreciation, depletion and impairment losses as of January 1, 2017 (2,174) (371) (30) (2,575) Net book value as of January 1, 2017 5,339 1,681 89 7,109 Prepayments for property, plant and equipment as of January 1, 2017 21 16 5 42 Total as of January 1, 2017 5,360 1,697 94 7,151 Cost Acquisitions of subsidiaries and shares in joint operations (Note 7) 277 – 4 281 Additions 948 125 20 1,093 Including capitalized expenses on loans and borrowings 105 39 – 144 Disposals and other movements (25) (17) (2) (44) Foreign exchange differences (23) 12 (2) (13) Cost of asset retirement (decommissioning) obligations 29 – – 29 As of December 31, 2017 8,719 2,172 139 11,030 Depreciation, depletion and impairment losses Depreciation and depletion charge (474) (113) (9) (596) Disposals and other movements 11 8 1 20 Impairment of assets (4) (2) (7) (13) Foreign exchange differences 13 – 1 14 As of December 31, 2017 (2,628) (478) (44) (3,150) Net book value as of December 31, 2017 6,091 1,694 95 7,880 Prepayments for property, plant and equipment as of December 31, 2017 9 7 27 43 Total as of December 31, 2017 6,100 1,701 122 7,923 Cost Acquisitions of subsidiaries and shares in joint operations (Note 7) 2 – 2 4 Additions 995 130 5 1,130 Including capitalized expenses on loans and borrowings 143 48 – 191 Disposals and other movements (61) 14 (8) (55) Foreign exchange differences 129 31 3 163 Cost of asset retirement (decommissioning) obligations (27) – – (27) As of December 31, 2018 9,757 2,347 141 12,245 Depreciation, depletion and impairment losses Depreciation and depletion charge (519) (113) (8) (640) Disposals and other movements 40 (14) 3 29 Impairment of assets (17) (12) – (29) Foreign exchange differences (59) (3) (1) (63) As of December 31, 2018 (3,183) (620) (50) (3,853) Net book value as of December 31, 2018 6,574 1,727 91 8,392 Prepayments for property, plant and equipment as of December 31, 2018 9 15 29 53 Total as of December 31, 2018 6,583 1,742 120 8,445
24. Property, plant and equipment and construction in progress (continued) The cost of construction in progress included in property, plant and equipment was RUB 2,351 billion and RUB 2,013 billion as of December 31, 2018 and 2017, respectively. The depreciation charge includes depreciation which was capitalized as part of the construction cost of property, plant and equipment and the cost of inventory in the amount of RUB 18 billion and RUB 15 billion for the years ended December 31, 2018 and 2017, respectively. The Company capitalized RUB 191 billion (including RUB 147 billion in capitalized interest expense) and RUB 144 billion (including RUB 117 billion in capitalized interest expense) of expenses on loans and borrowings in 2018 and 2017, respectively. During 2018 and 2017 the Company received government grants for capital expenditures in the amount of RUB 10 billion and RUB 8 billion, respectively. Grants are accounted for as a reduction of additions in the Exploration and production segment. The weighted average rates used to determine the amount of borrowing costs eligible for capitalization are 11.63% and 8.31% p.a. in 2018 and 2017, respectively. Due to the factors and circumstances leading to the impairment of goodwill in the Refining and distribution segment (Note 25), the Company performed an impairment test of its refining assets by individual refinery (groups of refineries) which resulted in the impairment of the segment's property, plant and equipment in the amount of RUB 12 billion, recognized in Other expenses (Note 13). The key assumptions used in calculating the value in use of property, plant and equipment largely coincide with those presented in Note 25, but take into consideration the more favorable macroeconomic indicators and forecasts for this segment, as well as the clarification of the regulatory parameters of taxation in the oil refining industry in the fourth quarter of 2018. Exploration and evaluation assets Exploration and evaluation assets included in the Exploration and production segment, including mineral rights to unproved properties, comprise the following: 2018 2017 Cost as of January 1 386 243 Impairment losses as of January 1 – – Net book value as of January 1 386 243 Cost Acquisition of subsidiaries (Note 7) – 47 Acquisition of interest in joint arrangements – 37 Capitalized expenditures 42 71 Reclassified to development assets (43) (8) Expensed (1) (2) Utilization of impairment reserve – – Foreign exchange differences 13 (2) As of December 31 397 386 Impairment losses Accrual of impairment reserve (17) – As of December 31 (17) – Net book value as of December 31 380 386
24. Property, plant and equipment and construction in progress (continued) Provision for asset retirement (decommissioning) obligations The provision for asset retirement (decommissioning) obligations was RUB 80 billion and RUB 98 billion as of December 31, 2018 and 2017, respectively, and included in Property, plant and equipment. 25. Intangible assets and goodwill Intangible assets and goodwill comprise the following: Rights for land lease Other intangible assets Total intangible assets Goodwill Cost as of January 1, 2017 34 48 82 256 Amortization as of January 1, 2017 (13) (10) (23) – Net book value as of January 1, 2017 21 38 59 256 Cost Additions – 10 10 – Acquisition of subsidiaries (Note 7) – 30 30 15 Disposals – (18) (18) (6) Foreign exchange differences – – – – As of December 31, 2017 (restated) 34 70 104 265 Amortization Amortization charge (2) (5) (7) – Disposal of amortization – 1 1 – Foreign exchange differences – – – – As of December 31, 2017 (restated) (15) (14) (29) – Net book value as of December 31, 2017 (restated) 19 56 75 265 Cost Additions – 15 15 – Acquisition of subsidiaries (Note 7) – – – – Disposals – (4) (4) (180) Foreign exchange differences 1 3 4 – As of December 31, 2018 35 84 119 85 Amortization Amortization charge (1) (14) (15) – Disposal of amortization – 2 2 – Foreign exchange differences (1) (1) (2) – As of December 31, 2018 (17) (27) (44) – Net book value as of December 31, 2018 18 57 75 85
25. Intangible assets and goodwill (continued) December 31, 2018 December 31, 2017 Goodwill Exploration and production 85 85 Refining and distribution – 180 Total 85 265 Goodwill acquired through business combinations is allocated to the relevant groups of cash generating units that are operating segments – the Exploration and production segment and the Refining and distribution segment. In assessing whether goodwill has been impaired, the current value of the operating segments (including goodwill) is compared with their estimated value in use. The Company estimates the value in use of the operating segments using a discounted cash flow model. Future cash flows are adjusted for risks specific to each segment and discounted using a rate that reflects current market assessments of the time value of money and the risks specific to each segment, for which the future cash flow estimates have not been adjusted. The Company’s business plan, approved by the Company’s Board of Directors, is the primary source of information for the determination of the operating segments’ value in use. The business plan contains internal forecasts of oil and gas production, refinery throughputs, sales volumes of various types of refined products, revenues, operating and capital expenditures. As an initial step in the preparation of these plans, various assumptions, such as concerning oil prices, natural gas prices, refining margins, petroleum product margins and cost inflation rates, are set. These assumptions take into account the current prices, U.S. dollar and RUB inflation rates, other macroeconomic factors and historical trends, as well as market volatility. In determining the value in use for each of the operating segments, twelve-year period cash flows calculated on the basis of the Company management’s forecasts are discounted and aggregated with the segments’ terminal value. The use of a forecast period longer than five years originates from the industry’s average investment cycle. For the calculation of the terminal value of the Company’s segments in the post-forecast period the Gordon model is used. The Company performs its annual goodwill impairment test as of October 1 of each year. The impairment test was performed at the beginning of the fourth quarter of each year using the most actual information available at the date of the impairment test. As a result of the annual test, no impairment of goodwill was identified in 2017. In the beginning of August 2018, the laws on the completion of the tax maneuver in the Russian oil industry were adopted, involving a significant change in the parameters of the fiscal regime. These laws, in a number of scenarios, combined with the current macroeconomic environment and taking into account the measures on stabilizing the prices for petroleum products in the domestic market could create conditions in which the value in use of the oil refining, marketing and logistics business of the Company would be exposed to additional risks. Considering that for the six months of 2018 Refining and distribution segment demonstrated an operating loss, the Company decided to revise the key assumptions used for determining the estimated value in use of the Refining and distribution segment. As a result the carrying amount exceeded its value in use, and RUB 47 billion of impairment loss was recognized in the Interim condensed consolidated financial statements for six months ended June 30, 2018.
25. Intangible assets and goodwill (continued) In the third quarter of 2018 the impairment test was updated following further ruble depreciation and oil prices growth along with the corresponding change of the long-term macroeconomic forecast, as well as an uncertainty about the changes to the calculation and administration procedures in respect of the reverse excise for refineries and its price-shocks reducing component. As a result of the update, the excess of carrying amount over its value in use was identified for the Refining and distribution segment and the impairment of the full amount of goodwill was recognized. The lag in the growth rate of market prices for petroleum products compared to the growth rate of crude oil prices is the main factor that led to the impairment of goodwill of the Refining and distribution segment. The impairment loss of RUB 133 billion was recognized in Other expenses of the Interim consolidated statement of profit or loss for three months ended September 30, 2018. The total amount of goodwill impairment loss recognized in Other expenses of the Consolidated statement of profit or loss for twelve months ended December 31, 2018 is RUB 180 billion. Due to the recognized impairment of the Refining and distribution segment goodwill the Company also performed impairment test of its refining property, plant and equipment, as a result of which the impairment loss was identified and recognized in Property, plant and equipment (Note 24). As a result of the annual goodwill impairment test, no impairment of goodwill was identified in 2018 for the Exploration and production segment due to the substantial headroom in the esteemed value in use over identified net assets for the segment. Key assumptions applied to the calculation of value in use Discounted cash flows are most sensitive to changes in the following factors: The discount rate The discount rate calculation is based on the Company’s weighted average cost of capital adjusted to reflect the pre-tax discount rate and the discount rate was 10.3% p.a. in 2018 (12.4% p.a. in 2017). The estimated average annual RUB / U.S. dollar exchange rate The average annual RUB / U.S. dollar exchange rate was forecasted as follows: RUB 63.9 for 2019, RUB 63.8 for 2020, RUB 64.0 for 2021, RUB 64.7 for 2022, RUB 66.3 for 2023 and RUB 68.0 from 2024 onwards. Oil and petroleum products prices The Urals oil price was forecasted as follows: RUB 4,051 per barrel for 2019, RUB 3,811 per barrel for 2020, RUB 3,703 per barrel for 2021, RUB 3,647 per barrel for 2022, RUB 3,651 per barrel for 2023 and RUB 3,636 per barrel from 2024 onwards. These prices, in turn, form the basis of the forecasted purchase prices for oil consumed in refining and export sales prices for Company’s petroleum products. Oil purchases of the Refining and distribution segment are based on “netback” (export market prices for oil and gas condensate, minus transportation costs, export duties, storage costs, selling expenses and other sales-related expenses). The weighted average price of petroleum products (excluding petrochemicals) was forecasted as follows: RUB 34.5 thousand per tonne, RUB 33.3 thousand per tonne and RUB 33.0 – 34.0 thousand per tonne for 2019, 2020 and from 2021 onwards, respectively. Production volumes Estimated production volumes were based on detailed data for the fields and refineries and the field development plans and refineries utilization rates approved by management through the long-term planning process were taken into account. As of December 31, 2018 and 2017 the Company did not have any intangible assets with indefinite useful lives. As of December 31, 2018 and 2017 no intangible assets have been pledged as collateral.
26. Other long-term financial assets Other long-term financial assets net of future credit losses comprise the following: As of December 31, 2018 2017 Financial assets at fair value through other comprehensive income Stocks and shares 18 18 Financial assets at amortized cost Bonds 28 13 Loans granted 18 4 Loans issued to associates 31 26 Deposits and certificates of deposit 23 49 Other accounts receivable 11 3 Financial assets at fair value through profit or loss Deposits 110 493 Total other long-term financial assets 239 606 Bank deposits of the Company are placed in rubles, US dollars and euros at interest rates ranging from 1.5% to 8.75% p.a. Bonds mainly include federal loan bonds owned by JSCB Peresvet and JSC Russian Regional Development Bank (VBRR). No long-term financial assets were pledged as collateral as of December 31, 2018 and 2017. As of December 31, 2018 and 2017, no long-term financial assets were received by the Company as collateral. Set out below is the movement in the loss allowance for expected credit losses on other long-term financial assets: As of January 1, 2018 Increase in allowance Decrease in allowance Reclassifica- tion As of December 31, 2018 Loss allowance at an amount equal to 12-month expected credit losses: - on financial assets at amortized cost 1 – – – 1 Loss allowance at an amount equal to lifetime expected credit losses: - on financial assets at amortized cost 7 3 – 4 14 As of December 31, 2018 the Company has no financial assets, which were credit-impaired at initial recognition.
27. Investments in associates and joint ventures Investments in associates and joint ventures comprise the following: Name of investee Country Company’s share as of December 31, 2018, % As of December 31, 2018 2017 (restated) Joint ventures PJSC NGK Slavneft Russia 49.94 167 156 Petromonagas S.A. Venezuela 40.00 77 46 Taihu Ltd (OJSC Udmurtneft) Cyprus 51.00 58 47 Messoyahaneftegaz JSC Russia 50.00 37 15 Petrovictoria S.A. Venezuela 40.00 31 25 National Oil Consortium LLC Russia 80.00 30 24 Fuel-filling complex of Vnukovo Russia 50.00 17 18 SIA ITERA Latvija Latvia 66.00 3 4 Arktikshelfneftegaz JSC Russia 50.00 2 2 RN Pechora LLC Russia 1.00 – 8 Associates Nayara Energy Limited India 49.13 251 224 Purgaz CJSC Russia 49.00 34 39 Petrocas Energy International Ltd Cyprus 49.00 11 9 Nizhnevartovskaya TPP JSC Russia 25.01 4 4 Other associates various various 13 14 Total associates and joint ventures 735 635 The equity share in profits/(losses) of associates and joint ventures comprises the following: Company’s share as of December 31, 2018, % Share in income/(loss) of equity investees 2018 2017 (restated) Messoyahaneftegaz JSC 50.00 31 11 Petromonagas S.A. 40.00 19 8 PJSC NGK Slavneft 49.94 11 7 TNK Trading International S.A. 59.95 – 10 Other various 21 21 Total equity share in profits of associates and joint ventures 82 57 The unrecognized share of losses of associates and joint ventures comprises the following: Name of investee As of December31, 2018 2017 LLC Veninneft 2 2 LLP Adai Petroleum Company 8 7 Boqueron S.A. 6 6 Petroperija S.A. 4 3 Total unrecognized share of losses of associates and joint ventures 20 18
27. Investments in associates and joint ventures (continued) Financial information of significant associates and joint ventures as of December 31, 2018 and 2017 is presented below: Nayara Energy Limited As of December 31, 2018 2017 Current assets 162 264 Non-current assets 396 359 Total assets 558 623 Current liabilities (242) (415) Non-current liabilities (284) (187) Total liabilities (526) (602) Net assets 32 21 The Company’s share, % 49.13 49.13 The Company’s total share in net assets 16 10 Goodwill 235 214 Total 251 224 Nayara Energy Limited 2018 2017 Revenues 912 282 Finance expenses (27) (15) Depreciation, depletion and amortization (16) (6) Other expenses (860) (257) Income before tax 9 4 Income tax (4) (1) Net income 5 3 The Company’s share, % 49.13 49.13 The Company’s total share in net income 2 2 The Company’s share of the currency translation effect amounted to an income of RUB 25 billion and a loss of RUB 8 billion for the years ended December 31, 2018 and 2017, respectively, which was included in foreign exchange differences in the translation of foreign operations in the consolidated statement of other comprehensive income for 2018 and 2017. As of December 31, PJSC NGK Slavneft 2018 2017 Current assets 93 60 Non-current assets 473 447 Total assets 566 507 Current liabilities (63) (66) Non-current liabilities (168) (129) Total liabilities (231) (195) Net assets 335 312 The Company’s share, % 49.94 49.94 The Company’s total share in net assets 167 156
27. Investments in associates and joint ventures (continued) PJSC NGK Slavneft 2018 2017 Revenues 314 241 Finance income – 1 Finance expenses (9) (7) Depreciation, depletion and amortization (47) (47) Other expenses (228) (171) Income before tax 30 17 Income tax (8) (4) Net income 22 13 The Company’s share, % 49.94 49.94 The Company’s total share in net income 11 7 As of December 31, Messoyahaneftegaz JSC 2018 2017 Current assets 24 17 Non-current assets 180 145 Total assets 204 162 Current liabilities (19) (25) Other non-current liabilities (110) (120) Total liabilities (129) (145) Net assets 75 17 The Company’s share, % 50.00 50.00 The Company’s total share in net assets 37 9 Messoyahaneftegaz JSC 2018 2017 Revenues 126 61 Finance income – – Finance expenses (6) (7) Depreciation, depletion and amortization (12) (8) Other expenses (2) (1) Income before tax 75 28 Income tax (13) (6) Net income 62 22 The Company’s share, % 50.00 50.00 The Company’s total share in net income 31 11
27. Investments in associates and joint ventures (continued) As of December 31, Taihu Ltd 2018 2017 Current assets 67 42 Non-current assets 80 89 Total assets 147 131 Current liabilities (19) (17) Other non-current liabilities (15) (15) Total liabilities (34) (32) Net assets 113 99 One-off adjustment in accordance with the joint-stock agreement – (6) The Company’s share, % 51.00 51.00 The Company’s total share in net assets 58 47 28. Other non-current non-financial assets Other non-current non-financial assets comprise the following: As of December 31, 2018 2017 Long-term advances issued 293 282 Other 2 3 Total other non-current non-financial assets 295 285 Long-term advances issued include RUB 125 billion (US$ 1.8 billion) of the prepayment for the Company's contribution to the newly created Joint Venture – an operator of the infrastructure project for the operation of the oil pipeline in Kurdish Autonomous Region of Iraq. 29. Accounts payable and accrued liabilities Accounts payable and accrued liabilities comprise the following: As of December 31, 2018 2017 Financial liabilities Accounts payable to suppliers and contractors 452 451 Current operating liabilities of subsidiary banks 451 333 Salary and other benefits payable 88 81 Dividends payable 1 5 Other accounts payable 63 46 Total financial liabilities 1,055 916 Non-financial liabilities Short-term advances received 75 55 Total accounts payable and accrued liabilities 1,130 971 Trade and other payables are non-interest bearing.
30. Loans and borrowings and other financial liabilities Loans and borrowings and other financial liabilities comprise the following: As of December 31, Currency 2018 2017 Long-term Bank loans RUB 423 326 Bank loans US$, euro 921 878 Bonds RUB 461 427 Eurobonds US$ 177 213 Borrowings RUB 77 71 Other borrowings RUB 704 16 Other borrowings US$ 691 224 Less: current portion of long-term loans and borrowings (202) (545) Total long-term loans and borrowings 3,252 1,610 Finance lease liabilities 27 32 Other long-term financial liabilities 139 146 Less: current portion of long-term finance lease liabilities (5) (5) Total long-term loans and borrowings and other financial liabilities 3,413 1,783 Short-term Bank loans RUB 326 237 Bank loans US$, euro 16 10 Other borrowings RUB 209 919 Other borrowings US$ 25 346 Current portion of long-term loans and borrowings 202 545 Total short-term loans and borrowings and current portion of long-term loans and borrowings 778 2,057 Current portion of long-term finance lease liabilities 5 5 Other short-term financial liabilities 162 93 Short-term liabilities related to derivative financial instruments 33 74 Total short-term loans and borrowings and other financial liabilities 978 2,229 Total loans and borrowings and other financial liabilities 4,391 4,012 Long-term loans and borrowings Long-term bank loans comprise the following: Currency Interest rate p.a. Maturity date As of December 31, 2018 2017 US$ 3.23% – LIBOR + 3.50% 2020-2029 915 869 EUR EURIBOR + 0.35% – EURIBOR + 2.00% 2019-2020 6 10 RUB 8.25% – 9.75% 2020-2024 423 326 Total 1,344 1,205 Debt issue costs – (1) Total long-term bank loans 1,344 1,204
30. Loans and borrowings and other financial liabilities (continued) Long-term loans and borrowings (continued) Long-term bank loans from a foreign bank to finance special-purpose business activities denominated in U.S. dollars are partially secured by oil export contracts. If the Company fails to make timely debt repayments, the terms of such contracts normally provide the lender with the express right of claim to contractual revenue in the amount of the late loan repayments, which the purchaser generally remits directly through transit currency accounts with the lender banks. The outstanding balance of Accounts receivable arising from such contracts amounts to RUB 28 billion and RUB 22 billion as of December 31, 2018 and 2017, respectively, and is included in Trade receivables of purchasers and customers. In March 2013, the Company drew down four long-term unsecured loans from a group of international banks for a total of US$ 31 billion to finance the acquisition of TNK-BP. Three out of four were fully repaid in previous years. In February 2018 the Company repaid the fourth one for a total amount of US$ 0.2 billion (RUB 11.4 billion at the CBR official exchange rate on the date of transaction). For the year ended December 31, 2018, the Company drew down long-term funds from Russian banks under a floating and fixed rate loans. In the first quarter of 2018 the Company raised funds through the placement of three series of documentary non-convertible fixed interest-bearing long-term bonds with a nominal amount of RUB 75 billion and maturity periods of 3 and 10 years: the first one with nominal amount of RUB 5 billion, coupon 7.8% and maturity period of 3 years; the second one with nominal amount of RUB 50 billion, coupon 7.5% and maturity period of 10 years; the third one with nominal amount of RUB 20 billion, coupon 7.3% and maturity period of 10 years. Coupon payments will be made on a semi-annual basis. Bonds with maturity periods of 10 years allow early repurchase at the request of the bond holder, as set out in the respective offering documents. Such purchase/repayment of the bonds does not constitute early redemption. The funds received are used for general corporate purposes. In March 2018, the Company fully repaid Eurobonds (Series 6) of US$ 1.1 billion (RUB 62.3 billion at the CBR official exchange rate at the transaction date) assumed through the TNK-BP acquisition.
30. Loans and borrowings and other financial liabilities (continued) Long-term loans and borrowings (continued) Interest-bearing RUB denominated bearer bonds in circulation comprise the following: Security ID Date of issue Date of maturity Total volume in RUB billions Coupon (%) As of December 31, 2018 2017 Bonds 04,05 10.2012 10.20221 20 7.90% 20 20 Bonds 07,08 03.2013 03.20231 30 7.30% 31 31 Bonds 066,096,106 06.2013 05.20231 40 7.00% 1 40 SE Bonds БО-056, БО-066 12.2013 12.2023 40 8.50%5 10 11 SE Bonds БО-01, БО-07 02.2014 02.2024 35 8.90% 36 36 SE Bonds БО-02, БО-03, БО-04 БО-094 12.2014 11.20241 65 9.40% 55 55 SE Bonds4 БО-08, БО-10 БО-11, БО-12, БО-13 БО-14 12.2014 11.20241 160 9.40%5 – – SE Bonds4 БО-15, БО-16 БО-17, БО-24 12.20142 12.20201 400 7.85%5 – – SE Bonds4 БО-18, БО-19, БО-20 БО-21, БО-22, БО-23 БО-25, БО-26 01.20152 01.2021 400 7.60%5 – – SE Bonds4 001Р-01 12.20162 11.2026 600 7.60%5 – – SE Bonds 001Р-02 12.2016 12.2026 30 9.39%5 30 30 SE Bonds 001Р-03 12.2016 12.20261 20 9.50%5 20 20 SE Bonds 001Р-04 05.2017 04.2027 40 8.65%5 41 41 SE Bonds 001Р-05 05.20172 05.20251 15 8.60%5 15 15 SE Bonds4 001Р-06, 001Р-07 07.2017 07.2027 266 8.50%5 – – SE Bonds4 001Р-08 10.2017 09.2027 100 7.60%5 – – SE Bonds4 002Р-01, 002Р-02 12.2017 11.2027 600 7.60%5 – – SE Bonds 002Р-03 12.2017 12.2027 30 7.75%5 30 30 SE Bonds 002Р-04 02.2018 02.2028 50 7.50%5 51 – SE Bonds 002Р-05 03.2018 02.2028 20 7.30 %5 21 – Bonds of subsidiary banks: SE Bonds 001Р-01 10.2017 10.20201 10 8.50%5 10 10 SE Bonds 001Р-02 02.2018 07.20211 5 7.80%5 5 – SE Bonds БО-02 08.20143 08.20341 3 0.51%5 – – SE Bonds БО-03 07.20153 06.20351 4 0.51%5 – – SE Bonds БО-04 04.20152 04.20181 3 13.25%5 – 3 SE Bonds БО-П01 09.20153 08.20351 5 0.51%5 – – SE Bonds БО-П02 10.20153 09.20351 4 0.51%5 1 1 SE Bonds БО-П03 11.20153 10.20351 1 0.51%5 – – SE Bonds БО-П05 06.20163 06.20361 5 0.51%5 – – Convertible Bonds С-01 02.20173 02.20321 69 0.51%5 2 2 Bashneft SE Bonds: Bonds 046 02.2012 02.2022 10 7.00%5 – – Bonds 06, 08 02.2013 01.20231 15 7.70%5 15 15 Bonds 07, 09 02.2013 01.2023 15 8.85%5 16 16 SE Bonds БО-06, БО-08 05.2016 04.2026 15 10.90%5 16 16 SE Bonds БО-09 10.2016 10.2026 5 9.30%5 5 5 SE Bonds БО-10 12.2016 12.2026 5 9.50%5 5 5 SE Bonds 001P-01R 12.2016 12.20241 10 9.50%5 10 10 SE Bonds 001P-02R 12.2016 12.20231 10 9.50%5 10 10 SE Bonds 001P-03R 01.2017 01.20241 5 9.40%5 5 5 Total long-term RUB bonds 461 427 1 Early repurchase at the request of the bond holder is not allowed. 2 Coupon payments every three months. 3 Coupon payments at the maturity day. 4 On the reporting date these issues are fully or partially used as an instrument for other borrowings under repurchasing agreement operations. 5 For the coupon period effective as of December 31, 2018. 6 As of December 31, 2018 part of issue early repurchased.
30. Loans and borrowings and other financial liabilities (continued) Long-term loans and borrowings (continued) All of the bonds, excluding certain issues, allow early repurchase at the request of the bond holder as set in the respective offering documents. In addition, the issuer, at any time and at its discretion, may purchase/repay the bonds early with the possibility of subsequently placing the bonds in the market. Such purchase/repayment of the bonds does not constitute an early redemption. Certain RUB denominated non-convertible bonds were acquired through the acquisitions of PJSC Bashneft Oil Company and JSCB Peresvet (Note 7). Through the JSCB Peresvet acquisition the Company reported RUB denominated bonds with coupon payments at the end of the redemption and maturity periods of 3, 15 and 20 years. Part of the RUB denominated bonds series С01 consisted of convertible bonds. Corporate Eurobonds comprise the following: Coupon rate (%) Currency Maturity As of December 31, 2018 2017 Eurobonds (Series 2) 4.199% US$ 2022 141 117 Eurobonds (Series 6) 7.875% US$ 2018 – 65 Eurobonds (Series 8) 7.250% US$ 2020 36 31 Total long-term Eurobonds 177 213 In the fourth quarter of 2018 the Company continued to settle other long-term borrowings under repurchasing agreement operations and entered into new transactions. As of December 31, 2018, the liabilities of the Company under those transactions amounted to the equivalent of RUB 1,395 billion at the CBR official exchange rate as of December 31, 2018. The Company’s own corporate bonds were used as an instrument for those transactions. The Company is obliged to comply with a number of restrictive financial and other covenants contained in several of its loan agreements. Such covenants include maintaining certain financial ratios. As of December 31, 2018 and December 31, 2017 the Company was in compliance with all restrictive financial and other covenants contained in its loan agreements. Short-term loans and borrowings In 2018 the Company drew down funds under short-term fixed and float rates loans from Russian and foreign banks. In 2018 the Company continued to meet its obligations in relation to other short-term floating and fixed rate borrowings under repurchasing agreement operations and had entered into new long-term and short-term transactions. As of December 31, 2018 the liabilities of the Company under those transactions amounted to the equivalent of RUB 234 billion (at the CBR official exchange rate as of December 31, 2018). Own corporate bonds were used as an instrument for those transactions. In 2018 the Company was current on all payments under loan agreements and interest payments.
30. Loans and borrowings and other financial liabilities (continued) Finance leases Repayments of finance lease obligations comprise the following: As of December 31, 2018 Minimum lease payments Finance expenses Present value of minimum lease payments Less than 1 year 9 (4) 5 From 1 to 5 years 19 (9) 10 Over 5 years 18 (6) 12 Total 46 (19) 27 As of December 31, 2017 Minimum lease payments Finance expenses Present value of minimum lease payments Less than 1 year 9 (4) 5 From 1 to 5 years 24 (11) 13 Over 5 years 21 (7) 14 Total 54 (22) 32 Finance leases entered into by the Company do not contain covenants and are long-term agreements, with certain leases having purchase options at the end of the lease term. Finance leases are denominated in RUB and US$. Property, plant and equipment under capital leases recognized in Property, plant and equipment (Note 24) comprise the following: As of December 31, 2018 2017 Buildings 4 4 Plant and machinery 27 27 Vehicles 16 16 Total cost 47 47 Less: accumulated depreciation (24) (18) Total net book value of leased property 23 29 Liabilities related to derivative financial instruments Short-term liabilities related to derivative financial instruments include liabilities related to cross-currency rate swaps. In accordance with its foreign currency and interest rate risk management policy the Company enters into cross-currency rate swaps to sell US$. The transactions balance the currency of revenues and liabilities and reduce the overall interest rates on borrowings. The cross-currency rate swaps are recorded in the consolidated balance sheet at fair value. The measurement of the fair value of the transactions is based on a discounted cash flow model and consensus forecasts of foreign currency rates. The consensus forecasts include forecasts of the major international banks and agencies. The Bloomberg system is the main information source for the model.
30. Loans and borrowings and other financial liabilities (continued) Liabilities related to derivative financial instruments (continued) Derivative financial instruments comprise the following: Issue date Expiry date Nominal amount as of December 31, 2018 Interest rate type Fair value of the liabilities as of December 31, US$ million RUB billion* 2018 2017 Swaps 2013 2018 – – floating – 52 Swaps 2014 2019 1,010 70 floating 33 22 Total 1,010 70 33 74 * The equivalent nominal amount at the CBR official exchange rate as of December 31, 2018. Reconciliation of movements in financing activities in the Statement of cash flows with balance-sheet items of liabilities: Long-term loans and borrowings Short-term loans and borrowings Finance lease liabilities Other long-term financial liabilities Other short-term financial liabilities Short-term liabilities related to derivative financial instruments Total As of January 1, 2017, including 1,889 1,475 22 4 4 98 3,492 Financing activities (cash flow) Proceeds/repayment of loans and borrowings (298) 644 – 144 192 – 682 Interest paid (145) (70) (4) – – – (219) Repayment of other financial liabilities – – (7) (1) – (14) (22) Operating and investing activities (non-cash flow) Foreign exchange gain/loss (196) 96 – (1) 1 – (100) Acquisition of interest in subsidiary, net of cash acquired 61 (8) 3 – – – 56 Offset of other financial liabilities – – – – (105) – (105) Acquisition – – 14 – – – 14 Finance expenses 134 91 4 – – – 229 Finance income – – – – – (10) (10) Others – (6) – – 1 – (5) Reclassification 165 (165) – – – – – As of December 31, 2017 1,610 2,057 32 146 93 74 4,012 Financing activities (cash flow) Proceeds/repayment of loans and borrowings 1,022 (933) – 246 87 – 422 Interest paid (189) (78) (4) – – – (271) Repayment of other financial liabilities – – (6) – – (57) (63) Repurchase of bonds (40) – – – – – (40) Operating and investing activities (non-cash flow) Foreign exchange gain/loss 310 16 – 15 (1) – 340 Offset of other financial liabilities – – – (126) (164) – (290) Finance expenses 198 58 4 4 1 15 280 Finance income – – – – – 1 1 Reclassification 341 (342) 1 (146) 146 – – As of December 31, 2018 3,252 778 27 139 162 33 4,391 31. Other current tax liabilities Other short-term tax liabilities comprise the following:
As of December 31, 2018 2017 Mineral extraction tax 163 160 VAT 121 78 Excise duties 27 26 Property tax 10 10 Personal income tax 3 2 Other 3 2 Total other tax liabilities 327 278 32. Provisions Asset retirement obligations Environmental remediation provision Legal, tax and other claims Total As of January 1, 2017, including 178 41 13 232 Non-current 174 28 1 203 Current 4 13 12 29 Provisions charged during the year (Note 40) 6 5 7 18 Increase/(decrease) in the liability resulting from: Changes in estimates (5) (1) – (6) Change in the discount rate 28 – – 28 Foreign exchange differences (1) – – (1) Unwinding of discount 14 3 – 17 Acquisition of subsidiaries (Note 7) – – 2 2 Utilization (2) (7) (7) (16) As of December 31, 2017, including 218 41 15 274 Non-current 213 27 5 245 Current 5 14 10 29 Provisions charged during the year (Note 40) 9 7 10 26 Increase/(decrease) in the liability resulting from: Changes in estimates (24) – 9 (15) Changes in the discount rate (12) – – (12) Foreign exchange differences 8 – 2 10 Unwinding of discount 17 2 – 19 Utilization (3) (6) (6) (15) As of December 31, 2018, including 213 44 30 287 Non-current 207 29 8 244 Current 6 15 22 43 Asset retirement (decommissioning) obligations and Environmental remediation provision represent an estimate of the costs of liquidating oil and gas assets, the reclamation of sand pits, slurry ponds, and disturbed lands, and the dismantling of pipelines and power transmission lines. The budget for payments under asset retirement obligations is prepared on an annual basis. Depending on the current economic environment the Company’s actual expenditures may vary from the budgeted amounts.
33. Prepayment on long-term oil and petroleum products supply agreements During 2013-2014 the Company entered into a number of long-term crude oil and petroleum products supply contracts which require the buyer to make a prepayment. The total minimum delivery volume under those contracts at inception approximated 400 million tonnes. The crude oil and petroleum product prices are based on current market prices. The prepaymens are settled through physical deliveries of crude oil and petroleum products. Deliveries of oil and petroleum products that reduce the prepayment amounts commenced in 2015. The Company considers these contracts to be regular-way contracts. 2018 2017 As of January 1 1,586 1,841 Received 123 – Reimbursed (283) (255) Total prepayment on long-term oil and petroleum products supply agreements 1,426 1,586 Less current portion (354) (264) Long-term prepayment as of December 31 1,072 1,322 The off-set amounts under these contracts were RUB 283 billion and RUB 255 billion (US$ 7.03 billion and US$ 7.59 billion at the CBR official exchange rate at the prepayment dates, the prepayments are not revalued at each balance sheet date) for 2018 and 2017, respectively. 34. Other non-current liabilities Other non-current liabilities comprise the following: As of December 31, 2018 2017 Joint project liabilities 1 23 Liabilities for investing activities 2 4 Liabilities for joint operation contracts in Germany 21 14 Operating liabilities of subsidiary banks 17 1 Other 5 3 Total other non-current liabilities 46 45 35. Pension benefit obligations Defined contribution plans The Company makes payments to the State Pension Fund of the Russian Federation. These payments are calculated by the employer as a percentage of salary expense and are expensed as accrued. The Company also maintains a defined contribution corporate pension plan to finance the non-state pensions of its employees. Pension contributions recognized in the consolidated statement of profit or loss were as follows: 2018 2017 State Pension Fund 52 53 NPF Neftegarant 12 7 Total pension contributions 64 60
36. Shareholders’ equity Common shares As of December 31, 2018 and 2017: Authorized common shares quantity, millions 10,598 amount, billions of RUB 0.6 Issued and fully paid shares quantity, millions 10,598 amount, billions of RUB 0.6 Nominal value of 1 common share, RUB 0.01 On June 22, 2017 the Annual General Shareholders’ Meeting approved dividends on the Company’s common shares for 2016 in the amount of RUB 5.98 per share, which comprised RUB 63.4 billion. On September 29, 2017 the Extraordinary Shareholders’ Meeting approved interim dividends on the Company’s common shares for the first half of 2017 in the amount of RUB 3.83 per share, which comprised RUB 40.6 billion. On June 21, 2018 the Annual General Shareholders’ Meeting approved dividends on the Company’s common shares for 2017 in the amount of RUB 6.65 per share, which comprised RUB 70.5 billion. On September 28, 2018 the Extraordinary Shareholders’ Meeting approved interim dividends on the Company’s common shares for the first half of 2018 in the amount of 14.58 per share, which comprised RUB 154.5 billion. The dividends are distributed from the net profit of PJSC Rosneft Oil Company calculated in compliance with the current legislation of the Russian Federation. Program for the acquisition of own shares In accordance with the Program for the acquisition of shares on the market, including in the form of global depositary receipts certifying the rights to such shares, approved by the Board of Directors in August 2018 (hereinafter – the Program) ordinary shares of PJSC Rosneft Oil Company can be purchased up to a maximum amount of US$ 2 billion. The Program will run from the date of approval by the Board of Directors to December 31, 2020 inclusive. The maximum volume of shares and global depositary receipts that can be purchased under the Program is set to be no more than 340,000,000. The Program aims to sustain high returns to shareholders in case of significant market volatility. During 2018 there were no such share purchase transactions. 37. Fair value of financial instruments The fair value of financial assets and liabilities is determined as follows: The fair value of financial assets and liabilities quoted on active liquid markets is determined in accordance with market prices; The fair value of other financial assets and liabilities is determined in accordance with generally accepted models and is based on discounted cash flow analysis that relies on prices used for existing transactions in the current market; The fair value of derivative financial instruments is based on market quotes. In illiquid and highly volatile markets fair value is determined on the basis of valuation models that rely on assumptions confirmed by observable market prices or rates as of the reporting date. 37. Fair value of financial instruments (continued) Assets and liabilities of the Company that are measured at fair value on a recurring basis in accordance with the fair value hierarchy are presented in the table below.
Fair value measurement as of December 31, 2018 Level 1 Level 2 Level 3 Total Assets Current assets Financial assets at fair value through other comprehensive income 39 372 – 411 Financial assets at fair value recognized in profit or loss – 1 – 1 Non-current assets Financial assets at fair value through other comprehensive income – 18 – 18 Financial assets at fair value recognized in profit or loss – 110 – 110 Total assets measured at fair value 39 501 – 540 Liabilities Derivative financial instruments – (33) – (33) Total liabilities measured at fair value – (33) – (33) The fair value of financial assets at fair value through other comprehensive income, financial assets at fair value through profit or loss and derivative financial instruments included in Level 2 is measured at the present value of future estimated cash flows, using inputs such as market interest rates and market quotes of forward exchange rates. The carrying value of cash and cash equivalents and derivative financial instruments recognized in these consolidated financial statements equals their fair value. The carrying value of accounts receivable and accounts payable, loans issued, other financial assets and other financial liabilities recognized in these consolidated financial statements approximates their fair value. There were no transfers of financial liabilities between Level 1 and Level 2 during the reporting period. Carrying value Fair value (Level 2) As of December 31, As of December 31, 2018 2017 2018 2017 Financial liabilities Financial liabilities at amortized cost: Loans and borrowings with a variable interest rate (2,669) (1,549) (2,614) (1,467) Loans and borrowings with a fixed interest rate (1,361) (2,118) (1,316) (2,038) Finance lease liabilities (27) (32) (30) (36)
38. Related party transactions For the purpose of these consolidated financial statements, parties are considered to be related if one party has the ability to control the other party or exercise significant influence over the other party in making financial or operational decisions. In 2018 and 2017 the Company entered into transactions with shareholders and companies controlled by shareholders (including enterprises directly or indirectly controlled by the Russian Government and the BP Group), associates and joint ventures, key management and pension funds (Note 35). Related parties may enter into transactions which unrelated parties might not, and transactions between related parties may not be effected on the same terms as transactions between unrelated parties. The disclosure of related party transactions is presented on an aggregate basis for shareholders and companies controlled by shareholders, joint ventures and associates, and non-state pension funds. In addition, there may be additional disclosures of certain significant transactions (balances and turnovers) with certain related parties. In the course of its ordinary business, the Company enters into transactions with other companies controlled by the Russian Government. In the Russian Federation, electricity and transport tariffs are regulated by the Federal Antimonopoly Service, an authorized governmental agency of the Russian Federation. Bank loans are recorded based on market interest rates. Taxes are accrued and paid in accordance with applicable tax law. The Company sells crude oil and petroleum products to related parties in the ordinary course of business at prices close to average market prices. Transactions with shareholders and companies controlled by shareholders Revenues and income 2018 2017 Oil, gas, petroleum products and petrochemicals sales 888 784 Support services and other revenues 9 6 Finance income 19 26 916 816 Costs and expenses 2018 2017 Production and operating expenses 8 14 Cost of purchased oil, gas, petroleum products and refining costs 97 73 Pipeline tariffs and transportation costs 500 473 Other expenses 21 15 Financial expenses 26 8 652 583 Other operations 2018 2017 Acquisition of subsidiaries and interest in associates (3) – Loans received 266 297 Loans repaid (111) (58) Loans and borrowings issued (9) – Repayment of loans and borrowings issued 2 1 Deposits placed (69) (7) Deposits repaid 463 2
38. Related party transactions (continued) Transactions with shareholders and companies controlled by shareholders (continued) Settlement balances As of December 31, 2018 2017 Assets Cash and cash equivalents 498 57 Accounts receivable 77 68 Prepayments and other current assets 65 61 Other financial assets 325 636 965 822 Liabilities Accounts payable and accrued liabilities 47 32 Loans and borrowings and other financial liabilities 904 655 951 687 Transactions with joint ventures Crude oil is purchased from joint ventures at Russian domestic market prices. Revenues and income 2018 2017 Oil, gas, petroleum products and petrochemicals sales 13 11 Support services and other revenues 3 10 Finance income 5 26 21 47 Costs and expenses 2018 2017 Production and operating expenses 3 5 Cost of purchased oil, gas, petroleum products and refining costs 297 285 Pipeline tariffs and transportation costs 12 9 Other expenses 3 4 Finance expenses 1 1 316 304 Other operations 2018 2017 Acquisition of interest in associates and joint ventures – (8) Loans and borrowing issued (6) (2) Repayment of loans and borrowings issued 29 127 Settlement balances As of December 31, 2018 2017 Assets Accounts receivable 3 6 Other financial assets 17 52 20 58 Liabilities Accounts payable and accrued liabilities 141 85 Loans and borrowings and other financial liabilities 30 15 171 100 38. Related party transactions (continued) Transactions with associates
Revenues and income 2018 2017 Oil, gas, petroleum products and petrochemicals sales 364 222 Support services and other revenues 1 5 Finance income 4 – 369 227 Costs and expenses 2018 2017 Production and operating expenses 13 11 Cost of purchased oil, gas, petroleum products and refining costs 42 14 Pipeline tariffs and transportation costs 1 1 Other expenses 17 13 Finance expenses 2 – 75 39 Other operations 2018 2017 Loans and borrowing issued (31) (32) Repayment of loans and borrowings issued 17 – Settlement balances As of December 31, 2018 2017 Assets Accounts receivable 26 33 Prepayments and other current assets 13 1 Other financial assets 57 41 96 75 Liabilities Accounts payable and accrued liabilities 16 8 Loans and borrowings and other financial liabilities 239 124 255 132 Transactions with non-state pension funds Costs and expenses 2018 2017 Other expenses 12 7 As of December 31, 2018 2017 Loans received 7 – Loans repaid (4) –
38. Related party transactions (continued) Transactions with non-state pension funds (continued) Settlement balances As of December 31, 2018 2017 Liabilities Accounts payable and accrued liabilities 4 1 Loans and borrowings and other financial liabilities 3 – 7 1 Compensation to key management personnel For the purpose of these consolidated financial statements key management personnel include members of the Management Board of PJSC Rosneft Oil Company and members of the Board of Directors. Short-term gross benefits of the Management Board members, taking into account personnel rotation, including payroll, bonuses and compensation payments totaled RUB 3,854 million and RUB 3,927 million in 2018 and 2017, respectively (social security fund contributions, which are not Management Board members’ income, totaled RUB 567 million and RUB 579 million, respectively). Short-term gross benefits for 2018 are disclosed in accordance with the Russian securities law on information disclosure. On June 21, 2018, the Annual General Shareholders Meeting approved remuneration to the following members of the Company’s Board of Directors for the period of their service in the following amounts: Mr. Gerhard Schröder – US$ 600,000 (RUB 38.2 million at the CBR official exchange rate on June 21, 2018); Mr. Faisal Alsuwaidi – US$ 530,000 (RUB 33.7 million at the CBR official exchange rate on June 21, 2018); Mr. Matthias Warnig – US$ 580,000 (RUB 36.9 million at the CBR official exchange rate on June 21, 2018); Mr. Oleg Viyugin – US$ 565,000 (RUB 35.9 million at the CBR official exchange rate on June 21, 2018); Mr. Ivan Glasenberg – US$ 530,000 (RUB 33.7 million at the CBR official exchange rate on June 21, 2018); Mr. Donald Humphreys – US$ 580,000 (RUB 36.9 million at the CBR official exchange rate on June 21, 2018). Remuneration does not include compensation of travel expenses. No remuneration was paid to members of the Board of Directors who are state officials (Andrey Belousov and Alexander Novak) or to Mr. Igor Sechin, the Chairman of the Management Board, for their Board of Directors service. On June 22, 2017, the Annual General Shareholders Meeting approved remuneration to the following members of the Company’s Board of Directors for the period of their service in the following amounts: Mr. Andrey Akimov – US$ 545,000 (RUB 32.7 million at the CBR official exchange rate on June 22, 2017); Mr. Matthias Warnig – US$ 580,000 (RUB 34.8 million at the CBR official exchange rate on June 22, 2017); Mr. Oleg Viyugin – US$ 580,000 (RUB 34.8 million at the CBR official exchange rate on June 22, 2017); Mr. Donald Humphreys – US$ 565,000 (RUB 33.9 million at the CBR official exchange rate on June 22, 2017). Remuneration does not include compensation of travel expenses. No remuneration was paid to members of the Board of Directors who are state officials (Andrey Belousov and Alexander Novak) or to Mr. Igor Sechin, the Chairman of the Management Board, for their Board of Directors service.
39. Key subsidiaries Name Country of incorporation Core activity 2018 2017 Preferred and common shares Voting shares Preferred and common shares Voting shares % % % % Exploration and production JSC Orenburgneft Russia Oil and gas development and production 100.00 100.00 100.00 100.00 JSC Samotlorneftegaz Russia Oil and gas development and production 100.00 100.00 100.00 100.00 JSC Vankorneft Russia Oil and gas development and production 50.10 50.10 50.10 50.10 LLC RN-Yuganskneftegaz Russia Oil and gas production operator services 100.00 100.00 100.00 100.00 PJSC Bashneft Oil Company Russia Oil and gas development and production 60.33 70.93 60.33 70.93 Refining, marketing and distribution JSC RORC Russia Petroleum refining 100.00 100.00 100.00 100.00 JSC Angarsk Petrochemical Company Russia Petroleum refining 100.00 100.00 100.00 100.00 JSC Novokuybyshev Refinery Russia Petroleum refining 100.00 100.00 100.00 100.00 LLC RN-Komsomolsky Refinery Russia Petroleum refining 100.00 100.00 100.00 100.00 JSC Syzran Refinery Russia Petroleum refining 100.00 100.00 100.00 100.00 JSC Achinsk Refinery Russia Petroleum refining 100.00 100.00 100.00 100.00 JSC Kuybyshev Refinery Russia Petroleum refining 100.00 100.00 100.00 100.00 LLC RN-Tuapse Refinery Russia Petroleum refining 100.00 100.00 100.00 100.00 LLC RN-Bunker Russia Marketing and distribution 100.00 100.00 100.00 100.00 LLC RN-Aero Russia Marketing and distribution 100.00 100.00 100.00 100.00 LLC RN-Commerce Russia Marketing and distribution 100.00 100.00 100.00 100.00 LLC RN-Trade Russia Investing activity 100.00 100.00 100.00 100.00 Rosneft Trading S.A. Switzerland Marketing and distribution 100.00 100.00 100.00 100.00 Rosneft Deutschland GmbH Germany Marketing and distribution 100.00 100.00 100.00 100.00 Other JSC RN Holding Russia Holding company 100.00 100.00 100.00 100.00 JSC Russian Regional Development Bank (VBRR) Russia Banking 98.34 98.34 98.34 98.34 LLC RN-GAZ Russia Holding company 100.00 100.00 100.00 100.00 Rosneft Singapore Pte. Ltd. Singapore Holding company 100.00 100.00 100.00 100.00 LLC RN-Foreign Projects Russia Holding company 100.00 100.00 100.00 100.00 Rosneft Holdings LTD S.A. Luxemburg Holding company 100.00 100.00 100.00 100.00 TOC Investments Corporation Limited Cyprus Other services 100.00 100.00 100.00 100.00 40. Contingencies Russian business environment Russia continues economic reforms and the development of its legal, tax and regulatory frameworks as required by a market economy. The future stability of the Russian economy is largely dependent upon these reforms and developments and the effectiveness of economic, financial and monetary measures undertaken by the government. The Russian economy has been negatively impacted by sanctions imposed on Russia by a number of countries. Ruble interest rates remained high. The combination of the above has resulted in reduced access to capital, a higher cost of capital and uncertainty regarding economic growth, which could negatively affect the Company’s future financial position, results of operations and business prospects. Management is taking appropriate measures to support the sustainability of the Company’s business in the current circumstances.
40. Contingencies (continued) Russian business environment (continued) The Company also has investments in associates and joint ventures and advances issued to contractors operating in foreign jurisdictions. Besides commercial risks being a part of any investment operation, assets in a number of regions of the Company’s activities also bear political, economic and tax risks which are analyzed by the Company on a regular basis. The Company continuously monitors projects in Venezuela realized with its participation. Commercial relations with the Venezuelan state oil company PDVSA are carried out on the basis of existing contracts and in accordance with applicable international and local legislation. Guarantees and indemnities issued An unconditional unlimited guarantee issued in 2013 in favor of the Government and municipal authorities of Norway is effective in respect of the Company’s operations on the Norwegian continental shelf. That guarantee fully covers all potential ongoing environmental liabilities of RN Nordic Oil AS. A parent company guarantee is required by Norwegian legislation and is an essential condition for licensing the operations of RN Nordic Oil AS on the Norwegian continental shelf jointly with Equinor (until July 2018 – Statoil ASA). The Company’s agreements with Eni S.p.A, Equinor (until July 2018 г. – Statoil ASA) and the ExxonMobil Oil Corporation under the Russian Federation shelf exploration program contain mutual guarantees provided in 2013 and 2014 that are unconditional, unlimited and open-ended. The partnership agreement with the ExxonMobil Oil Corporation for difficult to extract oil reserves in Western Siberia contains mutual guarantees that are unconditional, unlimited and open-ended. In the fourth quarter of 2015 in accordance with the cooperation agreement on difficult to extract oil reserves with Equinor (until July 2018 г. – Statoil ASA), both parties issued parent guarantees on the discharging of the mutual liabilities of their related parties. These guarantees are unconditional, unlimited and open-ended. During 2018, as part of the operating activities of Rosneft, an unconditional irrevocable guarantees were issued in favor of the Government of the Republic of Mozambique providing the coverage of potential liabilities for geological exploration on the Mozambique continental shelf (4 years). In the course of its investing activities, the Company issued guarantees and sureties to third parties up to the RUB 57 billion. As of the period-end the Company assesses the probability of settlement as remote. Legal claims Rosneft and its subsidiaries are involved in litigations which arise from time to time in the course of their business activities. Management believes that the ultimate results of these litigations will not materially affect the performance or financial position of the Company. Taxation Legislation and regulations regarding taxation in Russia continue to evolve. Various legislative acts and regulations are not always clearly written, and their interpretation is subject to the opinions of the taxpayers, and local, regional, and national tax authorities, and the Ministry of Finance of the Russian Federation. Instances of inconsistent opinions are not unusual.
40. Contingencies (continued) Taxation (continued) In Russia, tax returns remain open and subject to inspection for a period of up to three years. The fact that a year has been reviewed does not close that year, or any tax return applicable to that year, from further review during the period of three calendar years preceding the year when the inspection started. In accordance with Russian tax legislation, if an understatement of a tax liability is detected as a result of an inspection, penalties and fines to be paid might be material in respect of the tax liability misstatement. During the reporting period, the tax authorities continued their inspections of Rosneft and some of its subsidiaries for 2014-2017. The Company’s management does not expect the outcome of the inspections to have a material impact on the Company’s consolidated balance sheet or results of operations. As part of the new regime for fiscal control over the pricing of related party transactions, the Company and the Federal Tax Service signed a number of pricing agreements in 2012-2018 with respect to the taxation of oil sales transactions in Russia. To date, the Russian Federal Tax Service has not exercised its right to conduct tax audits under the rules of transfer pricing for 2012-2015 and these periods are now “closed” for tax control purposes. For subsequent periods the Company has provided explanations to the Russian Federal Tax Service and the regional tax authorities to the extent necessary for the completed transactions. The Company believes that transfer pricing risks in relation to intragroup transactions during the twelve months of 2018 and earlier will not have a material effect on its financial position or results of operations. In 2012 the Company has created a consolidated group of taxpayers (hereinafter “CGT”) which includes Rosneft and its 21 subsidiaries. Rosneft became the responsible taxpayer of the CGT. At present, under the terms of the agreement the number of members of the consolidated group of taxpayers has been 64. The Company follows the rules of tax legislation on de-offshorization, including income tax rules for controlled foreign companies to calculate its current and deferred income tax estimates. Overall, management believes that the Company has paid and accrued all taxes that are applicable. For taxes where uncertainty exists, the Company has accrued tax liabilities based on management’s best estimate of the probable outflow of resources that will be required to settle these liabilities. Capital commitments The Company and its subsidiaries are engaged in ongoing capital projects for the exploration and development of production facilities and the modernization of refineries and the distribution network. The budgets for these projects are generally set on an annual basis. The total amount of contracted but not yet delivered goods and services related to the construction and acquisition of property, plant and equipment amounted to RUB 758 billion and RUB 716 billion as of December 31, 2018 and 2017, respectively. Environmental liabilities The Company periodically evaluates its environmental liabilities pursuant to environmental regulations. Such liabilities are recognized in the consolidated financial statements as and when identified. Potential liabilities, that could arise as a result of changes in existing regulations or the settlement of civil litigation, or as a result of changes in environmental standards, cannot be reliably estimated but may be material. With the existing system of control, management believes that there are no material liabilities for environmental damage other than those recorded in these consolidated financial statements.
Note 41 (Supplementary oil and gas disclosure (unaudited)) has been omitted in accordance with Form 20-F.