IMPORTANT NOTICE

This prospectus (the ‘‘Prospectus’’) is a prospectus for the purposes of Directive 2003/71/EC, as amended (the ‘‘Prospectus Directive’’) and has been prepared solely in connection with the proposed offering (the ‘‘Offering’’) of Notes (the ‘‘Notes’’) of Alliance Oil Company Ltd. (the ‘‘Issuer’’) and guaranteed by Closed Joint-Stock Company Alliance Oil, Open Joint Stock Company Oil Company Alliance, Limited Liability Company ‘‘Alliance-Bunker’’, Closed Joint-Stock Company Alliancetransoil, Open Joint Stock Company ‘‘Amurnefteproduct’’, OPEN Joint Stock Company ‘‘Khabarovsknefteproduct’’, Closed Joint Stock Company Khvoinoye, Kolvinskoe Limited Liability Company, Open Joint Stock Company ‘‘Pechoraneft’’, ‘‘Potential Oil’’ Limited Liability Partnership, Public Joint Stock Company ‘‘Primornefteprodukt’’, Open Joint Stock Company ‘‘Eastern Transnational Company’’ and Limited Liability Company SN-Gasproduction (collectively, the ‘‘Guarantors’’). THIS OFFERING IS AVAILABLE ONLY TO INVESTORS WHO ARE EITHER (1) QUALIFIED INSTITUTIONAL BUYERS (‘‘QIBS’’) IN RELIANCE ON THE EXEMPTION FROM THE REGISTRATION REQUIREMENTS OF THE U.S. SECURITIES ACT OF 1933 (THE ‘‘SECURITIES ACT’’) PROVIDED BY RULE 144A OR (2) OUTSIDE OF THE UNITED STATES IN COMPLIANCE WITH REGULATION S UNDER THE SECURITIES ACT (‘‘REGULATION S’’). IMPORTANT: You must read the following before continuing. The following applies to the Prospectus following this page, and you are therefore advised to read this carefully before reading, accessing or making any other use of the Prospectus. In accessing the Prospectus, you agree to be bound by the following terms and conditions, including any modifications to them any time you receive any information as a result of such access. NOTHING IN THIS ELECTRONIC TRANSMISSION CONSTITUTES AN OFFER OF SECURITIES FOR SALE IN ANY JURISDICTION WHERE IT IS UNLAWFUL TO DO SO. THE SECURITIES HAVE NOT BEEN, AND WILL NOT BE, REGISTERED UNDER THE SECURITIES ACT, OR THE SECURITIES LAWS OF ANY STATE OF THE UNITED STATES OR OTHER JURISDICTION AND THE SECURITIES MAY NOT BE OFFERED OR SOLD WITHIN THE UNITED STATES (AS DEFINED IN REGULATION S UNDER THE SECURITIES ACT), EXCEPT PURSUANT TO AN EXEMPTION FROM, OR IN A TRANSACTION NOT SUBJECT TO, THE REGISTRATION REQUIREMENTS OF THE SECURITIES ACT AND APPLICABLE STATE OR LOCAL SECURITIES LAWS. THE FOLLOWING DOCUMENT MAY NOT BE FORWARDED OR DISTRIBUTED TO ANY OTHER PERSON AND MAY NOT BE REPRODUCED IN ANY MANNER WHATSOEVER. ANY FORWARDING, DISTRIBUTION OR REPRODUCTION OF THE DOCUMENT IN WHOLE OR IN PART IS UNAUTHORISED. FAILURE TO COMPLY WITH THIS DIRECTIVE MAY RESULT IN A VIOLATION OF THE SECURITIES ACT OR THE APPLICABLE LAWS OF OTHER JURISDICTIONS. Confirmation of your representation: In order to be eligible to view the Document or make an investment decision with respect to the securities, investors must be either (1) a QIB (within the meaning of Rule 144A under the Securities Act (‘‘Rule 144A’’)) or (2) outside the United States. The Document is being sent at your request and by accepting the e-mail and accessing the Document, you shall be deemed to have represented to us that (1) you and any customers you represent are either (a) QIBS or (b) you and the electronic mail address that you gave us and to which this e-mail has been delivered are not located in the United States and (2) you consent to delivery of such Document by electronic transmission. Under no circumstances shall this Prospectus constitute an offer to sell or the solicitation of an offer to buy, nor shall there be any sale of the securities being offered, in any jurisdiction in which such offer, solicitation or sale would be unlawful. Recipients of this Prospectus who intend to subscribe for or purchase the Notes are reminded that any subscription or purchase may only be made on the basis of the information contained in this Prospectus. The Notes are not eligible for placement and circulation in the Russian Federation, unless, and to the extent, otherwise permitted by Russian law. The information provided in this Prospectus is not an offer or an invitation to make offers, sell, exchange or otherwise transfer the Notes in the Russian Federation or to or for the benefit of any Russian person or entity. This Prospectus and information contained herein does not constitute an advertisement or an offer of any securities in the Russian Federation. It is not intended to be, and must not be, distributed or circulated in the Russian Federation unless and to the extent otherwise permitted under Russian law. Securities may be offered or sold in Bermuda only in compliance with the provisions of the Investment Business Act 2003, the Exchange Control Act 1972 and related regulations of Bermuda which regulate the sale of securities in Bermuda. In addition, specific permission may be required from the Bermuda Monetary Authority (the ‘‘BMA’’), pursuant to the provisions of the Exchange Control Act 1972 and related regulations. Additionally, non-Bermudian persons may not carry on or engage in any or business in Bermuda unless such persons are authorised to do so under applicable Bermuda legislation. Engaging in the activity of offering or marketing the offered Notes in Bermuda to persons in Bermuda may be deemed to be carrying on business in Bermuda. Except with the permission of the Controller of Foreign Exchange in Bermuda, the Issuer shall not issue notes in bearer form in Bermuda. The BMA, the Minister of Finance of Bermuda and the Registrar of Companies accept no responsibility for the financial soundness of any proposal or for the correctness of any of the statements made or opinions expressed in this Prospectus or in any prospectus supplement. You are reminded that this Prospectus has been delivered to you on the basis that you are a person into whose possession this Prospectus may be lawfully delivered in accordance with the laws of the jurisdiction in which you are located and you may not, nor are you authorised to, deliver this Prospectus to any other person. The materials relating to the offering do not constitute, and may not be used in connection with, an offer or solicitation in any place where offers or solicitations are not permitted by law. If a jurisdiction requires that the offering be made by a licenced broker or dealer and the underwriters or any affiliate of the underwriters is a licenced broker or dealer in that jurisdiction, the offering shall be deemed to be made by the underwriters or such affiliate on behalf of the Issuer in such jurisdiction. No person may communicate or cause to be communicated any invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act 2000, as amended (the ‘‘FSMA’’)) received by it in connection with the issue or sale of the Notes other than in circumstances in which Section 21(1) of the FSMA does not apply. This Prospectus has been sent to you in an electronic form. You are reminded that documents transmitted via this medium may be altered or changed during the process of electronic transmission and consequently none of the Managers or any person who controls them, nor any director, officer, employee or agent of any of them or affiliate of any such person accepts any liability or responsibility whatsoever in respect of any difference between the Prospectus distributed to you in electronic format and the hard copy version available to you on request from the Managers. Alliance Oil Company Ltd. (Registered number 25413, incorporated with limited liability under the laws of Bermuda) as issuer of USD 500,000,000 7.000% Guaranteed Notes due 2020 Unconditionally and irrevocably guaranteed on a joint and several basis by Closed Joint-Stock Company Alliance Oil, Open Joint Stock Company Oil Company Alliance, Limited Liability Company ‘‘Alliance-Bunker’’, Closed Joint-Stock Company Alliancetransoil, Open Joint Stock Company ‘‘Amurnefteproduct’’, OPEN Joint Stock Company ‘‘Khabarovsknefteproduct’’, Closed Joint Stock Company Khvoinoye, Kolvinskoe Limited Liability Company, Open Joint Stock Company ‘‘Pechoraneft’’, ‘‘Potential Oil’’ Limited Liability Partnership, Public Joint Stock Company ‘‘Primornefteprodukt’’, Open Joint Stock Company ‘‘Eastern Transnational Company’’ and Limited Liability Company SN-Gasproduction

Issue price of Notes: 99.32%

Alliance Oil Company Ltd. (the ‘‘Issuer’’) is issuing USD 500,000,000 aggregate principal amount of 7.000% guaranteed notes due 2020 (the ‘‘Notes’’). Interest on the Notes will accrue from 3 May 2013 at a rate of 7.000% per annum of their outstanding principal amount payable semi- annually in arrears on 4 May and 4 November of each year, commencing on 4 November 2013. Each of the Partly Owned Guarantors (as defined below) will separately enter into a Deed of Guarantee with BNY Mellon Corporate Trustee Services Limited as trustee for the holders of the Notes (the ‘‘Trustee’’) to be dated on or about 3 May 2013 (each a ‘‘Deed of Guarantee’’ and together, the ‘‘Deeds of Guarantee’’) and each of the Fully Owned Guarantors (as defined below) will enter into the trust deed with the Trustee and the Issuer to be dated 3 May 2013 (the ‘‘Trust Deed’’) to unconditionally and irrevocably on a joint and several basis guarantee the due and punctual payment of all amounts at any time becoming due and payable in respect of the Notes (each a ‘‘Guarantee’’ and together, the ‘‘Guarantees’’). The Notes will be subject to, and have the benefit of, the Trust Deed. Payments on the Notes will be made free and clear of any withholding imposed by Bermuda, the Russian Federation or to the extent described in ‘‘Terms and Conditions of the Notes’’ herein. The Notes may be redeemed by the Issuer in whole but not in part at 100% of their principal amount, plus accrued and unpaid interest, if the Issuer becomes obliged to pay certain additional amounts and otherwise as described under ‘‘Terms and Conditions of the Notes – Redemption and Purchase – Redemption for Taxation Reasons’’. Unless previously redeemed or purchased and cancelled, the Notes will be redeemed at their principal amount on 4 May 2020. An investment in the Notes involves a high degree of risk. Prospective Investors should have regard to the factors described under the section headed ‘‘Risk Factors’’ beginning on page 5. The Notes will be unsecured and unsubordinated obligations of the Issuer and will rank equally in right of payment with the Issuer’s existing and future unsecured and unsubordinated obligations. The Notes will be fully, irrevocably and unconditionally guaranteed on a joint and several basis by Open Joint Stock Company Oil Company Alliance (‘‘NK Alliance’’), Closed Joint-Stock Company Alliancetransoil (‘‘Alliancetransoil’’), Closed Joint-Stock Company Alliance Oil (‘‘Alliance Oil’’), Limited Liability Company ‘‘Alliance-Bunker’’ (‘‘Alliance-Bunker’’), Closed Joint Stock Company Khvoinoye (‘‘Khvoinoye’’), Kolvinskoe Limited Liability Company (‘‘Kolvinskoe’’), Open Joint Stock Company ‘‘Eastern Transnational Company’’ (‘‘VTK’’) and Limited Liability Company SN-Gasproduction (‘‘SN-Gasproduction’’) (the ‘‘Fully Owned Guarantors’’) and Open Joint Stock Company ‘‘Amurnefteproduct’’ (‘‘Amurnefteproduct’’), OPEN Joint Stock Company ‘‘Khabarovsknefteproduct’’ (‘‘Khabarovsknefteproduct’’), Open Joint Stock Company ‘‘Pechoraneft’’ (‘‘Pechoraneft’’), ‘‘Potential Oil’’ Limited Liability Partnership (‘‘Potential Oil’’) and Public Joint Stock Company ‘‘Primornefteprodukt’’ (‘‘Primornefteproduct’’) (the ‘‘Partly Owned Guarantors’’ and, together with the Fully Owned Guarantors, the ‘‘Guarantors’’). The Guarantees will be unsecured and unsubordinated debt obligations of the Guarantors and will rank equally in right of payment with all existing and future unsecured and unsubordinated obligations of the Guarantors. The Notes and the Guarantees have not been and will not be registered under the U.S. Securities Act of 1933 (the ‘‘Securities Act’’) and, subject to certain exceptions, may not be offered or sold within the United States. This Prospectus has been approved by the Central Bank of Ireland (the ‘‘Central Bank’’), as competent authority under Directive 2003/71/EC, as amended (the ‘‘Prospectus Directive’’). The Central Bank only approves this Prospectus as meeting the requirements imposed under Irish and EU law pursuant to the Prospectus Directive. Such approval relates only to the Notes that are to be admitted to trading on the regulated market of the Irish Stock Exchange (the ‘‘Irish Stock Exchange’’) or other regulated markets for the purposes of Directive 2004/39/EC or which are to be offered to the public in any Member State of the European Economic Area. Application will be made to the Irish Stock Exchange for the Notes to be admitted to the Official List (the ‘‘Official List’’) and trading on its regulated market (the ‘‘Main Securities Market’’). Reference in this Prospectus to Notes being ‘‘listed’’ (and all related references) shall mean that such Notes have been admitted to trading on the Main Securities Market. The language of this Prospectus is English. The Central Bank has only approved this document in relation to Notes that are to be listed on the Main Securities Market of the Irish Stock Exchange or another regulated market in the European Economic Area. This Prospectus will be filed with the Registrar of Companies in Bermuda pursuant to section 26(2)(b) of the Companies Act 1981 of Bermuda. Regulation S Notes will initially be represented by interests in a global unrestricted Note in registered form (each a ‘‘Regulation S Global Note’’), without interest coupons, which will be deposited with a common depositary for Euroclear Bank SA/NV (‘‘Euroclear’’) and Clearstream Banking, socie´te´ anonyme (‘‘Clearstream, Luxembourg’’), and registered in the name of the nominee of the common depository, on its issue date as set out in this Prospectus (the ‘‘Issue Date’’). Beneficial interests in a Regulation S Global Note will be shown on, and transfers thereof will be effected only through records maintained by, Euroclear or Clearstream, Luxembourg. Rule 144A Notes will initially be represented by a global restricted Note in registered form (each a ‘‘Rule 144A Global Note’’ and together with any Regulation S Global Notes, the ‘‘Global Notes’’), without interest coupons, which will be deposited with a custodian for, and registered in the name of Cede & Co., the nominee of The Depository Trust Company (‘‘DTC’’) on its Issue Date. Beneficial interests in a Rule 144A Global Note will be shown on, and transfers thereof will be effected only through, records maintained by DTC and its participants. See ‘‘Clearing and Settlement’’. Individual definitive Notes in registered form will only be available in certain limited circumstances as described herein. The credit ratings included in this Prospectus have been issued, for the purposes of Regulation (EC) No 1060/2009 as amended by Regulation (EU) No 513/2011 (the ‘‘CRA Regulation’’), by Fitch Ratings Ltd. (‘‘Fitch’’) and Standard & Poor’s Credit Market Services Europe Limited (‘‘S&P’’). Fitch and S&P are established in the European Union (the ‘‘EU’’) and registered under the CRA Regulation. As such, Fitch and S&P are included in the list of credit rating agencies published by the European Securities and Markets Authority on its website in accordance with the CRA Regulation. The Notes will be in registered form and will be offered and sold in the minimum denomination of USD 200,000 (or integral multiples of USD 1,000 in excess thereof). Joint Lead Managers Deutsche Bank Gazprombank Goldman Sachs International Raiffeisen Bank International Co-Managers Carnegie Investment Bank OTKRITIE UniCredit Bank

The date of this Prospectus is 30 April 2013 This Prospectus comprises a prospectus for the purposes of the Prospectus Directive and for the purpose of giving information with regard to the Issuer and its consolidated subsidiaries and affiliates taken as a whole (the ‘‘Group’’), the Guarantors, the Notes and the Guarantees, which, according to the particular nature of the Issuer, the Group, the Guarantors and the Notes and the Guarantees, is necessary to enable investors to make an informed assessment of the assets and liabilities, financial position, profits and losses and prospects of the Issuer, the Group and the Guarantors, and the rights attaching to the Notes and the Guarantees. The Issuer accepts responsibility for the information contained in this Prospectus. To the best of the knowledge of the Issuer (which has taken all reasonable care to ensure that such is the case), the information contained in this Prospectus is in accordance with the facts and does not omit anything likely to affect the import of such information. Each Guarantor accepts responsibility for the information contained in this Prospectus relating to itself and to its Guarantee. To the best of the knowledge of each Guarantor (each of which has taken all reasonable care to ensure that such is the case), the information contained in this Prospectus relating to itself and its Guarantee is in accordance with the facts and does not omit anything likely to affect the import of such information. THE NOTES ARE OF A SPECIALIST NATURE AND SHOULD ONLY BE BOUGHT AND TRADED BY INVESTORS WHO ARE PARTICULARLY KNOWLEDGEABLE IN INVESTMENT MATTERS. AN INVESTMENT IN THE NOTES IS SPECULATIVE, INVOLVES A HIGH DEGREE OF RISK AND MAY RESULT IN THE LOSS OF ALL OR PART OF THE INVESTMENT. No person has been authorised to give any information or to make any representation other than those contained in this Prospectus and any information or representation not so contained must not be relied upon as having been authorised by or on behalf of the Issuer, the Trustee or the Managers (as defined herein). Neither the delivery of this Prospectus nor any sale made in connection herewith shall, under any circumstances, create any implication that there has been no change in the affairs of the Issuer or the Guarantors or the Group since the date hereof or that there has been no adverse change in the financial position of the Issuer or the Guarantors or the Group since the date hereof or that the information contained in it or any other information supplied in connection with the Notes and the Guarantees is correct as of any time subsequent to the date on which it is supplied or, if different, the date indicated in the document containing the same. Neither the Issuer nor any other person assumes any obligation (and expressly declares that it has no such obligation) to update or change any information contained in this Prospectus once there is no longer a requirement under the Prospectus Directive for the Prospectus to be updated. No representation, warranty or undertaking, express or implied, is made and no responsibility is accepted by the Managers or the Trustee as to the accuracy or completeness of the information contained in this Prospectus or any other information supplied in connection with the Notes and Guarantees. Each person receiving this Prospectus acknowledges that such person has not relied on any of the Managers or the Trustee in connection with its investigation of the accuracy of such information or its investment decision and each person must rely on its own examination of the Issuer and the merits and risks involved in investing in the Notes and Guarantees. None of the Managers accepts any responsibility whatsoever for the contents of this Prospectus or for any other statement made or purported to be made by it, or on its behalf, in connection with the Issuer, the Guarantors, the Notes or the Guarantees. Each of the Managers accordingly disclaims all and any liability whether arising in tort, contract or otherwise which it might otherwise have in respect of this Prospectus or any such statement. This Prospectus does not constitute an offer to sell or an invitation to subscribe for or purchase any of the Notes in any jurisdiction in which such offer or invitation is not authorised or to any person to whom it is unlawful to make such an offer or invitation. Laws in certain jurisdictions may restrict the distribution of this Prospectus and the offer and sale of the Notes. Persons into whose possession this Prospectus or any of the Notes are delivered must inform themselves about, and observe, any such restrictions. Each prospective purchaser of the Notes must comply with all applicable laws and regulations in force in any jurisdiction in which it purchases, offers or sells the Notes or possesses or distributes this Prospectus. In addition, each prospective purchaser must obtain any consent, approval or permission required under the regulations in force in any jurisdiction to which it is subject or in which it purchases, offers or sells the Notes. The Issuer shall not have any responsibility for obtaining such consent, approval or permission. This Prospectus may not be used for, or in connection with, any offer to, or solicitation by, anyone in any jurisdiction or under any circumstances in which such offer or solicitation is not authorised or is unlawful. For a description of

ii c108210pu010 Proof 9: 29.4.13_14:30 B/L Revision: 0 Operator PutA these further restrictions on offers and sales of the Notes and distribution of this Prospectus, see ‘‘Subscription and Sale’’ beginning on page 172. This Prospectus is only being distributed to and is only directed at (i) persons who are outside the United Kingdom (ii) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the ‘‘Order’’) or (iii) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as ‘‘relevant persons’’). The Notes are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such Notes will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this document or any of its contents. No action is being taken to permit a public offering of the Notes or the distribution of this Prospectus (in any form) in any jurisdiction where action would be required for such purposes. The contents of this Prospectus should not be construed as legal, financial, business or advice. Each prospective investor should consult his or her own legal adviser, financial adviser or tax adviser for legal, financial or tax advice in relation to any purchase or proposed purchase of Notes. Prospective purchasers should be aware that they might be required to bear the financial risks of an investment in the Notes for an indefinite period of time. In connection with the offering of the Notes, the Managers and any of their affiliates, acting as investors for their own accounts, may purchase Notes and in that capacity may retain, purchase, sell, offer to sell or otherwise deal for their own accounts in such Notes and other securities of the Issuer or the Guarantors or related investments in connection with the offering of the Notes or otherwise. Accordingly, references in this Prospectus to the Notes being issued, offered, acquired, placed or otherwise dealt in should be read as including any issue or offer to, or acquisition, placing or dealing by, the Managers and any of their affiliates acting as investors for their own accounts. The Managers do not intend to disclose the extent of any such investment or transactions otherwise than in accordance with any legal or regulatory obligations to do so. Recipients of this Prospectus are authorised to use it solely for the purpose of considering an investment in the Notes and may not reproduce or distribute this Prospectus, in whole or in part, and may not disclose any of the contents of this Prospectus or use any information herein for any purpose other than considering an investment in the Notes. In making an investment decision, prospective investors must rely upon their own examination of the Issuer, the Group and the Guarantors and the terms of this Prospectus, including the risks involved. None of the Issuer, any Guarantor, the Managers nor the Trustee is making any representation to any offeree or purchaser of the Notes regarding the legality of an investment by such offeree or purchaser. The Managers and their respective affiliates have performed and expect to perform in the future various financial advisory, investment banking and commercial banking services for, and may arrange loans and other non-public market financing for, and enter into derivative transactions with, the Issuer and its affiliates (including its shareholders and the Guarantors). The Managers and their respective affiliates have performed and expect to perform in the future various financial advisory, investment banking and commercial banking services for, and may arrange non-public market financing for, and enter into derivatives transactions with, the Issuer and its affiliates. The Managers are acting exclusively for the Issuer and no one else in connection with the Notes and will not be responsible to any other person for providing the protections afforded to their respective clients or for providing advice in relation to this offering. The Issuer was incorporated with limited liability under the laws of Bermuda on 1 September 1998 for an unlimited duration with registered number 25413. The registered office of the Issuer is located at Clarendon House, 2 Church Street, Hamilton HM11, Bermuda. This Prospectus has been filed with and approved by the Central Bank of Ireland as required by the Prospectus (Directive 2003/71/EC) Regulations 2005. Any investment in any Notes does not have the status of a bank deposit and is not within the scope of the deposit protection scheme operated by the Central Bank of Ireland.

iii c108210pu010 Proof 9: 29.4.13_14:30 B/L Revision: 0 Operator PutA STABILISATION

IN CONNECTION WITH THE ISSUE OF THE NOTES, GOLDMAN SACHS INTERNATIONAL (THE ‘‘STABILISING MANAGER’’) (OR ANY PERSON ACTING ON BEHALF OF THE STABILISING MANAGER) MAY OVER-ALLOT NOTES OR EFFECT TRANSACTIONS WITH A VIEW TO SUPPORTING THE MARKET PRICE OF THE NOTES AT A LEVEL HIGHER THAN THAT WHICH MIGHT OTHERWISE PREVAIL. HOWEVER, THIS IS NO ASSURANCE THAT THE STABILISING MANAGER) (OR ANY PERSON ACTING ON BEHALF OF THE STABILISING MANAGER) WILL UNDERTAKE STABILISATION ACTION. ANY STABILISATION ACTION MAY BEGIN ON OR AFTER THE DATE ON WHICH ADEQUATE PUBLIC DISCLOSURE OF THE TERMS OF THE OFFER OF NOTES IS MADE AND, IF BEGUN, MAY BE ENDED AT ANY TIME, BUT IT MUST END NO LATER THAN THE EARLIER OF 30 DAYS AFTER THE ISSUE DATE OF THE NOTES AND 60 DAYS AFTER THE DATE OF THE ALLOTMENT OF THE NOTES. ANY STABILISATION ACTION OR OVER-ALLOTMENT MUST BE CONDUCTED BY THE STABILISING MANAGER (OR ANY PERSON ACTING ON BEHALF OF THE STABILISING MANAGER) IN ACCORDANCE WITH ALL APPLICABLE LAWS AND RULES. NO REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, IS MADE BY THE MANAGERS AS TO THE ACCURACY OR COMPLETENESS OF THE INFORMATION SET FORTH IN THIS PROSPECTUS, AND NOTHING CONTAINED IN THIS PROSPECTUS IS, OR SHALL BE RELIED UPON AS, A PROMISE OR REPRESENTATION, WHETHER AS TO THE PAST OR THE FUTURE. EACH PERSON RECEIVING THIS PROSPECTUS ACKNOWLEDGES THAT SUCH PERSON HAS NOT RELIED ON THE MANAGERS OR ANY OF THEIR AFFILIATES OR ANY PERSON ACTING ON THEIR BEHALF IN CONNECTION WITH ITS INVESTIGATION OF THE ACCURACY OR COMPLETENESS OF SUCH INFORMATION OR ITS INVESTMENT DECISION. EACH PERSON CONTEMPLATING MAKING AN INVESTMENT IN ANY NOTES MUST MAKE ITS OWN INVESTIGATION AND ANALYSIS OF THE CREDITWORTHINESS OF THE ISSUER AND THE GROUP AND ITS OWN DETERMINATION OF THE SUITABILITY OF ANY SUCH INVESTMENT, WITH PARTICULAR REFERENCE TO ITS OWN INVESTMENT OBJECTIVES AND EXPERIENCE, AND ANY OTHER FACTORS WHICH MAY BE RELEVANT TO IT IN CONNECTION WITH SUCH INVESTMENT. THE NOTES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE U.S. SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION IN THE UNITED STATES OR ANY OTHER U.S. REGULATORY AUTHORITY, NOR HAVE ANY OF THE FOREGOING AUTHORITIES PASSED UPON OR ENDORSED THE MERITS OF THE OFFERING OF NOTES OR THE ACCURACY OR THE ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENCE IN THE UNITED STATES. INFORMATION CONTAINED IN THIS PROSPECTUS IS NOT AN OFFER, OR AN INVITATION TO MAKE OFFERS, SELL, PURCHASE, EXCHANGE OR TRANSFER ANY SECURITIES IN THE RUSSIAN FEDERATION, AND DOES NOT CONSTITUTE AN ADVERTISEMENT OF OFFERING OF ANY SECURITIES IN THE RUSSIAN FEDERATION. THE SECURITIES REFERENCED TO IN THIS PROSPECTUS HAVE NOT BEEN AND WILL NOT BE REGISTERED IN THE RUSSIAN FEDERATION OR ADMITTED TO PUBLIC PLACEMENT AND/OR PUBLIC CIRCULATION IN THE RUSSIAN FEDERATION AND ARE NOT INTENDED FOR ‘‘PLACEMENT’’ OR ‘‘CIRCULATION’’ IN THE RUSSIAN FEDERATION EXCEPT AS PERMITTED BY RUSSIAN LAW.

NOTICE TO NEW HAMPSHIRE RESIDENTS

NEITHER THE FACT THAT A REGISTRATION STATEMENT, OR AN APPLICATION FOR A LICENSE HAS BEEN FILED UNDER CHAPTER 421-B OF THE NEW HAMPSHIRE REVISED STATUTES WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN THE STATE OF NEW HAMPSHIRE CONSTITUTES A FINDING BY THE SECRETARY OF STATE OF NEW HAMPSHIRE THAT ANY DOCUMENT FILED UNDER RSA 421-B IS TRUE,

iv c108210pu010 Proof 9: 29.4.13_14:30 B/L Revision: 0 Operator PutA COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT AN EXEMPTION OR EXCEPTION IS AVAILABLE FOR A SECURITY OR A TRANSACTION MEANS THAT THE SECRETARY OF STATE OF NEW HAMPSHIRE HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GIVEN APPROVAL TO, ANY PERSONS, SECURITY OR TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE MADE, TO ANY PROSPECTIVE PURCHASER, CUSTOMER, OR CLIENT ANY REPRESENTATION INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH.

AVAILABLE INFORMATION

The Issuer and Guarantors have agreed that, so long as any Notes are ‘‘restricted securities’’ within the meaning of Rule 144(a)(3) of the Securities Act, the Issuer and Guarantors will, during any period in which it is neither subject to Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended (the ‘‘Exchange Act’’) nor exempt from reporting thereunder pursuant to Rule 12g3-2(b) under the Exchange Act, provide to any holder or beneficial owner of any such ‘‘restricted security’’, or to any prospective purchaser of such restricted security designated by such holder or beneficial owner, the information specified in, and meeting the requirements of, Rule 144A(d)(4) of the Securities Act upon the request of such holder or beneficial owner. This Prospectus is being furnished by the Issuer in connection with an offering exempt from the registration requirements of the Securities Act solely for the purpose of enabling a prospective investor to consider the acquisition of Notes described herein. The information contained in this Prospectus has been provided by the Issuer and other sources identified herein. This Prospectus is being furnished on a confidential basis to QIBs in the United States. Any reproduction or distribution of this Prospectus, in whole or in part, in the United States and any disclosure of its contents or use of any information herein in the United States for any purpose, other than considering an investment by the recipient in the Notes offered hereby, is prohibited. Each potential investor in the Notes, by accepting delivery of this Prospectus, agrees to the foregoing.

v c108210pu010 Proof 9: 29.4.13_14:30 B/L Revision: 0 Operator PutA TABLE OF CONTENTS

OVERVIEW...... 1 RISK FACTORS ...... 5 FORWARD-LOOKING STATEMENTS ...... 36 ENFORCEABILITY OF JUDGMENTS...... 38 PRESENTATION OF CERTAIN INFORMATION ...... 40 OVERVIEW OF THE OFFERING ...... 45 USE OF PROCEEDS...... 48 CAPITALISATION...... 49 SUMMARY CONSOLIDATED FINANCIAL INFORMATION...... 50 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS...... 55 BUSINESS ...... 89 MANAGEMENT ...... 114 PRINCIPAL SHAREHOLDERS ...... 121 RELATED PARTY TRANSACTIONS ...... 123 TERMS AND CONDITIONS OF THE NOTES ...... 126 THE ISSUER AND GUARANTORS...... 156 TRANSFER RESTRICTIONS ...... 163 CLEARING AND SETTLEMENT...... 166 SUBSCRIPTION AND SALE ...... 172 REGULATION OF THE RUSSIAN OIL AND GAS INDUSTRY...... 175 TAXATION ...... 188 GENERAL INFORMATION...... 197 INDEX TO FINANCIAL STATEMENTS...... F-1

vi c108210pu010 Proof 9: 29.4.13_14:30 B/L Revision: 0 Operator PutA OVERVIEW

This section contains an overview of the detailed information and financial information included elsewhere in this Prospectus. This overview may not contain all of the information that may be material to prospective investors and, therefore, should be read in conjunction with this entire Prospectus, including the more detailed information regarding the Group’s business and financial information and related notes included elsewhere in this Prospectus or referenced herein. Prospective investors should also carefully consider the information set forth under the heading ‘‘Risk Factors’’. The Group is an independent and vertically integrated oil and gas company with both upstream and downstream operations in Russia and upstream operations in Kazakhstan. The Group’s upstream operations include crude oil exploration, extraction and production in the Timano-Pechora, Volga- Urals and Tomsk regions of Russia and the Atyrau region of Kazakhstan, as well as upstream gas operations in the Tomsk region; its downstream operations include oil refining as well as transportation, marketing and sale of refined petroleum products primarily in the Russian Far East. As of 31 December 2012, 2011 and 2010, the Group’s proven and probable crude oil and gas reserves under the Petroleum Resource Management System (‘‘PRMS’’) classification were 732.6 mmboe, 647.9 mmboe and 638.3 mmboe, respectively, and the Group’s proven crude oil and gas reserves under the PRMS classification were 330.8 mmboe, 309.6 mmboe and 286.4 mmboe, respectively. In addition, the Group holds an equity interest in the non-consolidated oil and gas reserves of AR Oil & Gaz B.V. (‘‘AROG’’), a joint venture with Repsol Exploracion, S.A. (‘‘Repsol’’), proportional to the Group’s ownership stake in the joint venture. For the years ended 31 December 2012, 2011 and 2010, the Group’s total crude oil production was 19.7 mmbbl, 17.9 mmbbl and 16.0 mmbbl, respectively. The Group has a diversified portfolio of assets and is currently developing 18 fields in Russia and one field in Kazakhstan as well as participating in AROG with the aim of increasing production in Russia. The Group is engaged in crude oil refining and marketing of refined products focused in the Russian Far East and conducts its refining operations at the Khabarovsk oil refinery (the ‘‘Khabarovsk Refinery’’), which as of 31 December 2012 had a refining capacity of 90,000 bopd. For the years ended 31 December 2012, 2011 and 2010, the Khabarovsk Refinery processed 29.3 mmbbl, 26.9 mmbbl and 23.7 mmbbl, respectively, and the Group sold 29.9 mmbbl, 27.6 mmbbl and 24.4 mmbbl of petroleum products during those periods, respectively. The Group markets refined petroleum products through its own network of 267 refuelling stations and 21 wholesale petroleum products terminals in the Khabarovsk, Primorsk, Amur, Jewish Autonomous District and Republic of Buryatia regions in Russia and also its petroleum products on market terms through Lia Oil S.A (‘‘Lia Oil’’), an affiliate, to neighbouring Asian markets. For the years ended 31 December 2012, 2011 and 2010, the Group’s revenue was USD 3,445,239 thousand, USD 3,082,660 thousand and USD 2,195,756 thousand, respectively. Revenue from crude oil sales was USD 602,354 thousand, USD 531,656 thousand and USD 397,943 thousand for the years ended 31 December 2012, 2011 and 2010, respectively, while revenue from oil product sales was USD 2,787,761 thousand, USD 2,496,218 thousand and USD 1,756,295 thousand for the years ended 31 December 2012, 2011 and 2010, respectively. For the years ended 31 December 2012, 2011 and 2010, the Group’s Adjusted EBITDA (as defined in ‘‘Selected Consolidated Financial Information’’) was USD 734,096 thousand, USD 690,345 thousand and USD 438,391 thousand, respectively.

Competitive Strengths The Group believes that it benefits from the following competitive strengths: * Diversified vertically integrated Russian oil and gas company. The Group is a vertically integrated oil and gas company with a diversified upstream and downstream asset mix delivering strategic flexibility in a volatile crude oil price environment. The Group expects to increase refining capacity from 90,000 bopd to 100,000 bopd at the Khabarovsk Refinery by the end of 2013 and to connect its operations at the Khabarovsk Refinery to the Eastern Siberia – Pacific Ocean (‘‘ESPO’’) oil pipeline in 2014. * Well positioned for growth across entire value chain. The Group believes it is optimally positioned to capitalise on growth opportunities along the entire upstream – downstream – marketing value chain. The Group’s business model generates strong cash flows from operations, providing flexibility and stability to its development plan and allowing it to

1 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA capitalise on new investment opportunities as they arise. The Group believes that it is well placed to improve its capital structure and lower its cost of capital by financing capital requirements through a combination of operating cash flow, long-term debt available under existing credit agreements and additional external debt. * High quality upstream assets. The Group has a balanced portfolio of high quality upstream oil and gas assets, which are geographically diversified across three major Russian oil- producing basins (West Siberia, Timano-Pechora and Volga-Urals) and in Kazakhstan. The Group’s upstream portfolio includes producing assets which provide significant production volumes, as well as exploration and development projects which are expected to contribute to the Group’s strong organic reserves growth profile going forward. The acquisition of gas assets and the launch of gas production have further expanded the Group’s upstream portfolio. * Robust retail and wholesale network. The Group has developed an extensive retail and wholesale petroleum product network in the Russian Far East and the Republic of Buryatia and also enjoys premium brand recognition among its retail and wholesale corporate customers in these regions. The Group believes that its premium brand, quality of facilities and high standard of service will continue to permit it to achieve a leading position on the retail market in these regions. * Advantageous geographic position of downstream and upstream assets. The Group operates in a relatively isolated petroleum products consumption market in the Russian Far East. There are currently only two major refineries operating in this market: the Group’s Khabarovsk Refinery and Rosneft’s Komsomolsk refinery. The isolated nature of the market contributes to sustained profitability of the Group’s marketing operations. The Group’s network of filling stations and wholesale petroleum products terminals allow for significant flexibility in the volumes and range of petroleum products sold. The Group’s refining operations are expected to benefit from the proposed connection of the Khabarovsk Refinery to the ESPO oil pipeline, resulting in decreased costs, especially related to railway transhipment expenses. Furthermore, the Khabarovsk Refinery is located close to the Russian Federation’s borders, which facilitates access to the growing Asia- Pacific petroleum products consumption markets (in particular, China, Japan and South Korea). The Group’s upstream assets are located in regions with existing transportation infrastructure which facilitates access to domestic and international markets. * Experienced management team and strong corporate governance. The Group benefits from the extensive upstream and downstream experience of the combined management team. The management of the Group strives to implement the latest technological innovations as well as industry’s best practices. The Group’s management is also committed to a high standard of transparency and corporate governance. The Group started the implementation of the Swedish code of corporate governance in 2006. Since 2006, the Group has also developed and implemented an application of the code that also corresponds to Bermudian law and company practice.

Strategy The Group seeks to capitalise on its position as an integrated oil and gas company, increased financing capacity and strong cash flows to further strengthen its position within the upstream and refined products industry. In particular, the Group intends to focus on increasing oil and gas reserves and production as well as producing and providing high-quality petroleum products and related services in Russia, the Commonwealth of Independent States (the ‘‘CIS’’), the Asia-Pacific region and other key markets. Some highlights of the Group’s development strategy are set forth below. There can be no assurance, however, that the Group will be able to achieve these targets. The targets are necessarily based upon a number of assumptions and estimates that, while considered reasonable by the Group, are inherently subject to significant market, business, actuarial, operational, political, economic, tax and competitive uncertainties and contingencies, many of which are beyond the Group’s control, and upon assumptions with respect to future business decisions that are subject to change. These targets also assume the success of the Group’s business strategy. The success of this strategy is subject to significant uncertainties and contingencies beyond the Group’s control, and no assurance can be given that the strategy will be effective or that the anticipated benefits from the strategy will be realised in the periods for which targets have been prepared, or at all. Accordingly, the Group cannot provide any assurance that these targets will be realised. The targets may vary

2 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA materially from the Group’s actual results. Prospective investors in the Notes are cautioned not to place undue reliance on this information. See ‘‘Forward-Looking Statements’’ and ‘‘Risk Factors’’. * Modernise refining capabilities. The Group will continue a significant modernisation programme for the Khabarovsk Refinery, which is expected to increase the refinery’s depth of refining from 65% to more than 90%, at 3 mmtonnes of production volume per year. This investment is expected to lead to an increase in refining capacity from 90,000 bopd to 100,000 bopd and the share of higher value-added light petroleum products in total output to meet a growing demand for light petroleum products in the Russian Far East, the Republic of Buryatia and the Asia- Pacific region, and is expected to result in refining margins improving significantly. The Group expects that it will be able to produce Euro-4/5 diesel upon the completion of the hydroprocessing complex at the Khabarovsk Refinery. * Increase hydrocarbon production. The Group aims to increase production by continuing to develop existing oil fields and new gas assets via investments in exploration activities, improving existing infrastructure and implementing operating efficiencies. It is expected that production can be increased while maintaining control of operating costs by employing proven technologies such as water injection, horizontal drilling, hydrofracturing and acid treatment to optimise oil recoveries from producing but under-developed fields. The Group’s assets contain a number of significant greenfield exploration and development opportunities that the Group is actively pursuing. * Further improve financial efficiency. The Group seeks to develop a cost conscious culture with strict financial controls and a daily financial review procedure for all subsidiaries put in place by the Group’s senior management team. The Group’s strategy is to further improve profitability by a combination of controlling and reducing costs and a focus on improving revenues from existing, newly developed and acquired assets, as well as by improving netbacks by more effectively allocating oil and petroleum product sales from each region to exports. * Increase upstream asset base. The Group will consider acquiring Russian oil and gas resources with proven developed reserves as well as development and exploration potential that are not sufficiently large to be of primary strategic interest to Russia’s larger oil companies but which can be developed profitably. For example, in January 2013, the Group completed the formation of a joint venture with Repsol, AROG to expand its exploration and production growth in Russia. As part of the joint venture, OJSC Eurotek (‘‘Eurotek’’), an exploration and production gas company with assets in Russia, was contributed by Repsol in early 2013. The Group also continues to review opportunities to participate in future subsoil licence auctions and tenders where access to economically attractive development and exploration opportunities with acceptable risk profiles and potential synergies with the Group’s existing operations are offered. * Bolster revenues from retail outlets. The Group is working to optimise its portfolio of existing filling stations with a focus on increasing non-fuel sales at these stations. The Group expects to increase its portfolio of retail filling stations in the Russian Far East and the Republic of Buryatia by constructing new stations and closing underperforming ones. As part of this process, the Group will seek to substantially increase the number of filling stations that also provide supplemental services and have associated retail shops with a diversified product offering or food kiosks, where appropriate. In addition, the Group recently has implemented a client loyalty system. Management expects this optimisation to enable the Group to implement price differentiation strategies according to the local market conditions. As a result, the Group believes it can increase both fuel and non-fuel retail sales in the Russian Far East and the Republic of Buryatia. * Optimise Russian oil terminal network. The Group aims to optimise its Russian oil terminal network for increased competitiveness and retention of its wholesale market share in the Russian Far East and the Republic of Buryatia. The Group believes it can increase its wholesale market share in the Russian Far East and the Republic of Buryatia by increasing sales of petroleum products under federal programmes as well as sales to airline, gold mining, and road construction companies. The Group plans to optimise its oil terminal network for more efficient storage and delivery of petroleum products. * Increase export sales of petroleum products. The Group will work to increase export sales by capitalising on the close geographical proximity of the Group’s refining operations to growing Asian markets, where demand for petroleum products is expected to increase in the coming years. The Group plans to increase export sales of its petroleum products by widening the range

3 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA of its petroleum products and increasing sales volumes of diesel and jet fuel through the modernisation of the Khabarovsk Refinery. The Group plans to support this strategy by optimising its transportation and logistics network, including by constructing new logistics infrastructures for export sales.

4 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA RISK FACTORS

An investment in the Notes involves a high degree of risk. Prospective investors should consider carefully, among other matters, the risks set forth below, which represent the principal risks relating to the Issuer, the Guarantors, the Group, the Group’s industry and the Notes, and the other information contained elsewhere in this Prospectus, prior to making any investment decision with respect to the Notes. Each of the risks highlighted below could have a material adverse effect on the Group’s businesses, operations, financial condition or prospects, which in turn could have a material adverse effect on the value of the Notes. The trading price of the Notes could decline due to any of these risks, and investors could lose some or all of their investment.

Potential investors should note that the risks described below are not the only risks the Group faces. The Group has described only the risks it considers to be material. However, there may be additional risks that the Group currently considers not to be material or of which it is not currently aware, and any of these risks could have the effects set forth above. The order in which the following risks are presented is not intended to be an indication of the probability of their occurrence or the magnitude of their potential effects.

Risks Relating to the Group and the Oil and Gas Industry

Global economic developments and Russian market conditions may adversely affect the Group’s business, financial condition and results of operations. The Group’s results of operations are significantly influenced by general economic conditions, in particular in the countries in which it operates and those in which it makes sales. The economic situation in these markets has in various ways been adversely affected by weakening economic conditions and the turmoil in the global financial markets. Volatility and market disruption continued throughout 2010, 2011 and 2012 and into the first three months of 2013. In particular, global financial markets have experienced increased volatility since the second half of 2011, a period which has seen the sovereign rating downgrades of, amongst others, the United States, the United Kingdom, France, Japan, Austria, Greece, Ireland, Portugal, Spain and Italy and continued concerns over the stability of the European monetary system and the stability of certain European economies, notably Greece, Ireland, Portugal, Spain, Italy and Cyprus. Though repeated attempts by European leaders to find a lasting solution to market concerns about such countries’ ability to repay their debt have produced bail-out packages and restructuring agreements for certain sovereign debtors such as Greece, there remain continuing doubts concerning the stability of the European monetary system and economy. There can be no assurance that a further economic downturn or financial crisis will not occur. This includes developments that occurred beginning in late March 2013 with respect to the financial crisis in Cyprus. To the extent that the crisis has destabilising effects on the Eurozone, this could have a material adverse effect on the Group’s business, results of operations, financial condition and prospects. The countries in which the Group operates, particularly Russia, and most of the countries in which the Group’s products are sold, have experienced declining growth rates in gross domestic product (‘‘GDP’’), reduced industrial production, increasing rates of unemployment and decreasing asset values. For example, in January 2012, Fitch Ratings Ltd. lowered its credit outlook for the Russian Federation from positive to stable based on perceived increased political uncertainty and the global economic outlook.

A deterioration in the financial condition of the Group’s customers could have an adverse impact on their credit ratings and/or access to capital which, in turn, could lower demand for the Group’s products and services. Furthermore, a worsening in the financial condition of the Group’s joint venture partners or counterparties (e.g. failure to meet applicable capital commitments or insolvency) could adversely affect the Group’s operations. In addition, a deterioration in the global financial markets could lead to the downgrade of lenders’ credit ratings, both in Russia and abroad, making access to credit more difficult and costly.

Adverse economic developments of the kind described above have negatively affected and may continue to negatively affect the Group’s business in a number of ways and could have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

5 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA A substantial or extended decline in crude oil, refined products or petrochemical products prices could have a material adverse effect on the Group’s business, financial condition and results of operations. The Group’s business, financial condition and results of operations depend substantially upon prevailing prices of crude oil, refined products and petrochemical products. Historically, prices for crude oil, refined products and petrochemical products have fluctuated widely in response to even relatively minor changes in many factors. The Group does not and will not have control over certain factors affecting prices for crude oil, refined products and petrochemical products. These factors include: * global and regional supply and demand and expectations regarding future supply and demand for crude oil, refined products or petrochemical products; * Russian and foreign governmental regulations and actions, including export restrictions and taxes on crude oil and refined products, which can substantially affect profitability; * the ability and willingness of the Organisation of Petroleum Exporting Countries (‘‘OPEC’’) and other crude oil-producing nations to influence global production levels and prices; * the worldwide military and political environment and uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or further acts of terrorism, including in the United States, the Middle East, the CIS or other resource-producing regions; * prices and availability of alternative and competing fuels; * global and regional social, economic and political conditions, particularly in the Middle East and other oil-producing regions; * prices and availability of new technology; and * weather and climate conditions, natural disasters and industrial accidents. Future crude oil, refined products and petrochemical product price movements cannot be predicted with certainty. For example, crude oil pricing has been particularly volatile over the past several years. According to data from the U.S. Department of Energy, the spot price per barrel for Brent crude, an international benchmark oil blend, in 2010 ranged from a low of USD 67.18 on 25 May to a high of USD 93.63 on 23 December, averaging USD 79.61 per barrel for the year; in 2011 ranged from a low of USD 93.52 on 4 January to a high of USD 126.64 on 2 May, averaging USD 111.26 per barrel for the year; and in 2012 ranged from a low of USD 88.99 on 25 June to a high of USD 129.92 on 9 March, averaging 112.44 per barrel for the year. In the first three months of 2013, the price per barrel for Brent crude ranged from a low of USD 106.41 on 21 March to a high of USD 118.90 on 8 February 2013. On 8 April 2013, the price for Brent crude was USD 103.16 per barrel. International prices for refined products and petrochemical products, which typically follow changes in international oil prices, have also fluctuated considerably in recent years leading to changes in refining margins that can significantly affect the Group’s profitability. The Group’s revenues, operating income and future rate of growth are highly dependent on the prices received for its crude oil, refined products and petrochemical products. In addition, lower prices may reduce the amount of crude oil that the Group can produce economically or reduce the economic viability of projects planned or in development, leading to a reduction in capital expenditures or the inability to meet certain strategic goals, including production forecasts. A decline or volatility in the prices of crude oil, refined products or petrochemical products could have a material adverse effect on the Group’s production forecasts, business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

Recent amendments to Russian and have shifted the tax dynamics and affected the profitability of the Group’s upstream and downstream operations, and further Russian tax amendments may negatively affect the Group’s profitability. On 1 October 2011, the first stage of a new tax regime for the Russian oil industry took effect (the ‘‘60-66 Amendments’’). The 60-66 Amendments reduced the marginal export rate on crude oil from 65% to 60% and unified export duties for light and dark petroleum products at 66% of the export duty on crude oil. More specifically, the 60-66 Amendments increased the export duty on fuel oil from 46.7% to 66% while decreasing the export duty on diesel and jet oil from 67% to 66%. Petrol and naphtha export duty remained unchanged at 90% of the export duty of crude oil. Further

6 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA tax changes aimed at improving the profitability of upstream operations while incentivising Russian oil companies to invest in upgrading their refineries may be passed in the future. For example, the marginal export duty rate for certain heavy petroleum products is expected to increase from 66% to 100% of the export duty on crude oil beginning 1 January 2015. In addition, current Russian legislation envisions regular increases in taxes on petroleum products through 2015, and further changes to the excise tax regime are reportedly being contemplated. Such tax changes may be especially detrimental to oil companies with low complexity refining capabilities. The government of the Russian Federation (the ‘‘Russian Government’’) receives substantial revenues from export duties on crude oil and refined products, and the Group has no control over changes to Russian customs law. The profitability of the Group’s crude oil sales is also significantly impacted by the levels of mineral extraction tax (‘‘MET’’) levied on its production. MET is levied on extracted crude oil, gas condensate, natural gas and a number of other mineral resources. Similar to export duties, MET rates have been revised several times by the Russian Government during the period under review and MET on crude oil has risen significantly since 2009. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations – Key Factors Affecting Operating Results – Taxation – Mineral Extraction Tax’’. The Group has no control over changes to MET rates and continued or sustained increases in MET rates may have have a material adverse effect on the Group’s business, financial condition, results of operations and prospects. The Russian Government may institute changes in export duties and other tax rates in an attempt to promote macroeconomic goals, while at the same time altering profitability dynamics of the Group’s operations negatively, including in ways that could have a material adverse effect on the Group’s financial results. The Group could be negatively affected by such tax changes if its planned modernisation of the Khabarovsk Refinery is not completed. Future Russian legislative initiatives, if approved, could have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations – Key Factors Affecting Operating Results – Taxation’’.

Margins in the refining industry are highly volatile. The Group’s results of operations are significantly affected by the difference between the price of petroleum products and the price of crude oil used for refining, which, once direct costs are subtracted, constitutes the refining margin. Factors impacting the price of crude oil and refined petroleum products, and therefore the Group’s refining margins, include: * the aggregate refining capacity in the global and regional refining industry to convert crude oil into refined petroleum products, including the petroleum products the Group refines; * the availability of price arbitrage for refined petroleum products among different geographical markets; * changes in the mandatory specifications of governmental authorities for refined petroleum products in Russia and other countries to which the Group exports its refined petroleum products; and * general political and economic conditions in Russia and countries to which the Group exports its refined petroleum products. Additionally, positive trends in the market for refined petroleum products have encouraged many companies to increase their refining and conversion capacity and, as a result, if such increases are not matched by increased demand, the Group’s refining margins could deteriorate. These and other factors could have either a short-term or a long-term impact on the Group’s refining margins, a decline in which could have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The Group is substantially dependent on its operations at the Khabarovsk Refinery. The Group’s business is largely dependent on the Khabarovsk Refinery, which produces substantially all of the refined petroleum products the Group sells. Refining, transportation and storage of crude oil and refined petroleum products involves significant hazards that could result in fires, explosions, spills and other unexpected or dangerous conditions or accidents. Although the Khabarovsk Refinery

7 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA is currently being upgraded, it was built in 1935 and, therefore, such risks may be greater than for a newly constructed facility. No assurance can be given that accidents will not occur in the future. In addition, the Group may need to cease operations to perform maintenance. There can be no assurance that such interruptions will not last longer than expected or that emergency interruptions will not occur. Any such occurrence could have a material adverse effect on the Group’s production forecasts, business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees. In addition, an important part of the Group’s business strategy is the modernisation of the Khabarovsk Refinery, which it believes will increase its capacity for production of higher value, lighter petroleum products. Complications with the modernisation, bankruptcy or breach of contract by the Group’s sub-contractors, cost overruns, unforeseen ecological and environmental issues, technical delays, equipment import delays, a shortage of qualified labour and other issues which typically arise in connection with large-scale construction and modernisation projects could significantly delay or even prevent the upgrade of the Khabarovsk Refinery or could negatively impact the refinery’s ability to maintain its current rate of petroleum products production. Any delay or failure to complete modernisation projects at the Khabarovsk Refinery or any significant decrease in the refinery’s refining capacity could have a material adverse effect on the Group’s production forecasts, business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The Group is dependent on third parties for supplies of crude oil to the Khabarovsk Refinery, and the cost and availability of such supplies are largely beyond the Group’s control. The Group’s oil production fields are geographically far from the Khabarovsk Refinery, making it economically impractical to transport significant amounts of the Group’s crude oil to the refinery. Accordingly, the Group is dependent on purchases of crude oil from third party producers in Russia, and in the years ended 31 December 2012, 2011 and 2010, it purchased approximately 72%, 74%, and 79%, respectively, of its crude oil needs from third parties. The Group does not control the prices charged by third party producers. Dependence on third parties for crude oil supply and competitive pressure from other refineries in the region can cause increases in crude oil prices, a key component of the final prices for the Group’s refined petroleum products, thereby decreasing the Group’s refining margins. Failure to secure sufficient supplies of crude oil to the Khabarovsk Refinery or an increase in the price of the Group’s crude oil supplies could decrease the Group’s refining margin and could have a material adverse effect on the Group’s production forecasts, business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

Oil, natural gas and gas condensate reserves data and production forecasts are only estimates, and the Group’s actual production, revenues and expenditures with respect to its reserves may differ materially from those estimates. DeGolyer and MacNaughton (‘‘D&M’’) carried out independent audits of the reserve estimates of the Group’s consolidated subsidiaries as of 31 December 2012, 2011 and 2010 (collectively, the ‘‘Reserves Reports’’), in each case according to the PRMS classification. There are numerous uncertainties inherent in estimating quantities of proved, probable and possible reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond the control of the Group. The oil, natural gas and gas condensate reserves data included in this Prospectus represent only estimates and should not be construed as exact quantities. Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner, and estimates can vary significantly. Estimates of the value and quantity of economically recoverable oil and gas reserves, rates of production, future net revenues and the timing of development expenditures are based on existing economic and operating conditions using prices and costs as at the date the estimate is made. In addition, estimates of reserves and production forecasts necessarily depend upon a number of variable factors and assumptions, including the following: * historical production from the area compared with production from other comparable producing areas; * interpretation of geological and geophysical data; and

8 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA * the assumed effects of regulations by governmental agencies. Because all reserves estimates and production forecasts are subjective, each of the following items may prove to differ materially from the Group’s assumptions: * the quantities of oil and gas that are ultimately recovered; * the production and operating costs incurred; * the amount and timing of future development expenditures; and * oil and gas prices. Results of drilling, testing and production after the date of the estimates may require substantial upward or downward revisions in the Group’s reserves data. Reserve estimates may be materially different than the quantities of crude oil that are ultimately recovered, and, if recovered, the revenue therefrom could be materially less than, and the costs related thereto could be higher than, estimated amounts. The significance of such estimates is highly dependent upon the accuracy of the assumptions on which they were based, the quality of the information available and the ability to verify such information against industry standards. In addition, from time to time, the Group provides forecasts of expected quantities of future production. These forecasts are based on a number of estimates, including expectations of production from existing reserves and the outcome of exploratory and development projects. The reserves estimates and production forecasts assume, among other things, that the future development of the Group’s oil fields and the future marketability of the Group’s oil will be similar to past development and marketability. These economic assumptions may prove to be incorrect. In particular, the Russian economy is more unstable and subject to more significant and sudden changes than the economies of many other countries, and thus economic assumptions in Russia are subject to a significant degree of uncertainty. Potential investors should not place undue reliance on the forward-looking statements in this Prospectus regarding the Group’s estimated reserves or on comparisons of similar estimates concerning companies established in places with more mature economic systems. Additionally, in estimating its proved oil and gas reserves and production forecasts, the Group has assumed that the production licences for its Russian fields will be renewed and that the fields will be produced until the economic limit of production is reached. The Group’s licences do not extend to the economic limit of production at its fields, and if any production licences for its Russian fields are not renewed, the Group-estimated oil and gas reserves may materially decrease. The Group does not commission audits of its reserves under the standards of the U.S. Securities and Exchange Commission (the ‘‘SEC’’). The PRMS classification differs in certain material respects from SEC standards. The amount of estimated proved crude oil and gas reserves reported under SEC standards could potentially be lower than those reported under the PRMS classification. A decrease in the amount of crude oil or gas reserves reported by the Group could, if material, affect certain financial data reported by the Group in its consolidated financial statements in future periods.

The Group may be unable to secure sufficient funding to finance its planned capital expenditures or such financing may restrict its operational flexibility. The Group’s business requires significant capital expenditures, including in exploration and development, production, transport, refining and marketing, and to meet its obligations under environmental laws and regulations. In addition, the Group is undertaking significant projects to modernise the Khabarovsk Refinery and develop the Kolvinskoye oil field, both of which will require significant capital investment to complete. See ‘‘– The Group is substantially dependent on its operations at the Khabarovsk Refinery’’. The Group expects to finance its capital expenditures through net cash provided by operations and debt financing. There can be no assurance, however, that the Group will be able to generate and raise sufficient funds to meet such capital requirements in the future or to do so at a reasonable cost. The Group depends on regular access to bank finance and the debt capital markets to meet a significant portion of the Group’s financing requirements. However, the global banking sector and capital markets have experienced significant disruptions since 2008 that have been characterised by severe reductions in liquidity, greater volatility, general widening of spreads, and, in some cases, lack of price transparency in money and capital markets interest rates. As a result, many lenders have reduced or ceased providing funding to borrowers, particularly in the emerging markets, and there has been a general increase in the cost of borrowing for private-sector borrowers, including the Group. The continuation or worsening of this market disruption may adversely impact the Group’s ability to borrow in the credit or debt capital markets and may further increase the cost of such

9 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA borrowing. The Group is exposed to interest rate risk as Group entities borrow a portion of funds at floating interest rates. At 31 December 2012 and 2011, 22% and 24%, respectively, of the Group’s borrowings were at floating interest rates. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations – Risk Management – Interest Rate Risk’’. If the Group is unable to raise the necessary financing, or is subject to increased borrowing costs, it may have to reduce planned capital expenditures, which could include the capital expenditures necessary to complete the modernisation of the Khabarovsk Refinery, which could materially and adversely affect its business, results of operations (through penalties and capitalised cost write-offs in the near future as well as a lower margin after the modernisation completion date), financial condition and prospects. Additionally, some of the Group’s financing documents, including the terms governing the Notes, contain cross default clauses, which, in the event of a default under a single facility, could lead to a default under other credit facilities and, potentially, to acceleration of the Group’s obligations to repay all or a significant part of the debt, which could have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The petroleum products retail sector is highly competitive, and the Group may be unable to compete in the petroleum products retail sector or find suitable locations to open new filling stations or it may encounter delays or greater than anticipated costs in remodelling existing filling stations. The retail sale of petroleum and non-fuel goods in Russia through filling stations is increasingly competitive, and changing demographics and consumer preferences in individual geographic locations may greatly impact the operations of filling stations in those locations. The Group’s business strategy depends in part on its ability to compete by assessing locations and successfully opening filling stations in new locations or remodelling existing filling stations to add facilities for non-fuel sales, such as shops and car wash facilities. Desirable locations for new filling stations may not be available at an acceptable cost or on acceptable terms. The Group may experience delays or higher than anticipated costs in opening new locations or remodelling existing locations or in obtaining any required governmental approvals for such new locations. In addition, the Group may not correctly anticipate consumer preferences in choosing to remodel or to close certain locations or may face higher than anticipated costs in closing existing locations. There can be no assurance that new or remodeled locations will operate profitably or deliver increased revenue or margins sufficient to justify the capital expenditures necessary to build and maintain such stations. Furthermore, the Group may face increased competition from companies that have more established brand names or more experience in combining fuel and non-fuel sales. The impact of any of these events on a significant number of the Group’s new or remodeled filling stations could materially adversely affect its business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The Group depends on a monopoly rail provider for the transport of crude oil and petroleum products to and from the Khabarovsk Refinery, and the Group has no control over its transportation infrastructure or fees. The Khabarovsk Refinery is not connected to the pipeline systems of OAO AK Transneft (‘‘Transneft’’) or OAO AK Transnefteproduct (‘‘Transnefteproduct’’). As a result, the Group depends on a combination of railway and pipeline transportation for the operation of its refinery. Alliancetransoil, a wholly-owned logistics subsidiary of the Group, is generally responsible for the transportation of the Group’s crude oil and petroleum products by tank railcars to and from the Khabarovsk Refinery. The Group currently owns more than 1,400 railcars and rents additional railcars when required. Crude oil is transported by pipeline from various suppliers to the Uyar loading station in the Krasnoyarsk region and to the Meget loading station in the Irkutsk region, where it is then transferred to tank rail cars for railway transportation via OJSC Russian Railways (‘‘Russian Railways’’), a state-owned monopoly provider of railway transportation services. Petroleum products are distributed from the Khabarovsk Refinery primarily by railway via Russian Railways. It is expected that the Khabarovsk Refinery will be connected to the ESPO oil pipeline in 2014. See ‘‘Business – Transportation and Logistics – Pipelines’’. However, there can be no assurance that the Khabarovsk Refinery will be connected to the ESPO oil pipeline when expected, or at all. Therefore, the Group expects that it will continue to rely on Russian Railways to provide crude oil to the Khabarovsk Refinery for some time, and it will always rely on Russian Railways, or any successor, to deliver its petroleum products to end-users via rail. The Group’s use of the railways creates

10 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA exposure to risks such as potential delivery disruptions due to the generally poor physical condition of Russia’s railway infrastructure and possible shortages of rolling stock. Further Russian Railways transportation tariffs are beyond the Group’s control, and increased tariffs would increase the costs of transporting crude oil and petroleum products to and from the Khabarovsk Refinery. Because the Khabarovsk Refinery is supplied with crude oil by a combination of pipeline and rail transportation, and because the Khabarovsk Refinery relies on rail transportation to ship its petroleum products, any service interruption in either system could interrupt operations at the Khabarovsk Refinery. Any of these factors could materially adversely affect the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The Group depends on a monopoly operator of crude oil and gas pipelines, and the Group has no control over its infrastructure or fees. The Group and the Group’s third-party crude oil suppliers rely on the pipeline system operated by Transneft to transport crude oil to the Khabarovsk Refinery and the Group primarily transports the crude oil it produces via the Transneft pipeline system. In the periods under review, the Transneft pipeline system transported substantially all of the crude oil produced by the Group. While alternative means of transportation that are not dependent on the Transneft system exist in Russia, such means are generally more expensive than the Transneft pipeline system. Transneft has generally avoided serious disruptions in the transport of crude oil and, to date, the Group has not suffered significant losses arising from the failure of the pipeline system. Nonetheless, the Transneft-operated system may experience outages or capacity constraints during required maintenance periods, resulting in the delay or suspension of shipments. While Transneft has been making significant investments to enable the system to expand capacity to accommodate the growth in oil production (specifically, in Eastern Siberia), those efforts have contributed to significant increases in Transneft’s tariffs in recent years. Increases in Transneft’s tariffs, above those projected and budgeted by the Group, could have a material adverse effect on the Group’s business and financial results. The Russian Government allocates access to Transneft’s pipeline network and is required to provide equitable access to the pipeline to all entities meeting certain technical requirements. Pipeline capacity, including export pipeline capacity, is allocated to oil producers on a quarterly basis, generally in proportion to the amount of crude oil produced and delivered to Transneft’s pipeline network in the prior quarter. Generally, a Russian oil company is given an allocation for export that equals approximately 40% of its crude oil so produced in the preceding quarter. The Group, along with all other Russian crude oil producers, must pay transportation fees to Transneft in order to transport crude oil through the Transneft network. The Federal Service (the ‘‘FTS’’) is responsible for setting Transneft’s fees, which have risen in recent years and may continue to rise. In the years ended 31 December 2012, 2011 and 2010, the Group’s average per tonne tariff to use the Transneft system was RUB 1,109.4, RUB 1,001.9 and RUB 893.7, respectively. Failure to pay these fees could result in the termination or temporary suspension of the Group’s access to the Transneft network. Although Transneft has not constrained the Group’s production deliveries in the last five years, significant increases in Transneft’s fees or the termination or suspension of the Group’s access to the Transneft network would materially adversely affect the Group’s business, as would any disruption in (or in the Group’s access to) the Transneft system. Historically, the Transneft system did not have sufficient capacity to meet the total demand for crude oil pipeline exports from Russian oil producers. However, Transneft has made substantial investments in the development of additional export routes and trans-shipment terminals (e.g. at the Primorsk port) in order to increase capacity. However, failure by Transneft to maintain or sufficiently increase the capacity of the Transneft system, breakdowns and leakages could require the Group to utilise more expensive alternative export routes or to sell excess production on the local market. This could result in a decline in the Group’s profit margins. In addition, the Group sells its gas through a transportation system owned and operated by Gazprom. Under existing regulations, Gazprom must provide access to this system to all domestic independent suppliers on a non-discriminatory basis as long as capacity exists. These ‘‘equal access’’ regulations might not remain in place, however, and Gazprom might fail to comply with them in the future. Moreover, in practice, Gazprom is able to exercise discretion in determining third party access to its gas transportation network through its priority right to use the system for its own production.

11 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA A significant disruption in the Group’s transportation of its crude oil or gas could materially affect its business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

Any significant interruption of operations at the Group’s rail and port transshipment oil terminal in Vladivostok may impede shipments. The Group uses its rail and water transshipment oil terminal in Vladivostok, as well as other facilities, to transship its crude oil and refined petroleum products. In 2012, approximately 51% of petroleum products produced by the Group were transshipped through the oil terminal in Vladivostok. The Group uses the terminal for both domestic and international shipments. Operations at the Vladivostok oil terminal may be adversely affected as a result of hazards inherent in transshipment of crude oil and petroleum products which may cause unexpected or dangerous conditions or accidents. Operations at the Vladivostok oil terminal may also be adversely affected by climatic conditions. Although third-party transshipment oil terminals in Nakhodka and Vanino (Russian Far East) may also be used by the Group for the transshipment of its crude oil and petroleum products, were the operations at its Vladivostok oil terminal to become interrupted or suspended, any prolonged delay in transshipments through the Vladivostok oil terminal could result in delays and increased costs of transshipments, which could materially adversely affect the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The Group’s subsoil licences may be suspended or revoked prior to their expiration and the Group may be unable to obtain or maintain various licences, permits or authorisations. In accordance with Russian law, many of the Group’s business operations are subject to licensing or obtaining of various permits and authorisations. The Group has been able to obtain and extend licences, permits and authorisations necessary to carry out its operations, but no assurance can be given that it will be able to do so in the future. The licensing regime in Russia for the exploration and production of oil and gas is governed primarily by the Law ‘‘On Subsoil’’ No. 2395-1 dated 21 February 1992, as amended (the ‘‘Subsoil Law’’), and related regulations. Under current Russian legislation, the Federal Agency for Subsoil Use (‘‘Rosnedra’’) and the Federal Service for Supervision in the Sphere of Nature Use (‘‘Rosprirodnadzor’’), both operating under the jurisdiction of the Ministry of Natural Resources and Ecology of the Russian Federation (the ‘‘Ministry of Natural Resources’’), are responsible, respectively, for issuing subsoil licences and monitoring compliance with subsoil licence terms. The Subsoil Law provides that fines may be imposed and/or licences may be suspended, amended or terminated if the relevant licencee fails to comply with licence requirements (such as development and operational obligations), make timely payments of levies and taxes for the subsoil use, provide geological information to controlling bodies or meet other requirements. The imposition of any such penalties may have an adverse effect on the Group’s operations and the value of its assets. Subsoil use rights in Kazakhstan may be terminated by a designated government body if the contracting party does not satisfy its contractual obligations, which include payment of taxes to the Kazakh government and the satisfaction of mining, environmental, safety and health requirements. Terms of exploration, production and combined exploration and production contracts may generally be extended, provided that the agreed work programme and other obligations are fulfilled under such contract. The Group currently conducts its operations under multiple exploration and production licences. See ‘‘Business – Upstream Operations – Licences’’. The Group has from time to time requested and received appropriate amendments to certain licences, and has not had any material licences revoked or suspended. There can be no assurance that the decisions of the Russian Government regulators in the future will always be favourable for the Group. Three of the Group’s Russian licences expire in 2014; most of the Group’s other licences extend significantly longer. In accordance with current legislation and government approval processes, the Group plans to extend its licences that have a fixed term to the end of the economic life of the field to which such licence relates. Currently none of the Group’s licences extend to the economic limit of production at its fields, and although historically, the Group has been able to obtain extensions for its licences, the Group may fail to do so in the future.

12 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA The Group may be unable to, or may voluntarily decide not to, comply with certain licence agreements or contractual requirements for some or all of its licence areas or areas under contract. For example, in Russia, subsoil users may not produce annual volumes of hydrocarbons below or in excess of certain limits, as determined by the licence. There can be no assurance that these production requirements can or will be met, particularly where the minimum production requirements exceed the amount of proved and probable reserves. For example, in 2012, some of the Group’s companies were fined after producing volumes that were deemed significantly in excess of their licence limits by the relevant Russian authorities. If the authorities in Russia or Kazakhstan determine that the Group has failed to fulfil the terms of its licences, contracts, permits or authorisations, or if the Group operates in its licence areas or areas under contract in a manner that violates Russian or Kazakh law, such authorities may impose fines on the Group or suspend or ultimately terminate its licences or contracts. Furthermore, the Group may have to increase spending to comply with licence or contractual terms. Any suspension, restriction or termination of the Group’s licences or contracts could have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees. In addition, because the Group did not own or control all of its subsidiaries when they obtained their initial subsoil licences or entered into the initial contracts, it cannot be certain that all of the licences of its subsidiaries were issued, or the preceding and current licences were re-issued, or the contracts were entered into, in accordance with all applicable laws and regulations at the time. If it is determined that any of the subsoil licences held or contracts entered into by the Group were issued and/or reissued and/or entered into in violation of applicable laws, such licences would be subject to revocation and/or such contracts would be subject to termination. Moreover, vague and inconsistent requirements of the Subsoil Law and the regulations thereunder can make it difficult to conclude that any given subsoil licence has been issued in full compliance with applicable law. While the law may be read to permit revocation of a licence based only on defects relating to the issuance of that licence, a more aggressive interpretation of the law would suggest that defects in the issuance of any predecessor licences could also constitute a basis for challenging an existing or successor licence. A loss of any such licence or contract could have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The Foreign Strategic Investments Law may affect the Group’s ability to undertake future acquisitions or access equity capital markets. On 7 May 2008, Federal Law No. 57-FZ ‘‘On the Procedure for Making Foreign Investments in Commercial Organisations of Strategic Importance for the National Defence and Security of the State’’ dated 29 April 2008, as amended (the ‘‘Foreign Strategic Investments Law’’), came into force in Russia. The Foreign Strategic Investments Law restricts the level of foreign investments in certain sectors of the Russian economy considered to be strategic. In accordance with the Foreign Strategic Investments Law, a ‘‘strategic company’’ is a legal entity incorporated in the Russian Federation which engages in at least one activity of strategic importance. The list of strategically important activities set forth in the Foreign Strategic Investments Law includes, inter alia, the exploration and development of subsoil resources on ‘‘subsoil plots of federal importance’’. A list of these plots was first published on 5 March 2009 and has been periodically reviewed and updated. See – ‘‘Regulation of the Russian Oil and Gas Industry – Regulation of Oil and Gas Production – Subsoil Plots of Federal Importance’’. From the effective date of the Foreign Strategic Investments Law, an acquisition of direct or indirect control over a strategic company by a foreign investor requires preliminary approval by the Governmental Committee for Control over Foreign Investments in the Russian Federation. Moreover, if a foreign investor acquires 5% or more of the shares in a subsoil strategic company, it must notify the Russian Federal Antimonopoly Service (the ‘‘FAS’’) in writing and provide certain information and documents relating to the transaction. ‘‘Control’’ is broadly defined by the Foreign Strategic Investments Law and includes: (i) the ability, directly or indirectly, to control more than 50% of the voting shares in a strategic company and 25% or more of the voting shares in a strategic company engaged in exploration or production on subsoil plots of federal importance (a ‘‘strategic subsoil company’’); (ii) the right to direct business decisions taken by a strategic company; (iii) the right to appoint the chief executive officer or elect more than

13 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA 50% of members of the management board or the board of directors of a strategic company and more than 25% of members of the management board or the board of directors of a strategic subsoil company; or (iv) the right to serve as a stategic company’s management company. At the date of this Prospectus, none of the Group’s oil fields have been designated as subsoil plots of federal importance. Given that the provisions of the Foreign Strategic Investments Law have not been widely tested, there is a risk that in case of acquisitions of new oil fields, the Group, which would be treated as a foreign investor, may be required to obtain the prior consent of the Russian Government and, should such consent be withheld or unobtainable, the Group may be required to dispose of the relevant licence. Moreover, in the event that the Group should acquire a subsoil plot of federal importance, it could face difficulties in placing additional amounts of equity with non-Russian investors and may be limited in its ability to access the equity capital markets. Should any of the foregoing events occur, it could have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The Group’s development and exploration projects involve numerous uncertainties and operating risks that can prevent the Group from realising profits and may cause substantial losses. One of the Group’s primary businesses is exploring and developing oil and gas reservoirs in Russia. The Group’s decision to undertake an exploration or development project depends upon a number of factors, including availability and cost of capital, current and projected oil and gas prices, receipt of government approvals, access to the property, the costs and availability of drilling rigs and other equipment supplies and personnel necessary to conduct these operations, success or failure of activities in similar areas and changes in the estimates to complete the projects. The Group’s development and exploration projects may be delayed or unsuccessful for many reasons, including cost overruns, lower oil prices, equipment shortages and mechanical difficulties. Crude oil development and exploration projects also often require the use of new and advanced technologies, which can be expensive to develop, purchase and implement, and may not function as expected. Furthermore, unusually warm or severe weather conditions could impede the Group’s development plans for its fields and facilities. Many of these factors, though partially controlled by the Group, can be affected by external circumstances and developments. In addition, a shortage of power could affect production growth. There is a regional lack of sufficient power-generating capabilities to meet the growing demand for extra power from a wide range of oil producers in Western Siberia. This shortage of power, cost overruns, lower oil prices, equipment shortages, mechanical difficulties and unusually warm or severe weather conditions could impede the Group’s development or exploration plans for its fields and facilities. The Group is conducting exploration operations in areas including the Volga-Urals, Tomsk and Timano-Pechora regions, as well as in the Atyrau region in Kazakhstan. Oil and gas exploration may involve unprofitable efforts both from dry wells and from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. The cost of drilling, completing and operating wells is often uncertain. As a result, the Group may incur cost overruns or may be required to curtail, delay or cancel drilling operations because of many factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions, compliance with environmental regulations, governmental requirements and shortages or delays in the availability of drilling rigs and the delivery of equipment. In particular, a significant portion of the Group’s exploration and development projects may involve production from challenging reservoirs. If the Group fails to acquire assets holding proved reserves or to conduct successful exploration activities, its proved reserves will decline as it extracts crude oil and gas, thereby depleting existing reserves. In addition, the volume of production of crude oil generally declines as reserves are depleted. The Group’s future production depends significantly upon its success in acquiring and developing or finding additional reserves. If the Group is unsuccessful in doing so, it may not meet its production targets, and its total proved reserves and production would decline, which could materially adversely affect the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

14 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA The Group faces numerous operational risks in its crude oil and gas exploration, production, transportation and other core activities, which may result in losses and additional expenditures and which may not be covered by insurance. Exploration for, the production of, and the transportation of oil and natural gas is hazardous, and natural disasters, operator error or other occurrences can result in oil spills, gas leaks, loss of containment of hazardous materials, cratering, fires, equipment failure and loss of well control. Failure to manage these risks could result in injury or loss of life; damage or destruction of wells, production facilities pipelines and other property; and damage to the environment. For example, in 2010, a major oil spill resulting in substantial damage occurred offshore in the Gulf of Mexico at a site operated by BP p.l.c. All modes of transportation of hydrocarbons contain inherent risks. A loss of containment of hydrocarbons and other hazardous materials could occur during transportation by pipeline, rail, road or ship. Given the high volumes of hydrocarbon transported by the Group in the normal course of business, such potential loss represents a significant liability risk due to the serious impact a release would have on the environment and surrounding population. The Group’s existing insurance only covers operational risks that could lead to a material reduction in the Group’s financial position as well as certain medical and accident insurance coverage for its employees. The Group does not have full insurance coverage against all possible risks associated with its plants and facilities, business interruption or third-party liability in respect of property or environmental damage relating to its operations. Thus, in certain circumstances, the Group would have to cover financial losses from its own cash flow, which could materially adversely affect the operations and financial position of the Group and, ultimately, the value of the Notes. In addition, there can be no guarantee that the Group will be able to secure adequate insurance coverage in the future, on economically viable terms or at all, or that the insurance obtained will cover all losses incurred in connection with a particular occurrence.

The Group faces intense competition from other oil and gas companies in all areas of its operations, including the acquisition of licences, exploratory prospects and producing properties, and it may encounter competition from suppliers of alternative forms of energy sources. The oil industry is intensely competitive. The Group competes with other major Russian and international oil companies, some of which have greater resources, are more diversified and have been operating in a competitive economic environment for longer than the Group. The Group’s ability to market its products and crude oil and gas depends on its ability to negotiate contracts with its customers. The key activities in which the Group faces competition are: * the acquisition of subsoil licences at auctions or tenders run by governmental authorities and obtaining desirable licences for future exploration and production; * the acquisition of other companies that may already own licences or existing hydrocarbon- producing assets; * the implementation of foreign exploration and development projects; * the engagement of leading third-party service providers (including, among others, oil field services providers) whose capacity to provide key services may be limited; * the purchase of capital equipment that may be scarce; * the employment of the best-qualified and most experienced staff; * access to critical transportation infrastructure; * the acquisition of existing retail outlets or of sites for new retail outlets; * the acquisition of or access to refining capacity; and * marketing of crude oil, petroleum products and gas. In refining, the Group competes principally with the Komsomolsk oil refinery owned by Rosneft. While the Group continues a significant modernisation programme at the Khabarovsk Refinery, the Komsomolsk oil refinery is also undergoing modernisation works. The Group’s principal competitor in the petroleum products retail sector is Rosneft. The oil industry is currently subject to several important influences which impact the industry’s competitive landscape. In recent years, the oil industry has experienced consolidation, as well as increased deregulation and integration in strategic markets. In addition, the Group’s ability to remain competitive will require, among other things, management’s continued focus on reducing unit costs

15 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA and improving efficiency, including maintaining production costs comparable to its competitors, and maintaining long-term growth in the Group’s reserves and production through continued technological innovation. A number of other Russian oil companies, as well as foreign oil companies, are permitted to compete for licences and to offer services in Russia, increasing the competition which the Group faces. Competition will also continue to grow due to the limited quantities of unexploited and unallocated oil and gas reserves. In the face of intense competition, oil companies are also facing increasing demands to conduct their operations in a manner consistent with environmental and social goals. Investors, customers and governments are more actively following the oil industry’s performance on environmental responsibility and human rights, including performance with respect to the development of alternative and renewable fuel resources. As a result of these influences and other factors, the Group expects that competition will continue to intensify. Any failure by the Group to compete effectively could materially and adversely affect the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The Group may incur material costs to comply with, or as a result of, environmental, health and safety laws and regulations. The Group incurs, and expects to continue to incur, substantial capital and operating costs in order to comply with increasingly complex health, safety and environmental laws and regulations. The Group has undertaken measures to minimise the effects of operations on the environment. For example, in recent years, the Group has implemented measures to limit air pollutant emissions, including by constructing a new tank-filling rack for light petroleum products at the Khabarovsk Refinery and by furnishing tanks with floating roofs. To limit water pollutant emissions, the Group has equipped oil terminals that include wharfs for loading of petroleum products with petroleum products spill localisation and skimming equipment. To limit pollutant emissions in the soil, the Group uses hard ground coating and other emergency prevention and containment systems at its facilities. The Group also expects to implement additional environmental measures through the modernisation of the Khabarovsk Refinery. See ‘‘Business – Health, Safety and Environment’’. New laws and regulations, the imposition of tougher requirements in licences, increasingly strict enforcement or new interpretations or application of existing laws, regulations and licences or the discovery of previously unknown contamination or pollution may require the Group to modify, curtail or cease certain activities or require further expenditures. These expenditures may include expenditures to install pollution-control equipment, perform site clean-ups and pay fines or make other payments for discharges or other breaches of environmental standards. As of 31 December 2012, the Group’s provision for decommissioning and site restoration costs increased by USD 57,755 thousand compared to 31 December 2011. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contingencies and Commitments – Environmental Matters’’. The Group’s operations could also expose it to civil claims by third parties for alleged liability resulting from contamination of the environment or personal injuries caused by environmental damage. Russian regulatory authorities exercise considerable discretion in matters of enforcement and interpretation of applicable laws, regulations and standards, the issuance and renewal of permits and monitoring compliance with the terms thereof. Compliance with new requirements may be costly and time consuming and may result in delays in the commencement or continuation of the Group’s operations. Moreover, any failure by the Group to comply with such requirements may result in the imposition of sanctions, including civil and administrative penalties, upon the Group or its subsidiaries and criminal and administrative penalties applicable to officers of the Group or its subsidiaries. There can be no assurance that the Group will be able to comply with this or other new requirements and, as a result, the Group may be required to cease certain of its business activities and/or to remedy past infringements. Any such decisions, requirements or sanctions may restrict the Group’s ability to conduct its operations or to do so profitably. Furthermore, the implementation of the Kyoto Protocol to the United Nations Framework Convention on Climate Change from February 2005 may impose new and/or additional rules or more stringent environmental norms. Such rules may mandate additional capital expenditures or modifications in the Group’s operating practices.

16 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA The Group may not always succeed in complying with environmental laws and regulations. Such non- compliance could result in greater than anticipated liabilities for environmental remediation. Furthermore, under its exploration, production and combined licences, the Group must generally commit to limit the level of pollutants that it releases and to undertake remediation in the event of environmental contamination. Non-compliance could result in the loss or suspension of the Group’s exploration and development licences. Under existing legislation, the Group believes that there are no significant environmental liabilities, beyond the amounts that have already been incurred, as set forth above, in order to comply with the environmental requirements, which will have a material adverse effect on its operating results or financial position. However, there can be no guarantee that this assessment will be viewed as correct. There can be no assurance that these expenditures will not have a greater impact in the future. The Russian Government has enacted legislation restricting gas flaring and mandating the utilisation of 95% of associated gas produced during oil extraction. The Group may incur fines for failing to reach the 95% utilisation rate mandated by Russian law. The Group’s subsidiary CJSC Saneco (‘‘Saneco’’) is working to meet the relevant utilisation standards and expects to complete necessary modernisation projects to meet these requirements by the end of 2013. There can be no guarantee that changes in Russian legislation will not significantly raise these fines. See ‘‘Regulation of the Russian Oil and Gas Industry – Gas Flaring Operations’’. Any of these factors could have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The Bazhaev Family owns a significant stake in the Group; its interests may conflict with those of other shareholders and the Noteholders. Mr. Musa Yusupovich Bazhaev, Mr. Mavlit Yusupovich Bazhaev and Mr. Deni Ziyaudinovich Bazhaev (together, the ‘‘Bazhaev Family’’) control a significant stake interest in Alliance Oil Company Ltd. As of the date of this Prospectus, the Bazhaev Family’s significant stake amounts to approximately 44.1% of the voting rights and 43.3% of the issued share capital of Alliance Oil Company Ltd. As a result of its significant interest, the Bazhaev Family has the ability to influence the Group’s operations through its share ownership and its representation on the board of directors of the Issuer (the ‘‘Board of Directors’’). The Bazhaev Family may cause the Group to take actions that may be contrary to the interests of other shareholders or Noteholders. Any such conflict could have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The Group may fail to integrate its acquisitions successfully. The Group has expanded its operations significantly through acquisitions in recent years, and the Group expects to continue to do so in the future. The integration of these recently acquired businesses, and of businesses the Group may acquire in the future, requires significant time and effort of its senior management, who are also responsible for managing the Group’s existing operations. Integration of new businesses can be difficult, as the Group’s culture may differ from the cultures of the businesses it acquires; unpopular cost-cutting measures may be required and control over cash flows and expenditures may be difficult to establish. In addition, difficulties can arise in retaining key employees crucial to the success of newly acquired businesses and achieving financial and strategic goals of acquired businesses, taking advantage of tax benefits of acquisitions, identifying problems, liabilities or other challenges of acquired businesses. In addition, the Group may be exposed to litigation or other claims in connection with its acquisitions. Thus, there can be no assurance that past, ongoing or future integrations of acquired businesses will be successful or achieve desired or expected results. Difficulties with the integration of acquired businesses could have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The Group depends on its management and other key personnel, the loss of any of whom could have an adverse impact on its business. The Group depends on the continued services and performance of its top management and other key personnel. If it loses the services of its senior managers or if any of its other executive officers or key employees should cease to take an active role in managing its affairs, the Group may not be able to

17 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA operate its business as effectively as it anticipates and its operating results may suffer. The Group cannot assure that their services, or those of other key managers, will continue to be available to the Group or that, if their services were lost to the Group, they could be replaced with comparable quality personnel. Accordingly, the loss of any one of these could materially adversely affect its business, results of operations, financial condition and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The Group’s business depends on the services of key personnel and may be affected by shortages of skilled labour, in particular in engineering and technology areas. The success of the Group depends in part upon the efforts and abilities of key personnel, in particular skilled technical personnel in both upstream and downstream activities, as well as upon the Group’s ability to continue to attract and retain such personnel. The competition in Russia for such personnel can be intense due to the limited number of qualified individuals, and the failure to attract new qualified personnel and/or retain current qualified personnel may put the Group at a disadvantage against competitors. The demand and related costs for skilled employees is expected to continue to increase, reflecting significant demand from other industries and public projects. Continued high demand for skilled labour and continued increases in labour costs could have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

Russian Government policies to ensure sufficient supplies of oil and refined petroleum products in the domestic market could impact the Group’s ability to sell its products at the best available prices and disrupt the Group’s relations with its export customers. The Group sells a substantial portion of its crude oil and a majority of its refined petroleum products in the Russian domestic market. Historically, the Russian Government has used and continues to use various administrative and fiscal measures to ensure sufficient supplies of oil and refined petroleum products are made available to the domestic market. There is no significant active commodity exchange market for crude oil in Russia and, as a result, prices are contract-specific. Although netbacks generated from domestic crude oil sales are generally consistent with the netbacks generated from export sales, domestic crude oil prices trade significantly below international market prices as export duties and additional transportation costs raise the prices of exported crude oil. For a more detailed discussion of export and domestic crude oil pricing, see ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations – Key Factors Affecting Operating Results – Price of Crude Oil and Petroleum products’’. In addition, the Russian Government has the authority to direct the Group to deliver significant volumes of crude oil or refined petroleum products to the Russian domestic market, which may take precedence over non-Russian sales. Requirements for the delivery of domestic crude oil and refined products, with or without a corresponding limitation or ban on export sales, could be used if the domestic market experiences a shortage of crude oil, liquid hydrocarbons or refined products. The Group may be directed to make deliveries to Russian Government agencies, the military, railways, agricultural producers, remote regions, specific consumers or refineries or to domestic refineries in Russia in general. Depending on the level of such required supplies, any Russian Government-directed deliveries may force the Group to curtail its export of crude oil or refined products, may disrupt the Group’s relations with its customers and may lead to delays in payments for crude oil and refined products. In addition, Russian Government-directed deliveries may create an oversupply of crude oil or refined products in the domestic market, with a resulting decline in the sale price and in the netbacks realised by the Group. Any failure by the Group to make Russian Government-directed deliveries may also affect the Group’s ability to export its crude oil. For example, the Russian Government has previously threatened to limit the access of Russian oil companies to export pipelines and sea terminals for failing to provide domestic refineries with the required supply of oil. As a result of these factors, an increase in the levels of Russian Government-directed deliveries, a revocation of export rights or any further increase in export duties on crude oil or refined products, as well as any resulting increasing disparity between Russian and international market prices for crude oil and refined petroleum products, could materially adversely affect the Group’s business. The general system of export quotas and licensing of exports was abolished in 1995. At present, quantitative restrictions on exports may be imposed only if required to comply with Russia’s obligations under international treaties or for national security purposes. No such restrictions

18 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA currently apply to the export of crude oil or refined petroleum products or gas. However, the legislation may change, and quantitative restrictions on existing or extended legal grounds may be re- introduced, which could have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The Group faces foreign exchange and inflation risks. Over the past ten years, the U.S. dollar/Rouble exchange rate has been volatile. Although the Rouble steadily appreciated during the first half of 2011 and the first months of 2012 and 2013, it experienced depreciation in the second half of 2011 and 2012. In the past three years, the Rouble has had periods of material depreciation. For example, the Rouble depreciated against the U.S. dollar by almost 40% and against the Euro by nearly 30% from October 2008 to February 2009, due in part to significant declines in the prices of oil and commodities, which are the principal generators of Russia’s export earnings. During the financial crisis in late 2008 and early 2009, the Russian Government used its international currency reserves to support the Rouble, but has expressed that it may be unwilling or unable to continue such support in the future. 46% of the Group’s revenues are generated in foreign currency. In addition, financing, investing, debt obligations and commitments are also undertaken in U.S. dollars and Euros. However, significant operating and investing expenditures, other obligations and commitments as well as tax liabilities are denominated in Roubles. As a result of any decline of the U.S. dollar and Euro against the Rouble, the Group is exposed to the corresponding currency risk. The Group manages its foreign currency risk by economically hedging transactions that are expected to occur within a maximum 24-month period. See ‘‘Note 39 to the 2012 Financial Statements’’. In addition, the relatively high rate of inflation in Russia reduces the value of the Group’s Rouble- denominated cash assets, including Rouble deposits, domestic debt instruments and accounts receivable. According to Rosstat, inflation in Russia in 2012, 2011 and 2010 was 6.6%, 6.1% and 8.8%, respectively. According to the Central Bank of Russia (the ‘‘CBR’’), in real terms the Rouble decreased 2.7% in 2012 and increased 8.8% and 9.7% against the U.S. dollar in 2011 and 2010, respectively. The Rouble also remains largely non-convertible outside of the Russian Federation. A market exists within the Russian Federation for the conversion of Roubles into other currencies, but it is limited in size and is subject to rules limiting or prohibiting such conversion. From 1 January 2009 to 1 March 2013, Russia’s foreign currency and gold reserves increased from USD 426.3 billion to USD 526.2 billion. There can be no assurance that the currency market will not further deteriorate in the medium or long term due to the lack of foreign currency funding available in the global markets. The lack of growth of the Russian currency market in the medium or long term could materially adversely affect the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The Group is exposed to risks regarding the safety and security of its operations. The Group’s core operations may be adversely affected by many factors, including the breakdown or failure of equipment or processes, labour disputes, natural disasters, political disputes and terrorist attacks or industrial sabotage. Inability to provide safe environments for the Group’s workforce and the public could lead to injuries or loss of life and could result in regulatory action, legal liability and damage to its reputation. Security threats require continuous oversight and control. A breach of security, such as an act of terrorism or industrial sabotage against the Group’s plants and offices, pipelines, transportation or computer systems could severely disrupt businesses and operations and could cause harm to people. In addition, accidents, explosions or malfunctions at the Group’s refineries could halt or significantly slow down refining activities. Any of these safety and security risks could have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The introduction of new specifications for fuel quality standards may force the Group to incur further capital expenditures to upgrade the Khabarovsk Refinery. Fuel production from the Khabarovsk Refinery currently meets Russian domestic quality standards, and in some cases European standards, though currently the Group does not produce Euro 4 and Euro 5 standard diesel. The Group’s investment plans for its refinery anticipate a progressive

19 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA strengthening of Russian domestic fuel standards. The cost of making technical upgrades at the refineries to meet new Russian domestic standards have already been included in the Group’s investment plans and the Group intends to work closely with the relevant federal and local authorities to understand the timing for any such changes in standards. However, there is a risk that the Russian Government may accelerate the introduction of standards for cleaner fuels or that such changes, when introduced, may vary from the Group’s current expectations with respect thereto, which could force the Group to incur greater than expected capital expenditures to upgrade its operations and could limit the Group’s fuel supply for the domestic market until the necessary technical upgrades at the Khabarovsk Refinery are completed, which could produce a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The Group’s business operations could be disrupted if management information systems fail to perform adequately. The Group depends on its management information systems to conduct its operations. The Group is in the process of introducing updated information technology solutions to support its activities and business continuity. The implementation and security of the Group’s new systems and enhancements to existing systems could cause disruptions in its operations. There can be no assurance that such systems or their updates will prove to be sufficient or adequate. Any of these or other systems-related problems could, in turn, result in a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The creditors of Khvoinoye and Pechoraneft may demand early performance of their obligations or compensation of damages as a result of the Merger The Federal Law of the Russian Federation No. 208-FZ ‘‘The Joint Stock Companies’’ dated 26 December 1995, as amended (‘‘the Joint Stock Companies Law’’) provides that a company must notify the competent authority within three business days of the approval by the general shareholders’ meeting of a reorganisation. The company must then publish two notifications on the reorganisation in specifically designated mass media once per month in successive months. On 25 March 2013, the general shareholders’ meeting of Pechoraneft and the sole shareholder of Khvoinoye approved the merger of Khvoinoye into Pechoraneft (the ‘‘Merger’’). The first notification on the Merger is expected to be published in mid-April 2013. Under Russian law, creditors whose rights arose prior to publication of a notification on a reorganisation may demand, within 30 days following the last such notification: (i) early performance of the company’s obligations, or, if such early performance is impossible; (ii) early termination of their contractual relations with the company and recovery of the related damages. In case of reorganisation in the form of a merger, respective claims may be filed only if the company’s obligations are not adequately secured by the company, its shareholders or any third parties. If the amount of the respective creditors’ claims is significant and such claims are sustained by the court, this can materially adversely affect the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

Risks Relating to Business Operations in Emerging Markets Emerging markets such as Russia and Kazakhstan are subject to greater risks than more developed markets and the global financial and economic crisis could have a particularly significant adverse effect on companies operating in emerging markets such as Russia and Kazakhstan. Generally, investment in emerging markets is only suitable for sophisticated investors who fully appreciate the significance of the risks involved in, and are familiar with, investing in emerging markets. Investors should also note that emerging markets such as Russia and Kazakhstan are subject to rapid change and that the information set out in this Prospectus may become outdated relatively quickly. Moreover, financial turmoil in any emerging market country tends to adversely affect prices in debt and equity markets of other emerging market countries, as investors move their money to more stable, developed markets. Financial problems or an increase in the perceived risks associated with investing in emerging economies could dampen foreign investment in Russia and Kazakhstan

20 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA and adversely affect their economies. In addition, during crises, companies operating in emerging markets can face particularly severe liquidity constraints as foreign funding sources are withdrawn. Thus, the current global financial and economic crisis could have a particularly significant adverse effect on companies operating in emerging markets such as Russia and Kazakhstan. The Group currently conducts exploration and production projects in Kazakhstan. Kazakhstan is an emerging market and is subject to greater political, economic, social and legal risks than more developed markets. In many respects, the risks associated with conducting business in Kazakhstan are similar to, or can be greater than those associated with, conducting business in Russia, particularly for a non-Kazakh group, such as the Group.

Risks Relating to Russia The majority of the Group’s fixed assets are located in, and a significant portion of the Group’s revenues are derived from, Russia. There are certain risks associated with an investment in Russian businesses.

Political, Economic and Social Risks Political and governmental instability could materially adversely affect the value of investments in Russia. Since 1991, Russia has evolved from a one-party state with a centrally planned economy to a federal republic with democratic institutions and a market-oriented economy. However, the Russian political system remains vulnerable to popular dissatisfaction, including dissatisfaction with the results of privatisations in the 1990s, as well as to demands for autonomy from particular regional and ethnic groups. The course of political, economic and other reforms has in some respects been uneven, and the composition of the Russian Government, including the prime minister and the other heads of federal ministries, has at times been unstable. For example, there were six different prime ministers in the period between March 1998 and May 2008. Vladimir Putin was elected president of Russia in March 2000. Since that time, Russia has generally experienced a higher degree of governmental stability. In March 2008, Dmitry Medvedev was elected president of Russia, and Mr. Putin served as his prime minister for his entire administration. In March 2012, Vladimir Putin was re-elected as president and inaugurated 7 May 2012, for a term of six years; Dmitry Medvedev now serves as prime minister. Future political instability could result in a worsening of the overall economic situation, including capital flight and a slowdown of investment and business activity. Future shifts in governmental policy and regulation in Russia also could lead to political instability and disrupt or reverse political, economic and regulatory reforms, which could have a material adverse effect on the value of investments relating to Russia and the Notes in particular, as well as on the Group’s business, its ability to obtain financing in the international markets and its financial condition or prospects. Emerging markets such as Russia are also subject to heightened volatility resulting from political and economic conflicts. Any recurrence of political or governmental instability or significant or recurring terrorist attacks may lead to a deterioration in Russia’s investment climate and trading volatility, which could materially adversely affect the Group’s ability to raise equity or debt capital in the international markets, as well as its business, financial condition, results of operations or prospects. Following the Russian parliamentary elections in December 2011, controversy concerning alleged voting in favour of the current ruling party, United Russia, led to the unprecedented organised protests in several Russian cities, including protests in Moscow, in which tens of thousands of individuals participated. Allegations of voting irregularities also appeared following the election of Vladimir Putin to the Russian presidency in March 2012, with a number of protests occurring throughout the country both before and after his May inauguration. Future changes in the Russian Government, the Duma or the presidency, the creation, abolishment or reform of Russian Government bodies regulating the oil and gas industry, major policy shifts or eventual lack of consensus between the president, the Russian Government, Russia’s parliament and powerful economic groups could lead to political instability, which could have a material adverse effect on the value of investments in Russia generally and the Notes in particular. Emerging markets such as Russia are also subject to heightened volatility based on economic, military and political conflicts. For example, a military conflict in August 2008 between Russia and Georgia involving South Ossetia and Abkhazia resulted in a significant overall price decline for listed Russian securities. The emergence or escalation of any tensions in Russia or with neighbouring countries could negatively affect the economy of Russia. Such tensions or conflicts may lead to reduced liquidity,

21 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA trading volatility and significant reductions in the price of listed Russian securities, with a resulting negative effect on the liquidity, stability and trading price of the Notes and the Group’s ability to raise debt or equity capital in the international capital markets.

Conflicts between federal and regional authorities and other domestic political conflicts could create an uncertain operating environment that may hinder the Group’s long-term planning ability. Russia is a federation of various sub-federal political units, consisting of republics, territories, regions, cities of federal importance and autonomous regions and districts, some exercising considerable autonomy over their internal affairs pursuant to agreements with the federal authorities and in accordance with applicable laws. In practice, the division of authority between federal and regional authorities, in certain instances, remains uncertain and contested. This uncertainty could hinder the Group’s long-term planning efforts and may create uncertainties in its operating environment, any of which may prevent the Group from effectively and efficiently carrying out its business strategy. In addition, ethnic, religious, historical and other divisions have on occasion given rise to tensions and, in certain cases, military conflict. In the future, such tensions, military conflict or terrorist activities could have significant political and economic consequences, including the imposition of a state of emergency in some or all of Russia or heightened security measures, which could disrupt normal economic activity in Russia and have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

Economic and social instability in Russia could materially adversely affect the Group’s business. Over the last two decades, the Russian economy has experienced at various times: * significant declines in its GDP; * high levels of inflation; * high levels of corruption and the penetration of organised crime into the economy; * increases in, or high, interest rates; * sudden price declines in the natural resources sector; * instability in the local currency market; * high levels of government debt relative to GDP; * the lack of reform in the banking sector and a weak banking system, providing limited liquidity to Russian enterprises; * the continued operation and loss-making enterprises due to the lack of effective bankruptcy proceedings; * the use of fraudulent bankruptcy actions in order to take unlawful possession of property; * widespread ; * the growth of a black- and grey-market economy; * pervasive capital flight; * unstable credit conditions; * a weakly diversified economy which depends significantly on global prices of raw materials; * significant increases in unemployment and underemployment; * ethnic and religious tensions; * low personal income levels of a significant part of the Russian population; and * a major deterioration of physical infrastructure. The recent global financial turmoil has also adversely affected the Russian economy. Changes in emerging economies can occur quickly, and financial turmoil in any emerging market tends to adversely affect equity markets in all emerging areas, as investors move their money to more developed markets. In the past few years, the Russian economy has been characterised by extreme volatility in the debt and equity markets (which experienced significant declines in the second half of 2008), causing market regulators to temporarily suspend trading multiple times on the principal Russian securities exchanges, Moscow Interbank Currency Exchange and Russian Trading System.

22 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA The Russian economy has also been characterised by significant reductions in foreign investment and sharp decreases in GDP. For example, in 2009, Russian GDP declined 7.8%. As Russia produces and exports large quantities of crude oil, natural gas and other commodities, the Russian economy is particularly vulnerable to fluctuations in the prices of crude oil, natural gas and other commodities on the world market, which reached record high levels in the first half of 2008 but experienced significant decreases during the global financial crisis beginning in the second half of 2008. Russian banks, and the Russian economy generally, have also been adversely affected by the global financial crisis. During the crisis, the Russian economy has been characterised by volatility in debt and equity markets, reductions in foreign investment and sharp decreases in GDP. The Russian economy has not fully recovered from the economic crisis. There can be no assurance that any measures adopted by the Russian Government to mitigate the effect of the financial and economic crisis will result in a sustainable recovery of the Russian economy. Current macroeconomic challenges, low or negative economic growth in the United States, Japan and Europe and market volatility may prolong the economic crisis. In recent months, global markets have shown increased volatility due to continued macroeconomic challenges. The Russian economy remains vulnerable to further external shocks. Events occurring in one geographic or financial market sometimes result in an entire region or class of investments being disfavoured by international investors – so-called ‘‘contagion effects’’. Russia has been adversely affected by contagion effects in the past, and it is possible that the market for Russian investment, including the Notes, will be similarly affected in the future by negative economic or financial developments in other countries. There can be no assurance that recent economic volatility, or a future economic crisis, will not negatively affect investors’ confidence in the Russian markets, economy or ability to raise capital in the international debt markets, any of which, in turn, could have a material adverse effect on the Russian economy and the Group’s results of operations, financial condition and prospects. In addition, any declines in the price of crude oil, natural gas or other commodities could further disrupt the Russian economy and produce a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The Russian banking system remains underdeveloped, and another banking crisis in Russia could place severe liquidity constraints on the Group’s business. Russia’s banking and other financial systems are not well developed or regulated, and Russian legislation relating to banks and bank accounts is subject to varying interpretations and inconsistent applications. There are currently a limited number of creditworthy Russian banks, most of which are headquartered in Moscow. Although the CBR has the mandate and authority to suspend banking licences of insolvent banks, many insolvent banks still operate. Many banks do not follow existing CBR regulations with respect to lending criteria, credit quality, loan loss reserves or diversification of exposure. Many Russian banks also do not meet international banking standards, and the transparency of the Russian banking sector still does not meet internationally accepted norms. The serious deficiencies in the Russian banking sector, combined with the deterioration in the credit portfolios of Russian banks, may result in the banking sector being more susceptible to the current worldwide credit market downturn and economic slowdown. The credit crisis that began in the United States in the autumn of 2008 has resulted in decreased liquidity in the Russian credit market and weakened the Russian financial system. Efforts by the Russian Government to increase liquidity have been stymied by the unwillingness or inability of major banks to transfer money to the economy in the form of loans. The current lack of liquidity and economic slowdown have raised the possibility of Russian corporate defaults and led to bank failures and downgrades of Russian banks by credit rating agencies. More bank failures and credit downgrades may result in a crisis throughout the Russian banking sector. Beginning in the fourth quarter of 2008, the majority of Russian banks experienced difficulties with funding on domestic and international markets and interest rates increased significantly. Some of the banks were unable to service their obligations and were sold to larger banks. Credit ratings of several banks were lowered as well. A prolonged or serious banking crisis or the bankruptcy of a number of Russian banks could materially adversely affect the Group’s business and its ability to complete banking transactions in Russia.

23 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA The Group is required to repatriate its export sales revenues. The Group may be required to convert some portion of its export sales into Roubles in the future while its ability to convert Roubles into other currencies may be limited. The Group is subject to the requirement of mandatory repatriation of its export sales revenues. As of the date of this Prospectus, the CBR does not require any portion of the Group’s proceeds from export sales to be converted into Roubles. In the past, however, the Group has been required to convert into Roubles a percentage of its proceeds from export sales, and at times this percentage has been as high as 75%. There can be no assurance that the CBR will not require the Group to convert into Roubles a percentage of its export sale in the future. The Russian Government and the CBR may impose burdensome requirements governing currency operations, as they have done in the past. If these restrictions were re-introduced, they could prevent or delay any acquisition opportunities outside Russia that the Group might wish to pursue. Additionally, any delay or other difficulty in converting Roubles into a foreign currency to make a payment or any practical difficulty in the transfer of foreign currency could limit the Group’s ability to meet its payment and debt obligations, which could result in the acceleration of debt obligations and cross defaults. There are also only a limited number of available Rouble-denominated instruments in which the Group may invest its excess cash. Conversely, any balances maintained in Roubles would give rise to losses if the Rouble were to depreciate against major foreign currencies.

Crime, corruption and social instability could disrupt the Group’s ability to conduct business and could materially adversely affect its business, financial condition, results of operations and prospects. Levels of organised criminal activity continue to be significant in Russia. The Russian and international press have reported high levels of corruption in the Russian Federation, including the bribing of officials for the purpose of initiating investigations by government agencies. Additionally, published reports indicate that a significant number of Russian media regularly publish biased articles in exchange for payment. The Group’s business, financial condition, results of operation and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees could be materially adversely affected by illegal activities and corruption or by claims implicating the Group in illegal activities. Social instability in the Russian Federation, coupled with difficult economic conditions and the failure of salaries and benefits generally to keep pace with the rapidly increasing cost of living have led in the past to labour and social unrest (principally in urban areas). The rising level of unemployment and deteriorating standards of living in Russia that were principally caused by the global financial and economic crisis make labour and social unrest more likely in the future. Such labour and social unrest may have political, social and economic consequences, such as increased support for a renewal of centralised authority, increased nationalism, including restrictions on foreign involvement in the Russian economy and increased violence. Any of these could materially adversely affect the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

Russia’s physical infrastructure is in poor condition, which could disrupt normal business activity and efforts by the Russian Government to improve the country’s infrastructure may result in increased costs for the Group. Russia’s physical infrastructure largely dates back to the Soviet period and in certain respects has not been adequately maintained and developed due to insufficient funding and policy decisions. In some areas, the rail and road networks, power generation and transmission, communication systems and building stock are particularly affected. Road conditions throughout areas of Russia are poor, with many roads not meeting minimum requirements for usability and safety. The further deterioration of Russia’s physical infrastructure could harm the national economy, disrupt the transportation of goods and supplies, add costs to doing business in Russia and interrupt business operations. In an effort to improve national infrastructure, the Russian Government is reorganising the nation’s rail, electricity and telephone systems. These reorganisations may result in increased charges and tariffs but not produce the desired improvements in infrastructure. In addition, these reorganisations may be halted or delayed in the event of a prolonged economic downturn, which would likely lead to a further deterioration in Russia’s infrastructure network. The occurrence of any of these factors could have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

24 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA Risks Relating to the Russian Legal System and Russian Legislation Weaknesses relating to the Russian legal system and Russian legislation could affect the value of the Notes. The Russian legal framework applicable to a market economy is still under development. Since 1991, Soviet law has been largely, but not entirely, replaced by a new legal regime established by the 1993 Federal Constitution, the Civil Code, other federal laws, decrees, orders and regulations issued by the Russian President, the Russian Government and federal ministries, which are, in turn, complemented by regional and local rules and regulations. These legal standards at times overlap with or contradict one another. The recent nature of much Russian legislation and the rapid evolution of the Russian legal system cast doubt on the enforceability and underlying constitutionality of certain laws and result in ambiguities, inconsistencies and anomalies. In addition, the powers of the various Russian Government agencies are not always clearly delineated, which may lead to administrative and/or legal conflicts and challenges to transactions authorised and/or entered into by the relevant agencies with third parties, including in connection with the Notes. Russia is a civil law jurisdiction and, as such, judicial precedents have no binding effect on subsequent decisions. Among the risks of the current Russian legal system are: the limited availability of judicial and administrative guidance on interpreting Russian legislation; substantial gaps in the regulatory structure due to delay or absence of implementing legislation; the relative inexperience of judges and courts, especially in lower courts, in interpreting Russian legislation and in business and corporate law generally; the relative lack of independence of the judiciary; the difficulty in enforcing court judgments in practice; and corruption and bankruptcy procedures that are insufficiently developed and subject to abuse. Any of these weaknesses, as well as others, could hinder, delay or prevent the ability of investors to have their rights upheld in a Russian court.

If the FAS were to conclude that the Group has conducted its business in contravention of antimonopoly legislation, it could impose administrative sanctions on the Group. The oil industry in Russia is subject to strict pricing control by state authorities who, inter alia, monitor oil product prices. Unjustified increases in oil product prices can result in complaints to regulatory and control bodies and the commencement by FAS of charges of violating Russian antimonopoly legislation. Pursuant to Article 5 of the Federal Law No. 135-FZ ‘‘On the Protection of Competition’’ dated 26 July 2006, as amended (the ‘‘Competition Law’’), if a business (or several businesses) in a market of certain goods is able to exert a highly significant influence on the general conditions for such goods’ circulation and/or remove competitors from the market or impede their access thereto, such business (or several businesses) may be deemed to hold a dominant position. While a business’ dominant position in a commodity market does not itself constitute a violation of current Russian legislation, such business’ activities are controlled by the antimonopoly authorities. Regional branches of the FAS have included certain members of the Group on a list of business entities whose share in the market of certain goods exceeds 35% in certain constituent entities of Russia, a status that imposes restrictions on the Group in carrying out business activities intended to protect and develop competitive market conditions. As a result, the Group’s ability to set prices for its petroleum products is constrained. Sale prices for petroleum products must be economically justifiable, consistent with market prices and apply equally for all counterparties. Also, the Group may not refuse to enter into a supply contract if it has sufficient capacity or include in the contract any terms under which a particular counterparty may be placed in an unequal position compared to other businesses (including subsidiaries and dependent companies of the Group). The Group also must sell certain quantities of petroleum products at open exchange auctions; it may not reduce or discontinue production of petroleum products if there are no technological reasons to do so or remove goods from circulation by discontinuing sales. In addition, the Group may not cooperate with other oil companies in a way that could affect the price of goods and competition levels. Court practice related to challenging FAS decisions, in particular abuses of dominant position in the market by setting high prices and performing concerted actions with other market participants, is varied, but often Russian courts support the position of the antimonopoly authorities. On 6 January 2012, amendments to the Russian antimonopoly legislation entered into force. These amendments relate, inter alia, to the methodology of calculating administrative fines for the violation of antimonopoly legislation. More specifically, the amendments provide that a business abusing its dominant market position that results in the possible restriction of competition on a particular market is subject to an administrative fine of up to 15% of its revenue derived from the sale of goods on the

25 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA relevant market, with the base amount of fine set at 8%. The amendments also provide for certain aggravating and mitigating circumstances which should be taken into account by the antimonopoly authorities in determining the amount of fines. As a result of these amendments, the potential consequences of violating antimonopoly legislation have considerably increased. In addition, the FAS has prepared draft laws, ‘‘On Market Pricing of Oil and Petroleum Products’’ and ‘‘On Turnover of Oil and Petroleum Products in the Russian Federation’’, that hold other potential risks for the Group, including: * the possible prohibition for businesses having a dominant position on combining wholesale and retail sales of motor and diesel fuels, as well as on selling wholesale quantities of jet fuel from an oil refinery and selling jet fuel to aviation companies; * the possible prohibition for businesses with more than a 25% market share in a given motor fuel retail sales market on acquiring or leasing additional petrol stations or land plots for the construction of petrol stations intended for the retail sale of motor fuel (a market share that the Group has in a number of Russian markets); * the possible requirement on businesses having more than 25% of the total motor fuel storage capacity in a regional market to make available to third parties motor fuel storage services on a non-discriminatory basis; and * the introduction of a methodology for calculating competitive domestic market prices, a deviation from which may be treated by the FAS as setting monopolistic prices. According to the draft law, the new methodology would use comparative foreign market price indices (on a netback parity principle), domestic over-the-counter market price indices (based on commodity exchange-registered over-the-counter-transactions, as well as indices regularly published by various research and analytical agencies) and domestic commodity exchange price indices. Although the draft laws have not yet been submitted to the State Duma for consideration, there is a risk that they ultimately will be adopted. Such draft laws, if implemented, could materially affect the sales of the Group’s petroleum products in Russia. The level of market dominance of some of the Group’s subsidiaries, in particular Khabarovsknefteproduct, Primornefteproduct and Amurnefteproduct, in certain markets exceeds 35%, 50% and 65%. In addition, Khabarovsknefteproduct and Amurnefteproduct have been sanctioned by the FAS for abuse of the dominant position and for concerted actions. Administrative fines were imposed on Amurnefteproduct in 2009 and on Khabarovsknefteproduct in 2012 and further fines may amount to 15% of the respective company’s turnover in the relevant market. On 13 February 2008, in connection with the Issuer’s acquisition of 100% of the voting shares in NK Alliance, FAS issued Prescription No. AG/2928 (the ‘‘FAS Prescription’’) restricting certain activities of the Group which may potentially lead to unfair competition. The FAS Prescription is valid as long as the Issuer holds a controlling share in NK Alliance. The actions required by the FAS Prescription include (i) the obligation of Khabarovsknefteproduct, Primornefteproduct and Amurnefteproduct to notify the FAS of increases in retail prices for petroleum products of more than 5% in the Khabarovsk, Primorsky and Amur regions 90 days in advance; and (ii) the obligation of Khabarovsknefteproduct, Primornefteproduct and Amurnefteproduct, in the event of a decrease in sales of petroleum products in these respective regions, to maintain the previous ratios of intra-group to external sales of petroleum products. Failure to comply with the FAS Prescription may result in administrative fines and invalidation of the acquisition of the Issuer’s stake in NK Alliance. Khabarovsknefteproduct, Primornefteproduct and Amurnefteproduct respond to documentary requests from the FAS from time to time, and are currently in the process of responding to such requests. If the FAS were to conclude that the Group’s business had been conducted in a prohibited manner, it could impose administrative sanctions on the Group, which could have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

Selective or arbitrary government action could materially adversely affect the Group’s business. Governmental authorities in Russia have a high degree of discretion and may at times exercise their discretion arbitrarily, without hearing or prior notice, or in a manner that is unduly influenced by political or commercial considerations. Selective or arbitrary governmental actions have included unscheduled inspections by regulators, suspension or withdrawal of licences and permissions,

26 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA unexpected tax audits, criminal prosecutions and civil actions. In addition, governmental authorities have also tried, in certain circumstances, by regulation or government act, to interfere with the performance of, or to nullify or terminate contracts. Furthermore, federal and local government entities have used common defects in matters surrounding the documentation of business activities as pretexts for court claims and other demands to invalidate such activities or to void transactions, often to further interests different from the formal substance of the claims. The occurrence of such selective or arbitrary action against the Group could have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees.

The difficulty of enforcing court decisions and the discretion of governmental authorities to file and join claims and enforce court decisions could prevent the Group or investors from obtaining effective redress in court proceedings. The Russian judicial system is not immune from economic and political influences. The court system is understaffed and underfunded, and many judges and courts are inexperienced in the area of business and corporate law. Under Russian legislation, judicial precedents generally have no binding effect on subsequent decisions and are not recognised as a source of law. However, in practice, courts usually consider judicial precedents in their decisions. Enforcement of court judgments can in practice be very difficult in Russia. Additionally, court claims are sometimes used in furtherance of political and commercial aims. All of these factors can make judicial decisions in Russia difficult to predict and make effective redress uncertain in certain instances. Russia is not a party to treaties for the mutual enforcement of court judgments with most Western countries. Consequently, if a judgment is obtained from a court in any such jurisdiction, it is highly unlikely to be given direct effect in Russian courts. However, Russia (as a successor to the Soviet Union) is a party to the United Nations (New York) Convention on the Recognition and Enforcement of Foreign Arbitral Awards of 1958 (the ‘‘New York Convention’’). A foreign arbitral award obtained in a state which is a party to the New York Convention should be recognised and enforced by a Russian court (subject to the qualifications provided for in the New York Convention and in compliance with Russian civil procedure and other procedures and requirements established by Russian legislation). The Arbitration Procedural Code of the Russian Federation is in conformity with the New York Convention and thus has not introduced any substantial changes relating to the grounds for refusing to recognise and enforce foreign arbitral awards and court judgments. Nonetheless, in practice, reliance upon international treaties may meet with resistance or a lack of understanding on the part of Russian courts or other officials, thereby introducing substantial delay, difficulty and uncertainty into the process of enforcing any foreign judgment or any foreign arbitral award in Russia. Such issues could prevent the Group or investors from obtaining effective redress in court proceedings in Russia.

Shareholder liability under Russian legislation could cause the Group to become liable for the obligations of its subsidiaries. Russian legislation generally provides that shareholders in a Russian joint stock company or members in a Russian limited liability company are not liable for the obligations of the joint stock company or limited liability company and bear only the risk of loss of their investment. This may not be the case, however, when one company (an ‘‘effective parent’’) is capable of making decisions for another company (an ‘‘effective subsidiary’’) on the basis of an agreement or in accordance with the charter of the subsidiary. Under certain circumstances, the effective parent bears joint and several responsibility for transactions concluded by the effective subsidiary in carrying out such decisions. In addition, the effective parent is secondarily liable for the effective subsidiary’s debts if the effective subsidiary becomes insolvent or bankrupt as a result of the action or inaction of an effective parent. Accordingly, if the Issuer acts as the effective parent of its subsidiaries, the Issuer as parent could be liable for their debts.

Interested party transactions of the Group require the approval of disinterested directors or disinterested shareholders. Russian law requires a joint stock company that enters into transactions with certain related persons that are referred to as ‘‘interested party transactions’’ to comply with special prior approval procedures. Under Russian law, an ‘‘interested party’’ of a company includes: (i) members of the board of directors, (ii) the executive body of the company, including the managing organisation or

27 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA hired manager, (iii) a member of a collegial executive body, (iv) a shareholder who, together with its affiliates, owns at least 20% of the company’s voting shares or (v) a person who has the right to give mandatory instructions to the company. The above persons are considered interested parties in a transaction if they, a close relative or an affiliate of such person, are: * a party, representative, intermediary or a beneficiary of the transaction; * the owner, whether individually or collectively, of at least 20% of the shares in a company that is a party to a transaction with the company, whether directly or as a representative or intermediary, or a beneficiary of the transaction; * a member of a governing body of a company that is a party to, or a beneficiary of, a transaction with the company, whether directly or as a representative or intermediary, or an officer of the managing organisation of such company; or * in other cases provided for by the company’s charter. Under applicable Russian law, interested party transactions require approval by a majority of the disinterested (or, if the company has more than 1,000 shareholders, also independent) directors or disinterested shareholders of the company. A majority vote of the disinterested shareholders of the company is required if (i) the number of disinterested directors is less than the required quorum for board of directors (supervisory council) meetings (or, if a company with more than 1,000 shareholders, there are no disinterested independent directors), (ii) the value of the transaction (or of a number of interrelated transactions) is equal to or exceeds 2% of the balance sheet value of the company’s assets (determined under Russian Accounting Standards according to its latest balance sheet) or (iii) the transaction (or a number of interrelated transactions) involves the issuance or sale by the company of ordinary shares or securities convertible into such shares, in an amount exceeding 2% of the company’s issued ordinary shares. A failure to obtain the appropriate approval for a transaction may result in it being declared invalid upon a claim by the company or its shareholders made within one year from the day when the reasons for which it may be declared invalid were known or should have been known.

One or more of the Group’s subsidiaries may be forced into liquidation due to technical non-compliance with certain requirements of Russian law. Certain provisions of Russian law may allow a court to order liquidation of a Russian legal entity on the basis of its technical non-compliance with certain requirements during formation, reorganisation or operation. There have been cases in the past in which formal deficiencies in the establishment process of a Russian legal entity or non-compliance with provisions of Russian law have been used by Russian courts as a basis for liquidation of a legal entity. For example, in Russian corporate law, negative net assets calculated on the basis of Russian accounting standards as at the end of the second or any subsequent year of a company’s operation can serve as a basis for a court to order the liquidation of the company, upon a claim by governmental authorities (if no decision is taken to liquidate the company within six months of the end of the financial year). Many Russian companies have negative net assets due to very low historical asset values reflected on their Russian accounting standards balance sheets. However, their solvency (i.e., their ability to pay debts as they come due) is not otherwise adversely affected by such negative net assets. Some of the Group’s regional subsidiaries had net assets below the minimum charter capital required by law. The Group believes that, as long as these subsidiaries continue to fulfil their obligations, the risk of their liquidation is remote. Moreover, the Group may choose to mitigate these risks by increasing the retained earnings of such subsidiaries. However, weaknesses in the Russian legal system create an uncertain legal environment, which makes the decisions of a Russian court or a governmental authority difficult, if not impossible, to predict. If involuntary liquidation were to occur, then the Group may be forced to reorganise the operations it currently conducts through the affected subsidiaries. Any such liquidation could lead to additional costs, which could materially adversely affect the Group’s business, financial condition and results of operations.

The Russian taxation system is not well-developed and is subject to frequent changes, which could have an adverse effect on the Group. The Russian Government is constantly reforming the tax system by redrafting parts of the Tax Code of the Russian Federation (the ‘‘Russian Tax Code’’). These changes have resulted in some improvement in the tax climate. As of 1 January 2009, the corporate profits was reduced to 20%. For individuals who are tax residents in Russia, the current personal rate is 13%. The general rate of VAT is 18%. Since 1 January 2010, the Unified Social Tax was replaced by social

28 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA security charges to the Russian pension, social security and medical insurance funds. The total rate of the respective social security charges equals 30% on the taxable base for up to RUB 568,000 of an employee’s annual remuneration and 10% on the amount exceeding RUB 568,000 for 2013. In addition, new Russian rules on have been in force since 1 January 2012. Russian tax laws, regulations and court practice are subject to frequent change, varying interpretations and inconsistent and selective enforcement. In accordance with the Constitution of the Russian Federation, laws that introduce new taxes or worsen a taxpayer’s position cannot be applied retroactively. Nonetheless, there have been several instances in which such laws have been introduced and applied retroactively. Despite the Russian Government having taken steps to reduce the overall tax burden in recent years in line with its objectives, there is a possibility that the Russian Federation would impose arbitrary or onerous taxes and penalties in the future, which could have a material adverse effect on the Group’s business, results of operations and financial condition. In addition to the usual tax burden imposed on Russian taxpayers, these conditions complicate tax planning and related business decisions. These uncertainties could possibly expose the Group to significant fines and penalties and potentially severe enforcement measures despite its best efforts at compliance, and could result in a greater than expected tax burden, and could have a material adverse effect on the Group’s business, results of operations and financial condition or prospects. Generally, taxpayers are subject to tax audits for a period of three calendar years immediately preceding the year in which the decision to carry out a tax audit has been taken. In certain circumstances repeated tax audits (i.e. audits with respect to the same taxes and for the same periods) are possible. Generally, the statute of limitations for liability for the commission of a tax offence is also limited to three years from the date on which it was committed or from the date following the end of the tax period during which the tax offence was committed (depending on the nature of the tax offence). Nevertheless, according to the Russian Tax Code and based on current judicial interpretation, there may be cases where the statute of limitations for liability for the commission of a tax offence may be extended beyond three years. Tax audits or inspections may result in additional costs to the Group, in particular if the relevant tax authorities conclude that the Group did not satisfy its tax obligations in any given year. Such audits or inspections may also impose additional burdens on the Group by diverting the attention of management resources. The outcome of these audits or inspections could have a material adverse effect on the Group’s business, results of operations and financial condition. In October 2006, the Plenum of the Supreme Arbitrazh Court of the Russian Federation issued a ruling concerning judicial practice with respect to unjustified tax benefits. In this context, a tax benefit means a reduction in the amount of a tax liability resulting, in particular, from a reduction of the tax base, the receipt of a tax deduction or tax concession or the application of a lower tax rate, and the receipt of a right to a refund (offset) or reimbursement of tax. The ruling provides that, where the true economic intent of operations is inconsistent with the manner in which they have been taken into account for tax purposes, a tax benefit may be deemed to be unjustified. The same conclusion may apply when an operation lacks a reasonable economic or business rationale. As a result, a tax benefit cannot be regarded as a business objective in its own right. On the other hand, the fact that the same economic result might have been obtained with a lesser tax benefit accruing to the taxpayer does not constitute grounds for declaring a tax benefit to be unjustified. Moreover, there are no rules and little practice for distinguishing between lawful tax optimisation and or evasion. The tax authorities have actively sought to apply this concept when challenging tax positions taken by taxpayers in court, and are anticipated to this trend in the future. Although the intention of this ruling was to combat tax law abuses, in practice there can be no assurance that the tax authorities will not seek to apply this concept in a broader sense than may have been intended by the Supreme Arbitrazh Court. The above conditions create tax risks in the Russian Federation that are more significant than the tax risks typically found in countries with more developed taxation, legislative and judicial systems. These tax risks impose additional burdens and costs on the Group’s operations, including management resources. Furthermore, these risks and uncertainties complicate the Group’s tax planning and related business decisions, potentially exposing the Group to significant fines, penalties and enforcement measures, and could materially adversely affect the Group’s business, results of operations and financial condition.

29 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA In addition, according to the Russian thin capitalisation rules, if the overall amount of ‘‘controlled debt’’ of a Russian corporate taxpayer which is not a banking or leasing organisation, calculated on an individual Related Party (as defined below) basis, exceeds three times its capital, calculated in accordance with the requirements of the Russian Tax Code, part or all of the interest to be paid by such Russian corporate taxpayer with respect to the debt obligation between (or secured by) any foreign corporate shareholder owning directly or indirectly more than a 20% share in the Russian taxpayers’ charter capital and, potentially, affiliates of such foreign corporate shareholder (collectively the ‘‘Related Parties’’) would be reclassified as dividends for Russian tax purposes and subject to Russian domestic profits withholding tax at the rate of 15%. Therefore, if any part of the proceeds from the issue of the Notes is used by the Issuer to finance loans to its Russian subsidiaries, there is a risk that in certain circumstances part or all of the interest to be paid by such Russian subsidiaries to the Issuer under the relevant loans could be reclassified as dividends for Russian tax purposes under the above Russian thin capitalisation rules. Such reclassification of all or a portion of the interest as dividends could potentially lead to the imposition of Russian withholding tax on such reclassified interest at the rate of 15%, subject to possible exemption under an applicable double , and the non-deductibility of such interest for Russian profits tax purposes by such Russian subsidiaries of the Issuer. Furthermore, Russian tax legislation is consistently becoming more sophisticated. It is possible that new revenue raising measures could be introduced. Although it is unclear how any new measures would operate, the introduction of such measures may affect the Group’s overall tax efficiency and may result in significant additional taxes becoming payable. No assurance can be given that no additional tax exposures will arise. Additional tax exposures could have a material adverse effect on the Group’s business, results of operations and financial condition.

Russian transfer pricing rules may subject the Group’s transfer prices to challenge by the Russian tax authorities. Since 1 January 2012, new transfer pricing rules were introduced to Russian tax law. In particular, the methods for monitoring the prices of controlled transactions have been expanded and the list of controlled transactions currently includes: * cross-border transactions with certain types of commodities where the amount of income attributable to one counterparty exceeds RUB 60 million; * Russian domestic transactions between related entities if the total annual turnover of such transactions exceeds RUB 1 billion (RUB 3 billion for 2012 and RUB 2 billion for 2013); * transactions with residents of offshore jurisdictions included in the list established by the Ministry of Finance of the Russian Federation where the amount of income attributable to one counterparty exceeds RUB 60 million; and * transactions between Russian legal entities and related foreign legal entities. The new transfer pricing rules require taxpayers to notify the Russian tax authorities as to all controlled transactions (for 2012 and 2013, the notification must be made in the event that the income attributable to one counterparty exceeds RUB 100 million and RUB 80 million, respectively). Taxpayers must also be required to present to the Russian tax authorities transfer pricing documentation upon their request. The Russian transfer pricing law could have a material adverse effect on the Group’s business, results of operations and financial condition.

Risks Relating to the Issuer, the Notes and the Trading Market The Notes will be structurally subordinated to subsidiary debt and to secured creditors. The Issuer’s operations are principally conducted through its subsidiaries. Accordingly, the Issuer is and will be dependent on its subsidiaries’ operations to service its indebtedness, including the Notes. However, even though several of the Issuer’s subsidiaries will act as Guarantors, not all will. In particular, Open Joint Stock Company Khabarovsk Oil Refinery, which owns the Khabarovsk Refinery, as well as Saneco, OJSC Tatnefteotdacha (‘‘Tatnefteotdacha’’) and the Group’s joint venture AROG will not guarantee the Notes. The Notes will be effectively subordinated to the claims of all holders of debt securities and other secured and unsecured creditors, including trade creditors, of the Issuer’s non-guarantor subsidiaries (including the Khabarovsk Refinery), and to all secured creditors of the Issuer and its subsidiaries as to the assets securing such creditors’ claims. As of 31 December 2012, the Group’s total secured debt

30 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA was USD 473 million. As of 31 December 2012, the Issuer’s non-guarantor subsidiaries had indebtedness in the aggregate principal amount of USD 309 million, substantially all of which was secured. In the event of an insolvency, bankruptcy, liquidation, reorganisation, dissolution or winding- up of the business of any subsidiary of the Issuer, creditors of a non-guarantor subsidiary and secured creditors of a Guarantor subsidiary as to the assets securing their claim generally will have the right to be paid in full before any distribution is made to the Issuer.

The Issuer’s ability to pay amounts due on the Notes is to a significant extent dependent on the financial performance of its subsidiaries. The Issuer’s results of operations and financial condition are to a significant extent dependent on the financial performance of its subsidiaries. The Issuer’s ability to pay amounts due on the Notes will depend upon the level of distributions, interest payments and loan repayments, if any, received from the Issuer’s operating subsidiaries, any amounts received on disposals of assets and equity holdings and the level of cash balances. Certain of the Issuer’s subsidiaries and associated undertakings are and may, from time to time, be subject to restrictions on their ability to make distributions and loans, including as a result of restrictive covenants in loan agreements, foreign exchange and other regulatory restrictions and agreements with the other shareholders of such subsidiaries or associated undertakings.

The Issuer has limited net assets with which to meet its obligations under the Notes. The Issuer will use the net proceeds from the issue of the Notes for general corporate purposes, including the repayment of the Group’s indebtedness. The Issuer has insufficient net assets, other than amounts due to it from its subsidiaries, including the Guarantors, in respect of any intercompany loans, to meet its obligations to pay interest and other amounts payable in respect of the Notes. The Issuer would, therefore, in the absence of other funding sources, have to rely on its subsidiaries, including the Guarantors, contributing funds to it to meet such obligations.

The Notes may not be a suitable investment for all investors. Each potential investor in the Notes must determine the suitability of that investment in light of its own circumstances. In particular, each potential investor should: (a) have sufficient knowledge and experience to make a meaningful evaluation of the Notes, the merits and risks of investing in the Notes and the information contained or incorporated by reference in this Prospectus or any applicable supplement; (b) have access to, and knowledge of, appropriate analytical tools to evaluate, in the context of its particular financial situation, an investment in the Notes and the impact such investment will have on its overall investment portfolio; (c) understand thoroughly the terms of the Notes and be familiar with the behaviour of financial markets in which they participate; and (d) be able to evaluate possible scenarios for economic, interest rate and other factors that may affect its investment and its ability to bear the applicable risks.

There is no active trading market for the Notes. The Notes are new securities which may not be widely distributed and for which there is currently no active trading market. If the Notes are traded after their initial issuance, they may trade at a discount to their initial offering price, depending upon prevailing interest rates, the market for similar securities, general economic conditions, the financial condition of the Issuer, the Group’s results of operations and the market price of the Shares. Although application has been made for the Notes to be traded on the Irish Stock Exchange, there is no assurance that such application will be accepted or that an active trading market will develop. Accordingly, there is no assurance as to the development or liquidity of any trading market for the Notes.

The price of emerging market debt is subject to substantial volatility. The markets for emerging market debt have been subject to disruptions on account of the global financial crisis that have caused substantial volatility in the prices of securities similar to the Notes. There can be no assurance that the market for the Notes will not be subject to similar disruptions. Any such disruptions could have a material adverse effect on holders of the Notes.

31 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA The Notes may be redeemed prior to maturity. The Conditions provide that the Notes are redeemable at the Issuer’s option in certain circumstances and, accordingly, the Issuer may choose to redeem the outstanding Notes at times when prevailing interest rates may be relatively low. In such circumstances, an investor may not be able to reinvest the redemption proceeds in a comparable security at an effective interest rate as high as that of the Notes. Even if the Issuer does not exercise its option to redeem the Notes, its ability to do so may adversely affect the value of the Notes.

Noteholders may face difficulties in enforcing their rights under the Guarantees or the Notes. The Issuer and its subsidiaries, including the Guarantors, are incorporated outside of the United States and the United Kingdom, primarily in the Russian Federation. Further, the enforceability of the Guarantees issued in connection with the Notes may be subject to numerous legal defences and legal risks. See ‘‘Enforceability of Judgments’’.

Substantial leverage and debt-service obligations may adversely affect the Group’s cash flow. The Group will have substantial amounts of outstanding indebtedness upon the completion of the issuance, primarily under the Notes and the Group’s obligations under existing credit arrangements. As of 31 December 2012, the Issuer’s non-guarantor subsidiaries had indebtedness in the aggregate principal amount of USD 309 million. As a result of the Offering, the Group’s principal and interest payment obligations will increase substantially. Although the Notes will contain provisions limiting the Group’s ability to incur additional indebtedness, the Issuer and its subsidiaries will continue to be able to incur substantial amounts of additional indebtedness, and may also obtain additional long- term debt. The Group may not be able to generate enough cash to pay the principal, interest and other amounts due under all of its indebtedness. The Group’s substantial leverage could have significant negative consequences, including: * increasing its vulnerability to general adverse economic and industry conditions; * limiting its ability to obtain additional financing or to refinance existing indebtedness; * requiring the dedication of a substantial portion of its cash flow from operations to service its indebtedness, thereby reducing the amount of its cash flow available for other purposes, including capital expenditures; * limiting its flexibility in planning for, or reacting to, changes in its business and the industry in which the Group competes; and * placing the Group at a possible competitive disadvantage relative to less leveraged competitors and competitors that have greater access to capital resources. There can be no assurance that the Group will be able to meet such obligations, including its obligations under the Notes. If the Group is unable to generate sufficient cash flow or otherwise obtain funds necessary to make required payments, it would be in default under the terms of its indebtedness, which would permit the holders of such indebtedness to accelerate the maturity of such indebtedness and could cause defaults under the Group’s various indebtedness, including the Notes. Such defaults could delay or preclude payments of interest or principal on the Group’s indebtedness, including the Notes.

Payments required under the Guarantees may be subject to Russian withholding tax. Payments following enforcement of the Guarantee to be made by the Guarantor to the non-resident Noteholders relating to interest on the Notes are likely to be characterised as Russian source income. Accordingly, there is a risk that such payments may be subject to withholding tax at a rate of 20% in the event that a payment under the Guarantee is made to a non-resident Noteholder that is a legal entity or organisation which in each case is not organised under Russian law and which holds the Notes otherwise than through a in Russia. In the event a payment under the Guarantee is made to a non-resident individual, there is a risk that such payment may be subject to withholding tax at a rate of 30%. We cannot offer any assurance that such withholding tax would not be imposed on the full amount of the payment under the Guarantee, including with respect to the principal amount of the Notes. The imposition or possibility of imposition of this withholding tax could adversely affect the value of the Notes. See ‘‘Taxation – Russian Taxation’’. All payments made by the Guarantor with respect to the Guarantee, except in certain limited circumstances, will be made free and clear of and without withholding or deduction for, or on account of, any present or future Russian taxes unless the withholding or deduction for, or on

32 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA account of, such taxes is then required by law. In the event of such a deduction or withholding, the Guarantor, as applicable, will pay such additional amounts as may be necessary in order that the net amounts received in respect of such payments after such withholding or deduction will equal the respective amounts that would have been received in respect of such payments in the absence of such withholding or deduction. While this Prospectus provides for the Guarantor to pay such corresponding amounts in these circumstances, it is unclear as to whether a tax gross up clause such as that contained in this Prospectus is enforceable in the Russian Federation. There is a risk that the tax gross-up for withholding tax will not take place and that the full amount of the payments made by the Guarantor, which are Russian legal entities, will be reduced by Russian withholding income tax at a rate of 20% (or, potentially, 30% in respect of individual Noteholders). See ‘‘Taxation – Russian Taxation’’.

Tax might be withheld on disposals of the Notes in Russia, reducing their value. If a non-resident Noteholder that is a legal entity or organisation, which in each case is not organised under Russian law and which holds and disposes of the Notes otherwise than through a permanent establishment in Russia, sells the Notes and receives proceeds from a source within the Russian Federation, there is a risk that any part of the payment that represents accrued interest may be subject to a 20% Russian withholding tax (even if a disposal is performed at a loss). The foreign Noteholder may be entitled to a reduction of such Russian withholding tax under an applicable double tax treaty. Where proceeds from a disposal of the Notes are received from a source within the Russian Federation by a non-resident Noteholder that is an individual, there is a risk that Russian withholding tax would be charged at a rate of 30% on gross proceeds from such disposal of the Notes less any available cost deduction. There is no assurance that advance double tax treaty relief would be granted to an individual and obtaining a refund can involve considerable practical difficulties. The imposition or risk of imposition of this withholding tax could adversely affect the value of the Notes. See ‘‘Taxation – Russian Taxation’’.

Payments required under the Guarantee provided by Potential Oil are subject to Kazakh income tax. Normally, payments to Non-Kazakhstan Holders (as defined below) under the Guarantees issued by non-resident Guarantors are not subject to taxation in Kazakhstan. Interest payments to Non-Kazakhstan Holders under Potential Oil’s Guarantee are likely to be subject to withholding tax at a rate of 15% unless reduced by an applicable treaty. Payments of interest under the Guarantee issued by Potential Oil to Non-Kazakhstan Holders registered in countries with a favourable tax regime which appear in a list published from time to time by the Kazakhstan government (these countries currently include Cyprus, Liechtenstein, Luxembourg, Nigeria, Malta, Aruba and others) will be subject to withholding tax in Kazakhstan at a rate of 20% unless reduced by an applicable double taxation treaty. Payments of interest to Kazakhstan Holders (as defined below), other than to individuals and the Exempt Holders (as defined below), under the Guarantee issued by Potential Oil, will be subject to withholding tax at a rate of 15%. Interest payable by the Guarantors, other than Potential Oil, to Kazakhstan Holders, other than the exempt holders, will be subject to corporate income tax at a rate of 20%. As a general rule, repayment of principal under notes to a noteholder does not give rise to income tax implications in Kazakhstan. Normally, interest payments on notes admitted, as of the date of accrual of interest, to the official list of a stock exchange operating in the territory of Kazakhstan are exempt from Kazakhstan income tax. The Issuer and Potential Oil cannot provide assurance that: (i) income tax would not be imposed upon the entire payment under the Guarantees, including with respect to the principal amount of the Notes (safe for payments between non-residents), and in such a case not 15% tax rate, but 20%, would be applied; and (ii) that the above tax relief which is generally available for payments under notes admitted to trading on a Kazakh stock exchange would be in practice available for the interest payments on the Notes under the Guarantees. See ‘‘Taxation – Kazakh taxation’’. The Guarantors will agree under their Guarantees in the Trust Deed to pay Amounts or Claims (as defined in the Trust Deed) in respect of any such withholding, subject to certain exceptions set out in full in ‘‘Terms and Conditions of the Notes – Taxation’’. Under Kazakhstan laws, any provision of

33 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA any document which has or purports to have the purpose or effect of imposing on a person any obligation to pay any tax or similar payment or fee owed by another person may not be valid. The amendments to the Kazakhstan Tax Code, effective from 1 January 2012, provide that a Kazakhstan income-payer being a tax agent is allowed to pay withholding tax calculated on the income payable to a non-resident income-receiver from its own funds, without any deductions from the amounts payable. Although there is an element of doubt, and so far as the Group is aware there has been no case in Kazakhstan in which tax gross-up provisions have been considered by Kazakhstan courts, the Group is of the view that such provisions of the Trust Deed should be considered as contractual obligations on Potential Oil to pay withholding tax from its own funds rather than constitute an obligation to pay taxes imposed on the payee.

Investors may receive less interest or principal than expected because of U.S. withholding tax under the Foreign Account Tax Compliance Act. Pursuant to the foreign account tax compliance provisions of the Hiring Incentives to Restore Employment Act of 2010 (‘‘FATCA’’), the Issuer and other non-U.S. financial institutions through which payments on the Notes are made may be required to withhold U.S. tax at a rate of 30% on all, or a portion of, payments made after 31 December 2016 in respect of any Notes issued or materially modified on or after the later of (a) 1 January 2014, and (b) the date that is six months after the date on which the final regulations applicable to ‘‘foreign passthru payments’’ are published in the Federal Register. Under existing guidance, this withholding tax may be triggered on payments on the Notes if (i) the Issuer is a foreign financial institution (‘‘FFI’’) (as defined in FATCA) which enters into and complies with an agreement with the U.S. Internal (‘‘IRS’’) to provide certain information on its account holders (making the Issuer a ‘‘Participating FFI’’), (ii) the Issuer is required to withhold on ‘‘foreign passthru payments’’, and (iii)(a) an investor does not provide information sufficient for the relevant Participating FFI to determine whether the investor is subject to withholding under FATCA, or (b) any FFI to or through which payment on such Notes is made is not a Participating FFI or otherwise exempt from FATCA withholding.

The application of FATCA to interest, principal or other amounts paid with respect to the Notes is not clear. In particular, Bermuda may enter into an intergovernmental agreement with the United States to help implement FATCA for certain Bermudian entities. The full impact of such an agreement on the Issuer and the Issuer’s reporting and withholding responsibilities under FATCA is unclear. The Issuer may be required to report certain information on its U.S. account holders to the government of Bermuda in order (i) to obtain an exemption from FATCA withholding on payments it receives and/or (ii) to comply with any applicable Bermudian law. It is not yet certain how the United States and Bermuda will address withholding on ‘‘foreign passthru payments’’ (which may include payments on the Notes) or if such withholding will be required at all.

If an amount in respect of U.S. withholding tax were to be deducted or withheld from interest, principal or other payments on the Notes as a result of FATCA, none of the Issuer, the Guarantor, any paying agent or any other person would, pursuant to the Terms and Conditions of the Notes be required to pay additional amounts as a result of the deduction or withholding. As a result, investors may receive less interest or principal than expected.

FATCA is particularly complex and its application to the Issuer, the Notes and holders of the Notes is uncertain at this time. Each holder of Notes should consult its own tax adviser to obtain a more detailed explanation of FATCA and to learn how FATCA might affect each holder in its particular circumstance.

Noteholders may not be adequately protected against corporate restructurings or highly leveraged transactions. The terms of the Notes do not contain provisions that would afford Noteholders protection in the event of a decline in the Group’s credit quality resulting from highly leveraged or other similar transactions in which the Group may engage. Provided that a certain leverage ratio is maintained and no actual or potential Event of Default (as defined in the Terms and Conditions of the Notes) has occurred or will occur as a result of such incurrence, the Group may incur additional indebtedness. Noteholders do not have the right to require the Group to repurchase or redeem the Notes in the event of many types of highly leveraged transactions.

34 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA The Notes may only be transferred in accordance with the procedures of the depositaries in which the Notes are deposited. Except in limited circumstances, the Notes will be issued only in global form with interests therein held through the facilities of Euroclear, Clearstream, Luxembourg and/or DTC. Ownership of beneficial interests in the Notes is shown on, and the transfer of that ownership is effected only through, records maintained by Euroclear, Clearstream, Luxembourg and/or DTC or their nominees and the records of their participants. The laws of some jurisdictions may require that certain purchasers of securities take physical delivery of such securities in definitive form. These laws may impair the ability to transfer beneficial interests in the Notes. Because Euroclear, Clearstream, Luxembourg and/or DTC can only act on behalf of their participants, which, in turn, act on behalf of owners of beneficial interests held through such participants and certain banks, the ability of a person having a beneficial interest in a note to pledge or transfer such interest to persons or entities that do not participate in the Euroclear, Clearstream, Luxembourg and/or DTC systems may be impaired.

Other Risks The Group has not independently verified information it has sourced from third parties. The Group has sourced certain information contained in this Prospectus from third parties, including private companies and Russian Government agencies, and the Group has relied on the accuracy of this information without independent verification. The official data published by Russian federal, regional and local governments may be substantially less complete or researched than those of Western countries. Official statistics may also be produced on different bases than those used in Western countries. Any discussion of matters relating to Russia in this Prospectus must, therefore, be subject to uncertainty due to concerns about the completeness or reliability of available official and public information.

A Bermuda court may disregard bye-laws modelled on Swedish company law or jurisdiction of Swedish courts. The bye-laws of the Issuer provide that a number of key provisions of the bye-laws are modelled on Swedish company law and that these provisions shall be construed in accordance with Swedish law (taking into account the provisions of the Swedish Companies Act and relevant case law and sources of law). It is not certain that a Bermuda court would apply Swedish law to the construction of the bye-laws of a Bermuda company, notwithstanding such a bye-law. The bye-laws of the Issuer also provide that any dispute, controversy or claim between the Issuer and any director or shareholder or between any director and any shareholder shall be finally settled by the Stockholm City Court in accordance with the Swedish Code of Judicial Procedure. It is likely that a Bermuda Court would assume jurisdiction in relation to a Bermuda company, notwithstanding such a bye-law.

A derogation has been granted by the Central Bank in relation to the Guarantors. Under Annex VI of the European Commission Regulation (EC) No 809/2004, as amended, a guarantor must disclose information about itself as if it were the issuer of that same type of security that is the subject of the guarantee. This normally requires the inclusion of a guarantor’s individual financial statements in the prospectus relating to such securities. The Issuer has applied to the Central Bank for a derogation from the requirement for each of the Guarantors to include their individual financial statements in this Prospectus. Under Regulation 25(c) of the Prospectus (Directive 2003/71/ EC) Regulations 2005, the Central Bank has granted such a derogation. The equivalent information is included in financial statements of the Issuer, which are set out on pages F-2 to F-123 of this Prospectus.

35 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA FORWARD-LOOKING STATEMENTS

Certain statements in this Prospectus are not historical facts and are ‘‘forward-looking’’ within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. This Prospectus contains certain forward-looking statements in various locations, including, without limitation, under the headings ‘‘Overview’’, ‘‘Risk Factors’’, ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ and ‘‘Business’’ (including, but not limited, to the ‘‘Strategy’’ section therein). The Group may from time to time make written or oral forward-looking statements in reports to its shareholders and in other communications. Examples of such forward-looking statements include, but are not limited to, statements of plans, objectives or goals, including those related to the Group’s products or services; modernisation programmes and projects; statements of future economic performance; and statements of assumptions underlying such statements. Forward-looking statements that may be made from time to time may also include projections or expectations of revenues, income (or loss), earnings (or loss) per share, dividends, capital structure or other financial items or ratios. Words such as ‘‘believes’’, ‘‘anticipates’’, ‘‘expects’’, ‘‘estimates’’, ‘‘intends’’ and ‘‘plans’’ and similar expressions are intended to identify forward-looking statements but are not the exclusive means of identifying such statements. By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks exist that the predictions, forecasts, projections and other forward-looking statements will not be achieved. A number of important factors could cause actual results to differ materially from the plans, objectives, expectations, estimates and intentions expressed in such forward- looking statements. These factors include: * the prevailing global and domestic economic environment; * inflation, interest rate and exchange rate fluctuations; * the prices of crude oil and petroleum products; * the Group’s ability to finance its anticipated capital expenditures through the global capital markets, revenue from operations or otherwise; * the effects of, and changes in, the policies of the Russian Government; * the inherent uncertainties in estimating the Group’s reserves of crude oil; * the effects of competition in the geographic and business areas in which the Group conducts operations; * the inherent uncertainties in estimating the potential impact of efficiency, innovation, upgrade and other projects, including the modernisation programme in relation to the Khabarovsk Refinery; * the effects of changes in laws, regulations, taxation or accounting standards or practices; * the Group’s ability to increase market share for its products and control expenses; * acquisitions or divestitures; * technological changes; * the effects of international political events on the Group’s businesses; * the Group’s ability to manage operational risks in its crude oil exploration, production and transportation activities and other business operations; * the Group’s ability to retain its licences, permits or authorisations; and * the Group’s success at managing the risks of the aforementioned factors. This list of important factors is not exhaustive. When relying on forward-looking statements, investors should carefully consider the foregoing factors and other uncertainties and events, especially in light of the political, economic, social and legal environment in which the Group operates. Such forward- looking statements speak only as of the date on which they are made. Accordingly, the Group does not undertake any obligation to update or revise any of them, whether as a result of new information, future events or otherwise, except as otherwise required by applicable law or under the Prospectus Directive and the relevant implementing measures in Ireland. The Group does not make any representation, warranty or prediction that the results or events anticipated by such forward- looking statements will be achieved or occur, and such forward-looking statements represent, in each

36 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA case, only one of many possible scenarios and should not be viewed as the most likely or standard scenario. In addition, the estimates and projections relating to hydrocarbon reserves in this Prospectus reflect a number of assumptions, including future global and domestic pricing for crude oil and petroleum products, expected taxation levels, the application of Russian law and regulations consistent with the Group’s expectations and compliance by the Group with its licence obligations. Estimates of the Group’s reserves may differ materially from actual results. See ‘‘Risk Factors – Risks Relating to the Group and the Oil and Gas Industry – Oil, natural gas and gas condensate reserves data in the Prospectus are only estimates, and the Group’s actual production, revenues and expenditures with respect to its reserves may differ materially from those estimates’’. The Group may not pursue its development plans in their current form and there can be no assurance that the results and events contemplated by the forward-looking statements contained in this Prospectus will, in fact, occur. Prospective investors should specifically consider the factors identified in this Prospectus which could cause actual results to differ before making an investment decision.

37 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA ENFORCEABILITY OF JUDGMENTS

The Issuer is a limited liability company incorporated under the laws of Bermuda. With the exception of LLP Potential Oil, each of the Guarantors is organised under the laws of Russia, and most of the Guarantors and the Issuer’s directors and executive officers reside in Russia. Most of the assets of the Group and of such persons are located outside of the United States and the United Kingdom. Therefore, it may not be possible for investors to enforce, in the English or U.S. courts, judgments obtained outside English or U.S. courts against the Group or any such person in any action. In addition, it may be difficult for the Noteholders to enforce, in original actions brought in courts in jurisdictions located outside the United Kingdom and the United States, liabilities predicated upon English laws or the U.S. federal securities laws. Courts in Russia will generally recognise judgments rendered by a court in any jurisdiction outside Russia if: * an international treaty providing for the recognition and enforcement of judgments in civil cases exists between Russia and the country where the judgment is rendered; or * a federal law is adopted in Russia providing for the recognition and enforcement of foreign court judgments. No such treaty for the reciprocal recognition and enforcement of foreign court judgments in civil and commercial matters exists between Russia and the United States or the United Kingdom and no relevant federal law on enforcement of foreign court judgments has been adopted in Russia. In the absence of an applicable treaty, enforcement of a final judgment rendered by a foreign court may still be recognised by a Russian court on the basis of reciprocity, if courts of the country where the foreign judgment is rendered have previously enforced judgments issued by Russian courts. While Russian courts have recently recognised and enforced English court judgments on these grounds, the existence of reciprocity must be established at the time the recognition and enforcement of a foreign judgment is sought, and it is not possible to predict whether a Russian court will in the future recognise and enforce, on the basis of reciprocity, a judgment issued by a foreign court, including an English court. Even if an applicable international treaty is in effect or a foreign judgment might otherwise be recognised and enforced on the basis of reciprocity, the recognition and enforcement of a foreign judgment will in all events be subject to exceptions and limitations provided for in Russian law. For example, a Russian court may refuse to recognise or enforce a foreign judgment if its recognition or enforcement would contradict Russian public policy. The Notes and the Guarantees will be governed by English law and will provide for disputes, controversies and causes of action arising out of or in connection with the Notes and the Guarantees to be settled by arbitration in accordance with the LCIA Arbitration Rules. The Russian Federation is a party to the New York Convention. However, it may be difficult to enforce arbitral awards in the Russian Federation due to, inter alia: * the inexperience of the Russian courts in enforcing international commercial arbitral awards; * official and unofficial political resistance to enforcement of awards against Russian companies in favour of foreign investors; and * the Russian courts’ inability or unwillingness to enforce such orders. Furthermore, any arbitral award pursuant to arbitration proceedings in accordance with the rules of the LCIA and the application of English law to the Notes and Guarantees may be limited by the mandatory provisions of Russian law relating to the exclusive jurisdiction of Russian courts and the application of Russian law with respect to bankruptcy, winding up or liquidation of Russian companies. An award granted pursuant to arbitration proceedings in the United Kingdom or United States and conducted in accordance with English law granted against the Issuer based upon the Notes would be enforceable in Bermuda under the Bermuda International Conciliation and Arbitration Act 1993 (which incorporates the New York Convention) either by action or by leave of the Supreme Court or a judge thereof, in the same manner as a judgment or order to the same effect, and where leave is so given, judgment may be entered in the terms of the award. Enforcement of an award may be refused if the person against whom it is invoked proves:

38 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA a) that a party to the arbitration agreement was (under the law applicable to him) under some incapacity; or b) that the arbitration agreement was not valid under the law to which the parties subjected it or, in the absence of any indication thereon, under the law of the country where the award was made; or c) that such person was not given proper notice of the appointment of the arbitrator or of the arbitration proceedings or was otherwise unable to present his case; or d) that the award deals with a difference not contemplated by or not falling within the terms of the submission to arbitration or contains decisions on matters beyond the scope of the submission to arbitration (save that in such case an award on matters submitted to arbitration may be enforceable to the extent these matters can be separated from those not submitted); or e) that the composition of the arbitral authority or the arbitral procedure was not in accordance with the agreement of the parties or, in the absence of such agreement, with the law of the country where the arbitration took place; or f) that the award has not yet become binding on the parties, or has been set aside or suspended by a competent authority of the country in which, or under the law of which, it was made. Enforcement may also be refused if the award is in respect of a matter which is not capable of settlement by arbitration, or if it would be contrary to public policy to enforce the award. The Judgments (Reciprocal Enforcement) Act 1958 of Bermuda applies to a final and conclusive judgment of the superior courts of the United Kingdom under which a sum of money is payable (not being in respect of multiple damages, or a fine, penalty, tax or other charge of similar nature). Where that act applies, enforcement of such judgment in Bermuda must proceed under that act, and the judgment must be registered as if it were expressed in Bermuda currency at the rate of exchange prevailing on the date of the judgment. With respect to any other proceedings, the Bermuda court may make an award in any currency and has the discretion to give an award in the currency in which the claim is expressed. Courts in Kazakhstan will not enforce any judgment obtained in a court established in a country other than Kazakhstan unless there is in effect a treaty between such country and Kazakhstan providing for reciprocal enforcement of judgments and then only in accordance with the terms of such treaty. There is no such treaty in effect between Kazakhstan and England. However, each of Kazakhstan and England is a party to the New York Convention, and English arbitral awards are generally recognised and enforceable in Kazakhstan, provided the conditions to enforcement set out in the New York Convention and Kazakhstan legislation are met.

39 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA PRESENTATION OF CERTAIN INFORMATION

References In this Prospectus, the term ‘‘Group’’ refers to Alliance Oil Company Ltd. and its consolidated subsidiaries, taken as a whole, unless the context otherwise requires. The terms ‘‘oil products’’ and ‘‘petroleum products’’ are used interchangeably in this Prospectus.

Presentation of Financial Information The financial information of the Group included herein as at and for the years ended 31 December 2012, 2011 and 2010, unless otherwise indicated, has been derived from its audited consolidated financial statements as follows: * Financial information relating to 31 December 2012 or the fiscal year then ended has been derived from the audited consolidated financial statements as at and for the year ended 31 December 2012 (the ‘‘2012 Financial Statements’’). * Financial information relating to 31 December 2011 or for the fiscal year then ended has been derived from the audited consolidated financial statements as at 31 December 2011 (the ‘‘2011 Financial Statements’’). * Financial information relating to 31 December 2010 or for the fiscal year then ended has been derived from the unaudited comparatives included in the 2011 Financial Statements. The 2012 Financial Statements and 2011 Financial Statements (collectively the ‘‘Financial Statements’’) have been prepared in accordance with International Financial Reporting Standards (‘‘IFRS’’) as issued by the International Accounting Standards Board and have been audited by the Group’s independent auditors, ZAO ‘‘Deloitte & Touche CIS’’ and Deloitte AB (collectively, ‘‘Deloitte’’), as stated in their audit reports appearing herein, which expresses unqualified opinion on the Financial Statements. The address of ZAO ‘‘Deloitte & Touche CIS’’ is Lesnaya street, 5, Moscow 125047, Russian Federation. ZAO Deloitte & Touche CIS is a member of the non-commercial partnership, ‘‘Audit Chamber of Russia’’ (certificate no. 3026 dated 10 May 2009). Deloitte AB is a member of FAR, the professional institute for authorised public accountants, approved public accountants, and other highly qualified professionals in the accountancy sector in Sweden. Deloitte AB address is Rehnsgatan 11, SE-113 79, Stockholm, Sweden. The Financial Statements are contained elsewhere in this Prospectus and should be read, where applicable, in conjunction with the relevant notes and auditor’s reports thereto.

Presentation of Non-IFRS Financial Information The Group presents Adjusted EBITDA, which is not a measure of financial performance under IFRS or other generally accepted accounting principles. This measure is used by the Group to assess its financial performance. The measure as presented in this Prospectus may not be comparable to similarly titled measures of performance presented by other companies, and it should not be considered as a substitute for the information contained in the Financial Statements included in this Prospectus. As presented in this Prospectus, ‘‘Adjusted EBITDA’’ is defined as profit before tax plus currency exchange (gain)/loss, net, (gain)/loss on derivatives classified as held for trading, net, finance costs, interest income, loss/(gain) on disposal of shares in subsidiaries, depreciation, depletion and amortisation, reversal of impairment of oil and gas assets, net, and other one-off items in the consolidated statement of profit or loss. The Group’s Adjusted EBITDA is a supplemental measure of the Group’s performance and liquidity that are not required by or presented in accordance with IFRS. Furthermore, Adjusted EBITDA should not be considered as an alternative to profit after tax, profit before tax or any other performance measures derived in accordance with IFRS or as an alternative to cash flow from operating activities as a measure of the Group’s liquidity or as a measure of cash available to the Group to invest in the growth of its business. Adjusted EBITDA is presented in this Prospectus because the Group considers it to be an important supplemental measure of its financial performance. Additionally, the Group believes this measure is frequently used by investors, securities analysts and other interested parties to evaluate the efficiency of a group’s operations and its ability to employ its earnings toward repayment of debt, capital expenditures and working capital requirements. Adjusted EBITDA has limitations as an analytical

40 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA tool and should not be considered in isolation or as a substitute for the Group’s operating results as reported under IFRS. Some of these limitations are as follows: (a) Adjusted EBITDA does not reflect the impact of finance costs or the cash requirements necessary to service interest or principal payments in respect of any borrowings, which could further increase if the Group incurs more debt; (b) Adjusted EBITDA does not reflect the Group’s cash expenditures or future requirements for capital expenditure or contractual commitments; (c) Adjusted EBITDA does not reflect changes in or cash requirements for the Group’s working capital needs; (d) Adjusted EBITDA does not reflect the impact of depreciation, depletion and amortisation of assets on the Group’s performance. The assets of the Group’s business which are being depreciated, depleted and amortised will have to be replaced in the future, and such depreciation, depletion and amortisation expense may approximate the cost to replace these assets in the future. By excluding this expense from Adjusted EBITDA, Adjusted EBITDA does not reflect the Group’s future cash requirements for these replacements; (e) Adjusted EBITDA does not reflect the impact of income tax expense on the Group’s operating performance; (f) Adjusted EBITDA does not reflect the impact of a number of other significant non-cash items, specifically (gain)/loss on derivatives classified as held for trading, net, loss/(gain) on disposal of shares in subsidiaries, reversal of impairment of oil and gas assets, net, and other one-off items in the consolidated statement of profit or loss; (g) it does not reflect currency exchange gains or losses; and (h) Other companies in the Group’s industry may calculate Adjusted EBITDA differently or may use them for different purposes than the Group does, limiting their usefulness as a comparative measure. The Group compensates for these limitations by relying on its IFRS results and using Adjusted EBITDA only as a supplemental measure. Adjusted EBITDA is a measure of the Group’s operating performance that is not required by, or presented in accordance with, IFRS. Adjusted EBITDA is not a measurement of the Group’s operating performance under IFRS and should not be considered as an alternative to profit for the year, operating profit or any other performance measures derived in accordance with IFRS, or as an alternative to cash flow from operating activities or as a measure of the Group’s liquidity. In particular, Adjusted EBITDA should not be considered as a measure of discretionary cash available to the Group to invest in the growth of its business. For the calculation of the Group’s Adjusted EBITDA for the years ended 31 December 2012, 2011 and 2010 and the reconciliation of Adjusted EBITDA for each such year to profit before tax for the corresponding year, see ‘‘Summary Consolidated Financial Information’’. Certain operational and statistical information relating to the Group’s operations included herein is unaudited and has not been derived from its financial statements and/or accounting records.

Oil and Gas Information This Prospectus contains information concerning the Group’s estimated proved, probable and possible oil and gas reserves that has been derived from the Reserves Reports and which are estimated in accordance with the PRMS classification. The Reserves Reports set forth estimates of the Group’s reserves based on data derived from studies relating to the Group’s interest in reserves of crude oil and gas at its properties. The Group’s ownership in its relevant subsidiaries ranges from 50.8% to 100%; because the Group exercises control over these subsidiaries, their estimated reserves are reported at 100% in both the Reserves Reports and information extracted or derived from the Reserves Reports in this Prospectus. Additionally, the Group accounts for its share in the gas reserves of AROG under the equity method. D&M is a Delaware corporation with offices at 5001 Spring Valley Road, Suite 800 East, Dallas, Texas 75244, United States of America. The firm’s professional engineers, geologists, geophysicists, petrophysicists and economists are engaged in the independent appraisal of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies, equity studies, and studies of supply and economics related to the energy industry. D&M has given

41 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA and has not withdrawn its consent to the inclusion in this Prospectus of information from the Reserves Reports in the form and context in which they are included. The Group also present estimates of its reserves under the Russian reserves classification system, which is based on data approved by the relevant Russian governmental authorities. The Russian reserves system differs significantly from PRMS reserves methodologies, in particular with respect to which and the extent to which commercial factors are taken into account in calculating reserves. Reserves that are calculated using different methods cannot be accurately reconciled. The Group does not commission audits of its reserves under SEC standards. The PRMS classification differs in certain material respects from SEC standards. The SEC standards permit oil and gas companies, in their filings with the SEC, to disclose only proved reserves, probable reserves and possible reserves, each term as defined by the SEC. This Prospectus contains data presented in accordance with the PRMS classification, which the SEC’s guidelines would prohibit the Group from including in filings with the SEC. Accordingly, information concerning descriptions of oil and gas reserves contained in this document may not be comparable to information required or permitted to be made public by U.S. or other international companies engaged in oil and gas producing activities and subject to the reporting and disclosure requirements of the SEC. Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. These estimates necessarily depend upon a number of variable factors and assumptions, many of which are beyond the Group’s control. Due to the inherent uncertainties and the necessarily limited nature of reservoir data and the inherently imprecise nature of reserves estimates, the reserves amounts disclosed in this Prospectus may change as additional information becomes available. Prospective investors should not place undue reliance on the ability of the Reserves Reports to predict actual reserves or on comparisons of similar reports concerning companies established in other economic systems.

Presentation of Reserves and Production Data All numerical data regarding figures for production of crude oil presented in this Prospectus are presented in gross terms without any deduction for wastage or own use at the field unless otherwise stated by reference to net numerical data. The following abbreviations have the following meanings as used in this Prospectus: ‘‘bbl’’ means barrel(s); ‘‘bcf’’ means billion cubic feet; ‘‘bcm’’ means billion cubic metres; ‘‘boe’’ means barrel of oil equivalent; ‘‘bpd’’ means barrel per day; ‘‘mmbbl’’ means million barrels; ‘‘mmbd’’ means million barrels per day; ‘‘mmboe’’ means million barrels of oil equivalent; ‘‘mmboed’’ means million barrels of oil equivalent per day; ‘‘mmtoe’’ means million tonnes of oil equivalent; ‘‘mmtonnes’’ means million tonnes; ‘‘tcf’’ means trillion cubic feet; ‘‘tcm’’ means trillion cubic metres; and ‘‘toe’’ means tonne of oil equivalent.

Conversion of Hydrocarbon Volumetric Data This Prospectus presents data relating to the Group’s production, refining and marketing operations, which is expressed in barrels. As is common in the reporting of hydrocarbon production in countries of the CIS, the Group maintains its internal records regarding such data in metric tonnes. Tonnes of crude oil produced are translated into barrels using conversion rates reflecting oil density from each of the Group’s oil fields. Crude oil purchased as well as other operational indicators expressed in barrels are translated from tonnes using a conversion rate of 7.33 barrels per tonne. Translations of cubic metres to cubic feet are made at the rate of 35.3147 cubic feet per cubic metre.

42 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA Translations of barrels of crude oil into boe are made at the rate of one barrel per boe, and of cubic feet of natural gas into boe at the rate of six thousand cubic feet per boe.

Rounding of Figures Certain figures included in this Prospectus have been subject to rounding adjustments; accordingly, figures shown for the same category presented in different tables may vary slightly and figures shown as totals in certain tables may not be an arithmetic aggregation of the figures which precede them.

Currencies In this Prospectus, references to ‘‘Russian Roubles’’, ‘‘Roubles’’ and ‘‘RUB’’ are to the lawful currency of Russia; references to ‘‘U.S. dollars’’, ‘‘USD’’, ‘‘dollars’’ and ‘‘U.S.$’’ are to the lawful currency of the United States of America; references to ‘‘£’’ are to the lawful currency of the United Kingdom and references to ‘‘c’’ and ‘‘EUR’’ are to the lawful currency of the Member States of the EU that adopted the single currency in accordance with the Treaty of Rome establishing the European Economic Community, as amended. Solely for the convenience of the reader, this Prospectus contains certain translations from Roubles or other currencies into USD. These translations should not be construed as representations that the amounts actually represent such equivalent U.S. dollar amount or could be, or could have been, converted into U.S. dollars at the rate indicated as of the dates mentioned herein or at all. The table below sets forth, for the periods and dates indicated, the high, low, period end and period average exchange rate between the Rouble and the U.S. dollar, based on the official exchange rate quoted by the CBR for the relevant period. Fluctuations in the exchange rate between the Rouble and the U.S. dollar in the past are not necessarily indicative of fluctuations that may occur in the future. These rates may also differ from the actual rates used in the preparation of the Financial Statements and other financial information presented in this Prospectus.

RUB per USD 1.00

Period High Low Period end average(1)

Period 2007 ...... 26.58 24.26 24.55 25.58 2008 ...... 29.38 23.13 29.38 24.86 2009 ...... 36.43 28.67 30.24 31.72 2010 ...... 31.78 28.93 30.48 30.37 2011 ...... 32.68 27.26 32.20 29.35 2012 ...... 34.04 28.95 30.37 31.07 January 2013...... 30.42 30.03 30.03 30.26 February 2013...... 30.62 29.93 30.62 30.16 March 2013...... 31.08 30.51 31.08 30.80

(1) The average rates are calculated as the average of the daily exchange rates on each business day (which rate is announced by the CBR for each such business day) and on each non-business day (which rate is equal to the exchange rate on the previous business day). No representation is made that the Rouble or U.S. dollar amounts referred to herein could have been or could be converted into Roubles or U.S. dollars, as the case may be, at these rates, at any particular rate or at all. The exchange rate between the Rouble and the U.S. dollar has fluctuated significantly during the periods covered by the Financial Statements. The CBR rate on 13 April 2013 was RUB 30.93 = USD 1.00.

Industry and Market Data In this Prospectus, the Group refers to information regarding its business, the business of its competitors and the market in which it operates and competes. The Group obtained this information in part from various third-party sources and in part from its own internal estimates. Industry publications, surveys and forecasts generally state that the information contained therein has been obtained from sources believed to be reliable. The Group has relied on the accuracy of the information from industry publications, surveys and forecasts without carrying out an independent verification thereof and cannot guarantee their accuracy or completeness. Such information appears in

43 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA the sections of this Prospectus entitled ‘‘Risk Factors’’, ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’, and ‘‘Business’’, among others. The Group confirms that such third party information has been accurately reproduced and, as far as the Group is aware and is able to ascertain from information published by such third parties, no facts have been omitted from the information in this Prospectus that would render it inaccurate or misleading. See ‘‘Risk Factors – Other Risks – The Group has not independently verified information it has sourced from third parties’’. Some of the information contained in this Prospectus has been derived from the official data of Russian state agencies. Some of the official data and statistics published by Russian federal, regional and local governments may not be complete or researched to the standard of Western countries. Any discussion of matters relating to Russia in this Prospectus must, therefore, be subject to uncertainty due to the potential inaccuracy of available official and public information. In addition, in many cases, the Group has made statements in this Prospectus regarding the Russian oil industry and the Group’s position in this industry based on its own experience and investigation of market conditions. The Group cannot assure investors that any of its assumptions are accurate or correctly reflect its position in the industry, and its statements have not been verified by any independent sources. The language of this Prospectus is English. Certain legislative references and technical terms have been cited in their original language in order that the correct technical meaning may be ascribed to them under applicable law.

44 c108210pu020 Proof 9: 29.4.13_14:31 B/L Revision: 0 Operator PutA OVERVIEW OF THE OFFERING

The following is an overview of the terms of the Notes. This overview is derived from, and should be read in conjunction with, the full text of the Terms and Conditions of the Notes, the Guarantees and the Trust Deed constituting the Notes, which prevail to the extent of any inconsistency with the terms set out in this overview. Capitalised terms used herein and not otherwise defined have the respective meanings given to such terms in the Terms and Conditions of the Notes. Notes being offered USD 500,000,000 7.000% Guaranteed Notes due 2020. Issuer Alliance Oil Company Ltd. Guarantors Alliance Oil, NK Alliance, Alliance-Bunker, Alliancetransoil, Amurnefteproduct, Khabarovsknefteproduct, Khvoinoye, Kolvinskoe, Pechoraneft, Potential Oil, Primornefteproduct, SN-Gasproduction and VTK. The Issuer is not permitted to remove a Guarantor or Guarantors unless the remaining Guarantors in the aggregate constitute at least 75% of both the Group’s consolidated total net assets and revenues (calculated in accordance with IFRS). The Issuer is required to ensure that on each ‘‘Relevant Date’’ (being 10 days after the publication of the semi-annual and annual financial statements) either the total net assets (the ‘‘net asset test’’) or revenues (the ‘‘revenues test’’) of the Guarantors (calculated in accordance with IFRS) comprise 75% or more of the consolidated total net assets or revenues of the Group (calculated in accordance with IFRS). The Issuer is not required to ensure that both the net asset test and the revenue test are satisfied on any such date. Joint Lead Managers Deutsche Bank AG, London Branch, Goldman Sachs International, GPB-Financial Services Ltd and Raiffeisen Bank International AG. Co-Managers Carnegie Investment Bank AB (publ), OTKRITIE Bank JSC and UniCredit Bank AG. Closing Date 3 May 2013. Issue price 99.32%. Maturity date 4 May 2020. Interest The Notes will bear interest at the rate of 7.000% per annum from and including 3 May 2013. Interest payment dates Interest on the Notes will be payable semi annually in arrears on 4 May and 4 November of each year, commencing on 3 May 2013 with first long coupon. Ranking of the Notes The Notes will constitute direct, unconditional and unsecured obligations of the Issuer. The payment obligations of the Issuer under the Notes shall, save for such exceptions as may be provided by applicable legislation, at all times rank equally with each other and will rank equally with all its other present and future unsecured and unsubordinated obligations. Ranking of the Guarantees The Guarantees will constitute direct, unconditional and unsecured obligations of the Guarantors. The payment obligations of the Guarantors under the Guarantees shall, save for such exceptions as may be provided by applicable legislation, at all times rank equally with each other and will rank equally with each Guarantor’s other present and future unsecured and unsubordinated obligations. Use of proceeds After deduction of commissions and expenses (including total expenses related to the listing and admission to trading of the Notes), which are expected to be approximately USD 9,600,000, the Group anticipates the net proceeds from the issue of the Notes to be approximately USD 490,400,000. The Group intends to use the

45 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA net proceeds from the issue of the Notes for the repayment and/or the refinancing of existing indebtedness and for the Group’s general corporate purposes. Further issues The Issuer may from time to time, without the consent of the holders of the Notes, create and issue further notes or bonds either ranking pari passu in all respects (or in all respects save for the first payment of interest thereon) so that the same shall be consolidated and form a single series with the outstanding notes or bonds of any series (including the Notes) constituted by the Trust Deed or upon such terms as the Issuer may determine at the time of their issue. See ‘‘Terms and Conditions of the Notes – Further Issues’’. Additional amounts In the event that withholding taxes are required to be withheld or deducted from payments on any of the Notes, the Issuer will, subject to certain exceptions described in this Prospectus, pay such additional amounts as will result, after deduction or withholding of such taxes, in the payment of the amounts which would have been payable in respect of such Notes had no such withholding or deduction been required. See ‘‘Terms and Conditions of the Notes – Taxation’’. Optional redemption for tax The Notes may be redeemed at the option of the Issuer, in whole reasons but not in part, at any time at 100% of the principal amount thereof plus accrued interest on the date fixed for redemption if certain events occur that would require the Issuer to pay additional amounts, as described under ‘‘Terms and Conditions of the Notes – Redemption for Tax Reasons’’. Make-Whole call option The Issuer may, at its option, redeem the Notes, in whole but not in part, at any time, but one occasion only, on giving not less than 30 and not more than 60 days irrevocable notice, at a price equal to the principal amount thereof, plus the Make Whole Premium (as defined in the Terms and Conditions of the Notes) plus any accrued and unpaid interest and additional amounts (if any) to (but excluding) the date of redemption. See ‘‘Terms and Conditions of the Notes – Optional redemption’’. Form and denomination The Notes will be in registered form, without interest coupons attached, in denominations of USD 200,000 or multiples of USD 1,000 in excess thereof. The Notes will be issued in the form of a Regulation S Global Note and a Rule 144A Global Note, each in registered form without interest coupons. The Regulation S Global Note will be deposited with, and registered in the name of, a nominee for the common depository for Euroclear and Clearstream, Luxembourg. The Rule 144A Global Note will be deposited with a custodian for, and registered in the name of, Cede & Co., as nominee of DTC. Ownership interests in the Global Regulation S Global Note and the Rule 144A Global Note will be shown on, and transfer thereof will be effected only through, records maintained by DTC, Euroclear, Clearstream, Luxembourg and their respective participants. Notes in definitive form will be issued only in limited circumstances. Listing and Trading Application has been made to the Irish Stock Exchange for the Notes to be admitted to the Official List and to trading on the Main Securities Market. The Main Securities Market is a regulated market for the purposes of Directive 2004/39/EC of the European Parliament and of the Council on markets in financial instruments. Events of Default and certain The terms and conditions of the Notes contain events of default covenants and covenants (including a cross default provision and a negative

46 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA pledge) as described further in ‘‘Terms and Conditions of the Notes – Events of Default’’ and ‘‘Terms and Conditions of the Notes – Covenants’’. Trustee BNY Mellon Corporate Trustee Services Limited is the trustee under the Trust Deed to be dated on or about the Closing Date. Principal Paying Agent and The Bank of New York Mellon, London Branch. Transfer Agent Registrar The Bank of New York Mellon (Luxembourg) S.A., Vertigo Building – Polaris 2-4 rue Eugene Ruppert L-2453 Luxembourg. Governing law The Notes, the Guarantees and the Trust Deed will be governed by, and construed in accordance with, English law. Risk factors Prospective purchasers of the Notes should consider carefully all of the information set forth in this Prospectus and, in particular, the information set forth under ‘‘Risk Factors’’ before making an investment in the Notes. Selling restrictions The Notes are subject to selling restrictions in the United States, the Russian Federation, Bermuda, the United Kingdom, the Republic of Kazakhstan and otherwise only in compliance with applicable law in any relevant jurisdiction. See ‘‘Subscription and Sale’’. Security Codes Regulation S ISIN: XS0925043100 Regulation S Common Code: 092504310 Rule 144A ISIN: US018760AB41 Rule 144A Common Code: 092517772 Rule 144A CUSIP: 018760AB4 Expected Rating of the Notes ‘B(EXP)’/‘RR4’ by Fitch and ‘B+’/‘RR4’ by S&P. A rating is not a recommendation to buy, sell or hold securities and may be subject to revision, suspension or withdrawal at any time by the assigning rating organisation.

47 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA USE OF PROCEEDS

After deduction of commissions and expenses (including total expenses related to the listing and admission to trading of the Notes), which are expected to be approximately USD 9,600,000, the Group anticipates the net proceeds from the issue of the Notes to be approximately USD 490,400,000. The Group intends to use the net proceeds from the issue of the Notes for the repayment and/or the refinancing of existing indebtedness and for the Group’s general corporate purposes.

48 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA CAPITALISATION

The following table sets forth the Group’s consolidated capitalisation as of 31 December 2012. The consolidated capitalisation has been derived from the 2012 Financial Statements included elsewhere in this Prospectus For further information regarding the Group’s financial condition, see ‘‘Summary Consolidated Financial Information’’, ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ and the Financial Statements.

As of 31 December 2012

USD thousand Current debt Bank loans ...... 135,000 Interest payable ...... 41,342 Current portion of long-term debt ...... 225,264

Total current debt and current portion of long-term debt ...... 401,606

Non-current debt Bank loans ...... 637,607 Bonds...... 1,256,671 Less current portion of long-term debt ...... (225,264)

Total non-current debt...... 1,669,014

Equity attributable to the owners of the Company Share capital ...... 176,528 Additional paid-in capital...... 1,296,210 Translation reserve on intercompany loans...... (129,496) Translation reserve on foreign operations...... (217,145) Option premium on convertible bonds...... 22,271 Retained earnings ...... 1,638,943 Equity attributable to the owners of the Company ...... 2,787,311

Non-controlling interests...... 245,699

Total equity...... 3,033,010

Total capitalisation...... 5,103,630

There have been no material changes in the capitalisation of the Group since 31 December 2012.

49 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA SUMMARY CONSOLIDATED FINANCIAL INFORMATION

The tables below set forth the Group’s historical financial information as of and for the years ended 31 December 2012, 2011 and 2010. With the exception of the section entitled ‘‘Non-IFRS Financial Data’’, this information has been extracted without material adjustment from the Financial Statements. This summary consolidated financial information should be read in conjunction with ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ and the Financial Statements.

Year ended 31 December

2012 2011 2010

(USD thousand) CONSOLIDATED STATEMENT OF PROFIT OR LOSS Revenue Revenue from sales of crude oil ...... 602,354 531,656 397,943 Revenue from sales of oil products ...... 2,787,761 2,496,218 1,756,295 Revenue from other sales ...... 55,124 54,786 41,518

3,445,239 3,082,660 2,195,756

Cost of sales Production costs of crude oil...... (365,881) (353,047) (269,162) Production costs of oil products ...... (1,898,780) (1,635,262) (1,168,068) Cost of other sales ...... (24,315) (23,911) (21,824) Depletion and depreciation of oil and gas and refining assets.... (173,890) (156,170) (117,625) Reversal of impairment of oil and gas assets, net...... 58,721 — 1,051

Gross profit ...... 1,041,094 914,270 620,128

Selling expenses...... (314,587) (286,571) (223,730) Administrative expenses...... (95,740) (77,457) (67,890) Depreciation and amortisation of marketing and other assets ... (18,484) (18,025) (14,610) Other operating expenses, net...... (19,485) (18,220) (6,691) Share of profits of associates and joint venture ...... 2,309 2,153 104 (Loss)/gain on disposal of shares in subsidiaries...... — (2,894) 9

Operating income ...... 595,107 513,256 307,320 Interest income ...... 14,977 12,259 7,901 Finance costs ...... (95,034) (59,134) (29,473) Gain/(loss) on derivatives classified as held for trading, net...... 7,678 (15,444) — Currency exchange gain/(loss), net ...... 21,688 (18,176) 3,923

Profit before tax...... 544,416 432,761 289,671 Income tax expense...... (123,646) (104,471) (63,339)

Profit for the year ...... 420,770 328,290 226,332

Attributable to: Owners of the Company...... 402,833 318,873 222,221 Non-controlling interests ...... 17,937 9,417 4,111

50 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA As of 31 December

2012 2011 2010

(USD thousand) CONSOLIDATED STATEMENT OF FINANCIAL POSITION ASSETS Non-current assets Property, plant and equipment...... 4,474,599 3,223,798 2,528,244 Intangible assets...... 871 1,917 3,840 Goodwill ...... 20,394 19,239 11,728 Investments in associates and joint venture ...... 187,191 21,826 150 Deferred tax assets...... 28,531 26,439 25,319 Other financial assets...... — 167 10,188 Other assets...... 2,991 29,878 38,115

4,714,577 3,323,264 2,617,584

Current assets Inventories ...... 227,991 145,029 141,316 Trade and other accounts receivable...... 116,368 113,605 117,135 Value added tax and other taxes receivable ...... 296,236 224,552 135,766 Income tax receivable ...... 13,811 11,814 9,876 Advances paid and prepaid expenses ...... 161,262 125,907 98,003 Other financial assets...... 49,821 93,263 49,629 Restricted cash...... 26,887 27,318 79,322 Cash and cash equivalents...... 384,933 160,483 98,777

1,277,309 901,971 729,824

Total assets ...... 5,991,886 4,225,235 3,347,408

51 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA As of 31 December

2012 2011 2010

(USD thousand) EQUITY AND LIABILITIES Capital and reserves Share capital ...... 176,528 171,528 171,528 Additional paid-in capital...... 1,296,210 1,104,355 1,103,845 Translation reserve on intercompany loans...... (129,496) (170,348) (128,706) Translation reserve on foreign operations...... (217,145) (332,302) (234,665) Option premium on convertible bonds...... 22,271 22,271 22,271 Retained earnings ...... 1,638,943 1,159,946 839,716

Equity attributable to owners of the Company ...... 2,787,311 1,955,450 1,773,989 Non-controlling interests ...... 245,699 37,983 31,307

Total equity...... 3,033,010 1,993,433 1,805,296

Non-current liabilities Loans and borrowings...... 1,669,014 1,514,263 912,471 Deferred tax liabilities ...... 265,002 187,998 178,031 Provision for decommissioning and site restoration costs ...... 73,195 15,440 15,960 Advances received...... 26,309 — — Retirement benefit obligation ...... 8,728 2,669 — Derivatives classified as held for trading...... — 11,114 —

2,042,248 1,731,484 1,106,462

Current liabilities Loans and borrowings...... 401,606 106,829 127,134 Trade and other accounts payable ...... 129,864 144,184 95,797 Advances received and accrued expenses ...... 296,065 170,466 152,484 Income tax payable...... 10,199 5,524 1,607 Other taxes payable ...... 72,913 68,408 58,628 Derivatives classified as held for trading...... 5,981 4,907 —

916,628 500,318 435,650

Total liabilities ...... 2,958,876 2,231,802 1,542,112

Total equity and liabilities ...... 5,991,886 4,225,235 3,347,408

52 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA CONSOLIDATED CASH FLOWS DATA Year ended 31 December

2012 2011 2010

(USD thousand) Operating activities Profit before tax...... 544,416 432,761 289,671 Adjustments for: Depreciation, depletion and amortisation ...... 192,374 174,195 132,235 Reversal of impairment of oil and gas assets ...... (58,721) — (1,051) Interest income ...... (14,977) (12,259) (7,901) Finance costs ...... 95,034 59,134 29,473 (Gain)/loss on derivatives classified as held for trading, net...... (7,678) 15,444 — Currency exchange (gain)/loss, net ...... (21,688) 18,176 (3,923) Share of profits of associates and joint venture ...... (2,309) (2,153) (104) Loss/(gain) on disposal of shares in subsidiaries...... — 2,894 (9) Loss on disposal of assets...... 5,948 3,196 204 Impairment of trade and other accounts receivable...... 8,323 753 348 Other non-cash items...... 20,777 2,518 4,385

Operating cash flows before changes in working capital...... 761,499 694,659 443,328 Movements in working capital Increase in inventories ...... (72,905) (13,832) (26,052) Increase in accounts receivable, advances paid and prepaid expenses ...... (56,235) (144,624) (170,934) Increase in accounts payable, advances received and accrued expenses ...... 115,482 40,078 21,357

Cash generated from operations ...... 747,841 576,281 267,699

Interest paid...... (82,136) (42,106) (18,934) Income tax paid...... (95,829) (71,675) (45,010)

Total cash generated from operating activities ...... 569,876 462,500 203,755 Investing activities Investments in oil and gas assets...... (359,843) (603,744) (351,905) Investments in refining assets ...... (328,267) (314,912) (223,505) Investments in marketing and other assets...... (40,719) (28,194) (29,234) Interest capitalised and paid...... (77,751) (78,268) (45,991) Acquisition of controlling interest in subsidiaries, net of cash acquired...... (155,758) (15,636) — Proceeds from disposal of assets ...... 2,963 1,683 1,704 Interest received ...... 8,984 5,582 6,711 Payments on settlement of swap contract, net of interest received...... (2,130) 188 — Loans provided ...... (56,417) (56,588) (29,372) Loans repaid ...... 57,903 19,169 16,912 Investments in promissory notes ...... (15,621) — — Proceeds from sale of promissory notes ...... 7,209 — — Short-term deposits placed ...... (30,320) (30,015) (29,859) Proceeds from deposits withdrawn...... 27,030 30,076 — Advances for acquisition of shares...... — — (20,000)

Total cash used in investing activities ...... (962,737) (1,070,659) (704,539) Financing activities Proceeds from loans and borrowings ...... 758,151 1,111,272 825,837 Repayment of loans and borrowings...... (466,696) (478,913) (519,668) Proceeds from issue of preference shares ...... 201,527 — — Proceeds from contribution of shares to a joint venture ...... 116,728 — — Acquisition of non-controlling interest in subsidiaries...... (1,551) (1,267) (4,716) Dividends paid by subsidiaries ...... — (397) (8) Other financing activities ...... — — 89

Total cash generated from financing activities ...... 608,159 630,695 301,534

Effect of exchange rate changes on cash balances held in foreign currencies (7,166) 4,148 (4,970) Translation difference ...... 15,887 (16,982) (9,751)

Change in cash, cash equivalents and restricted cash...... 224,019 9,702 (213,971)

Cash, cash equivalents and restricted cash at beginning of the year ...... 187,801 178,099 392,070

Cash, cash equivalents and restricted cash at end of the year...... 411,820 187,801 178,099

53 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA NON-IFRS FINANCIAL DATA

Year ended 31 December (Unaudited)

2012 2011 2010

(USD thousand) Adjusted EBITDA(1)...... 734,096 690,345 438,391

(1) Adjusted EBITDA is defined as profit before tax plus currency exchange (gain)/loss, net, (gain)/loss on derivatives classified as held for trading, net, finance costs, interest income, loss/(gain) on disposal of shares in subsidiaries, depreciation, depletion and amortisation, reversal of impairment of oil and gas assets, net, and other one-off items in the consolidated statement of profit or loss. The table below presents a reconciliation of the Group’s profit before tax to Adjusted EBITDA for each of the years ended 31 December 2012, 2011 and 2010.

Year ended 31 December

2012 2011 2010

(USD thousand) Profit before tax...... 544,416 432,761 289,671 Currency exchange (gain)/loss, net ...... (21,688) 18,176 (3,923) (Gain)/loss on derivatives classified as held for trading, net...... (7,678) 15,444 — Finance costs ...... 95,034 59,134 29,473 Interest income ...... (14,977) (12,259) (7,901) Loss/(gain) on disposal of shares in subsidiaries...... — 2,894 (9) Depreciation, depletion and amortisation ...... 192,374 174,195 132,235 Reversal of impairment of oil and gas assets, net...... (58,721) — (1,051) Other1 ...... 5,336 — (104)

Adjusted EBITDA...... 734,096 690,345 438,391

(1) For the year ended 31 December 2012, ‘‘Other’’ includes impairment of interest receivable in the amount of USD 5,336 thousand. For the year ended 31 December 2010, ‘‘Other’’ is comprised of a number of immaterial adjustments.

Year ended 31 December

2012 2011 2010

Adjusted EBITDA of reportable segments ...... 794,986 729,812 474,157 Adjusted EBITDA of other companies...... (46,403) (23,116) (28,892) Inter-segment eliminations...... (537) (230) — Effect of reconciling items ...... (13,950) (16,121) (6,874)

Adjusted EBITDA...... 734,096 690,345 438,391

54 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with ‘‘Summary Consolidated Financial Information’’ and the Financial Statements included in this Prospectus. This review includes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those anticipated in the forward-looking statements as a result of numerous factors, including the risks discussed in ‘‘Risk Factors’’ appearing elsewhere in this Prospectus.

Overview The Group is an independent and vertically integrated oil and gas company with both upstream and downstream operations in Russia and upstream operations in Kazakhstan. The Group’s upstream operations include crude oil exploration, extraction and production in the Timano-Pechora, Volga- Urals and Tomsk regions of Russia and the Atyrau region of Kazakhstan, as well as upstream gas operations in the Tomsk region; its downstream operations include oil refining as well as transportation, marketing and sale of refined petroleum products primarily in the Russian Far East. As of 31 December 2012, 2011 and 2010, the Group’s proven and probable crude oil and gas reserves under the PRMS classification were 732.6 mmboe, 647.9 mmboe and 638.3 mmboe, respectively, and the Group’s proven crude oil and gas reserves under the PRMS classification were 330.8 mmboe, 309.6 mmboe and 286.4 mmboe, respectively. In addition, the Group holds an equity interest in the non-consolidated oil and gas reserves of AROG proportional to the Group’s ownership stake in the joint venture. For the years ended 31 December 2012, 2011 and 2010, the Group’s total crude oil production was 19.7 mmbbl, 17.9 mmbbl and 16.0 mmbbl, respectively. The Group has a diversified portfolio of assets and is currently developing 18 fields in Russia and one field in Kazakhstan as well as participating in AROG, a joint venture with Repsol, with the aim of increasing production in Russia. The Group is engaged in crude oil refining and marketing of refined products focused in the Russian Far East and conducts its refining operations at the Khabarovsk Refinery, which as of 31 December 2012 had a refining capacity of 90,000 bopd. For the years ended 31 December 2012, 2011 and 2010, the Khabarovsk Refinery processed 29.3 mmbbl, 26.9 mmbbl and 23.7 mmbbl, respectively and the Group sold 29.9 mmbbl, 27.6 mmbbl and 24.4 mmbbl of petroleum products during those periods, respectively. The Group markets refined petroleum products through its own network of 267 refuelling stations and 21 wholesale petroleum products terminals in the Khabarovsk, Primorsk, Amur, Jewish Autonomous District and Republic of Buryatia regions in Russia and also exports its petroleum products on market terms through Lia Oil, an affiliate, to neighbouring Asian markets. For the years ended 31 December 2012, 2011 and 2010, the Group’s revenue was USD 3,445,239 thousand, USD 3,082,660 thousand and USD 2,195,756 thousand, respectively. Revenue from crude oil sales was USD 602,354 thousand, USD 531,656 thousand and USD 397,943 thousand for the years ended 31 December 2012, 2011 and 2010, respectively, while revenue from oil product sales was USD 2,787,761 thousand, USD 2,496,218 thousand and USD 1,756,295 thousand for the years ended 31 December 2012, 2011 and 2010, respectively. For the years ended 31 December 2012, 2011 and 2010, the Group’s Adjusted EBITDA was USD 734,096 thousand, USD 690,345 thousand and USD 438,391 thousand, respectively.

Changes in Group Structure and Holdings from 1 January 2010 to 31 December 2012 Set forth below is a description of significant changes in the Group’s structure and holdings from 1 January 2010 to 31 December 2012.

Acquisition of CJSC Gavanbunker In February 2011, the Group acquired 100% of the shares in CJSC Gavanbunker, a sea terminal in the Sovetskaya Gavan port located in the Khabarovsk region of Russia, for total consideration transferred of USD 17,284 thousand, including advance payment of USD 1,500 thousand made in 2010.

Acquisition of Stake in Lia Oil In May 2011, the Group completed the acquisition of 40% of the share capital of Lia Oil from a related party for cash consideration of USD 20,000 thousand. The Group exports petroleum products on market terms through Lia Oil to neighbouring Asian markets. From the date of acquisition, Lia

55 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Oil was treated as an associate of the Group and accounted for using the equity method. Prior to the date of acquisition, transactions with Lia Oil were treated as transactions with a related party. See ‘‘Related Party Transactions’’.

AROG In 2011, the Group established AROG with the intention to convert it into a joint venture with Repsol. At the point of establishment, AROG was wholly owned by the Group, and had no assets, liabilities or operations. In August 2012, the Group contributed 100% of the shares of Saneco to AROG, and Repsol acquired 49% of the shares in AROG from the Group for USD 35,660 thousand cash paid directly to the Group and USD 37,302 thousand in cash contributed to AROG. As a result of these transactions, the Group’s ownership interest in AROG decreased to 51%. In December 2012, the Group contributed 99.54% of its shares in Tatnefteotdacha to AROG, and AROG issued shares to the Group in exchange. The Group then sold these shares to Repsol for USD 224,591 thousand, of which USD 81,068 thousand was paid in cash by Repsol directly to the Group, and the remaining USD 143,523 thousand was met by contributing Repsol’s subsidiary Eurotek to AROG. The subsidiary contribution was recorded as a receivable within investment in joint venture as at 31 December 2012, as the contribution of Eurotek did not legally occur until January 2013. The Group continues to consolidate Saneco and Tatnefteotdacha as the Group holds a fair value option that is deemed in the money. Repsol has the same fair value option over Eurotek. As such, AROG does not control any of the contributed subsidiaries, but does have significant influence. To avoid double-counting, the Group does not equity account for the impact of Saneco and Tatnefteotdacha on AROG’s results, and only equity accounts for the remaining portion of AROG. Thus, the Group’s investment in AROG was accounted for under the equity method, as a 51% share in the joint venture’s net assets, excluding the investment in Saneco and Tatnefteotdacha. The Group recorded its share in the joint venture’s net loss from 16 August to 31 December 2012 of USD 89 thousand in its consolidated statement of profit or loss. Following the contribution of Saneco and Tatnefteotdacha to AROG and transfer of 49% interest to Repsol, the total balance of non-controlling interests in respect of these subsidiaries increased and was recognised in the consolidated financial statements in the amount of USD 183,572 thousand, with any difference between the cash received, increase in non-controlling interests, and the Group’s share in the net assets of AROG being recognised in equity. The net cash inflow in respect of the AROG investment was USD 116,728 thousand: USD 35,660 thousand cash contribution for Saneco and USD 81,068 thousand cash contribution for Tatnefteotdacha. The carrying value of investment in AROG, excluding Saneco and Tatnefteotdacha, as of 31 December 2012 was as follows:

31 December 2012

(USD thousand), except for % Net assets...... 37,284 Voting power held by the Group ...... 51% Group’s share of net assets...... 19,014 Eurotek contribution outstanding ...... 143,523

Carrying value of investment ...... 162,537

The Group’s share in AROG’s net loss from 16 August to 31 December 2012 of USD 89 thousand was recognised in profit or loss. Following the contribution of Saneco and Tatnefteotdacha, a non-controlling interest representing 49% of Saneco’s net assets and 48.78% of Tatnefteotdacha’s net assets was recognised in the consolidated financial statements in the amount of USD 183,572 thousand.

56 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Acquisition of Limited Liability Company SN-Gasproduction In October 2012, the Group acquired 100% of the shares in Polonio Holdings Limited, the ultimate owner of LLC SN-Gasproduction, an upstream segment company holding two gas licences in the Tomsk region of the Russian Federation, for cash consideration of USD 127,768 thousand. See ‘‘Business – Upstream Operations – Gas Operations’’.

Acquisition of CAP Agro S.A. In August 2012, the Group acquired a 100% interest in CAP Agro S.A., the ultimate owner of LLC GeoInvestService, for cash consideration of USD 30,026 thousand. See ‘‘Business – Upstream Operations – Timano-Pechora Region’’.

Key Factors Affecting Operating Results The following factors are key factors that have significantly affected the Group’s results of operations and financial condition during the period under review, and the comparability thereof, or which the Group expects will significantly affect (or continue to affect) its operations in the future.

Price of Crude Oil and Petroleum Products The prices for crude oil and petroleum products in the international and Russian markets are the primary factors affecting the Group’s results of operations. Crude oil prices have historically been highly volatile and fluctuate depending on, among other things, the global balance of supply and demand, OPEC production levels, the global economic environment and various speculative factors. This volatility affects the Group’s operations by influencing revenues and taxes, which in Russia are partly set based on market prices. See ‘‘Risk Factors – Risks Relating to the Group and the Oil and Gas Industry – Global economic developments and Russian market conditions may adversely affect the Group’s business, financial condition and results of operations’’, ‘‘Risk Factors – Risks Relating to the Group and the Oil and Gas Industry – A substantial or extended decline in crude oil, refined products or petrochemical products prices would have a material adverse effect on the Group’s business, financial condition and results of operations’’ and ‘‘– Taxation’’. The price of petroleum products on international and domestic markets is mainly determined by international oil prices, supply and demand of petroleum products and competition within various product markets, though price dynamics differ for various types of petroleum products. There is no significant active commodity exchange market for Russian domestic crude oil and, as a result, prices in the Russian domestic crude oil market are negotiated on a contract-by-contract basis. The following table sets forth average annual international crude oil and oil product prices for the years ended 31 December 2012, 2011 and 2010.

Year ended 31 December % Change

Units 2012 2011 2010 2012/11 2011/10

International market Brent ...... USD/bbl 111.67 111.26 79.50 0.4% 40.0% Urals (Med/NWE) ...... USD/bbl 110.43 109.10 78.28 1.2% 39.4% Premium petro (Med/NWE) ... USD/tonne 1,035.87 983.88 735.26 5.3% 33.8% Naphtha (Med/NWE) ...... USD/tonne 926.84 920.81 704.68 0.7% 30.7% Diesel fuel (Med/NWE) ...... USD/tonne 980.17 958.97 689.65 2.2% 39.1% Gas oil 0.2% (Med/NWE)...... USD/tonne 953.79 931.87 672.65 2.4% 38.5% Fuel oil 3.5% (Med/NWE)...... USD/tonne 623.48 602.55 436.17 3.5% 38.1%

Sources: Platts

Although the price of crude oil has steadily risen since 2010, prices have been volatile throughout the period under review. According to Platts, for the year ended 31 December 2012, the average Brent oil price increased 0.4%, to USD 111.67 per barrel, compared to an average Brent oil price of USD 111.26 per barrel in the year ended 31 December 2011. In 2011, the average Brent oil price increased by 40.0%, to USD 111.26 per barrel, compared to an average Brent oil price in 2010. In 2010 and 2009, the average Brent oil price was USD 79.50 and 61.67 per barrel, respectively, reflecting increases following the gradual recovery from the global economic crisis.

57 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA In 2012, the average price of diesel fuel in the international market was USD 980.17 per tonne, a 2.2% increase from the 2011 average price. In 2011, the average price of diesel fuel in the international market was USD 958.97 per tonne, a 39.1% increase from 2010 prices. In 2012, the average price of fuel oil in the international market was USD 623.48 per tonne, a 3.5% increase from the 2011 average price. In 2011, the average fuel oil price in the international market was USD 602.55 per tonne, an 38.1% increase from the average fuel oil price of USD 436.17 per tonne in 2010.

Taxation The Group is subject to numerous taxes at the federal, regional and local levels, some of which are based on revenue or volumetric measures, which have had and are expected to continue to have a significant impact on the Group’s results of operations. Export duties payable on the sale of crude oil and refined petroleum products to markets outside of Russia (excluding Belarus and Kazakhstan) and MET on crude oil and natural gas represent the most significant direct duties and taxes to which the Group is subject. The following table sets forth the average export customs duty for various products and the MET for crude oil and natural gas payable by the Group for the years ended 31 December 2012, 2011 and 2010.

Year ended 31 December % Change

Units 2012 2011 2010 2012/11 2011/10

Export Customs Duty Crude oil ...... USD/tonne 404.26 408.92 273.61 (1.1%) 49.5% Light petroleum products(1) .... USD/tonne 266.78 274.08 196.66 (2.7%) 39.4% High octane petrol and naphtha(2) ...... USD/tonne 363.82 388.56 — (6.4%) — Heavy petroleum products(3) .. USD/tonne 266.78 208.21 105.94 28.1% 96.5% MET Crude oil ...... RUB/tonne 5,066 4,455 3,074 13.7% 44.9%

(1) Light petroleum products in this category include diesel and jet fuel. (2) Before May and June 2011, high octane petrol and naphtha, respectively, were taxed as light petroleum products. See ‘‘– Export Duty on Petroleum Products’’. (3) Heavy petroleum products in this category include fuel oil.

Export crude oil and petroleum product duties have been modified several times by the Russian Government in the periods under review, and the Group expects that they may be further amended in the future. See ‘‘ – Export Duty on Crude Oil’’, ‘‘– Export Duty on Petroleum Products’’, and ‘‘Risk Factors – Risks Relating to the Group and the Oil and Gas Industry – Recent amendments to Russian customs and tax law have shifted the tax dynamics and affected the profitability of the Group’s upstream and downstream operations, and further Russian tax amendments may negatively affect the Group’s profitability’’. The 60-66 Amendments, effective as of October 2011, reduced the marginal export duty rate on crude oil from 65% to 60% and unified export duties for light and dark petroleum products at 66% of the export duty on crude oil by increasing the export duty on fuel oil from 46.7% of the export duty on crude and decreasing export duty on light distillates such as diesel and jet fuel from 67% of the export duty on crude oil. High-octane petrol and naphtha export duty remained unchanged at 90% of the export duty of crude oil. The Russian Federation receives significant revenues from taxation of the Russian oil industry. Further changes to the Russian export duty regime could occur in an effort by the Russian Government to improve the profitability of upstream operations while incentivising Russian oil companies to invest in upgrading their refineries in order to encourage increased export of light distillates or for other reasons. MET is levied on extracted crude oil, gas condensate, natural gas and a number of other mineral resources. Similar to export duties, MET rates have been revised several times by the Russian Government during the period under review and MET on crude oil has risen significantly since 2009. In addition to export duties and MET, significant excise tax is levied on petroleum products produced by refineries in Russia. In Russia, excise taxes on petroleum products are established by the Russian

58 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Government and only apply to domestic sales and, because they are paid by the customer, represent an on the Group’s operations. An increase in excise tax rates generally exerts downward pressure on the domestic demand and profit margin of petroleum products. Social taxes, property, income and other taxes also affect the Group’s results of operations. Export Duty on Crude Oil Export duty rates per tonne of crude oil are established on a monthly basis by the government of the Russian Federation. The rate is based on the average Urals crude oil price for the period from the 15th calendar day in the month to the 14th calendar day of the following month referred to as the ‘‘monitoring period’’ (the ‘‘duty reference price’’). The rate is effective from the first calendar day of the month following the monitoring period. During the period under review, through October 2011, customs duty rates were set according to the following formula:

Export customs duty rate per Urals price, USD bbl Urals price1, USD tonne tonne – calculation formula

Greater than 25 Greater than 182.50 USD 29.20 + 65.0% x (Urals price – USD 182.50)

(1) ‘‘Urals price’’ means the Urals (Med/NWE) crude oil average price.

The mechanism for setting the export duty rates results in a difference between the duty reference price and the actual Urals price for a given period, referred to as the ‘‘duty lag effect’’. In periods when prices are rising, this normally results in a benefit to the Group as export duties are levied on a price per barrel which is lower than the actual market price per barrel as of that time or a positive duty lag effect. Conversely, falling prices normally result in a negative duty lag effect. Crude oil sold for export to Kazakhstan and Belarus is not subject to export duties. Effective October 2011, the 60-66 Amendments reduced the then-prevailing 65% export customs duty rate to 60%. See ‘‘– Export Duty on Petroleum Products’’. Export Duty on Petroleum Products The Russian Government determines the export duty rate on petroleum products, based on the prices for crude on international markets. Petroleum products exported to Belarus, Kazakhstan and Kyrgyzstan are not subject to export duty. Before 1 February 2011, Russian export duty rate for light and medium distillates was calculated according to the formula: 0.438 6 (price 6 7.3 – 109.5), where the price is the average monthly Urals price at Rotterdam and Mediterranean exchanges (dollar/barrel). Export duty rate for dark petroleum products was calculated according to the formula: 0.236 6 (price 6 7.3 – 109.5). Beginning 1 February 2011, Russian customs duty rates on petroleum products were calculated according to the formula: R=K6Roil, where Roil = export customs duty rate per tonne of oil and K = a design factor with respect to certain categories of petroleum products defined in the following table:

2011 2012 2013

Light and medium distillates ...... 0.67 0.64 0.60 Dark petroleum products ...... 0.467 0.529 0.60

In May 2011, a protective duty for petrol exports amounting to 90% of the crude oil export duty was introduced to stabilise the Russian domestic market. An equivalent 90% duty was introduced for naphtha exports in June 2011.

59 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA As of 1 October 2011, as a result of the 60-66 Amendments, the coefficient K was further amended according to the following table. From 1 Oct. From 2011 to 31 1 Jan. Dec. 2014 2015

Petrol and naphtha ...... 0.90 0.90 Other light and medium distillates ...... 0.66 0.66 Dark petroleum products ...... 0.66 1.00

Mineral Extraction Tax MET is levied on extracted crude oil, gas condensate, natural gas and a number of other mineral resources. For extracted crude oil, the taxable base for MET is determined as the quantity of extracted oil in physical terms and is assessed at a specified base rate expressed in RUB metric tonne. The tax rate is multiplied by a coefficient reflecting movements in world prices for Urals oil. This coefficient is determined monthly by the taxpayer according to a complex formula. Legislation provides for differentiated rates of mineral extraction tax. In particular, the basic rate of mineral extraction tax is multiplied by a coefficient calculated on the basis of changes in the average world oil price and by a coefficient reflecting the level of depletion of a deposit. Base MET rates for extracted crude oil for the period under review were as follows: 2011 2012 2013

Crude oil (RUB/tonne)...... 419 446 470

The Group has received a on production at the Kolvinskoye and North Kharyaga oil fields under which it will pay no MET on the first 15 million tonnes (approximately 110 million barrels) produced through 2015 at each field. The Group commenced natural gas production in February 2013 through its participation in AROG and its acquisition of SN-Gasproduction. The base MET rate for natural gas was unchanged from January 2006 to December 2011 at RUB 147 per million cubic metres of natural gas. Associated gas is not subject to MET. The following base MET rates applicable to the Group were established for natural gas from 1 July 2013 through 2015: 1 July 2013 2014 2015

Natural gas, RUB/1,000m3...... 402 471 552

Excise Tax Prior to 1 January 2011, excise taxes on petroleum products were set based on the type of oil product and on its octane level. In accordance with Russian Federal Law No. 306 of 27 November 2010, the following domestic petroleum products excise rates were established from 1 January 2011.

Year ended 31 December

2012 2012 2013 2013 2011 (Jan.-June) (Jul.-Dec.) (Jan. – June) (July- Dec.) 2014 2015

(RUB/tonne) Petrol Below Euro 3 5,995 7,725 8,225 10,100 10,100 11,110 13,332 Euro 3...... 5,672 7,382 7,882 9,750 9,750 10,725 12,879 Euro 4...... 5,143 6,822 6,822 8,560 8,960 9,416 10,358 Euro 5...... 5,143 6,822 5,143 5,143 5,750 5,750 6,223 Naphtha...... 6,089 7,824 7,824 10,229 10,229 11,252 13,502 Diesel fuel Below Euro 3 2,753 4,098 4,300 5,860 5,860 6,446 7,735 Euro 3...... 2,485 3,814 4,300 5,860 5,860 6,446 7,735 Euro 4...... 2,247 3,562 3,562 4,934 5,100 5,427 5,970 Euro 5...... 2,247 3,562 2,962 4,334 4,500 4,767 5,244 Motor oil ...... 4,681 6,072 6,072 7,509 7,509 8,260 9,086

60 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Rouble/U.S. Dollar Exchange Rate and Inflation The following table sets forth rates of inflation and foreign exchange movements for the periods indicated.

2012 2011 2010

Inflation and RUB/USD exchange rate Russian inflation rate...... 6.6% 6.1% 8.8% Producer price index (‘‘PPI’’)...... 5.0% 12.0% 16.7% RUB/USD exchange rate at period beginning ...... 32.20 30.35 30.19 RUB/USD exchange rate at period end...... 30.37 32.20 30.48 Nominal appreciation/(depreciation) of Rouble...... (5.5%) 3.4% 4.3% Real Rouble appreciation/(depreciation)...... (2.7%) 8.8% 9.7%

Sources: CBR and Rosstat (Russian inflation rate and PPI)

Over the past decade, the Rouble has at times fluctuated dramatically against the U.S. dollar. For the years ended 31 December 2012, 2011 and 2010, the Group’s reporting currency was the U.S. dollar, as the Group believes it is a more convenient presentation currency for international investors and is a common presentation currency in the oil and gas industry. Amounts presented in the Financial Statements of each of the Group’s entities are measured using the currency of the primary economic environment in which the entity operates: for entities in Russia, the Russian Rouble; for entities in Kazakhstan, the Kazakh Tenge and for entities in Cyprus and Bermuda, the U.S. dollar. Fluctuations in the Rouble-U.S. dollar exchange rate affect the Group’s results of operations as 71% of the Group’s revenues from sales of crude oil and 42% of the Group’s revenues from sales of petroleum products are denominated in U.S. dollars, while a substantial portion of its expenses are denominated in Roubles. Accordingly, any appreciation of the Rouble versus the U.S. dollar negatively affects the Group’s gross and operating margins. In addition, during the period under review, fluctuations in the Rouble-U.S. dollar exchange rate impacted the Group’s financial condition and working capital, in particular with respect to Rouble- denominated debt and deposits and foreign exchange gains/losses from the period-end revaluation of the Rouble-denominated monetary working capital. See ‘‘– Results of Operations for the Years Ended 31 December 2012, 2011 and 2010 – Currency exchange gain/(loss), net’’. In addition, the Russian economy has been characterised by high rates of inflation. According to Rosstat, inflation in Russia in 2012, 2011 and 2010 was 6.6%, 6.1% and 8.8%, respectively, as measured by the consumer price index and was 5.0%, 12.0% and 16.7%, respectively, as measured by the producer price index. The relatively high rate of inflation in Russia increases the Group’s Rouble- denominated costs, such as tariff payments, salary costs and utility costs, and reduces the value of its Rouble-denominated cash assets, such as Rouble deposits, domestic debt instruments and accounts receivable. High Rouble inflation may also negatively impact the domestic demand for the Group’s products.

Transportation Costs of Crude Oil and Petroleum Products The Group transports most of its crude oil through third-party pipelines and by railway transportation. The Group relies primarily on its subsidiary Alliancetransoil for its railway transit requirements. The Group uses the Transneft pipeline network for transporting the crude oil produced by Tatnefteotdacha, Saneco and Pechoraneft to customers within and outside of Russia and by VTK to the Khabarovsk Refinery. Potential Oil uses a combination of the Transneft pipeline, the KazTransOil pipeline, rail transport and motor transport for transportation of crude to export markets and to the domestic market of Kazakhstan. Saneco uses rail transport for delivery of crude to CIS and some deliveries to the domestic market. The Group’s oil fields located in Tatarstan, the Middle Kharyaga oil field in the Timano-Pechora region and oil fields in Kazakhstan are not directly connected to the Transneft network. The crude oil produced by the Group in Tatarstan is delivered to the Transneft pipelines via Tatneft’s pipeline network, while Potential Oil does so through the Sazankurak and KazTransOil pipeline networks and Pechoraneft transports crude oil to the Transneft pipeline via a LUKOIL-owned pipeline. Prices for the Group’s principal means of transportation for its crude oil and petroleum products, the pipeline network owned by Transneft and Transnefteproduct and the railway system of Russian

61 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Railways are determined by the Russian Government rather than the market. In particular, the Ministry of Energy of the Russian Federation allocates sea terminal capacity to oil producers for export deliveries on a quarterly basis, and the FTS of the Russian Federation sets tariffs for use on a ‘‘cost plus’’ basis. Pipeline transportation tariffs have risen substantially during the period under review. To reduce its pipeline-related transportation costs, the Group has sought to use shorter pipeline transportation routes for its deliveries. Similarly, railway tariffs are set by the FTS on an annual or semi-annual basis and are indexed to account for certain factors, such as inflation. Railway tariffs have also increased substantially during the period under review, and generally, transportation of the Group’s production by rail is more expensive than by pipeline. The Group’s transportation costs, the majority of which are denominated in Roubles, are also affected by USD/RUB fluctuations when translated into U.S. dollars in its consolidated financial statements. The Khabarovsk Refinery is not connected to the Transneft or Transnefteproduct pipeline systems. As a result, crude oil and petroleum products must be transported to and from Khabarovsk by other means, primarily by rail. Although the Group’s exact tariff rates for use of the ESPO oil pipeline have not been established, based on rates currently paid by other ESPO oil pipeline users, it is expected that after the Khabarovsk Refinery is connected to the ESPO oil pipeline, currently planned for 2014, the Group will significantly reduce its transportation costs as the ESPO oil pipline replaces rail transport currently used. See ‘‘Business – Transportation and Logistics – Pipelines’’. The Group delivers its jet fuel to the Khabarovsk airport through a pipeline connecting the Khabarovsk Refinery with the Khabarovsk airport. This pipeline has historically been used on the basis of a contract on maintenance of state property which provides no limitation on output. No fixed period of use is established in the contract. The issue of reformulating the contract as a lease agreement is being discussed with the Khabarovsk Regional Department of the Federal Agency for Federal Property Management of the Russian Federation. The following table sets forth the Group’s average historical costs per barrel of crude oil for both pipeline and railroad transportation for the years ended 31 December 2012, 2011 and 2010.

Year ended 31 December % Change

2012 2011 2010 2012/11 2011/10

USD/Barrel Transportation of crude oil to the Khabarovsk Refinery Pipeline transportation ...... 3.9 4.4 3.6 (11.4%) 22.2% Railroad transportation...... 14.0 14.6 13.0 (4.1%) 12.3% Transportation of crude oil to external customers Pipeline transportation ...... 4.9 4.7 4.1 4.3% 14.6% Railroad transportation (domestic market) ...... 6.2 5.0 3.6 24.0% 38.9%

Transportation costs vary according to the nature of the sale and location of the customer. Despite increasing tariffs rates, the Group’s transportation costs of crude oil to the Khabarovsk Refinery decreased in 2012 primarily as a result of using shorter transportation routes as well as Rouble depreciation against the U.S. dollar.

62 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Reserves For the years ended 31 December 2012, 2011 and 2010, the audit of the Group’s reserves has been conducted by D&M according to the PRMS classification. The following table sets forth the Group’s proven reserves and proven and probable hydrocarbon reserves under the PRMS classification as of 31 December 2012, 2011 and 2010 in its main production areas.

Hydrocarbon Reserves (mmboe)

Year ended 31 December

2012 2011 2010

Proven and Proven and Proven and Location Proven Probable Proven Probable Proven Probable

Atyrau, Kazakhstan .. 3.9 8.1 5.9 10.8 10.1 15.9 Timano-Pechora ...... 139.0 394.9 166.9 409.0 155.3 394.8 Tomsk...... 71.9 166.8 28.8 57.4 14.9 56.1 Volga-Urals ...... 116.0 162.8 108.0 170.7 106.1 171.5

Total ...... 330.8 732.6 309.6 647.9 286.4 638.3

The Group’s total proven and probable (‘‘2P’’) hydrocarbon reserves increased 13.1%, from 647.9 mmboe for the ended 31 December 2011 to 732.6 mmboe for the year ended 31 December 2012. The increase was largely attributable to the Group’s acquisition of SN-Gasproduction in October 2012, the 2P gas reserves of which were estimated by D&M at 111 mmboe as of 31 December 2012. The Group’s total 2P hydrocarbon reserves under the PRMS classification increased 1.5%, from 638.3 mmboe for the ended 31 December 2010 to 647.9 mmboe for the year ended 31 December 2011. The slight increase was due to the Group’s exploration and development projects as well as a revision in its estimated reserves. The Group’s possible hydrocarbon reserves were 473 mmboe, 349 mmboe and 341 mmboe for the years ended 31 December 2012, 2011 and 2010; for the year 31 December 2012 the Group’s fields in Timano-Pechora, Volga-Urals, Tomsk and Kazakhstan had 310 mmboe, 9 mmboe, 153 mmboe and 1 mmboe possible reserves, respectively. In addition to the Group’s consolidated reserves which are audited by D&M, the Group has an equity interest in the non-consolidated oil and gas reserves of AROG proportional to the Group’s ownership stake in the joint venture.

Production and Sale of Crude Oil As of 31 December 2012, the Group had 111 active wells in the Tomsk region, 78 of which were active production wells, and 33 active injection wells. Specifically, the Group had 114 wells in the Timano-Pechora region, 91 of which were active production wells, and 23 active injection wells; 351 active wells in the Volga-Urals region, 336 of which were active production wells, and 15 active injection wells; 56 active wells in Kazakhstan, 52 of which were active production wells, and four active injection wells. The following table sets forth oil production data of the Group by oil production region for the years ended 31 December 2012, 2011 and 2010.

Year ended 31 December

2012 2011 2010

(Thousand barrels) Location Timano-Pechora ...... 8,354 7,178 4,964 Volga-Urals...... 7,408 7,120 7,391 Tomsk...... 3,214 2,940 3,023 Atyrau, Kazakhstan...... 763 642 582

Total...... 19,739 17,879 15,960

63 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Crude oil Total crude oil production for the Group was 19,739 mmbbl in 2012, representing a 10.4% increase from 2011 levels. The 2012 crude oil production levels primarily increases in production from all the Group’s production regions, though most substantially in the Timano-Pechora region, where production increased 16.4%. In 2011, the Group produced 17,879 mmbbl of crude oil, a 12.0% increase from 2010 levels of 15,960 mmbbl. The increase in 2011 was primarily attributable to production growth in the Timano-Pechora region, in which production increased 44.6% in 2011, primarily due to the launch of production at the Kolvinskoye oil field. The following table sets forth the Group’s crude oil sales volumes and prices for export and domestic markets for the years ended 31 December 2012, 2011 and 2010, excluding intra-group crude oil sales.

Year ended 31 December

2012 2011 2010

Export CIS Domestic Total Export CIS Domestic Total Export CIS Domestic Total

Sold volume, thousand barrels(1) ...... 7,172 266 3,501 10,938 6,172 321 3,334 9,827 4,988 1,160 3,977 10,124 Gross price, USD/ barrel...... 107.61 51.41 61.53 91.49 107.40 60.12 59.16 89.49 76.40 78.92 40.92 67.99 Net price(2), USD/ barrel...... 56.63 51.41 52.14 55.07 55.93 60.12 50.13 54.10 42.46 41.50 34.71 39.31 Selling expenses, USD/ barrel...... 6.85 11.39 5.20 6.43 6.74 14.22 3.40 5.85 5.74 5.83 3.51 4.87 Netback price(3), USD/ barrel...... 49.78 40.02 46.94 48.64 49.19 45.90 46.73 48.25 36.72 35.67 31.20 34.44 Revenue, USD thousands...... 406,132 13,658 182,564 602,354 345,192 19,320 167,144 531,656 211,786 48,140 138,017 397,943

(1) The Group delivered to the Khabarovsk Refinery 5.7 mmbbl, 7.7 mmbbl and 8.3 mmbbl of crude oil for the years ended 31 December 2012, 2011 and 2010. (2) Net price means gross price less VAT or applicable export duties. (3) Netback prices are calculated by deducting from the gross price: VAT (for Russian domestic sales); railway and pipeline transportation costs and export duties, brokers’ commissions and certain other costs (for export sales); or transportation, brokers’ commissions and certain other costs (for CIS countries export).

Due to higher crude oil prices in the international market, the Group’s netbacks generated from export sales are consistently higher than those from domestic and CIS sales, although the differences are significantly less than those between the gross crude oil prices among the three markets due to the export duty levied on crude oil exports. Nevertheless, because export sales generate the highest netbacks, the Group attempts to maximise these sales, with CIS and domestic sales typically representing surplus amounts. As a result, crude oil volumes sold in the CIS and domestic markets can fluctuate significantly from year to year, both in absolute terms and as a percentage of total volumes sold. Netbacks for export and domestic sales remained relatively stable for the years ended 31 December 2012 and 2011, having risen significantly following 2010 as a result of an increase in crude oil prices. Selling expenses increased for domestic sales in the year ended 31 December 2012 to USD 5.20 per barrel compared to USD 3.40 per barrel in the year ended 31 December 2011 primarily due to an increase in the pipeline tariffs charged by Transneft. Selling expenses to the CIS are higher than those for other markets because the Group typically must transport these volumes by rail or truck, as use of Transneft’s pipelines are unavailable for these sales. Since 2011, sales to the CIS have been undertaken only by the Group’s subsidiary Saneco.

64 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Production of Petroleum Products The following table sets forth the Group’s oil product sales volumes, average net prices received, revenues and per barrel refining margins for the years ended 31 December 2012, 2011 and 2010.

Year ended 31 December

2012 2011 2010

Export Wholesale Retail Total Export Wholesale Retail Total Export Wholesale Retail Total

Sold volume, thousand barrels .... 15,551 9,211 5,154 29,916 12,443 10,562 4,644 27,648 9,139 11,477 3,744 24,360 Net price(1), USD/ barrel ...... 74.61 104.32 129.32 93.19 70.00 99.16 124.45 90.28 54.72 74.01 108.66 72.10 Revenue, USD thousand ...... 1,160,255 960,975 666,531 2,787,761 870,950 1,047,334 577,934 2,496,218 500,124 849,393 406,778 1,756,295

(1) Net price means the gross price less VAT or applicable export duties.

Sales volumes of petroleum products increased 8.2% in 2012, to 29,916 million barrels, compared to 27,648 million barrels in 2011. The increase was primarily driven by market demand growth. Sales volumes of petroleum products increased 13.5%, to 27,648 million barrels in 2011, compared to 24,360 million barrels in 2010, primarily as a result of increased demand both domestically and internationally, mainly due to improved macroeconomic conditions following the economic crisis of 2009 and 2010.

Recent Developments The following developments have occurred between 31 December 2012, the end of the last financial period for which financial information has been published, and the date of this Prospectus.

Current Trading In the first three months of 2013, the Group’s total hydrocarbon production was 5.2 mmboe, with an average daily hydrocarbon production rate of 57,359 boepd, and 7.8 mmbbl of crude oil was refined at the Khabarovsk Refinery during the period. For the first three months of 2013, 16 new wells were drilled by the Group, and the average oil production in the Timano-Pechora, Volga-Urals and Tomsk regions was 19,693 bopd, 20,363 bopd and 10,211 bopd, respectively. In Kazahkstan, average oil production for the first three months of 2013 was 2,434 bopd. Gas production in the Tomsk region was 3,248 boepd for the first three months of 2013. In the Khanty-Mansiysk region, non-consolidated gas production from equity interests for the first three months of 2013 amounted to 2,765 boepd, of which 1,410 boepd were from equity interests. In the downstream segment, the Group’s refinery capacity utilisation was increased due to strong demand for oil products domestically and in the bunker market. In addition, the production of Euro- 5 gasoline commenced at the Khabarovsk Refinery in the first three months of 2013. In furtherance of its strategic objective to increase its upstream asset base, the Group is currently evaluating the potential acquisition of a company in which an affiliate of one of the Joint Lead Managers owns a small minority interest. If consummated, this potential acquisition would not be expected to have a material effect on the Group’s results of operations.

AROG In January 2013, Repsol contributed its subsidiary, Eurotek, which holds two gas exploration and production licences, and also paid USD 116,728 thousand in cash to the Group. In March 2013, AROG began commercial gas production from the Syskonsyninskoye field in the Khanty-Mansiysk region of Russia, with initial daily gas production of 855,000 cubic metres (5,350 boe) per day.

Segment Information For management purposes, the Group is organised into separate reporting segments based on the nature of the Group’s operations. There are two business segments: the upstream segment, which includes crude oil and gas exploration, extraction and production, and the downstream segment, which includes oil refining, transportation and sales of oil products. The Group reviews and evaluates the performance of these segments on a regular basis. Operations of the parent company and

65 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA subsidiaries involved in non-core activities are disclosed as ‘‘Other companies’’, none of which meet the criteria for separate reporting. Upstream and downstream segment revenue includes revenue from sales of crude oil and petroleum products, respectively, and income from other non-core activities. Prices used in transactions between reportable segments are determined on an arm’s length basis in a manner equal to transactions with third parties, except for interest-free loans provided and obtained. See ‘‘Note 8 to the 2012 and 2011 Financial Statements’’.

Key Non-IFRS Financial and Operating Ratios The Group monitors and evaluates its activities on an ongoing basis. Key financial and operating ratios on which the Group relies are given below for the years ended 31 December 2012, 2011 and 2010. Year ended 31 December

2012 2011 2010

Financial ratios Adjusted EBITDA(1) (USD thousands) ...... 734,096 690,345 438,391 Debt/equity ratio(2) ...... 68% 81% 58% Interest coverage ratio(3) ...... 3.29 3.49 3.19 Debt coverage ratio(4) ...... 3.96 4.59 4.43 Debt to Adjusted EBITDA(5) ...... 2.82 2.35 2.37 Operational ratios Crude oil Sales volume (consolidated), barrels...... 10,938,263 9,826,948 10,124,297 Oil revenue (net sales price) per barrel sold, USD/barrel(6) ...... 55.07 54.10 39.31 export ...... 56.63 55.93 42.46 export CIS...... 51.41 60.12 41.50 domestic ...... 52.14 50.13 34.71 Production costs per barrel sold, USD/barrel(7)...... 26.68 27.84 23.38 production costs...... 6.51 6.96 5.49 production and other taxes...... 12.47 13.22 11.51 cost of purchased oil...... — 0.01 0.01 depletion and depreciation...... 7.70 7.65 6.37 Petroleum products Sales volume (consolidated), barrels...... 29,916,349 27,648,368 24,359,715 Petroleum products revenue per barrel sold, USD/barrel(6)...... 93.19 90.28 72.10 export ...... 74.61 70.00 54.72 wholesale (domestic) ...... 104.32 99.16 74.01 retail (domestic) ...... 129.32 124.45 108.66 Production costs per barrel sold, USD/barrel(7)...... 76.46 71.30 55.87 cost of refining ...... 2.34 2.47 1.92 transportation-crude oil for refining ...... 17.74 18.70 16.31 cost of crude oil purchased for refining...... 42.62 40.14 29.35 cost of petroleum products purchased for re-sale ...... 8.18 4.80 4.85 taxes ...... 4.73 4.38 2.76 depreciation of refining assets...... 0.85 0.81 0.68

Financial ratio definitions (1) Adjusted earnings before interest, tax, depreciation and amortisation (Adjusted EBITDA) is defined as the Group’s is defined as profit before tax plus currency exchange (gain)/loss, net, (gain)/loss on derivatives classified as held for trading, net, finance costs, interest income, loss/(gain) on disposal of shares in subsidiaries, depreciation, depletion and amortisation, reversal of impairment of oil and gas assets, net, and other significant one-off items in the consolidated statement of profit or loss. For the calculation of the Group’s Adjusted EBITDA for the years ended 31 December 2012, 2011 and 2010 and the reconciliation of Adjusted EBITDA for each such year to profit before tax for the corresponding year, see ‘‘Summary Consolidated Financial Information’’. (2) Debt/equity ratio is defined as loans and borrowings, as shown in the consolidated statement of financial position, in relation to the total equity. See ‘‘Note 39 to the 2012 Financial Statements, and Note 38 to the 2011 Financial Statements’’. (3) Interest coverage ratio is defined as the Group’s operating income plus interest income, divided by finance costs (both capitalised and expensed in the statement of profit or loss). (4) Debt coverage ratio is defined as the Group’s Adjusted EBITDA, divided by interest expenses (both capitalised and expensed in the statement of profit and loss). (5) Debt to Adjusted EBITDA is defined as total loans and borrowings of USD 2,070,620 as of 31 December 2012, USD 1,621,092 as of 31 December 2011 and USD 1,039,605 as of 31 December 2012, divided by Adjusted EBITDA. Operational ratio definitions

66 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Crude Oil (6) Oil revenue per barrel ratios are defined as net sales price (gross price less VAT or export duties) per barrel of oil sold to external customers. (7) Production costs per barrel ratios are based on volumes of crude oil sold both intergroup and to external customers excluding crude oil purchased for re-sale. Petroleum products (6) Petroleum products revenue per barrel ratios are defined as net sales price (gross price less VAT or export duties) per barrel of petroleum products sold to external customers. (7) Production costs per barrel ratios are defined as operating cost component (including purchases of crude oil and other services from intergroup companies) divided by volumes of petroleum products sold both intergroup and to external customers.

Results of Operations for the Years Ended 31 December 2012, 2011 and 2010 Financial Overview The following table sets forth the components of the Group’s net profit for the periods indicated, as reported under IFRS. Year ended 31 December

2012 2011 2010

(USD thousand) Consolidated statement of profit or loss Revenue Revenue from sales of crude oil ...... 602,354 531,656 397,943 Revenue from sales of oil products ...... 2,787,761 2,496,218 1,756,295 Revenue from other sales ...... 55,124 54,786 41,518

3,445,239 3,082,660 2,195,756

Cost of sales Production costs of crude oil...... (365,881) (353,047) (269,162) Production costs of oil products ...... (1,898,780) (1,635,262) (1,168,068) Cost of other sales ...... (24,315) (23,911) (21,824) Depletion and depreciation of oil and gas and refining assets.... (173,890) (156,170) (117,625) Reversal of impairment of oil and gas assets...... 58,721 — 1,051

Gross profit ...... 1,041,094 914,270 620,128

Selling expenses...... (314,587) (286,571) (223,730) Administrative expenses...... (95,740) (77,457) (67,890) Depreciation and amortisation of marketing and other assets ... (18,484) (18,025) (14,610) Other operating expenses, net...... (19,485) (18,220) (6,691) Share of profits of associates and joint venture ...... 2,309 2,153 104 (Loss)/gain on disposal of shares in subsidiaries...... — (2,894) 9

Operating income ...... 595,107 513,256 307,320

Interest income ...... 14,977 12,259 7,901 Finance costs ...... (95,034) (59,134) (29,473) Gain/(loss) on derivatives classified as held for trading, net...... 7,678 (15,444) — Currency exchange gain/(loss), net ...... 21,688 (18,176) 3,923

Profit before tax...... 544,416 432,761 289,671 Income tax expense...... (123,646) (104,471) (63,339)

Profit for the year ...... 420,770 328,290 226,332

Attributable to: Owners of the Company...... 402,833 318,873 222,221 Non-controlling interests ...... 17,937 9,417 4,111

Revenue from Sale of Crude Oil Revenue from sales of crude oil increased 13.3%, to USD 602,354 thousand for the year ended 31 December 2012, compared to USD 531,656 thousand for the year ended 31 December 2011, while average netback prices increased 0.8% from USD 48.3 per barrel in 2011 to USD 48.7 in 2012. The

67 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA increase in total revenue from sales of crude oil was primarily driven by increases in export and domestic revenue from sales, which rose 17.7% and 9.2% in 2012, respectively, somewhat offset by a decrease in CIS sales of 29.3%. The increases in export and domestic sales were both primarily driven by higher production volumes. Export and domestic sales volumes increased 16.2% and 5.0%, respectively, in 2012 due to increased demand met by higher sales volumes from the Kolvinskoye oil field after the increase of production at that field in September 2011. Average gross prices per barrel obtained for the Group’s export and domestic crude oil sales remained stable in 2012 compared with 2011, in line with trends in international crude oil prices. Average gross prices per barrel obtained for the Group’s CIS sales decreased 14.5% in 2012 due to the fact that the majority of CIS shipments occurred in June and July, months when the prices were below the yearly average. The Group adjusts the volume of its CIS sales on an opportunistic basis depending on the terms available from its customers compared to the export and domestic market. As a result, CIS sales tend to fluctuate more from period to period than sales to the export and domestic market. Revenue from sales of crude oil increased 33.6%, to USD 531,656 thousand for the year ended 31 December 2011, compared to USD 397,943 thousand for the year ended 31 December 2010, while average netback prices increased 40.1% from USD 34.4 in 2010 to USD 48.3 in 2011.The increase in total crude sales revenues was primarily driven by a 63.0% and 21.1% increase in export and domestic sales, respectively, partially offset by a decrease in CIS sales of 59.9%. The increases in export sales were driven by both higher prices for crude oil and production volumes, while domestic sales were driven by higher prices obtained, despite lower volumes of sale. A recovery in crude oil prices helped drive the increases in revenues in 2011, as average gross prices per barrel obtained for the Group’s export and domestic crude oil sales increased 40.6% and 44.5%, respectively, in 2011 compared with 2010, in line with trends in international crude oil prices during the economic recovery following the financial crisis of 2009 and 2010. Average gross prices per barrel obtained for the Group’s CIS sales decreased 23.8% in 2011, due to the cancellation of export duty on sales to Belarus. Export sales volumes increased 23.7%, respectively, in 2011, primarily due to increased sales volumes from the Kolvinskoye oil field. Domestic and CIS sales volumes decreased 16.2% and 72.3%, respectively, in 2011, due to increased intragroup sales, which re-directed a portion of the Group’s production away from domestic and CIS markets.

Revenue from Sales of Oil Products Revenue from sales of oil products increased 11.7%, to USD 2,787,761 thousand for the year ended 31 December 2012, compared to USD 2,496,218 thousand for the year ended 31 December 2011, primarily due to higher volumes of fuel and bunker oil sold externally to export markets as well as higher net prices obtained for petroleum products in all markets. Export and retail domestic revenue from sales of oil products increased 33.2% and 15.4%, respectively, for the year ended 31 December 2012, while domestic wholesale sales decreased 8.2%. The significant increase in export sales was partially due to higher volumes of export bunkering activity in 2012. Revenue from sales of oil products increased 42.1%, to USD 2,496,218 thousand for the year ended 31 December 2011, compared to USD 1,756,295 thousand for the year ended 31 December 2010, primarily due to higher net prices and volumes related to improving macroeconomic conditions in 2011. Export, domestic wholesale and retail revenue from salse of oil products increased 74.2% 23.3% and 42.0%, respectively. Export sales increased due to higher volumes of fuel and bunker oil sold externally to export markets (volumes increased 36.1%) and higher net prices. Wholesales increased mainly due to higher net prices across all products as sales volumes decreased insignificantly.

Revenue from Other Sales Revenue from other sales consists primarily of sales of services and goods at fuel stations and transportation services. For the year ended 31 December 2012, revenue from other sales increased 0.6%, to USD 55,124 thousand for the year ended 31 December 2012, compared to USD 54,786 thousand for the year ended 31 December 2011. This increase was largely due to an increase in sales of transport, transhipment and storage services. For the year ended 31 December 2011, revenue from other sales increased 32.0%, to USD 54,786 thousand, compared to USD 41,518 thousand for the year ended 31 December 2010, primarily due to an increase in sales of transport, transhipment and storage services.

Production Costs of Crude Oil Production costs of crude oil increased 3.6%, to USD 365,881 thousand for the year ended 31 December 2012, compared to USD 353,047 thousand for the year ended 31 December 2011.

68 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Expressed on a per barrel basis, production costs of crude oil decreased from USD 27.9 for the year ended 31 December 2011 to USD 26.7 for the year ended 31 December 2012, a 4.3% decrease. The decrease in production costs of crude oil per barrel in 2012 was primarily due to the decreased cost of transportation from the Kolvinskoye oil field upon completion of the pipeline to the Kharyaga terminal in September 2012. Before that time, during winter months, while the oil field was in production, extracted crude oil had to be transported by winter roads. At the same time, production tax increased 0.6% year-on-year, reflecting the fact that the increased share of extracted crude oil attributable to the Kolvinskoye oil field is not currently subject to MET, as it holds an MET exemption on the first 15 million tonnes (approximately 110 million barrels) produced through 2015. Production costs of crude oil increased 31.2%, to USD 353,047 thousand for the year ended 31 December 2011, compared to USD 269,162 thousand for the year ended 31 December 2010, and from 23.4 per barrel to USD 27.8 per barrel, a 19.3% increase. The increase in production costs of crude oil year-on-year was primarily due to higher production-related taxes (which are linked to oil prices) due to an increase in average Ural crude oil prices, from USD 78.1 per barrel for the year ended 31 December 2010 to USD 109.5 per barrel for the year ended 31 December 2011, as well as the launch of production at the Kolvinskoye oil field, where production costs were initially high due to the necessity of transporting crude by road from the field.

Production Costs of Petroleum Products

Year ended 31 December % Change

2012 2011 2010 2012/11 2011/10

(USD thousand) Crude oil purchased for refining ..... 913,325 799,661 548,199 14.2% 45.9% Transportation...... 528,725 513,426 397,394 3.0% 29.2% Oil products purchased for re-sale .. 244,818 132,877 108,028 84.2% 23.0% Taxes other than income tax...... 141,560 121,054 67,494 16.9% 79.4% Payroll and related taxes ...... 32,485 30,881 20,952 5.2% 47.4% Other...... 37,867 37,363 26,001 1.3% 43.7%

Total production costs of oil products 1,898,780 1,635,262 1,168,068 16.1% 40.0%

Production costs of petroleum products increased 16.1%, to USD 1,898,780 thousand for the year ended 31 December 2012, compared to USD 1,635,262 thousand for the year ended 31 December 2011, primarily due to an increase in costs of crude oil purchased for refining, which rose 14.2% due to increased volumes purchased by the Group and higher international crude oil prices in 2012. In addition, petroleum products purchased for re-sale increased 84.2%, to USD 244,818 thousand in the year ended 31 December 2012, compared to USD 132,877 thousand for the year ended 31 December 2011, primarily as a result of the suspension of diesel production at the Khabarovsk Refinery until the end of the modernisation works at the facility, which are expected to conclude in 2013. Transportation costs also increased 3.0% year-on-year, primarily reflecting an increase in pipeline and railway tariffs. Production costs of petroleum products increased 40.0%, to USD 1,635,262 thousand for the year ended 31 December 2011, compared to USD 1,168,068 thousand for the year ended 31 December 2010, primarily due to increased crude oil prices paid by the Group and volumes of petroleum products sold. In addition, transportation costs rose 29.2%, to USD 513,426 thousand for the year ended 31 December 2011, compared to USD 397,394 thousand for the year ended 31 December 2010, primarily due to higher sales volumes and railroad tariffs paid to Russian Railways and pipeline transportation tariffs. The increase in transportation costs was also affected by the appreciation of the Rouble against the U.S. dollar in 2011, as most of the Group’s transportation costs are denominated in Roubles, leading to higher USD translations when expressed in the Group’s consolidated financial statements.

Cost of Other Sales Costs of other sales, which mainly include costs relating to transportation and storage services and the cost of goods sold by retail fuel stations increased 1.7%, to USD 24,315 thousand for the year ended 31 December 2012, compared to USD 23,911 thousand for the year ended 31 December 2011.

69 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Costs of other sales increased 9.6%, to USD 23,911 thousand for the year ended 31 December 2011, compared to USD 21,824 thousand for the year ended 31 December 2010. In both periods, the increase was primarily due to increased sales volumes at retail fuel stations and increased transportation and storage tariffs paid by the Group.

Depletion and Depreciation of Oil and Gas and Refining Assets Depletion and depreciation of oil and gas and refining assets increased 11.3%, to USD 173,890 thousand for the year ended 31 December 2012, compared to USD 156,170 thousand for the year ended 31 December 2011. The increase in depletion charge for the year ended 31 December 2012 resulted from higher production volumes at the Kolvinskoye oil field. Depletion and depreciation of oil and gas and refining assets increased 32.8%, to USD 156,170 thousand for the year ended 31 December 2011, compared to USD 117,625 thousand for the year ended 31 December 2010. The increase in the depletion charge resulted from the launch of production at the Kolvinskoye oil field in 2011 and revised estimates of future development costs relating to the field as of 31 December 2011.

Reversal of Impairment of Oil and Gas Assets For the year ended 31 December 2012, as a result of an impairment test performed relating to the Group’s upstream segment assets, a previously recognised impairment loss in the amount of USD 58,721 thousand was reversed. The reversal related to the Group’s Middle Nyurola, Klyuchevskoe and Puglalymskoye oil fields and reflected the fact that conditions that gave rise to impairment loss in prior years had improved. In performing the impairment test, the Group considered the significant increase in oil price projections and the relative stability of the Group’s reserves for two consecutive years. For the year ended 31 December 2010, the Group recorded a reversal of impairment of oil and gas assets, net of USD 1,051 thousand. The Group reversed an impairment loss of USD 3,336 thousand related to the Kolvinskoye oil field in the Timano-Pechora region, which was initially recorded in 2008. The Group’s judgment was primarily based on a significant increase in the proved and probable reserves at the Kolvinskoye oil field, as reported by D&M according to the PRMS classification. Following unsuccessful exploration works performed at the Ivanikhinskoye licence area located in the Volga-Urals region, the Group wrote off the value of capitalised exploration costs in the amount of USD 2,285 thousand.

Gross Profit As a result of the factors above, the Group’s gross profit increased 13.9%, to USD 1,041,094 thousand for the year ended 31 December 2012, compared to USD 914,270 thousand for the year ended 31 December 2011 and 47.4%, to USD 914,270 thousand for the year ended 31 December 2011, compared to USD 620,128 thousand for the year ended 31 December 2010.

70 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Selling Expenses

Year ended 31 December % Change

2012 2011 2010 2012/11 2011/10

(USD thousand) Transportation...... 201,907 182,249 135,164 10.8% 34.8% Payroll and related taxes ...... 59,145 55,820 46,503 6.0% 20.0% Repairs and maintenance ...... 15,778 13,960 12,731 13.0% 9.7% Energy and utilities...... 7,548 7,005 5,558 7.8% 26.0% Taxes other than income tax...... 7,024 7,726 6,799 (9.1%) 13.6% Export related expenses...... 3,162 3,240 3,437 (2.4%) (5.7%) Insurance ...... 3,148 3,791 3,254 (17.0%) 16.5% Advertising and marketing ...... 2,642 1,744 1,616 51.5% 7.9% Rent ...... 2,299 2,039 1,927 12.8% 5.8% Other...... 11,934 8,997 6,741 32.6% 33.5%

Total selling expenses...... 314,587 286,571 223,730 9.8% 28.1%

Selling expenses increased 9.8%, to USD 314,587 thousand for the year ended 31 December 2012, compared to USD 286,571 thousand for the year ended 31 December 2011, primarily due to increased volume of sales both in upstream and downstream segments. Transportation-related selling expenses increased 10.8% for the year ended 31 December 2012, to USD 201,907 thousand, compared to USD 182,249 thousand for the year ended 31 December 2011, primarily as a result of greater volumes of oil and petroleum products sold by the Group as well as an increase in tariffs paid.

Selling expenses increased 28.1% to USD 286,571 thousand for the year ended 31 December 2011, compared to USD 223,730 thousand for the year ended 31 December 2010, primarily due to increased volume of sales both in upstream and downstream segments. Transportation-related selling expenses increased 34.8% for the year ended 31 December 2011, to USD 182,249 thousand, compared to USD 135,164 thousand for the year ended 31 December 2010, primarily as a result of greater volumes of petroleum products sold by the Group and an increase in tariffs.

Administrative Expenses

Year ended 31 December % Change

2012 2011 2010 2012/11 2011/10

(USD thousand) Payroll and related taxes and share options...... 41,390 33,971 28,827 21.8% 17.8% Professional fees (legal, audit, consulting, etc.)...... 21,459 13,261 11,322 61.8% 17.1% Rent ...... 14,892 14,358 13,363 3.7% 7.4% Bank charges ...... 3,146 3,608 3,495 (12.8%) 3.2% Advertising and marketing ...... 3,057 2,771 3,758 10.3% (26.3%) Taxes other than income tax...... 2,773 2,269 2,210 22.2% 2.7% Other...... 9,023 7,219 4,915 25.0% 46.9%

Total administrative expenses...... 95,740 77,457 67,890 23.6% 14.1%

Administrative expenses increased 23.6%, to USD 95,740 thousand for the year ended 31 December 2012, compared to USD 77,457 thousand for the year ended 31 December 2011, primarily due to an increase in payroll and consulting and legal services related to the formation of AROG and the acquisition of SN-Gasproduction.

Administrative expenses increased 14.1%, to USD 77,457 thousand for the year ended 31 December 2011, compared to USD 67,890 thousand for the year ended 31 December 2010, primarily due to

71 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA annual increase in payroll by approximately 10% (partially reflecting increases in response to inflation) as well as an increase in annual bonuses paid to Group employees.

Depreciation and Amortisation of Marketing and Other Non-Production Assets Depreciation and amortisation of marketing and other non-production assets increased 2.5%, to USD 18,484 thousand for the year ended 31 December 2012, compared to USD 18,025 thousand for the year ended 31 December 2011, primarily due to additions to marketing and other assets of the Group as result of investing activities relating to the construction of filling stations and modernisation projects at the Group’s oil bases. Depreciation and amortisation of marketing and other non-production assets increased 23.4%, to USD 18,025 thousand for the year ended 31 December 2011, compared to USD 14,610 thousand for the year ended 31 December 2010, primarily due to increases in non-production assets following the purchase of Gavanbunker, a sea terminal in the Sovetskaya Gavan port located in the Khabarovsk region of Russia.

Other Operating Expenses, Net

Year ended 31 December % Change

2012 2011 2010 2012/11 2011/10

(USD thousand) Charity...... 9,986 12,736 6,539 (21.6%) 94.8% Loss on disposal of assets ...... 5,948 3,196 204 86.1% 1,466.7% Other...... 3,551 2,288 (52) 55.2% —

Total other operating expenses, net.. 19,485 18,220 6,691 6.9% 172.3%

Other operating expenses, net increased 6.9%, to USD 19,485 thousand for the year ended 31 December 2012, compared to USD 18,220 thousand for the year ended 31 December 2011, primarily due to an increase in loss of disposal of assets, related to the sale of aged oil and gas assets, which was partially offset by a decrease in contributions to the Bazhaev charity fund, which helps sponsor childrens groups and youth sports events. Other operating expenses increased 172.3%, to USD 18,220 thousand for the year ended 31 December 2011, compared to USD 6,691 thousand for the year ended 31 December 2010, primarily due to an increase in contributions to the Bazhaev charity fund.

Share of Profits of Associates and Joint Venture Share of profits of associates and joint venture increased 7.2%, to USD 2,309 thousand for the year ended 31 December 2012, compared to USD 2,153 thousand for the year ended 31 December 2011, primarily due to the purchase of Lia Oil in May 2011, with 2012 being the first full year reflecting the Group’s share of profits in the associate. Share of profits of associates increased to USD 2,153 thousand for the year ended 31 December 2011, compared to USD 104 thousand for the year ended 31 December 2010, primarily due to the acquisition of 40% shares in Lia Oil in May 2011.

(Loss)/Gain on Disposal of Shares in Subsidiaries The Group reported a loss on disposal of shares in subsidiaries of USD 2,894 thousand for the year ended 31 December 2011, compared to a gain on such disposal of USD 9 thousand for the year ended 31 December 2010. The loss on disposal of shares in subsidiaries in 2011 was mainly related to the disposal of the Group’s share in CJSC ‘‘Ecobioprom’’ and its subsidiaries, a group involved in operations with biofuels.

Operating Income As a result of the factors above, the Group’s operating income increased 15.9%, to USD 595,107 thousand for the year ended 31 December 2012, compared to USD 513,256 thousand for the year ended 31 December 2011 and 67.0%, to USD 513,256 thousand for the year ended 31 December 2011, compared to USD 307,320 thousand for the year ended 31 December 2010.

72 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Interest Income Interest income increased 22.2%, to USD 14,977 thousand for the year ended 31 December 2012, compared to USD 12,259 thousand for the year ended 31 December 2011, primarily due to an increase in income from cash deposits placed. Interest income increased 55.2% to USD 12,259 thousand for the year ended 31 December 2011, compared to USD 7,901 thousand for the year ended 31 December 2010, primarily due to interest income accrued on loans issued to the Polonio Group in November 2010 and March 2011.

Finance Costs

Year ended 31 December % Change

2012 2011 2010 2012/11 2011/10

(USD thousand) Interest expense on bonds ...... 117,883 105,809 58,740 11.4% 80.1% Interest expense on loans and borrowings...... 39,824 22,582 27,618 76.4% (18.2%) Total interest expense for financial liabilities not classified as at fair value through profit or loss...... 157,707 128,391 86,358 22.8% 48.7% Amortisation of debt issue costs and bank commissions ...... 24,524 18,937 10,786 29.5% 75.6% Unwinding of discount on provision for decommissioning and site restoration costs ...... 2,829 3,214 1,808 (12.0%) 77.8% Less: amounts included in the cost of qualifying assets ...... (90,026) (91,408) (69,479) (1.5%) 31.6%

Total finance costs...... 95,034 59,134 29,473 60.7% 100.6%

Finance costs increased 60.7%, to USD 95,034 thousand for the year ended 31 December 2012, compared to USD 59,134 thousand for the year ended 31 December 2011, primarily due an increase on interest expense on loans and borrowings other than bonds of 76.4% for the year ended 31 December 2012, which was largely due to interest payments on loans relating to the Kolvinskoye oil field, which were no longer capitalised after the field began production in September 2011. Finance costs increased 100.6% to USD 59,134 thousand for the year ended 31 December 2011, compared to USD 29,473 thousand for the year ended 31 December 2010, primarily due to interest expense on the Group’s issuance of Rouble denominated bonds in February and June 2011.

Gain/(loss) on Derivatives Classified as Held for Trading, Net For the year ended 31 December 2012, the Group reported a gain of USD 7,678 thousand on derivatives classified as held for trading net. This gain was related to the cross currency swap described below. For the year ended 31 December 2011, the Group reported a loss of USD 15,444 thousand on derivatives classified as held for trading net. In 2011, bonds with a notional amount of RUB 3,000 million were swapped to USD through a cross currency interest swap contract to balance cash inflows from export sales denominated in USD with cash outflows on interest payments denominated in RUB as well as to obtain a lower interest rate.

Currency exchange gain/(loss), net The Group’s currency exchange gains and losses mainly relate to loans and borrowings denominated in currencies other than functional currency of the Group’s subsidiaries, principally the U.S. Dollar and the Euro. The Group recorded a currency exchange gain of USD 21,688 thousand for the year ended 31 December 2012, compared to a currency exchange loss of USD 18,176 thousand for the year ended 31 December 2011, primarily as a result of a decrease in the RUB/USD exchange rate in 2012 by RUB 1.82 from RUB 32.20 to RUB 30.37.

73 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA The Group recorded a currency exchange loss of USD 18,176 thousand for the year ended 31 December 2011, compared to a currency exchange gain of USD 3,923 thousand for the year ended 31 December 2010, primarily as a result of an increase in the RUB/USD exchange rate in 2011 by RUB 1.72 from RUB 30.48 to RUB 32.20. In 2010, the RUB/USD exchange rate increased by RUB 0.23 from RUB 30.24 to RUB 30.48.

Profit Before Tax As a result of the factors above, the Group’s profit before tax increased 25.8%, to USD 544,416 thousand for the year ended 31 December 2012, compared to USD 432,761 thousand for the year ended 31 December 2011 and 49.4%, to USD 432,761 thousand for the year ended 31 December 2011, compared to USD 289,671 thousand for the year ended 31 December 2010.

Income Tax Expense The following table shows a breakdown of the Group’s income tax expense for the years ended 31 December 2012, 2011 and 2010. Year ended 31 December % Change

2012 2011 2010 2012/11 2011/10

(USD thousand) Current tax ...... 95,676 83,246 46,276 14.9% 79.9% Deferred tax...... 27,970 21,225 17,063 31.8% 24.4%

Total income tax expense...... 123,646 104,471 63,339 18.4% 64.9%

Income tax expense increased 18.4%, to USD 123,646 thousand for the year ended 31 December 2012, compared to USD 104,471 thousand for the year ended 31 December 2011, primarily due to an increase in profits of the Group’s upstream operations, mainly relating to Kolvinskoye and Pechoraneft. Income tax expense increased 64.9%, to USD 104,471 thousand for the year ended 31 December 2011, compared to USD 63,339 thousand for the year ended 31 December 2010, primarily due to an increase in profits of the Group’s upstream operations mainly realting to Kolvinskoye, Pechoraneft and Potential Oil. For the years ended 31 December 2012, 2011 and 2010, the Group’s effective tax rate was 23%, 24% and 22%, respectively. The Issuer, which is registered in Bermuda, is exempt from income tax. The statutory income tax rate in Russia, the location of the majority of the Group’s entities, is 20%. The Khabarovsk Refinery is subject to a 15.5% income tax rate due to a decreased regional budget component of its income tax. The profit of Potential Oil, a Kazakhstan subsidiary, is subject to a 30% income tax rate. The profit of Cypriot subsidiaries, Vostok Oil (Cyprus) Ltd. and O&G Credit Agency Ltd, is subject to income tax at the rate of 10%, and on taxable profits above EUR 1 million, an additional tax of 5% is imposed.

Profit for the Year As a result of the factors above, the Group’s profit for the year increased 28.2%, to USD 420,770 thousand for the year ended 31 December 2012, compared to USD 328,290 thousand for the year ended 31 December 2011 and 45.0%, to USD 328,290 thousand for the year ended 31 December 2011, compared to USD 226,332 thousand for the year ended 31 December 2010.

Adjusted EBITDA by segment Segment adjusted EBITDA is prepared on a basis that does not directly align with IFRS. For a reconciliation of Adjusted EBITDA by segment on a non-IFRS basis to Adjusted EBITDA on an IFRS basis for the years ended 31 December 2012, 2011 and 2010, see ‘‘Summary Consolidated Financial Information – Non-IFRS Data’’ and ‘‘Note 8 to the 2012 Financial Statements and 2011 Financial Statements’’. Adjusted EBITDA of the Group’s upstream segment increased 25.3% to USD 518,638 thousand for the year ended 31 December 2012, compared to USD 413,857 thousand for the year ended 31 December 2011. Adjusted EBITDA of the Group’s upstream segment increased 77.5% to USD 413,857 thousand for the year ended 31 December 2011, compared to USD 233,165 thousand for the

74 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA year ended 31 December 2010. In both periods, the increase in Adjusted EBITDA was primarily due to the launch of the Kolvinskoye oil field in September 2011, which resulted in a more significant increase in revenue than cost of sales due to the Kolvinskoye’s field MET exemption (which extends to the first 15 million tonnes (approximately 110 million barrels) produced through 2015). Adjusted EBITDA of the Group’s downstream segment decreased 12.5%, to USD 276,348 thousand for the year ended 31 December 2012, compared to USD 315,955 thousand for the year ended 31 December 2011, primarily due to increases in production costs (primarily crude oil prices and transportation tariffs) and selling expenses, which were more significant than increases in revenue from sales of petroleum products. This was due to the fact that petroleum products prices rose less than prices for crude oil purchased for processing. Adjusted EBITDA of the Group’s downstream segment increased 31.1%, to USD 315,955 thousand for the year ended 31 December 2011, compared to USD 240,992 thousand for the year ended 31 December 2010, primarily due to a considerable increase in revenue from sales of petroleum products caused by increased sales volumes and net prices.

Liquidity and Capital Resources In addition to cash generated from operating activities, the Group uses short- and long-term borrowings and strategic investments to fund capital expenditures. The Group plans to finance its budgeted capital expenditures, interest expense and dividend payments chiefly from cash generated from operating activities supplemented by additional borrowings.

Cash Flows for the Years Ended 31 December 2012, 2011 and 2010 The following table shows the Group’s cash flows for the years ended 31 December 2012, 2011 and 2010. Year ended 31 December % Change

2012 2011 2010 2012/11 2011/10

(USD thousand) Operating activities Profit before tax...... 544,416 432,761 289,671 25.8% 49.4% Adjustments for: Depreciation, depletion and amortisation ...... 192,374 174,195 132,235 10.4% 31.7% Reversal of impairment of oil and gas assets, net ...... (58,721) — (1,051) — — Interest income...... (14,977) (12,259) (7,901) 22.2% 55.2% Finance costs...... 95,034 59,134 29,473 60.7% 100.6% (Gain)/loss on derivatives classified as held for trading, net...... (7,678) 15,444 — (149.7%) — Currency exchange (gain)/loss, net ...... (21,688) 18,176 (3,923) (219.3%) (563.3%) Share of profits of associates and joint venture ...... (2,309) (2,153) (104) 7.2% 1,970.2% Loss/(gain) on disposal of shares in subsidiaries ...... — 2,894 (9) — — Loss on disposal of assets...... 5,948 3,196 204 86.1% 1,466.7% Impairment of trade and other accounts receivable...... 8,323 753 348 1,005.3% 116.4% Other non-cash items ...... 20,777 2,518 4,385 725.1% (42.6%)

Operating cash flows before changes in working capital ...... 761,499 694,659 443,328 9.6% 56.7%

Movements in working capital Increase in inventories ...... (72,905) (13,832) (26,052) 427.1% (46.9%) Increase in accounts receivable, advances paid and prepaid expenses..... (56,235) (144,624) (170,934) (61.1%) (15.4%) Increase in accounts payable, advances received and accrued expenses ...... 115,482 40,078 21,357 188.1% 87.7%

Cash generated from operations...... 747,841 576,281 267,699 29.8% 115.3%

75 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Year ended 31 December % Change

2012 2011 2010 2012/11 2011/10

(USD thousand) Interest paid ...... (82,136) (42,106) (18,934) 95.1% 122.4% Income tax paid ...... (95,829) (71,675) (45,010) 33.7% 59.2%

Total cash generated from operating activities...... 569,876 462,500 203,755 23.2% 127.0%

Investing activities Investments in oil and gas assets ...... (359,843) (603,744) (351,905) (40.4%) 71.6% Investments in refining assets...... (328,267) (314,912) (223,505) 4.2% 40.9% Investments in marketing and other assets ...... (40,719) (28,194) (29,234) 44.4% (3.6%) Interest capitalised and paid ...... (77,751) (78,268) (45,991) (0.7%) 70.2% Acquisition of controlling interest in subsidiaries, net of cash acquired ...... (155,758) (15,636) — 896.1% — Proceeds from disposal of assets...... 2,963 1,683 1,704 76.1% (1.2%) Interest received ...... 8,984 5,582 6,711 60.9% (16.8%) Payments on settlement of swap contract, net of interest received...... (2,130) 188 — — — Loans provided ...... (56,417) (56,588) (29,372) (0.3%) 92.7% Loans repaid ...... 57,903 19,169 16,912 202.1% 13.3% Investments in promissory notes...... (15,621) — — — — Proceeds from sale of promissory notes 7,209 — — — — Short-term deposits placed...... (30,320) (30,015) (29,859) 1.0% 0.5% Proceeds from deposits withdrawn ...... 27,030 30,076 — (10.1%) — Advances for acquisition of shares ...... — — (20,000) — —

Total cash used in investing activities .... (962,737) (1,070,659) (704,539) (10.1%) 52.0%

Financing activities Proceeds from loans and borrowings ... 758,151 1,111,272 825,837 (31.8%) 34.6% Repayment of loans and borrowings.... (466,696) (478,913) (519,668) (2.6%) (7.8%) Proceeds from issue of preference shares ...... 201,527 — — — — Proceeds from contribution of shares to a joint venture...... 116,728 — — — — Acquisition of non-controlling interest in subsidiaries...... (1,551) (1,267) (4,716) 22.4% (73.1%) Dividends paid by subsidiaries ...... — (397) (8) — 4,862.5% Other financing activities ...... — — 89 — —

Total cash generated from financing activities...... 608,159 630,695 301,534 (3.6%) 109.2% Effect of exchange rate changes on cash balances held in foreign currencies ...... (7,166) 4,148 (4,970) (272.8%) (183.5%) Translation difference ...... 15,887 (16,982) (9,751) (193.6%) 74.2%

Change in cash, cash equivalents and restricted cash...... 224,019 9,702 (213,971) 2,209.0% (104.5%) Cash, cash equivalents and restricted cash1 at beginning of the year ...... 187,801 178,099 392,070 5.4% (54.6%)

Cash, cash equivalents and restricted cash1 at end of the year ...... 411,820 187,801 178,099 119.3% 5.4%

(1) Restricted cash represents letters of credit with OJSC Bank VTB in relation to agreements for the reconstruction of the Khabarovsk Refinery.

76 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Cash generated from operations Total cash generated from operating activities increased as of 31 December 2012 to USD 569,876 thousand, compared to USD 462,500 thousand as of 31 December 2011. Profit before tax increased 25.8% for the year ended 31 December 2012. See ‘‘– Profit before tax’’. Following adjustments for non-cash items, the Group’s operating cash flows before changes in working capital increased 9.6%, to USD 761,499 thousand for the year ended 31 December 2012, compared to USD 694,659 thousand for the year ended 31 December 2011. Cash generated from operations was negatively affected by changes in working capital in both the year ended 31 December 2012 and 2011, decreasing cash by USD 13,658 thousand and USD 118,378 thousand, respectively. The Group’s interest and income tax paid also increased in the year ended 31 December 2012 to USD 82,136 thousand and USD 95,829 thousand, respectively, compared to USD 42,106 thousand and USD 71,675 thousand, respectively, for the year ended 31 December 2011.

Total cash generated from operating activities increased as of 31 December 2011 to USD 462,500 thousand, compared to USD 203,755 thousand as of 31 December 2010. Profit before tax increased 49.4% for the year ended 31 December 2011. See ‘‘– Profit before tax’’. Following adjustments for non-cash items, the Group’s operating cash flows before changes in working capital increased 56.7%, to USD 694,659 thousand for the year ended 31 December 2011, compared to USD 443,328 thousand for the year ended 31 December 2010. Cash generated from operations was negatively affected by changes in working capital in both the year ended 31 December 2011 and 2010, decreasing cash by USD 118,378 thousand and USD 175,629 thousand, respectively. The Group’s interest and income tax paid also increased in the year ended 31 December 2011 to USD 42,106 thousand and USD 71,675 thousand, respectively, compared to USD 18,934 thousand and USD 45,010 thousand, respectively, for the year ended 31 December 2010.

In 2012, net working capital was adversely impacted by an increase in inventories of USD 72,905 thousand, principally related to inventories of crude oil and petroleum products and primarily due to increased domestic demand. These changes were offset in part by an increase in accounts payable, advances received and accrued expenses of USD 115,482 thousand primarily reflecting an increase in advances received from customers for future delivery of crude oil (export sales). In 2011, net working capital changes principally included (i) an USD 144,624 thousand increase in accounts receivable, advances paid and prepaid expenses due to an increase in trade accounts receivable from export sales of crude oil and petroleum products and an increase in advances issued for sales of crude oil for refining, and (ii) a USD 40,078 thousand increase in accounts payable, advances received and accrued expenses primarily reflecting an increase in advances received from customers for future delivery of crude oil (export sales). In 2010, changes in net working capital included an increase in inventories of USD 26,052 thousand, an increase in accounts receivable, advances paid and prepaid expenses of USD 170,934 thousand, partly offset by an increase in accounts payable, advances received and accrued expenses of USD 21,357 thousand.

Total cash used in investing activities Total cash used in investing activities decreased 10.1% as of 31 December 2012 to USD 962,737 thousand, compared to USD 1,070,659 thousand as of 31 December 2011. The decrease was primarily attributable to lower investments in oil and gas assets, which decreased USD 243,901 thousand to USD 359,843 thousand for the year ended 31 December 2012, compared to USD 603,744 thousand for the year ended 31 December 2011, due to the completion of construction works at the Kolvinskoye oil field in September 2011. In addition, the Group’s acquisition of controlling interest in subsidiaries, net of cash acquired, increased to USD 155,758 thousand for the year ended 31 December 2012, compared to USD 15,636 thousand, due to the acquisition of SN-Gasproduction and LLC Geoinvestservice in 2012.

Total cash used in investing activities increased as of 31 December 2011 to USD 1,070,659 thousand, compared to USD 704,539 thousand as of 31 December 2010. The increase was primarily attributable to higher investments in oil and gas assets, which increased USD 251,839 thousand to USD 603,744 thousand for the year ended 31 December 2011, compared to USD 351,905 thousand for the year ended 31 December 2010, due to increased payments relating to construction works at the Kolvinskoye oil field during 2011. In addition, investments in refining assets increased USD 91,407 thousand, to USD 314,912 thousand in the year ended 31 December 2011, compared to USD 223,505 thousand for the year ended 31 December 2010, primarily due to the Khabarovsk Refinery’s modernisation.

77 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Total cash generated from financing activities Total cash generated from financing activities decreased as of 31 December 2012 to USD 608,159 thousand, compared to USD 630,695 thousand as of 31 December 2011. Proceeds from loans and borrowings costs decreased 31.8%, to USD 758,151 thousand for the year ended 31 December 2012, compared to USD 1,111,272 thousand for the year ended 31 December 2011, mainly due to financing from Vnesheconmbank received in 2011 relating to the Khabarovsk Refinery’s modernisation. This decrease was largely offset by proceeds from the Group’s 2012 issuance of preference share of USD 201,527 thousand and proceeds from the Group’s contribution of shares to AROG of USD 116,728 thousand. Total cash generated from financing activities increased as of 31 December 2011 to USD 630,695 thousand, compared to USD 301,534 thousand as of 31 December 2010. The increase was largely due to increased proceeds from loans and borrowings, net of issue costs, which rose USD 285,435 thousand, to USD 1,111,272 thouasand for the year ended 31 December 2011, compared to USD 825,837 thousand for the year ended 31 December 2010, due to financing from Vnesheconmbank received in 2011 relating to the Khabarovsk Refinery’s modernisation.

Indebtedness The tables below set forth a breakdown of the Group’s indebtedness by instrument.

31 December 2012

Currency Interest rate Principal Interest Total

Non-convertible interest bearing bonds .... RUB 8.85-9.75% 655,295 14,296 669,591 Non-convertible interest bearing Eurobonds ...... USD 9.88% 346,959 10,561 357,520 Convertible interest bearing bonds...... USD 7.25% 254,417 4,003 258,420 Libor 3m + 3.85%-Libor Bank loans denominated in USD...... USD 6m+5.5% 329,550 3,924 333,474 Euribor Bank loans denominated in EUR ...... EUR 6m+5.5% 175,088 4,548 179,636 Bank loans denominated in RUB ...... RUB 10.9-12% 267,969 4,010 271,979

Total loans and borrowings ...... 2,029,278 41,342 2,070,620

Current portion repayable within one year 401,606

Long-term loans and borrowings ...... 1,669,014

31 December 2011

Currency Interest rate Principal Interest Total

Non-convertible interest bearing bonds .... RUB 8.85-9.75% 616,579 13,174 629,753 Non-convertible interest bearing Eurobonds ...... USD 9.88% 345,772 10,561 356,333 Convertible interest bearing bonds...... USD 7.25% 248,302 4,003 252,305 Libor 1m+3.6%- Libor Bank loans denominated in USD...... USD 6m+5.5% 233,601 3,060 236,661 Euribor Bank loans denominated in EUR ...... EUR 6m+5.5% 142,077 3,963 146,040

Total loans and borrowings ...... 1,586,331 34,761 1,621,092

Current portion repayable within one year 106,829

Long-term loans and borrowings ...... 1,514,263

78 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA 31 December 2010

Currency Interest rate Principal Interest Total

Non-convertible interest bearing Eurobonds ...... USD 9.88% 344,697 10,561 355,258 Convertible interest bearing bonds...... USD 7.25% 237,064 9,691 246,755 Libor 3m Bank loans denominated in USD...... USD +2.3%-14% 228,852 1,604 230,456 Non-convertible interest bearing bonds .... RUB 9.75%-14% 171,317 6,942 178,259 Euribor Bank loans denominated in EUR ...... EUR 6m+5.5% 27,750 1,127 28,877

Total loans and borrowings ...... 1,009,680 29,925 1,039,605

Current portion repayable within one year 127,134

Long-term loans and borrowings ...... 912,471

In February 2011, OJSC ‘‘Alliance’’ Oil Company issued three-year bonds in the amount of RUB 5,000,000 thousand (approximately USD 170,248 thousand at the exchange rate on the date of the transaction) with a fixed coupon of 9.25% per annum maturing in February 2014. In June 2011, OJSC ‘‘Alliance’’ Oil Company issued ten-year bonds in the amount of RUB 10,000,000 thousand (approximately USD 360,968 thousand at the exchange rate on the date of the transaction) with a five-year put option and a fixed coupon for the five-year period of 8.85% per annum. In 2011, bonds with a notional amount of RUB 3,000,000 thousand and a fixed coupon of 9.75% were swapped to USD through a cross currency interest swap contract bearing interest from 5.3% to 5.8% in order to balance cash inflows from export sales denominated in USD with cash outflows on interest payments denominated in RUB as well as obtain a lower interest rate. In July 2012, the Group settled a cross currency swap with notional amount of RUB 1,000,000 thousand. As of 31 December 2012, 2011 and 2010, 22%, 24% and 30%, respectively, of the Group’s borrowings were at floating interest rates. The weighted average effective interest rates of the Group’s indebtedness as of 31 December 2012, 2011 and 2010 was 8.23%, 8.19% and 7.95%, respectively. As of 31 December 2012 and 2011, loans and borrowings were collateralised by: * 97.73% (31 December 2011: 97.90%) of the Group’s holding in Open Joint Stock Company Khabarovsk Oil Refinery; * 100% of the Group’s holding in Limited Liability Company SN-Gasproduction; * proceeds from sale of crude oil under the contract between Open Joint Stock Company ‘‘Eastern Transnational Company’’ (referred to as OJSC ‘‘Vostochnaya Transnationalnaya Kompaniya’’ in the Financial Statements) and one of its customers in the total amount of USD 330,000 thousand (2011: USD 330,000 thousand); * proceeds from sale of gas under the contract between Limited Liability Company SN- Gasproduction and one of its customers in the total amount of USD 42,854 thousand (2011: nil); and * property, plant and equipment with a carrying value of USD 137,540 thousand (31 December 2011: USD 123,763 thousand).

79 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA The table below sets out the maturity profile of the Group’s loans and borrowings based on contractual undiscounted payments, including accrued interest for the two years ending 31 December 2014 and thereafter.

As of 31 December

2012 2011 2010

(USD thousand) Within one year ...... 532,895 206,453 180,963 Within two years ...... 627,418 342,208 113,104 More than two years ...... 1,484,374 1,597,932 1,149,800

Total amount estimated to be repaid ...... 2,644,687 2,146,593 1,443,867

The Group is subject to external capital requirements imposed on Eurobonds and loans provided by CJSC UniCredit Bank and Gazprombank on the basis of debt to EBITDA ratio. As of 31 December 2012, the Group complied with all capital requirements.

Capital Expenditures The table below sets forth the Group’s cash capital expenditures for the years ended 31 December 2012, 2011 and 2010.

Year ended 31 December

2012 2011 2010

(USD thousand) Capital expenditures on oil and gas assets...... 359,843 603,744 351,905 Capital expenditures on refining assets ...... 328,267 314,912 223,505 Capital expenditures on marketing and other assets...... 40,719 28,194 29,234 Interest capitalised and paid...... 77,751 78,268 45,991

Total cash capital expenditures ...... 806,580 1,025,118 650,635

The Company’s capital expenditures for the years ended 31 December 2012, 2011 and 2010 have primarily been aimed at proejcts to increase hydrocarbon production as well as the modernisation of the Khabarovsk refinery. See ‘‘Business – Downstream Operations – Refining – Modernisation of the Khabarovsk Refinery’’. In 2013, the Group estimates that its consolidated upstream capital expenditures will be approximately USD 250 million to USD 290 million and will be funded from operating cash flows. In total the Company plans to drill 64 production wells and four exploration wells in 2013. In the Timano-Pechora region, the Group’s capital expenditures program will focus on further developing the Kolvinskoye oil field and evaluating and testing the Group’s expanded resource base. The Group’s downstream capital expenditures in 2013 are budgeted to be in the range of approximately USD 430 million to USD 490 million and will be funded from operating cash flows, existing cash and debt sources. A new hydrocracker and other hydroprocessing units are expected to be launched into test operations at the Khabarovsk Refinery in 2013. In addition, the Group will continue to construct a connection from the ESPO oil pipeline to the Khabarovsk refinery. The Group’s downstream capital expenditures in 2013 will also relate to expanding its wholesale and retail network in the Russian Far East. Upon completion of the hydroprocessing complex, improving the Khabarovsk Refinery’s refining capacity and the ESPO oil pipeline connection in 2013, the Group’s downstream capital expenditures and funding requirements are expected to be significantly reduced.

80 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Aggregated Adjusted EBITDA Coverage of the Guarantors The table below sets forth a breakdown of the Issuer’s, Guarantors’ and non-Guarantors’ share of the Aggregated Adjusted EBITDA of the Group (before elimination and consolidation adjustments) for the years ended 31 December 2012 and 2011. Adjusted EBITDA of the Issuer, Aggregated Adjusted EBITDA of the Guarantors and non-Guarantors, and Total Aggregated Adjusted EBITDA of the Group are defined as operating income adjusted for depletion and depreciation of oil and gas and refining assets, reversal of impairment of oil and gas assets, depreciation and amortisation of marketing and other assets, gain/loss on disposal of shares in subsidiaries and other (as defined below).

Year ended 31 December

2012 2011

(USD (USD thousand) % of total thousand) % of total

Adjusted EBITDA of the Issuer ...... (44,298) (5.9%) (47,828) (5.8%) Aggregated Adjusted EBITDA of Guarantors ..... 419,273 56.1% 468,038 56.4% Aggregated Adjusted EBITDA of non- Guarantors ...... 372,961 49.9% 410,066 49.4%

Total Aggregated Adjusted EBITDA of the Group 747,936 100% 830,276 100%

The tables below provide a reconciliation of Adjusted EBITDA of the Issuer, and Aggregated Adjusted EBITDA of the Guarantors and non-Guarantors to operating income for the years ended 31 December 2012 and 2011. All eliminations and other consolidation adjustments are presented within an ‘‘Adjustments’’ column.

Year ended 31 December 2012

Non- Adjust- Issuer Guarantors Gurantors Aggregated ments Total

(USD thousand) Adjusted EBITDA...... (44,298) 419,273 372,961 747,936 (13,840) 734,096 Depletion and depreciation of oil and gas and refining assets... — (87,192) (91,926) (179,118) 5,228 (173,890) Reversal of impairment of oil and gas assets ...... — 58,721 — 58,721 — 58,721 Depreciation and amortisation of marketing and other assets...... — (16,259) (2,225) (18,484) — (18,484) Other1 ...... — (5,336) — — — (5,336)

Operating income...... (44,298) 369,207 278,810 603,719 (8,612) 595,107

(1) For the year ended 31 December 2012, ‘‘Other’’ includes impairment of interest receivable in the amount of USD 5,336 thousand.

81 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Year ended 31 December 2011

Non- Adjust- Issuer Guarantors Gurantors Aggregated ments Total

(USD thousand) Adjusted EBITDA...... (47,828) 468,038 410,066 830,276 (139,931) 690,345 Depletion and depreciation of oil and refining assets ...... — (78,811) (75,325) (154,136) (2,034) (156,170) Depreciation and amortisation of marketing and other assets...... — (15,357) (2,528) (17,885) (140) (18,025) Gain/(loss) on disposal of shares in subsidiaries. 491,757 210 (16,154) 475,813 (478,707) (2,894)

Operating income...... 443,929 374,080 316,059 1,134,068 (620,812) 513,256

Aggregated Net Assets Coverage of the Guarantors The table below sets forth a breakdown of the Issuer’s, Guarantors’ and non-Guarantors’ share of the aggregated net assets reconciled to the Group’s net assets as of 31 December 2012 and 2011. All eliminations and other consolidation adjustments are presented within an ‘‘Adjustments’’ line.

As of 31 December

2012 2011

(USD (USD thousand) % of total thousand) % of total

Net assets of the Issuer...... 2,821,120 37.9% 2,671,775 47.0% Aggregated net assets of Guarantors ...... 1,953,4441 26.2% 1,240,3621 21.8% Aggregated net assets of non-Guarantors ...... 2,672,856 35.9% 1,772,438 31.2%

Total aggregated Group net assets ...... 7,447,420 100% 5,684,575 100%

Adjustments...... (4,414,410) — (3,691,142) —

Total consolidated Group net assets ...... 3,033,010 — 1,993,433 —

(1) Includes USD 34,745 thousand attributable to non-controlling interests as of 31 December 2012 and USD 25,889 thousand as of 31 December 2011.

Contingencies and Commitments

Capital Commitments The Group’s contractual capital commitments as of 31 December 2012 and 2011 amounted to USD 855,011 thousand and USD 750,651 thousand, respectively.

Licence Commitments The Group is subject to periodic reviews of its activities by local regulatory authorities regarding the requirements of its oil and gas licences. Management of the Group entities agrees with local regulatory authorities remedial actions necessary to resolve any findings resulting from these reviews. Non-compliance with the terms of a particular licence could result in penalties, fines or licence limitations, suspension or revocation. The Group believes that any non-compliance with licence terms that the Group may have in the future will be resolved through negotiations or proposed amendments without material effect on the consolidated financial position or the operating results of the Group.

82 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Litigation The Group has been and continues to be the subject of legal proceedings and adjudications from time to time, none of which has had or is expected to have, individually or in the aggregate, a material adverse impact on the Group. The legal system in Russia is not fully developed and cannot be compared with the legal system in western countries. It is also subject to constant changes, sometimes with retroactive effect. This fact could imply negative consequences to the Group.

Environmental Matters The Group is subject to extensive federal, state and local environmental controls and regulations in Russia and Kazakhstan. The Group’s operations involve air and water venting of detrimental impurities that may have a potential impact on flora and fauna in the region of operations and other environmental effects. The Group believes that its operations are in compliance with all current existing environmental laws and regulations. However, environmental laws and regulations of the Russian Federation and Kazakhstan continue to evolve. The Group is unable to predict the timing or extent to which those environmental laws and regulations may change. Such change, if it occurs, may require that the Group modernise technology to meet more stringent standards. In accordance with the terms of various laws and extracting licences upon completion of the oil and gas field exploitation, the Group is liable to perform decommissioning and site restoration of the oil fields. The estimated cost of known environmental obligations has been recorded in Note 31 of the 2012 Financial Statements. The Group regularly reassesses environmental obligations related to its operations. Estimates are based on the Group’s understanding of current legal requirements, the terms of licence agreements and the size and nature of the oil and gas fields under the licences. Should the requirements of applicable environmental legislation change or be clarified, the Group may incur additional environmental obligations. As of 31 December 2012, the Group’s provision for decommissioning and site restoration costs increased by USD 57,755 thousand compared to 31 December 2011 primarily due to an annual revision of assumptions, in particular the discounting rate and decomissioning cost per unit.

Russian Federation Economic Environment Emerging markets such as Russia are subject to different risks than more developed markets, including economic, political and social, and legal and legislative risks. As has happened in the past, actual or perceived financial problems or an increase in the perceived risks associated with investing in emerging economies could adversely affect the investment climate in Russia and its economy in general. The global financial system continues to exhibit signs of deep stress and many economies around the world are experiencing lesser or no growth than in prior years. Additionally, there is increased uncertainty about the creditworthiness of some sovereign states in the Eurozone and financial institutions with exposure to the sovereign debt of such states. These conditions could slow or disrupt Russia’s economy, adversely affect the Group’s access to capital and cost of capital for the Group and, more generally, its business, results of operations, financial condition and prospects. Because Russia produces and exports large volumes of oil and gas, its economy is particularly sensitive to the price of oil and gas on the world market which has fluctuated significantly during 2012 and 2011.

Russian Federation Tax and Regulatory Environment Laws and regulations affecting businesses in Russia continue to change rapidly. Tax, currency and customs legislation within Russia are subject to varying interpretations, and other legal and fiscal impediments contribute to the challenges faced by entities currently operating in Russia. The future economic direction of Russia is heavily influenced by the economic, fiscal and monetary policies adopted by the government, together with developments in the legal, regulatory and political environment. While the Group believes it has provided adequately for all tax liabilities based on its understanding of the tax legislation, the above facts may create tax risks for the Group. The Group believes that its interpretation of the relevant legislation is appropriate and the Group’s tax, currency and customs positions will be sustained.

83 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Risk Management Capital Risk Management The Group’s objective for managing capital is to deliver competitive, secure and sustainable returns to maximise long-term shareholders value and reduce the cost of capital maintenance. The Group monitors its capital structure on the basis of its total debt to equity ratio. Total debt comprises non-current and current loans and borrowings, as shown in the Group’s consolidated statement of financial position. Equity of the Group comprises share capital, additional paid-in capital, translation reserve on intercompany loans, translation reserve on foreign operations, option premium on convertible bonds, retained earnings and non-controlling interests.

31 December 31 December 2012 2011

(USD thousand) Loans and borrowings...... 2,070,620 1,621,092 Total equity ...... 3,033,010 1,993,433

Debt to equity ratio...... 68% 81%

In addition, the Group reviews the following ratios on a quarterly basis: net debt, total debt to Adjusted EBITDA, net debt to Adjusted EBITDA and EBIT to interest expense.

Major Categories of Financial Instruments Major categories of financial assets and financial liabilities are presented below:

31 December 31 December 2012 2011

(USD thousand) Financial assets Loans and receivables (including cash and cash equivalents): Trade and other accounts receivable...... 116,368 113,605 Other financial assets...... 48,484 91,088 Cash, cash equivalents and restricted cash...... 411,820 187,801 Fair value through profit or loss Other financial assets...... 1,337 2,175

578,009 394,669

Financial liabilities Measured at amortised cost: Loans and borrowings...... 2,070,620 1,621,092 Trade and other accounts payable ...... 129,864 144,184 Wages and salaries payable ...... 26,079 21,106 Fair value through profit or loss Derivatives classified as held for trading...... 5,981 16,021

2,232,544 1,802,403

The Group faces a number of financial risks arising from its operations and use of financial instruments, including, but not limited to, foreign currency risk, interest rate risk, credit risk and liquidity risk.

Foreign Currency Risk Currency risk is the risk that the financial results of the Group will be adversely impacted by changes in exchange rates. The Group undertakes certain transactions denominated in foreign currencies. A significant part of the Group’s revenues are denominated in USD, whereas the majority of the Group’s operational costs are denominated in RUB. At the same time, a significant part of the

84 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Group’s borrowings are denominated in USD and EUR, while most of the Group’s assets are denominated in RUB.

The Group’s exposure to the risk of changes in exchange rates relates primarily to the Group’s long- term debt obligations denominated in USD and EUR. The Group manages its foreign currency risk by economically hedging transactions that are expected to occur within a maximum 24-month period. In June and August 2011, the Group entered cross-currency interest rate swaps in order to balance cash inflows from export sales denominated in USD with cash outflows on interest payments denominated in RUB and obtain a lower interest rate.

The table below sets forth the outstanding balances of the Group’s foreign currency denominated monetary assets and monetary liabilities as of 31 December 2012 and 2011:

Denominated in USD Denominated in EUR

31 December 31 December 31 December 31 December 2012 2011 2012 2011

(USD thousand) Assets Trade and other accounts receivable ...... 67,038 58,792 18,180 14,772 Cash, cash equivalents and restricted cash... 232,776 19,637 28,938 29,348

299,814 78,429 47,118 44,120 Liabilities Loans and borrowings...... 361,452 289,991 198,155 166,777 Trade and other accounts payable ...... 2,473 3,300 32,799 435

363,925 293,291 230,954 167,212

Total net position ...... (64,111) (214,862) (183,836) (123,092)

The following table details the Group’s sensitivity to a 10% increase and decrease in the RUB against the relevant foreign currencies. The sensitivity rate used when reporting foreign currency risk internally to key management personnel is 10%. This represents management’s assessment of the reasonably possible change in foreign exchange rates. The sensitivity analysis includes only outstanding foreign currency denominated monetary items and adjusts their translation at the period end for a 10% change in foreign currency rates. A positive number below indicates an increase in profit or equity where the RUB strengthens for 10% against the relevant currency. For a 10% weakening of the RUB against the relevant currency, there would be a comparable impact on the profit or equity, and the balances below would be negative.

Denominated in USD Denominated in EUR

Year ended Year ended Year ended Year ended 31 December 31 December 31 December 31 December 2012 2011 2012 2011

(USD thousand) Profit or loss ...... 6,411 21,486 18,384 12,309

In addition, a change of exchange rate of the RUB against the USD by 10% would lead to recognition of USD 7,454 thousand profit or loss in relation to valuation of fair value of cross- currency interest rate swaps.

Interest Rate Risk The Group is exposed to interest rate risk as Group entities borrow a portion of funds at floating interest rates. At 31 December 2012 and 2011, 22% and 24%, respectively, of the Group’s borrowings were at floating interest rates. Management considers such portfolio of fixed and floating rate loans

85 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA and borrowings to be appropriate, therefore the Group does not use any derivatives to manage interest rate risk exposure.

The table below details the Group’s sensitivity to increase or decrease of the floating rate by 1%, which is used when reporting interest rate risk internally to key management personnel and represents management’s assessment of the reasonably possible change in interest rates. The analysis was applied to loans and borrowings based on the assumptions that amount of liabilities outstanding at the reporting date were outstanding for the whole year.

Profit or loss

Year ended Year ended 31 December 31 December 2012 2011

(USD thousand) LIBOR...... 1,475 1,185

Credit Risk Credit risk is the risk that a customer may default or not meet its obligations to the Group on a timely basis, leading to financial losses. The Group has adopted a policy of only dealing with creditworthy counterparties. The Group takes into account all available quantitative and qualitative information and its own trading records to mitigate the risk of financial loss from defaults.

Credit risk of the Group arises from cash, cash equivalents and restricted cash, loans and receivables and other financial assets, and has a maximum exposure equal to the carrying value of these instruments.

Description of risk management policies relating to trade and other receivables are described in ‘‘Note 24 to the 2012 Financial Statements’’.

The credit risk on cash, cash equivalents, restricted cash and investments in deposits is limited because the counterparties are highly rated banks or banks approved by the management of the Group, deposits in which are placed only within approved limits.

In addition, the Group is exposed to credit risk in relation to investments in loans. The counterparty’s business activities, financial resources and business risk management processes are taken into account in the assessment of their creditworthiness. The Group issues loans only to counterparties approved by management within the established limits.

There were no guarantees given to secure financing of third parties at 31 December 2012 and 2011.

Liquidity Risk Liquidity risk is the risk that the Group will not be able to settle all liabilities as they fall due. The Group’s liquidity position is carefully monitored and managed.

The net cash flow position of the Group is monitored on a daily basis by the central treasury function with weekly cash movements and cash balances being reported to the Group’s management. A significant portion of crude oil and petroleum products sales contracts is executed on an advanced basis and the Group has also a strict policy for collecting doubtful debts and monitoring trade debtors. The Group prepares detailed budgets and forecasts and reviews the global and domestic oil price environment on a monthly basis in order to optimise crude oil sales, supply routes, oil product mix and refinery volumes. Management is focusing on matching the maturity profiles of financial assets and liabilities and reducing short-term debt through repayment of existing short-term loans. Accordingly, management considers that it is taking all necessary actions to allow the Group to meet its current obligations as they fall due.

The Group’s primary sources of cash are its operations, as well as bank loans and the proceeds from equity and debt capital markets offerings.

At 31 December 2012, the Group’s unused financing facilities amounted to USD 444,025 thousand (2011: USD 635,646 thousand).

86 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Critical Accounting Policies New and revised IFRSs and IASs affecting the reported financial performance and/or financial position A number of new and revised Standards which became effective or available for early adoption on 1 January 2012, have been applied by the Group for the preparation of the Financial Statements.

New and revised Standards on consolidation, joint arrangements, associates and disclosures In May 2011, a package of five standards on consolidation, joint arrangements, associates and disclosures were issued including IFRS 10 ‘‘Consolidated Financial Statements’’, IFRS 11 ‘‘Joint Arrangements’’, IFRS 12 ‘‘Disclosures of Interests in Other Entities’’, IAS 27 (as revised in 2011) ‘‘Separate Financial Statements’’ and IAS 28 (as revised in 2011) ‘‘Investments in Associates and Joint Ventures’’. In 2012, the Group adopted these five standards in advance of their effective dates (annual periods beginning on or after 1 January 2013). The impact of the application of these standards was assessed by management as insignificant to the Group’s operations except for IFRS 10, IFRS 11 and IFRS 12.

Impact of the application of IFRS 10 IFRS 10 replaces the parts of IAS 27 ‘‘Consolidated and Separate Financial Statements’’ that deal with consolidated financial statements. IFRS 10 changes the definition of control such that an investor controls an investee when it is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. To meet the definition of control in IFRS 10, all of the three criteria, including (a) an investor has power over an investee, (b) the investor has exposure, or rights, to variable returns from its involvement with the investee, and (c) the investor has the ability to use its power over the investee to affect the amount of the investor’s returns, must be met. Previously, control was defined as the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. The application of IFRS 10 is relevant to the accounting for the Group’s subsidiaries Saneco and Tatnefteotdacha. In the year ended December 2012, the Group contributed its ownership interest in these subsidiaries, or 100% in the case of Saneco and 99.54% in the case of Tatnefteotdacha, to a newly established joint venture, AROG. Based on the definition of control under IFRS 10, the Group considers that it has retained control over Saneco and Tatnefteotdacha and continues to consolidate the entities. This determination is made on the basis that the Group has a substantive potential voting right in respect of Saneco and Tatnefteotdacha through the existence of a buy-back option, which can be exercised at fair value determined by independent valuators. Management expects to obtain non-monetary benefits from exercise of the option and thus deems the option to be substantive, such that this is a determinative factor in retaining control. See ‘‘Note 20 of the 2012 Financial Statements’’ for additional information in respect of the joint venture and related accounting.

Impact of the application of IFRS 11 IFRS 11 replaces IAS 31 ‘‘Interests in Joint Ventures’’ and SIC-13 ‘‘Jointly Controlled Entities – Non- Monetary Contributions by Venturers’’. IFRS 11 deals with how a joint arrangement of which two or more parties have joint control should be classified. Under IFRS 11, there are only two types of joint arrangements – joint operations and joint ventures. The classification of joint arrangements under IFRS 11 is determined based on the rights and obligations of parties to the joint arrangements by considering the structure, the legal form of the arrangements, the contractual terms agreed by the parties to the arrangement and, when relevant, other facts and circumstances. A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement (i.e. joint venturers) have rights to the net assets of the arrangement. Previously, IAS 31 ‘‘Interests in Joint Ventures’’ had three types of joint arrangements – jointly controlled entities, jointly controlled operations and jointly controlled assets. The classification of joint arrangements under IAS 31 was primarily determined based on the legal form of the arrangement (e.g. a joint arrangement that was established through a separate entity was accounted for as a jointly controlled entity). The subsequent accounting of joint ventures and joint operations is different. Investments in joint ventures are accounted for using the equity method (proportionate consolidation is no longer allowed). Investments in joint operations are accounted for such that each joint operator recognises and measures the assets and liabilities (and the related revenues and expenses) in relation to its interest in the arrangement in accordance with the applicable Standards.

87 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA Under IFRS 11, a newly established entity, AROG, has been determined as a joint venture and the Group’s interest in AROG is required to be accounted for using the equity method. Refer to Note 20 of the 2012 Financial Statements for additional information in respect of the joint venture and related accounting.

Impact of the application of IFRS 12 IFRS 12 is a disclosure standard and is applicable to entities that have interests in subsidiaries, joint arrangements, associates and/or unconsolidated structured entities. In general, the application of IFRS 12 has resulted in more extensive disclosures in the consolidated financial statements.

Amendments to IAS 19 ‘‘Employee Benefits’’ The Group early adopted amendments to IAS 19 ‘‘Employee Benefits’’ in advance of the effective date (annual period beginning on or after 1 January 2013). The most significant change relates to accounting for changes in defined benefit obligations and plan assets. The amendments require the recognition of changes in defined benefit obligations and in fair value of plan assets when they occur, and hence eliminate the ‘corridor approach’ permitted under the previous version of IAS 19 and accelerate the recognition of past service costs. The amendments require all actuarial gains and losses to be recognised immediately through other comprehensive income in order for the net pension asset or liability recognised in the consolidated statement of financial position to reflect the full value of the plan deficit or surplus. The amendments to IAS 19 require retrospective application. Previously, the past service costs at the introduction of the plans were deferred and amortised on a straight-line basis over the expected average remaining working lives of the employees participating in the plans. After adoption of the amended standard, the Group recognised the past service costs in the amount of USD 4,718 thousand in the consolidated statement of profit or loss for the year ended 31 December 2012. Due to immateriality, the amendments were not applied retrospectively.

88 c108210pu030 Proof 9: 29.4.13_14:32 B/L Revision: 0 Operator PutA BUSINESS

Overview The Group is an independent and vertically integrated oil and gas company with both upstream and downstream operations in Russia and upstream operations in Kazakhstan. The Group’s upstream operations include crude oil exploration, extraction and production in the Timano-Pechora, Volga- Urals and Tomsk regions of Russia and the Atyrau region of Kazakhstan, as well as upstream gas operations in the Tomsk region; its downstream operations include oil refining as well as transportation, marketing and sale of refined petroleum products primarily in the Russian Far East. As of 31 December 2012, 2011 and 2010, the Group’s proven and probable crude oil and gas reserves under the PRMS classification were 732.6 mmboe, 647.9 mmboe and 638.3 mmboe, respectively, and the Group’s proven crude oil and gas reserves under the PRMS classification were 330.8 mmboe, 309.6 mmboe and 286.4 mmboe, respectively. In addition, the Group holds an equity interest in the non-consolidated oil and gas reserves of AROG proportional to the Group’s ownership stake in the joint venture. For the years ended 31 December 2012, 2011 and 2010, the Group’s total crude oil production was 19.7 mmbbl, 17.9 mmbbl and 16.0 mmbbl, respectively. The Group has a diversified portfolio of assets and is currently developing 18 fields in Russia and one field in Kazakhstan as well as participating in AROG, a joint venture with Repsol, with the aim of increasing production in Russia. The Group is engaged in crude oil refining and marketing of refined products focused in the Russian Far East and conducts its refining operations at the Khabarovsk Refinery, which as of 31 December 2012 had a refining capacity of 90,000 bopd. For the years ended 31 December 2012, 2011 and 2010, the Khabarovsk Refinery processed 29.3 mmbbl, 26.9 mmbbl and 23.7 mmbbl, respectively, and the Group sold 29.9 mmbbl, 27.6 mmbbl and 24.4 mmbbl of petroleum products during those periods, respectively. The Group markets refined petroleum products through its own network of 267 refuelling stations and 21 wholesale petroleum products terminals in the Khabarovsk, Primorsk, Amur, Jewish Autonomous District and Republic of Buryatia regions in Russia and also exports its petroleum products on market terms through Lia Oil, an affiliate, to neighbouring Asian markets. For the years ended 31 December 2012, 2011 and 2010, the Group’s revenue was USD 3,445,239 thousand, USD 3,082,660 thousand and USD 2,195,756 thousand, respectively. Revenue from crude oil sales was USD 602,354 thousand, USD 531,656 thousand and USD 397,943 thousand for the years ended 31 December 2012, 2011 and 2010, respectively, while revenue from oil product sales was USD 2,787,761 thousand, USD 2,496,218 thousand and USD 1,756,295 thousand for the years ended 31 December 2012, 2011 and 2010, respectively. For the years ended 31 December 2012, 2011 and 2010, the Group’s Adjusted EBITDA was USD 734,096 thousand, USD 690,345 thousand and USD 438,391 thousand, respectively.

Competitive Strengths The Group believes that it benefits from the following competitive strengths: * Diversified and vertically integrated Russian oil and gas company. The Group is a vertically integrated oil and gas company with a diversified upstream and downstream asset mix delivering strategic flexibility in a volatile crude oil price environment. In addition to its solid base of upstream operations, the Group expects to increase the refining capacity at the Khabarovsk Refinery from 90,000 bopd to 100,000 bopd by the end of 2013 and to connect to the ESPO oil pipeline in 2014, further bolstering its downstream capabilities. * Well positioned for growth across the value chain. The Group believes it is optimally positioned to capitalise on growth opportunities along the entire upstream-downstream- marketing value chain. The Group’s business model generates strong cash flows from operations, providing flexibility and stability to its development plan and allowing it to capitalise on new investment opportunities as they arise. The Group believes that it is well placed to improve its capital structure and lower its cost of capital by financing capital requirements through a combination of operating cash flow, long-term debt available under existing credit agreements and additional external debt. * High quality upstream asset base. The Group has a balanced portfolio of high quality upstream oil and assets, which are geographically diversified across three major Russian oil producing basins (West Siberia, Timano-Pechora and Volga-Urals) and in Kazakhstan. The Group’s upstream portfolio includes assets which provide significant production volumes,

89 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA as well as exploration and development projects which will contribute to the Group’s strong organic reserves growth profile going forward. The acquisition of gas assets and the launch of gas production have further expanded the Group’s upstream portfolio. * Market leading retail and wholesale network. The Group has developed an extensive retail and wholesale refined petroleum product network in the Russian Far East and the Republic of Buryatia and also enjoys premium brand recognition among its retail and wholesale corporate customers in these regions. The Group believes that its premium brand, quality of facilities and high standard of service will continue to permit it to achieve a leading position on the retail market in these regions. * Advantageous geographic position of downstream and upstream assets. The Group operates in a relatively isolated petroleum products consumption market in the Russian Far East. There are currently only two major refineries operating in this market: the Group’s Khabarovsk Refinery and Rosneft’s Komsomolsk refinery. The relatively isolated nature of the market contributes to the profitability of the Group’s marketing operations as competition is reduced compared to that in other regions. The Group’s network of filling stations and wholesale petroleum products terminals allow for significant flexibility in the volumes and range of petroleum products sold. The Group’s refining operations are expected to benefit from the proposed connection of the Khabarovsk Refinery to the ESPO oil pipeline, resulting in decreased costs, especially related to railway transshipment expenses. Furthermore, the Khabarovsk Refinery is located close to the Russian Federation’s borders, which facilitates access to the larger Asia-Pacific petroleum products consumption markets (China, Japan and South Korea). The Group’s upstream assets are located in regions with existing transportation infrastructure which facilitates access to domestic and international markets. * Experienced management team and strong corporate governance. The Group benefits from the extensive upstream and downstream experience of the combined management team. The management of the Group strives to implement the latest technological innovations as well as industry’s best practices. The Group’s management is also committed to a high standard of transparency and corporate governance. The Group started the implementation of the Swedish code of corporate governance in 2006.

Strategy The Group seeks to capitalise on its position as an integrated oil and gas company, increased financing capacity and strong cash flows to further strengthen its position within the upstream and refined products industry. In particular, the Group intends to focus on increasing oil and gas reserves and production as well as producing and providing high-quality petroleum products and related services in Russia, the CIS, the Asia-Pacific region and other export markets. Some highlights of the Group’s development strategy are set forth below. There can be no assurance, however, that the Group will be able to achieve these targets. See ‘‘Forward-Looking Statements’’ and ‘‘Risk Factors’’. * Modernise refining capabilities. The Group will continue a significant modernisation programme for the Khabarovsk Refinery, which is expected to increase the refinery’s depth of refining from 65% to more than 90%, at 3 mmtonnes of production volume per year. This investment is expected to lead to an increase in refining capacity from 90,000 bopd to 100,000 bopd and the share of higher value-added light petroleum products in total output to meet a growing demand for light petroleum products in the Russian Far East, the Republic of Buryatia and the Asia-Pacific region. The Group expects that it will be able to produce Euro-4/5 diesel upon the completion of the hydroprocessing complex at the Khabarovsk Refinery. * Increase hydrocarbon production. The Group aims to increase production by continuing to develop existing oil fields and new gas assets via investments in exploration activities, improving existing infrastructure and implementing operating efficiencies. It is expected that production can be increased while maintaining control of operating costs by employing proven technologies, such as water injection, horizontal drilling, hydrofracturing and acid treatment to optimise oil recoveries from producing but under-developed fields. The Group’s assets contain a number of significant greenfield exploration and development opportunities that the Group is actively pursuing.

90 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA * Further improve financial efficiency. The Group seeks to develop a cost conscious culture with strict financial controls and a daily financial review procedure for all subsidiaries put in place by the Group’s senior management team. The Group’s strategy is to further improve profitability by a combination of controlling and reducing costs and a focus on improving revenues from existing and newly developed and acquired assets, as well as by improving netbacks by more effectively allocating oil and petroleum product sales from each region to exports. * Increase upstream asset base. The Group will consider acquiring Russian oil and gas resources with proven developed reserves as well as resources with development and exploration potential that are not sufficiently large to be of primary strategic interest to Russia’s larger oil companies but which can be developed profitably. For example, in January 2013, the Group completed the formation of AROG, a joint venture with Repsol, to expand its exploration and production growth in Russia. As part of the joint venture, Eurotek, an exploration and production gas company with assets in Russia, was contributed by Repsol, while the Group contributed its subsidiaries Saneco and Tatnefteotdacha. The Group also continues to review opportunities to participate in future subsoil licence auctions and tenders where access to economically attractive development and exploration opportunities with acceptable risk profiles and potential synergies with the Group’s existing operations are offered. * Bolster revenues from retail outlets. The Group is working to optimise its portfolio of existing filling stations with a focus on increasing non-fuel sales at these stations. The Group expects to increase its portfolio of retail filling stations in the Russian Far East and the Republic of Buryatia by constructing new stations and closing underperforming ones. As part of this process, the Group will seek to substantially increase the number of filling stations that also provide supplemental services and have associated retail shops with a diversified product offering or food kiosks, where appropriate. In addition, the Group recently has implemented a client loyalty system. Management expects this optimisation to enable the Group to implement price differentiation strategies according to the local market conditions. As a result, the Group believes it can increase both fuel and non-fuel retail sales in the Russian Far East and the Republic of Buryatia. * Optimise Russian oil terminal network. The Group aims to optimise its Russian oil terminal network for increased competitiveness and retention of its wholesale market share in the Russian Far East and the Republic of Buryatia. The Group believes it can increase its wholesale market share in the Russian Far East and the Republic of Buryatia by increasing sales of petroleum products under federal programmes as well as sales to airline, gold mining, coal and road construction companies. The Group plans to optimise its oil terminal network for more efficient storage and delivery of petroleum products. * Increase export sales of petroleum products. The Group will work to increase export sales by capitalising on the close geographical proximity of the Group’s refining operations to Asian markets, where demand for petroleum products is expected to increase in the coming years. The Group plans to increase export sales of its petroleum products by widening the range of its petroleum products and increasing sales volumes of diesel and jet fuel through the modernisation of the Khabarovsk Refinery. The Group plans to support this strategy by optimising its transportation and logistics network, including by constructing new logistics infrastructures for export sales.

History History and Development The Issuer is an exempted company limited by shares incorporated under the laws of Bermuda. The Issuer was incorporated on 1 September 1998 for an unlimited duration with registered number 25413. The Group emerged in 2008 as a result of a merger between West Siberian Resources Ltd. and NK Alliance. A brief history of NK Alliance and West Siberian Resources Ltd prior to the merger is outlined below. NK Alliance NK Alliance was formed in November 2001 by OJSC Alliance Group, CJSC Investment Company Alliance Capital and Wincor S.A. OJSC Alliance Group and CJSC Investment Company Alliance

91 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA Capital contributed to NK Alliance their respective ownership interests in Amurnefteproduct, Primornefteproduct and Khabarovsknefteproduct, marketing and sales companies, and in the Khabarovsk Refinery, which was NK Alliance’s primary refining facility. To create a vertically-integrated oil company, NK Alliance acquired in July 2005 a controlling interest in Tatnefteotdacha , a company engaged in crude oil exploration and production in Tatarstan, Russia. In November 2006, NK Alliance also acquired a controlling interest in Potential Oil (now held by the Issuer), a company engaged in crude oil exploration and production in Kazakhstan. West Siberian Resources Ltd. West Siberian Resources Ltd. was incorporated in 1998 in Bermuda (as Vostok Oil Limited). In 1999, it acquired OJSC Eastern Transnational Company that held a combined exploration and production licence for the Middle Nyurola, Klyuchevskoye and Puglalymskoye oil fields in the Tomsk region. Vostok Oil Limited listed Swedish Depositary Receipts (‘‘SDRs’’) on NASDAQ OMX First North (formerly known as Nya Marknaden) in 2000 and, after the restructuring and recapitalisation of the company, its name was changed to West Siberian Resources Ltd. in 2004. In 2005, West Siberian Resources Ltd. further expanded its oil production by acquiring the Khvoinoye oil field and the Alexandrovsky Refinery (later disposed) in the Tomsk region, the Middle Kharyaga oil field in the Timano-Pechora region, combined exploration and production licences for the North and Lek Kharyaga oil fields adjacent to the Middle Kharyaga oil field infrastructure. In 2006, West Siberian Resources Ltd. entered the Volga-Urals region through acquisition of Saneco that at the time held three combined exploration and production licences and three exploration licences and further increased its presence in the Timano-Pechora region by acquiring the Kolvinskoye oil field. In 2007, West Siberian Resourced Ltd. delisted its SDRs from NASDAQ OMX First North and listed on NASDAQ OMX Stockholm. In 2008, the NK Alliance shareholders contributed their respective shares in NK Alliance (representing 100% of NK Alliance’s share capital) in exchange for 1,783.5 million common shares issued by West Siberian Resources Ltd. representing approximately 60% of West Siberian Resources Ltd.’s share capital, which were then exchanged for SDRs in WSR and listed on NASDAQ OMX Stockholm in March 2008. In 2009, the merged company changed its name to Alliance Oil Company Ltd. In 2011, the Kolvinskoye oil field was launched, and the Group reached an agreement with Repsol to form a joint venture, AROG, to expand its exploration and production growth in Russia. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations - Changes in Group Structure and Holdings from 1 January 2010 to 31 December 2012 – AROG’’. In 2012, the Group entered the Russian gas sector through its acquisition of SN-Gasproduction, which holds the Ust-Silginskiy and Kargasokskiy-2 licence blocks, located in the Tomsk region in Russia.

Organisational Structure The Issuer is the parent company of the Group. The Issuer controls the overall planning, financing, commercial and acquisition strategies and oversees all exploration and development activities of the Group. The Group’s operations are conducted through regional subsidiaries in Russia and Kazakhstan. The Group continues to review its corporate structure with the possibility of reorganising its holdings to help facilitate more efficient operations and management.

92 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA The chart below sets forth the organisational structure of the Group’s principal operating subsidiaries as well as the percentages showing interests in their capitalowned or controlled by the Group as at the date of this Prospectus.

Alliance Oil Company Ltd.

100% 100% 100% 100% 100% Ɉ&G Credit Agency Ltd. LLC Paltovis LLC Pechora OJSC Oil Company Alliance LLC Alliance Oil Exploration 99.999% Company MC 97.75% (98.83%) 95.04% (98.61%) 88.89% (92.85%) Vostok Oil (Cyprus) Limited 100% LLC Gusikhinskoye OJSC Khabarovsk Oil Refinery PJSC Primornefteproduct OJSC OJSC Eastern Khabarovsknefteproduct 100% 96.19% Transnational 100% Company 100% SONOGEST S.a.r.l. (96.36%) OJSC Amurnefteproduct LLC Dom Kultury OJSC LLC Alliance-Bunker KhNPZ CJSC Khvoinoye 100% CJSC Gavanbunker 100% 100% 99% 1% LLC Alliance-Baikalneftesbyt LLC Kolvinskoe 100% 99.00% (99.93%) OJSC 99.9998% Pechoraneft CJSC Alliance Oil 1% CJSC Leasing Company 99% 100% ALLIANCEPROMSERVICE LLC WSR Invest 100% 100% PRIMULA INVESTMENTS S.à r.l. 1% CJSC Alliance-Energo 26.04% 0.00002% LLC Naftatekhresource VIOLET AR Oil&Gaz B.V. 24.96% 100% INVESTMENTS 99.54% CJSC Begstar 99% S.à r.l. 99.9998% 100% 100% 100% 0.0002% 100% CJSC Aliancetransoil CJSC SANECO LLC ALREP MC 100% Bekstar International OJSC Eurotek KINGSLEY Limited UNIVERSAL INC. 99.54% 80% 99.97% 0.03% 100% OJSC Tatnefteotdacha LLC GeoInvestService LLP Potential Oil CAP AGRO S.A.

POLONIO 0.5% 100% 100% TNG ENERGY HOLDINGS LLC SN- LIMITED Gasproduction LIMITED 99.5%

* Percentages stated in parentheses show interests in voting shares, where amounts differ. ** Beginning in March 2013, Khvoinoye began a merger into Pechoraneft.

Upstream Operations The Group has a diversified portfolio of oil and gas producing assets. Exploration and production of crude oil and gas is conducted in Russia and Kazakhstan. The Group operates in three of Russia’s largest basins: Western Siberia, Timano-Perchora and the Volga-Urals. As of 31 December 2012, the Group’s proven and probable hydrocarbon reserves were estimated at 732.6 mmboe. The Group’s crude oil production increased to 19.7 mmbbl for the year ended 31 December 2012, compared to 17.9 mmbbl and 16.0 mmbbl for the years ended 31 December 2011 and 2010, respectively. Growth in the Group’s upstream operations is primarily achieved by adding and developing hydrocarbon reserves through drilling within existing licence blocks. In 2012, the Group replaced 530% of its total 2012 hydrocarbon production by adding net proven and probable 2P oil and gas reserves of 84.8 mmboe primarily through the acquisition of gas assets in the Tomsk region, exploration and development.

Reserves For the years ended 31 December 2012, 2011 and 2010, the audit of the Group’s reserves has been conducted by D&M according to the PRMS classification (formerly called SPE standards). D&M carried out the Reserves Reports, which are available for inspection at the offices of the Principal Paying Agent. The Reserves Reports set forth estimates of the Group’s reserves based on data derived from studies relating to the Group’s interest in reserves of crude oil and gas at its properties. Unless otherwise specified, information in this Prospectus relating to the estimated crude oil and gas reserves of the Group is extracted or derived from the relevant reserves reports prepared by D&M as at 31 December 2012, 2011 and 2010 under the PRMS classification. The process of estimating oil and gas reserves is complex and inherently uncertain. Production rates and timing of development must be projected and available geological, geophysical, production, engineering and economic data analysed for each reservoir. The extent, quality and reliability of this data can vary. The accuracy of reserves data is also a function of the quality and quantity of other available data, engineering and geological interpretation and judgment. See ‘‘Presentation of Certain Information – Oil and Gas Information’’. See also ‘‘Risk Factors – Risks Relating to the Group and the

93 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA Oil and Gas Industry – Oil, natural gas and gas condensate reserves data in the Prospectus are only estimates, and the Group’s actual production, revenues and expenditures with respect to its reserves may differ materially from those estimates’’. The following table sets forth the Group’s proven and probable hydrocarbon reserves as of 31 December 2012, 2011 and 2010 under the PRMS classification at its main production areas.

Hydrocarbon Reserves (mmboe)

2012 2011 2010

Proven and Proven and Proven and Location Proven Probable Proven Probable Proven Probable

Atyrau, Kazakhstan .. 3.9 8.1 5.9 10.8 10.1 15.9 Timano-Pechora ...... 139.0 394.9 166.9 409.0 155.3 394.8 Tomsk...... 71.9 166.8 28.8 57.4 14.9 56.1 Volga-Urals ...... 116.0 162.8 108.0 170.7 106.1 171.5

Total ...... 330.8 732.6 309.6 647.9 286.4 638.3

In October 2012, the Group acquired SN-Gasproduction, a company holding two gas licences located in the Tomsk region of Russia. The 2P gas reserves under these licences are estimated at 111 mmboe under the PRMS classification.

Oil Production The Group’s oil production for the years ended 31 December 2012, 2011 and 2010 was 19.7 mmbbl, 17.9 mmbbl and 16.0 mmbbl. The following table sets forth oil production data of the Group by oil production region for the years ended 31 December 2012, 2011 and 2010.

2012 2011 2010

Location (Thousand barrels) Timano-Pechora ...... 8,354 7,178 4,964 Volga-Urals...... 7,408 7,120 7,391 Tomsk...... 3,214 2,940 3,023 Atyrau, Kazakhstan...... 763 642 582

Total...... 19,739 17,879 15,960

As of 31 December 2012, the Group had 643 active wells, 557 of which were active production wells, four active exploration wells and 86 active injection wells. As of 31 December 2011, the Group had 563 active wells, 494 of which were active production wells, and 69 active injection wells. As of 31 December 2010, the Group had 524 active wells, 467 of which were active production wells, and 57 active injection wells. Production wells are used to extract oil and associated gas, while injection wells are used to pump water or other agents into subsurface reservoirs in order to maintain pressure and enhance oil recovery.

Exploration and Development Activities The Group’s exploration drilling in Russia totalled approximately 10,806 metres for the year ended 31 December 2012, compared with 12,294 metres and 18,542 metres for the years ended 31 December 2011 and 2010, respectively. The Group’s additions to exploration and evaluation assets totalled USD 47,846 thousand for the year ended 31 December 2012, as compared with USD 9,322 thousand and USD 30,432 thousand for the years ended 31 December 2011 and 2010, respectively. Current exploration and production expenditures target the most promising exploratory prospects in the Timano-Pechora and Volga-Urals regions.

Licences The Group must obtain licences from governmental authorities to explore and produce oil and gas from its fields. As 31 December 2012, the Group held 32 licences, of which 17 are production

94 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA licences, six are combined exploration and production licences, and nine are exploration licences. Exploration licences give the licence holder the non-exclusive right to explore for oil in fields in a defined area and are generally valid for a period of five years and may be extended upon the expiration of such five-year term. These licences do not give the holder the right to extract any oil. However, if the exploration efforts are successful, the Group’s exploration licences generally provide that the Group can obtain a production licence without auction or tender. Production licences have generally been valid for 20 years and give the Group the exclusive right to extract oil from fields in a defined area. Combined exploration and production licences permit both exploration and production and are generally valid for 25 years. The Group’s licences expire at various times. Russian legislation, adopted after the issuance of many of the Group’s licences, provides that licences are now granted for a time equal to the economic viability of the relevant field. As long as the Group meets certain conditions, such as compliance with approved development programmes and other licence requirements, each of the Group’s licences issued prior to this legislation can be extended, upon expiration, for the economic life of the relevant fields. None of the Group’s production licences expire prior to 2014. The Group’s production licence for the Khvoinoye field expires in March 2014, while the Group’s exploration licences for the Cheremushskiy and Pushkarihinskiy oil fields expire in January 2014. The Group is working on the extension of the Cheremushskiy and Pushkarihinskiy licences and will be applying for the extension of the Khvoinoye licence pursuant to current Russian legislation. The Group is required to maintain the exploration works and levels of oil production for each field in accordance with the annual work programme, which must be approved by the Federal Service on Ecological, Technological and Nuclear Supervision. Furthermore, the Group is obliged to meet various requirements imposed by the licences, including requirements relating to the exploration activity set forth in its exploration licences, and ensure that fields are developed in accordance with agreed upon schedules. See ‘‘Risk Factors – The Group’s subsoil licences may be suspended or revoked prior to their expiration and the Group may be unable to obtain or maintain various licences, permits or authorisations’’. To date there have been no unsuccessful renewal applications.

Timano-Pechora Region The Timano-Pechora region is located in north-western Russia. The region is home to four of the Group’s oil fields: Middle Kharyaga, North Kharyaga, Lek-Kharyaga and Kolvinskoye. In addition, the Company has seven exploration and production licences in the region with total resources of approximately 560 mmboe under the Russian classifications (D1+D2). The Timano-Pechora basin is bound on the east and south by the Ural uplift and on the west by the Russian platform. Oil wells in the region are located at an average depth of 3,800 metres, in sediments ranging in age from the Ordovician to the Triassic period. The northern extent of the basin is open to the Kara Sea and is not well defined. The Group’s production of oil in the Timano-Pechora region accounted for 42.3%, 40.2% and 31.1% of the Group’s total oil production for the years ended 31 December 2012, 2011 and 2010, respectively. The Group holds two production licences, six exploration and three combined exploration and production licences in the region. Pechoraneft, an exploration and production subsidiary of the Group, is the operator of the Group’s four oil fields in the Timano-Pechora region. The Group has received a tax exemption on production at the Kolvinskoye and North Kharyaga oil fields under which it will pay no MET on the first 15 million tonnes (approximately 110 million barrels) produced through 2015 at each field. In 2012, the Group extended its presence in the Timano-Pechora region through its acquisition of an exploration licence for the West-Osoveiskoye block located on the eastern side of the Kolvinskoye oil field with an estimated 87.7 million barrels under Russian reserves classification (D1+D2). In addition, in November 2012, the Group obtained five exploration licences located in the Timano- Pechora region close to the Group’s existing operations through a tender process. Total resources under these five licences are estimated at 325 mmbbl and 14.6 bcm of gas (86.0 mmboe) under Russian reserves classification (D1+D2). In December 2012, the Group obtained an exploration and production licence in the Timano-Pechora region; the licence block’s crude resources are estimated at 61.1 mmbbl under Russian reserves classification (D1+D2).

95 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA The following table sets forth the Group’s estimated proven crude oil reserves and proven and probable crude oil reserves under PRMS classification in the Timano-Pechora region, by major oil field, as of 31 December 2012, 2011 and 2010.

Oil Reserves (thousand barrels)

2012 2011 2010

Proven and Proven and Proven and Location Proven Probable Proven Probable Proven Probable

Middle Kharyaga ...... 3,627 18,875 4,680 21,161 4,554 19,604 North Kharyaga...... 26,470 52,072 24,293 48,112 21,642 47,427 Lek Kharyaga...... 29,820 85,841 32,371 86,432 32,399 88,461 Kolvinskoye...... 79,118 238,097 105,563 253,281 96,737 239,265

Total ...... 139,035 394,885 166,907 408,986 155,332 394,757

The following table sets forth the Group’s production in the Timano-Pechora region for the years ended 31 December 2012, 2011 and 2010.

As of 31 December

2012 2011 2010

Location (Thousand barrels) Middle Kharyaga...... 841 766 1,072 North Kharyaga ...... 1,577 1,690 1,289 Lek Kharyaga...... 1,179 1,701 2,510 Kolvinskoye ...... 4,757 3,021 94

Total...... 8,354 7,178 4,964

As of 31 December 2012, the Group had 114 wells in the Timano-Pechora region, 91 of which were active production wells, and 23 active injection wells. As of 31 December 2011, the Group had 102 active wells in the Timano-Pechora region, 85 of which were active production wells and 17 active injection wells. As of 31 December 2010, the Group had 75 active wells in the Timano-Pechora region, 65 of which were active production wells, and 10 active injection wells.

Middle Kharyaga The Middle Kharyaga oil field is situated in the northern part of the Timano-Pechora basin and covers an area of approximately 11.5 square kilometres. This oil field was discovered in 1988, with the commercial production of crude oil starting in 2002. The Group started its operations at the Middle Kharyaga oil field through acquisition of Pechoraneft in 2005. The Group holds a production licence for the Middle Kharyaga oil field, which expires in 2015. See ‘‘Risk Factors – Risks Relating to the Group and the Oil and Gas Industry – The Group’s subsoil licenses may be suspended or revoked prior to their expiration and the Group may be unable to obtain or maintain various licenses, permits or authorisations’’.

North Kharyaga The North Kharyaga oil field is located approximately 15 kilometres from the Middle Kharyaga oil field and covers an area of approximately 67.7 square kilometres. This oil field was discovered in 1977, with the commercial production of crude oil starting in 2006. The Group started its operations at the North Kharyaga oil field through the acquisition of a combined exploration and production licence at a public auction in 2005. The Group holds a combined licence for exploration and production for the North Kharyaga oil field, which expires in 2030. See ‘‘Risk Factors – The Group’s subsoil licences may be suspended or revoked prior to their expiration and the Group may be unable to obtain or maintain various licences, permits or authorisations’’.

96 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA In 2007, the Group constructed an inter-field pipeline that enables oil produced at the North Kharyaga oil field to be taken to Middle Kharyaga treatment and production facility. In 2012, one production well was drilled and placed into production at the North Kharyaga oil field. Lek Kharyaga The Lek Kharyaga oil field is located approximately 12 kilometres from the Middle Kharyaga oil field and covers an area of approximately 27.8 square kilometres. This field was discovered in 1980, with the commercial production of crude oil starting in 2007. The Group started its operations at the Lek Kharyaga oil field through a combined exploration and production licence at a public auction in 2005. The Group holds a combined exploration and production licence for the Lek Kharyaga oil field, which expires in 2030. See ‘‘Risk Factors – The Group’s subsoil licences may be suspended or revoked prior to their expiration and the Group may be unable to obtain or maintain various licences, permits or authorisations’’. The Lek Kharyaga oil field is connected through a pipeline to the treatment and production facility at the Middle Kharyaga oil field. Kolvinskoye The Kolvinskoye oil field, which is located approximately 150 kilometres from the Kharyaga oil fields and covers an area of approximately 118.4 square kilometres, was acquired in 2006. Now one of the Group’s main producing oil fields, the Kolvinskoye oil field began production in September 2011. The Group holds a production licence for the Kolvinskoye oil field, which expires in October 2018. Sixteen production wells were drilled in 2012 at the Kolvinskoye oil field, while eleven production wells were placed into production. Drilling of three additional production wells was also in progress as of 31 December 2012. The Group aims to drill six to eight production and exploration wells at the Kolvinskoye oil field in 2013. In 2012, the Group reviewed its operations at the Kolvinskoye oil field to evaluate its reserves and potential, update its geological model and prepare an updated drilling and development plan. A new geologic model, prepared with assistance from Schlumberger and independently assessed by D&M, revealed the field’s geology to be more complex than initially anticipated. Based on new 3D seismic data available and recent drilling statistics from approximately 40 production wells and one exploration well, a new water-flooding programme was introduced and a better well management system implemented. In addition, the Group began testing and verifying undeveloped Permian and Silurian formations. As a result of the review, a reduction in net 2P reserves of approximately 6% was reported in the field’s 2012 audit by D&M, and the Group stabilised production at the field at approximately 11,500 bopd.

Volga-Urals Region The Volga-Urals oil region in the southern part of European Russia extends from the west flank of the Ural mountains to west of the Volga River. The Volga-Ural petroleum basin extends over an area of 700,000 square kilometres located between the Volga River on the west, the Ural mountains on the east and the Peri-Caspian depression to the south. The overall structural fabric of the Volga-Ural basin is a series of three ridges separated by elongated depressions; oil wells in the region are at an average depth of 2,000 metres. The Group holds 13 oil fields in the Volga-Urals region, primarily in the Samara region and Tatarstan through operations in AROG. The Group’s production of oil in the Volga-Urals region accounted for 37.5%, 39.8% and 46.3% of the Group’s total oil production for the years ended 31 December 2012, 2011 and 2010, respectively. The Group holds 12 production licences and one combined exploration and production licences in the region.

97 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA The following table sets forth the Group’s estimated proven crude oil reserves and proven and probable crude oil reserves under PRMS classification in the Volga-Urals region, by major oil field, as of 31 December 2012, 2011 and 2010.

Oil Reserves (thousand barrels)

2012 2011 2010

Proven and Proven and Proven and Location Proven Probable Proven Probable Proven Probable

Novo Kievskoye...... 9,100 10,983 6,298 18,085 4,777 18,605 Kochevnenskoye ...... 547 547 1,066 1,066 1,259 1,259 West Kochevnenskoye ..... 136 1,500 290 1,925 403 2,040 Solnechnoye ...... 3,274 3,274 1,863 2,739 644 2,351 Kovalevskoye ...... 3,143 5,724 4,996 7,910 5,633 9,300 Borschevskoye...... 83 83 58 470 53 53 Kulturnenskoye...... 139 293 385 906 107 107 West Borschevskoye...... — — — 670 — 677 South Kultashikhinskoye. 854 854 1,352 2,454 1,076 2,428 South Solnechnoye...... 563 1,363 1,780 1,780 279 279 Stepnoozerskoye...... 84,214 122,339 75,085 115,925 76,068 116,525 Yelginskoye...... 13,939 15,864 14,876 16,801 15,781 17,856

Total...... 115,992 162,824 108,049 170,731 106,080 171,480

The following table sets forth the Group’s production in the Volga-Urals region for the years ended 31 December 2012, 2011 and 2010.

As of 31 December

2012 2011 2010

Location (Thousand barrels) Novo Kievskoye ...... 873 933 967 Kochevnenskoye ...... 266 399 547 West Kochevnenskoye...... 75 117 200 Solnechnoye ...... 1,882 705 470 Kovalevskoye...... 647 1,335 1,600 Borschevskoye...... — — 16 Kulturnenskoye...... 12 36 — Saratovskoye...... — — 6 South Kultashikhinskoye...... 205 489 339 South Solnechnoye ...... 180 59 50 Stepnoozerskoye ...... 2,054 2,039 2,142 Yelginskoye...... 1,203 1,006 1,056

Total...... 7,408 7,120 7,391

As of 31 December 2012, the Group had 351 active wells in the Volga-Urals region, 336 of which were active production wells, and 15 active injection wells. As of 31 December 2011, the Group had 328 active wells in the Volga-Urals region, 312 of which were active production wells, and 16 active injection wells. As of 31 December 2010, the Group had 324 production wells in the Volga-Urals region, 308 of which were active production wells, and 16 active injection wells.

98 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA The following is a summary of the Group’s five principal oil fields in the Volga-Urals region. Stepnoozerskoye The Stepnoozerskoye oil field is the Group’s largest oil field in Tatarstan. This oil field was discovered in 1967 and covers an area of approximately 154 square kilometres. It was brought into production in 1999. The Group started its operations at this field through acquisition of Tatnefteotdacha by NK Alliance in 2005. The Group holds a combined exploration and production licence for the Stepnoozerskoye oil field, which expires in 2018. See ‘‘Risk Factors – The Group’s subsoil licences may be suspended or revoked prior to their expiration and the Group may be unable to obtain or maintain various licences, permits or authorisations’’. The Stepnoozerskoye oil field is connected to the Transneft pipeline system through the Tatneft transportation system. Transportation agreements with Tatneft are entered into annually. The facilities at the Stepnoozerskoye oil field include one booster pipeline pumping station, three oil heaters, 16 group metering stations, one commercial metering station, 76 kilometres of oil pipelines and 2 kilometres of water pipelines. Seven production wells were drilled at the Stepnoozerskoye oil field in 2012 and six production wells were placed into production. Solnechnoye The Solnechnoye oil field was discovered and brought into production in 2005 and covers an area of approximately 2.3 square kilometres. The Group holds a combined exploration and production licence for the Solnechnoye oil field, which expires in 2027. Production at the Solnechnoye oil field significantly increased in 2012 compared to 2011 due to an expanded drilling program at the field. See ‘‘Risk Factors – The Group’s subsoil licences may be suspended or revoked prior to their expiration and the Group may be unable to obtain or maintain various licences, permits or authorisations’’. Production at the Solnechnoye oil field significantly increased in 2012 compared to 2011 due to an expanded drilling program at the field. Yelginskoye The Yelginskoye oil field is situated in the south-east region of Tatarstan and covers an area of approximately 25.0 square kilometres. The Yelginskoye oil field was discovered in 1969, with the commercial production of crude oil starting in 1996. The Group holds a combined exploration and production licence for the Yelginskoye oil field, which expires in 2018. Novo Kievskoye The Novo Kievskoye oil field is situated in the Samara region and covers an area of approximately 6.0 square kilometres. This oil field was discovered in 1975, with commercial production of crude oil starting in 2000. The Group holds a development and production licence for the Novo Kievskoye oil field, which expires in 2016. Kovalevskoye The Kovalevskoye oil field is situated in the Samara region and covers an area of approximately 4.4 square kilometres. This oil field was discovered and put into commercial production of crude oil in 2006. The Group holds a development and production licence for the Kovalevskoye oil field, which expires in 2016.

Tomsk Region The Tomsk region is located in Western Siberia in Russia and covers an area of approximately 317,000 square kilometres. The region sits on the Siberian Platform – one of the largest oil-bearing tectonic elements in the world. The Group operates four oil fields in the region: Khvoinoye, Klyuchevskoye, Puglalymskoye and Middle Nyurola oil fields. The Group’s production of oil in the Tomsk region accounted for 16.3%, 16.4% and 19.0% of the Group’s total oil production for the years ended 31 December 2012, 2011 and 2010, respectively. Production operations in the Tomsk regions are conducted principally through two wholly owned subsidiaries – VTK and Khvoinoye. The Group holds three production licences, one exploration licence and one combined exploration and production licence in the region. A drilling programme was expanded at the Puglalymskoye field in 2012 to further develop the field and grow production in this region.

99 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA The following table sets forth the Group’s estimated proven crude oil reserves and proven and probable crude oil reserves under PRMS classification in the Tomsk region, by major oil field, as of 31 December 2012, 2011 and 2010.

Oil Reserves (thousand barrels)

2012 2011 2010

Proven and Proven and Proven and Location Proven Probable Proven Probable Proven Probable

Middle Nyurola...... 8,604 25,710 8,730 25,932 6,119 24,614 Klyuchevskoye...... 5,122 8,437 5,809 9,062 4,626 9,713 Puglalymskoye...... 8,261 8,290 7,777 7,811 322 7,347 Khvoinoye ...... 6,867 13,420 6,463 14,556 3,798 14,431

Total ...... 28,854 55,857 28,779 57,361 14,865 56,105

The following table sets forth the Group’s production in the Tomsk region for the years ended 31 December 2012, 2011 and 2010.

As of 31 December

2012 2011 2010

Location (Thousand barrels) Middle Nyurola ...... 1,126 1,190 1,045 Klyuchevskoye...... 709 876 1,177 Puglalymskoye ...... 642 346 364 Khvoinoye ...... 737 528 437

Total...... 3,214 2,940 3,024

As of 31 December 2012, the Group had 111 active wells in the Tomsk region, 78 of which were active production wells, and 33 active injection wells. As of 31 December 2011, the Group had 91 active wells in the Tomsk region, 59 of which were active production wells and 32 active injection wells. As of 31 December 2010, the Group had 88 active wells in the Tomsk region, 60 of which were active production wells, and 28 active injection wells.

In addition, the Group acquired gas production assets in the Tomsk region through its acquisition of SN- Gasproduction in October 2012, see ‘‘ – Gas Operations’’.

Middle Nyurola The Middle Nyurola oil field is approximately 25 square kilometres in area and has a single layer reservoir consisting of 12 metre Jurassic sandstone. The field was discovered in 1965, with the commercial production of crude oil starting in 2000. It has been extensively explored and its oil- bearing areas are well delineated. The sandstone is relatively homogenous across the Middle Nyurola oil field, making it relatively easy to appraise the reservoir. The Group started its operation at the Middle Nyurola oil field in 1999 through the acquisition of VTK that held a combined exploration and production licence for the Middle Nyurola, Klyuchevskoye and Puglalymskoye oil fields.

The Group holds a combined licence for exploration and production for the Middle Nyurola, Klyuchevskoye and Puglalymskoye oil fields. The Group’s licence for these oil fields expires in 2019. See ‘‘Risk Factors – The Group’s subsoil licences may be suspended or revoked prior to their expiration and the Group may be unable to obtain or maintain various licences, permits or authorisations’’.

In 2005, the Group’s 112 kilometer long direct pipeline was connected to the Transneft pipeline as well as to the Group’s commercial metering system on the neighbouring Luginetskoye oil field. The oil treatment facility at the Middle Nyurola oil field was completed in 2006. Treated oil is first stored in tank farms within the field before it is transported via a 109 kilometre pipeline to the Transneft network. The associated water separated in the oil treatment facility is re-injected in the field.

100 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA Khvoinoye The Khvoinoye oil field is situated approximately 150 kilometres to the north from the Middle Nyurola oil field and covers an area of approximately 20.3 square kilometres. Like the Middle Nyurola oil field, the Khvoinoye oil field consists of a sandstone base. The Khvoinoye oil field was discovered in 1984, with the commercial production of crude oil starting in 1997. The Group started its operations at the Khvoinoye oil field through the acquisition of Khvoinoye in 2005. The Group holds a production licence for the Khvoinoye oil field, which expires in March 2014. See ‘‘Risk Factors – The Group’s subsoil licences may be suspended or revoked prior to their expiration and the Group may be unable to obtain or maintain various licences, permits or authorisations’’. The Khvoinoye oil field is accessed by an all-weather road which is connected to the regional highway and it is also connected to the Alexandrovsky refinery, owned by the Sever Group. Klyuchevskoye The Klyuchevskoye oil field is situated approximately 24 kilometres from the Middle Nyurola oil field and covers an area of approximately 10.2 square kilometres. This oil field was discovered in 1986, with commercial production of crude oil starting in 2001. Puglalymskoye The Puglalymskoye oil field is situated approximately 13 kilometres from the Middle Nyurola oil field and covers an area of approximately 22.4 square kilometres. It was discovered in 1971, with the commercial production of crude oil starting in 2005. The Puglalymskoye and Klyuchevskoye oil fields have a joint infrastructure system with the Middle Nyurola oil field. Six production wells were drilled at the Puglalymskoye oil field in 2012, with two production wells placed into production.

Kazakhstan In Kazakhstan, the Group conducts production activities at the Zhanatalap Eastern Wing (‘‘Zhanatalap’’) oil field through its 80% owned subsidiary, Potential Oil, at the Begaidar block, in the Atyrau region of Kazakhstan on the northern shore of the Caspian Sea. The remaining 20% in Potential Oil is owned by First International Oil Corporation Limited. The Begaidar block covers an area of approximately 4,300 square kilometres and is part of the oil- and gas-bearing area between the Ural and Volga rivers. The Group’s production of oil in Kazakhstan accounted for 3.9%, 3.6% and 3.6% of the Group’s total oil production for the years ended 31 December 2012, 2011 and 2010, respectively. Generally, in Kazakhstan the rights for exploration and production are granted on the basis of contracts for subsoil use that are entered into between a subsoil user and the competent governmental authority. Subsoil use contracts are entered into for a specified period of time, but a subsoil user may extend such contract upon the expiration of the term. Subsoil use contracts may be terminated by the competent governmental authorities if a subsoil user does not meet its contractual obligations, including, but not limited to, periodic payment of royalties and taxes to the government and the satisfaction of mining, environmental, safety and health requirements. In 2001, Potential Oil entered into a subsoil use contract with the Ministry of Energy and Mineral Resources of the Republic of Kazakhstan for the exploration and production at the Begaidar block, which expires in 2031. See ‘‘Risk Factors – The Group’s subsoil licences may be suspended or revoked prior to their expiration and the Group may be unable to obtain or maintain various licences, permits or authorisations’’. Pursuant to the terms of this contract, the exploration stage was completed in 2009, and the Group started commercial development of its fields at the Begaidar block. Crude oil from these oil fields is delivered to the Transneft pipeline system through the Sazankurak and the KazTransOil transportation systems.

101 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA The following table sets forth the Group’s estimated proven crude oil reserves and proven and probable crude oil reserves under PRMS classification at the Zhanatalap field, as of 31 December 2012, 2011 and 2010.

Oil Reserves (thousand barrels)

2012 2011 2010

Proven and Proven and Proven and Location Proven Probable Proven Probable Proven Probable

Zhanatalap ...... 3,912 8,148 5,879 10,776 10,138 15,922

The following table sets forth the Group’s production at the Zhanatalap field for the years ended 31 December 2012, 2011 and 2010.

As of 31 December

2012 2011 2010

Location (Thousand barrels) Zhanatalap...... 763 642 582

As of 31 December 2012, the Group had 56 active wells in Kazakhstan, 52 of which were active production wells and four active injection wells. As of 31 December 2011, the Group had 42 active wells in Kazakhstan, 38 of which were active production wells, and four active injection wells. As of 31 December 2010, the Group had 37 active wells in Kazakhstan, 34 of which were active production wells and three active injection wells. The Zhanatalap oil field was discovered in 1967 and covers an area of approximately 2.4 square kilometres. The Group commenced pilot operation of the Zhanatalap oil field in January 2006. Four production wells were drilled at the Zhanatalap oil field in 2012.

Crude Oil Sales The Group sells crude oil through export (including CIS export) and domestic sales as well as swap contracts. The Group refines more crude oil than it produces at its fields. However, because the transshipment of crude oil by the Group’s subsidiaries to the Khabarovsk Refinery is not cost- effective, the Group enters into swap arrangements and sells the balance of its crude oil on the domestic, CIS and international markets. Depending upon market conditions, the Group participates in oil swap arrangements, primarily with TNK-BP. Pursuant to these swap agreements, the Group’s subsidiaries Pechoraneft, Tatnefteotdacha and Saneco sell crude oil to TNK-BP for delivery to the Slavneft-YANOS and Saratov refineries. In turn, TNK-BP sells its crude oil to the Group for delivery to the Khabarovsk Refinery. Crude oil refined by the Khabarovsk Refinery pursuant to these swaps can equal as much as 40% of the crude oil produced by the Group in a given year. Crude oil delivered pursuant to these swap arrangements is considered by the Group to be an intergroup sale. Pechoraneft and Tatnefteotdacha also transport crude oil via the Transneft pipeline network to customers in the domestic market (the Moscow, Yaroslav and Saratov refineries), the CIS market (the Novopolotsky and Mozyrsky refineries in Belorussia) and international markets (Primorsk terminal, Poland and Germany). Crude oil produced by Saneco is transported via railroad to Belarus, Kyrgyzstan and mini-refineries in Russia, via the Transneft pipeline to customers in Russia (the Saratov and Afipsk refineries) and the CIS market (the Novopolotsky and Mozyrsky refineries in Belarus) and to international markets (Novorossiisk terminal, Germany and Poland). VTK sells crude oil directly to the Group for delivery to the Khabarovsk Refinery, while Pechoraneft, Saneco and Tatnefteotdacha supplied oil to the refinery through swap agreements. Crude oil is transported by pipeline to the Uyar loading station in the Krasnoyarsk region and to the Meget loading station in the Irkutsk region, and subsequently transferred to tank rail cars for railway transportation to the Khabarovsk Refinery. Crude oil produced by Potential Oil is transported using a combination of the Transneft pipeline, KazTransOil pipeline, railway and motor transport to the domestic market of Kazakhstan and to the export markets via the Primorsk terminal.

102 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA Primary off-takers of the Group’s crude oil include Gunvor Trading and Vitol SA (via Primorsk terminal), Concept Oil Services Ltd (via Novorossiisk terminal), Altex Handelaund Beratun GmbH (to Germany and Poland) and the Group’s affiliate, Lia Oil (to Germany and Poland). The following table sets forth the Group’s crude oil sales volumes and prices for export and domestic markets for the years ended 31 December 2012, 2011 and 2010, excluding intra-group crude oil sales.

For the year ended 31 December

2012 2011 2010

Export CIS Domestic Total Export CIS Domestic Total Export CIS Domestic Total

Sold volume, thousand barrels ...... 7,172 266 3,501 10,938 6,172 321 3,334 9,827 4,988 1,160 3,977 10,124 Gross price, USD/ barrel...... 107.61 51.41 61.53 91.49 107.40 60.12 59.16 89.49 76.40 78.92 40.92 67.99 Net price(1), USD/ barrel...... 56.63 51.41 52.14 55.07 55.93 60.12 50.13 54.10 42.46 41.50 34.71 39.31 Selling expenses, USD/ barrel...... 6.85 11.39 5.20 6.43 6.74 14.22 3.40 5.85 5.74 5.83 3.51 4.87 Netback price(2), USD/ barrel...... 49.78 40.02 46.94 48.64 49.19 45.90 46.73 48.25 36.72 35.67 31.20 34.44 Revenue, USD thousands...... 406,132 13,658 182,564 602,354 345,192 19,320 167,144 531,656 211,786 48,140 138,017 397,943

(1) Net price means the gross price less VAT or applicable export duties. (2) Netback prices are calculated by deducting from the gross price: VAT (for Russian domestic sales); railway and pipeline transportation costs and export duties, brokers’ commissions and certain other costs (for export sales); or transportation, brokers’ commissions and certain other costs (for CIS countries export).

Joint Venture with Repsol In 2011, the Group reached an agreement with Repsol to form a joint venture, AROG, to expand its exploration and production growth in Russia. In August 2012, Repsol and the Group completed the first phase of the formation and capitalisation of AROG, in which the Group holds 51% and Repsol 49%. Though the Group holds a majority stake in AROG, AROG is not consolidated in the Group’s financial statements, however the Group continues to consolidate the results of Saneco and Tatnefteotdacha. In August 2012, the Group contributed Saneco, with brownfield upstream assets located in the Volga- Urals regions and total crude oil production of 4.2 mmbbl in 2012 and 2P reserves of 24.6 mmbbl as of 31 December 2012. In December 2012, the Group contributed Tatnefteotdacha’s upstream assets located in the Tatarstan region with total crude oil production of 3.3 mmbbl and 2P reserves of 138.2 mmbbl as of 31 December 2012. In January 2013, Repsol contributed its Eurotek subsidiary, which holds two gas exploration and production licences, and also paid USD 116,728 thousand in cash to the Group. In March 2013, AROG began commercial gas production from the Syskonsyninskoye field in the Khanty-Mansiysk region of Russia, with initial daily gas production of 855,000 cubic metres (5,350 boe) per day. 163 mmboe of AROG’s reserves are included in the Group’s consolidated oil and gas reserves. In addition, the Group has an equity interest in the non-consolidated oil and gas reserves of AROG in proportion to the Group’s ownership stake in the joint venture. Under the Group’s joint venture agreement with Repsol, AROG has a right of first refusal to acquire and participate in new oil and gas upstream business opportunities identified by the Group in Russia that are not within a 100 km radius from areas, licensed blocks, fields or sites held by, or which cannot be exploited with the existing infrastructure of, Eastern Transnational Company, Pechoraneft, Khvoinoye, Kolvinskoye or Potential Oil.

Gas Operations As part of its long-term growth strategy, the Group entered the Russian gas market in 2012 to capitalise on market conditions in the gas industry as well as Russia’s position as the largest holder of gas reserves and second largest gas consumer in the world. In October 2012, the Group acquired 100% of the shares in Polonio Holdings Limited and its subsidiary, SN-Gasproduction, for USD 127,768 thousand. The Group aims for natural gas production to ultimately represent as much as 20% of the Group’s total hydrocarbon production in the long-term. SN-Gasproduction holds two gas licences for the Ust-Silginskiy and Kargasokskiy-2 blocks in the Tomsk region, which facilitate

103 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA synergies with the Group’s regional operations. The 2P gas reserves of SN-Gasproduction were estimated by D&M at 111 mmboe under the PRMS classification as of 31 December 2012. Gas production commenced in February 2013 with initial daily gas production of approximately 700 thousand cubic metres (about 4,500 barrels of oil equivalent).

Downstream Operations The Group’s downstream business has two principal areas of activity. * Refining: The Group conducts its oil refining operations at the Khabarovsk Refinery, which as of 31 December 2012 had a refining capacity of 90,000 barrels per day. In 2012, 2011 and 2010, the Khabarovsk Refinery processed 29.3, 26.9 and 23.7 mmbbl of oil; and * Marketing and Sales: The Group markets refined petroleum products to (i) retail customers through its own network of filling stations and (ii) merchants through wholesale petroleum products terminals located in the Russian Far East as well as exports products through large and small third-party wholesalers to neighbouring Asian markets, namely South Korea, Japan and China.

Refining The Group owns one of the only two major oil refineries currently located in the Russian Far East, the Khabarovsk Refinery. This refinery’s geographical proximity to growing Asian markets is of strategic importance for the Group, see ‘‘ – Strategy’’. In March 2009, the Group disposed of the Alexandrovsky Refinery located in the Tomsk region for net cash consideration of USD 3,397 thousand. Khabarovsk Refinery The Group is a leading producer of advanced petroleum products in the Russian Far East. In 2002, the Khabarovsk Refinery was the first company to start production of A-98 gasoline in the Russian Far East. In 2005, it was the first refinery in the Russian Far East to begin production of gasoline with specifications in compliance with corresponding European standards EN-228:2004 (Regular, Euro-92/4, Premium, Euro-95/4, Super and Euro-98/4). In 2006, the Khabarovsk Refinery began to produce high-octane gasoline with improved cold start-up characteristics. In 2007, the Khabarovsk Refinery in cooperation with BASF started production of green eco-gasoline with high detergency. As of 31 December 2012, the Khabarovsk Refinery had a Nelson complexity index (a measure of refining capability) of 3.8. The average depth of crude oil processing at the Khabarovsk Refinery in 2012 was approximately 65%. Following the completion of the ongoing modernisation, the Khabarovsk Refinery’s Nelson complexity index is expected to increase to at least 9.0, and the depth of refining is expected to improve to more than 90.0%. Higher value light products represented approximately 58% of total petroleum products output at the refinery in 2012.

104 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA The following table sets forth data on the Khabarovsk Refinery, including its petroleum products output by type of product in thousand tonnes and as a percentage of the total refined products production volume for the years ended 31 December 2012, 2011 and 2010.

As of 31 December

2012 2011 2010

(Thousand tonnes, unless Product otherwise noted) Nameplate capacity ...... 4,350.0 4,350.0 4,350.0 Actual capacity (volume of processed crude oil)...... 3,935.5 3,702.8 3,264.0 Utilisation rate, % ...... 90.2 84.8 74.7 Refining depth, % ...... 64.8 64.4 62.5 Nelson complexity ...... 3.8 3.7 3.7 Supplies Crude oil supplied ...... 3,950.2 3,698.0 3,254.3 Supplies other than crude oil1 ...... 4.2 6.7 3.1

Commercial petroleum products output Types of petroleum products (Thousand tonnes, unless otherwise noted) Fuel oil (mazut) ...... 1,329.1 1,239.0 1,131.0 Diesel, including:...... 265.7 408.3 424.8 Diesel Winter ...... 201.8 240.7 219.7 Diesel Artic ...... 0.0 1.5 3.0 Diesel Summer ...... 63.9 166.1 202.1 Ship fuel...... 1,065.3 863.7 669.0 Petrol, including ...... 418.8 387.4 369.0 Petrol A-80...... 32.9 45.2 54.8 Petrol A-92...... 224.5 217.2 190.3 Petrol A-95...... 143.5 110.8 101.8 Petrol A-98...... 17.9 14.3 22.2 Naphtha...... 218.8 296.1 258.0 Jet fuel (kerosene)...... 277.4 188.9 154.8 Other commercial petroleum products ...... 211.7 160.2 115.0

Total commercial petroleum products output...... 3,786.7 3,543.5 3,121.6

Modernisation of the Khabarovsk Refinery Prior to 1998 when the Khabarovsk Refinery was acquired by NK Alliance, the Khabarovsk Refinery was a medium-capacity fuel supplier with a limited range of technological processes. In 2008, the Group launched a significant modernisation programme at the Khabarovsk Refinery to widen its production processes for a higher degree of oil refining, in order to produce lighter and higher value petroleum products, primarily diesel fuel. The modernisation programme contemplated the addition of new refinery facilities and upgrade of existing capabilities without suspending on-going operations. The first stage of the upgrade of the Khabarovsk Refinery, completed in 2007, involved the reconstruction of a catalytic reforming unit and the construction of an isomerisation block. Due to these developments, the refinery was the first in the Russian Far East to successfully produce 98- octane petrol. During the second stage of the modernisation programme, completed in 2012, the reforming capacity of the refinery was upgraded to 350,000 tonnes per year. The Group strives to ensure that the Khabarovsk Refinery produces high-quality products; for example, its GreenEco gasoline brand features improved operating and environmental performance with basic parametres in compliance with the Euro-4 standards. The GreenEco formulation was jointly developed by the Group, Shell and BASF. Specifically for the harsh climatic conditions encountered in the Russian Far East region, the Khabarovsk refinery has developed a winter version of the high-octane GreenEco gasoline with improved cold start up characteristics.

105 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA To address increasing demand for petroleum products and the evolving pattern of the Russian For Eastern markets, the scope of the Khabarovsk Refinery modernisation has gradually been expanded to enhance refining capacity, to improve quality of petroleum products and to facilitate crude oil supplies to the refinery through the ESPO oil pipeline. From 2009 to 2012, the Khabarovsk Refinery launched seven new units with upgraded utilities, infrastructure and off-sites. The refinery’s capacity was increased from 70,000 bopd to 90,000 bopd, and the Group’s current aim is to further increase capacity to 100,000 bopd. A new hydrocracker and other hydroprocessing units are expected to be launched into test operations in the third quarter of 2013. As of February 2013, the project progress is estimated at more than 95% complete in engineering and procurement, and 83% complete in construction works. The main turn- key contractor of the Group working on the modernisation of the Khabarovsk Refinery is the Spanish developer Tecnicas Reunidas, S.A. A new hydroprocessing complex will allow the refinery to make its entire line of diesel products fully compliant with Euro-5 standards as well as introduce new products such as Jet A-1 aviation fuel. As a result, the Group estimates the sulphur content of produced gasoline could potentially decrease from less than 100 parts per million (‘‘ppm’’) to less than 50 ppm, and from less than 0.33% to less than 0.0035% for produced diesel. The hydroprocessing project is being financed by the Group’s cash flows from operations and through a 13-year loan from Vnesheconombank, with an insurance guarantee from the Spanish state agency CESCE. Almost all real estate facilities and some production facilities of the Khabarovsk Refinery as well as 95.49% of the shares in Open Joint Stock Company Khabarovsk Oil Refinery (being 97.73% of the shares in Open Joint Stock Company Khabarovsk Oil Refinery owned by the Group) are pledged in favour of Vnesheconombank as security for obligations of Open Joint Stock Company Khabarovsk Oil Refinery under the financing provided by Vnesheconombank. The hydroprocessing complex includes a vacuum gasoil hydrocracking unit, an aviation kerosene and diesel hydrotreating unit, a hydrogen production unit and a sulphur recovery unit. These units involve advanced technologies of the world’s leading licensors–Shell Global Solutions, Foster Wheeler and Technip-KTI. The second stage of the upgrade is expected to be put into test operations in the third quarter of 2013. The table below sets out certain current output metrics of the Khabarovsk Refinery and those which the Group aims to be able to potentially achieve following the modernisation works at the Khabarovsk refinery.

As of 31 December

Pre-modernisation Post-modernisation (thousand tonnes per year) Atmospheric distillation ...... 2,950 3,300 Vacuum distillation ...... 1,400 1,700 Fuel oil vacuum distillation ...... — 1,800 Catalytic reforming ...... 300 390 Hydrofining ...... — 1,180 Hydrocracking...... — 506 Asphaltum oil visbreaking unit...... — 750

The total cost for the expanded refinery modernisation is estimated at USD 1.4 billion. Currently, the products produced by the Khabarovsk Refinery in greatest demand are gasoline, kerosene, winter diesel and low-viscosity marine fuel. After commissioning the new hydroprocessing complex, the output of premium-grade products will become significant as well. In addition, Euro-5 diesel and JetA-1 aviation fuel will be added to the list of existing products supplied both for domestic needs and export shipments. The Khabarovsk Refinery is not connected to the Transneft or Transnefteproduct pipeline systems. As a result, crude oil and petroleum products must be transported to and from Khabarovsk by other means, primarily by rail. It is expected that after the Khabarovsk Refinery is connected to the ESPO oil pipeline, currently planned for 2014, the Group will significantly reduce its transportation costs and expects to increase its product turnover starting from 2014. See ‘‘ – Transportation and Logistics – Pipelines’’.

106 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA The Khabarovsk Refinery has its own autonomous energy supply system which has a power generation capacity sufficient for its energy needs.

Crude Oil Suppliers For the year ended 31 December 2012, the main suppliers of crude oil processed at the Khabarovsk Refinery were TNK-BP, Tomskgazprom, VTK and Bashneft. Approximately 26% of crude oil arrives at the Khabarovsk Refinery from various Group swap arrangements. The Khabarovsk Refinery processes crude oil under tolling agreements with Alliance Oil, a wholly owned subsidiary of the Group. Services provided under the tolling agreements include processing of the crude oil purchased by the Group and related storage and transportation services for petroleum products. VTK sells crude oil directly to the Group for delivery to the Khabarovsk Refinery, while Pechoraneft, Saneco and Tatnefteotdacha supplied oil to the refinery through swap agreements. The following chart sets forth the main suppliers of crude oil processed at the Khabarovsk Refinery for the years ended 31 December 2012, 2011 and 2010.

As of 31 December

2012 2011 2010

Supplier (tonnes) TNK-BP ...... 2,683,717 1,967,556 1,359,981 Tomskgazprom ...... 365,021 452,000 344,950 Russneft ...... 330,323 301,186 276,569 VTK...... 195,945 193,884 339,798 Negusneft...... 180,027 300,832 289,475 Bashneft ...... 179,647 — — Lukoil ...... — 291,443 31,873 Transeft...... — 126,326 32,823 Surgutneftegaz ...... — 120,326 375,957 Other...... 51,785 92,787 246,206

Total...... 3,986,465 3,840,340 3,297,632

Marketing and Sales The Group’s network of onshore depots and petrol filling stations, as well as its sea terminals, enable it to operate within the entire value chain: wholesale and retail sectors, complex logistics with transshipment and storage services and bunker supply in the Khabarovsk, Vladivostok, Sakhalin and Kamchatka regions of Russia. The Group derives a major part of its revenue from sales of refined petroleum products. For the years ended 31 December 2012, 2011 and 2010, the Group’s revenues from sales of refined petroleum products were USD 2,787,761 thousand, USD 2,496,218 thousand and USD 1,756,295 thousand, respectively. The Group sells its petroleum products in the Russian Far East, in particular in the Amur, Khabarovsk and Primorsk regions. The Group estimates its market share in the Russian Far East at 50% in the retail market and 30% in the wholesale market in terms of volumes of petroleum products sold in 2012. In 2012, 2011 and 2010, the Group sold 29.9, 27.6 and 24.4 mmbbl of petroleum products. The refined petroleum products sold by the Group in the Russian Far East are produced by the Khabarovsk Refinery. The Group also sells on the domestic market small volumes of petroleum products purchased from unaffiliated companies.

107 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA The following tables set forth the Group’s export, domestic retail, domestic wholesale sales, and total sales of certain refined products for the years ended 31 December 2012, 2011 and 2010 by volume and as a percentage of the total refined products export or domestic retail or domestic wholesale sales.

Export

2012 2011 2010

(thousand tonnes, except for percentages) Product Fuel oil (mazut)1 ...... 1,194 54.8% 992 57.8% 827 65.5% Ship fuel1 ...... 647 29.7% 350 20.4% 177 14.0% Naphtha...... 218 10.0% 298 17.4% 258 20.4% Other ...... 118 5.4% 77 4.5% — —

Total ...... 2,177 100% 1,717 100% 1,263 100%

(1) Including bunkering fuel

Domestic Retail

2012 2011 2010

(thousand tonnes, except for percentages) Product Diesel...... 193 31.1% 174 31.1% 133 29.3% Petrol ...... 427 68.8% 384 68.7% 320 70.5% Other ...... 1 0.2% 1 0.2% 1 0.2%

Total ...... 621 100% 559 100% 453 100%

Domestic Wholesale

2012 2011 2010

(thousand tonnes, except for percentages) Product Fuel oil (mazut)...... 147 12.0% 233 16.4% 310 19.8% Diesel...... 261 21.3% 338 23.8% 4251 27.1% Ship fuel ...... 404 33.0% 507 35.7% 499 31.8% Petrol ...... 32 2.6% 66 4.7% 87 5.5% Other ...... 381 31.1% 275 19.4% 248 15.8%

Total ...... 1,225 100% 1,419 100% 1,569 100%

(1) Includes 18 thousand tonnes of wholesale diesel sales to the Group’s upstream operations.

108 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA Total Sales

2012 2011 2010

(thousand tonnes, except for percentages) Product Fuel oil (mazut)...... 1,341 33.3% 1,225 33.1% 1,137 34.6% Diesel...... 454 11.3% 512 13.9% 558 17.0% Ship fuel ...... 1,051 26.1% 858 23.2% 676 20.6% Petrol ...... 459 11.4% 450 12.2% 407 12.4% Naphtha...... 218 5.4% 298 8.1% 258 7.9% Other ...... 500 12.4% 353 9.6% 249 7.6%

Total ...... 4,023 100% 3,696 100% 3,286 100%

Domestic Sales The Group sells its petroleum products through its network of filling stations in the Amur, Khabarovsk, Primorsk, Jewish Autonomous District and Republic of Buryatia regions of Russia. For the years ended 31 December 2012, 2011 and 2010, the Group sold 5.2, 4.6 and 3.7 million barrels of petroleum products to its retail customers, respectively, all which where located in Russia. In 2012, the Group began a rebranding effort of its retain chain, with newly rebranded stores opened in the Russian Far East. The Group also seeks to substantially increase the number of stations providing non-fuel servicesThe Group estimates its market share in the Russian Far East at 50% in the retail market in terms of volumes of petroleum products sold in 2012. The petroleum products sold by the Group in the Russian Far East are primarily supplied by the Khabarovsk Refinery, but the Group also sells small volumes of petroleum products purchased from unaffiliated companies on the domestic market. As of 31 December 2012, the Group owned a network of 267 petrol stations and 21 petroleum product terminals in the Russian Far East and Siberia, including the Amur, Khabarovsk and Primorsk regions as well as the Jewish Autonomous District and the Republic of Buryatia (in which the Group has 11 petrol stations). The Group sells petroleum products to both wholesale and retail customers through its marketing and sales subsidiaries. Khabarovsknefteproduct, Amurnefteproduct, Primornefteproduct and Alliance- Baikalneftesbyt operate in the regions Khabarovsk, Amur, Primorsk, the Jewish Autonomous District and the Republic of Buryatia and are engaged in both wholesale and retail sales. Alliance-Bunker, a Group subsidiary, is engaged in fuelling of watercrafts and fishing ships, and operates in the Russian Far East including the Sakhalin and Kamchatka regions.

Wholesale Sales Wholesale sales (including bunkering) of petroleum products in the domestic Russian Far Eastern market take place through petroleum products terminals owned by the Group, while large wholesale sales are shipped directly from the Khabarovsk Refinery. The Group sold 9.2, 10.6 and 11.5 million barrels of petroleum products in the wholesale market in the years ended 31 December 2012, 2011 and 2009, respectively. The Group estimates its wholesale market share in the Russian For East at 30% in terms of volumes of petroleum products sold in 2012. The Group generally enters into framework supply contracts with its wholesale customers. The supply contracts are usually entered into for a one-year term and include a standard provision permitting the renewal of the contract by agreement of the parties. The Group sells most of its jet fuel to the Khabarovsk airport. Purchases of petroleum products under federal programmes are financed by the Russian federal, regional or local budgets. In addition, the Group also supplies petroleum products to Russian Railways under the federal programmes. Supplies under federal programmes are appointed primarily on a tender basis.

Bunkering The Group markets its petroleum products through a network of owned sea terminals designed for receiving, storing and dispensing mainly two types of petroleum products – fuel oil and diesel.

109 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA The Group investigates opportunities to increase its market share by negotiating long-term contracts with large customers, purchasing and leasing of modern bunkering tankers of ice class. In 2012, the Group estimates its market share in the Russian Far Eastern bunkering industry was 20%.

Retail Sales The Group’s retail customers are mainly individual car owners and transportation companies. The Group offers value-added services at some of its filling stations, such as car washes, car maintenance, retail shops and product kiosks and has commenced the roll-out of pay-at-the pump pre-pay debit card terminals which include a customer loyalty points programme. The Group is currently optimising its portfolio of retail filling stations in the Russian Far East by reconstructing existing filling stations and by constructing new filling stations while closing underperforming stations. As part of this process, the Group seeks to substantially increase the number of filling stations providing non-fuel services. The Group intends to increase its retail sale operations in the Russian Far East by entering into neighbouring regions, namely Kamchatka, Magadan and Sakhalin.

Export Sales The Group sells all exported petroleum products to Lia Oil, a Swiss petroleum products trading company which is an affiliate of the Group. The Group exports primarily fuel oil, naphtha and diesel. For the years ended 31 December 2012, 2011 and 2010, the Group exported 15.6, 12.4 and 9.1 million barrels of petroleum products, respectively.

Transportation and Logistics Pipelines The Group uses the Transneft pipeline network for transporting crude oil to customers within and outside of Russia. The Group’s oil fields located in Tatarstan, the Timano-Pechora region and Kazakhstan are not directly connected to the Transneft network. The crude oil produced by the Group in Tatarstan is delivered to the Transneft pipelines via Tatneft’s pipeline network, while Potential Oil transports crude oil from Kazakhstan through the Sazankurak and KazTransOil pipeline networks, and Pechoraneft transports crude oil from Middle Kharyaga to the Transneft pipeline via a LUKOIL-owned pipeline. Transneft is a state-owned oil pipeline monopoly. The Russian government regulates access to Transneft’s pipeline network and is required to provide access on a non-discriminatory basis. The Ministry of Energy, based on information provided by Transneft and oil producers, allocates pipeline network owned by Transneft and Transnefteproduct and sea terminal capacity to oil producers for export deliveries on a quarterly basis. Generally, the allocations are made in proportion to the amount of crude oil produced and delivered to Transneft’s pipeline network in the prior quarter. The Group pays Transneft transportation fees as set by the FTS on a ‘‘cost-plus’’ basis. Pipeline transportation tariffs have risen substantially over the past several years and may continue to rise. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations – Key Factors Affecting Operating Results – Transportation Costs of Crude Oil and Petroleum Products’’. The overall price to transport crude oil depends on the number of Transneft ‘‘districts’’ through which the oil is transported. In addition, the Group pays a premium to Transneft for the blending of its crude oil to reduce high sulphur content. To facilitate increased and efficient supplies of crude oil to the Khabarovsk Refinery, the Group has started the construction of a new transfer unit and 28 kilometres of pipeline to connect the ESPO oil pipeline to the Khabarovsk Refinery. The first crude supplies to the refinery by the ESPO oil pipeline are anticipated in 2014 with 40,000 bopd expected to be redirected from railway shipments. The pipeline supplies are scheduled to gradually increase to reach 100,000 bopd by 2015. Although the Group’s exact tariff rates for use of the ESPO oil pipeline have not been established, it is expected that the transportation costs for crude oil supplied through the ESPO oil pipeline are expected to be approximately half of the cost of those for 3,300 kilometre railway shipments. The Group delivers its jet fuel to the Khabarovsk airport through a pipeline connecting the Khabarovsk Refinery with the Khabarovsk airport. The pipeline’s length is approximately 14 kilometres. The Group leases the pipeline from the government of the Khabarovsk.

Railways The oil transportation system in the Russian Far East is undeveloped. As a result, oil refineries operating in the Russian Far East do not have direct access to Transneft’s pipelines and significant

110 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA quantity of crude oil is transported by rail. The Group’s wholly owned logistics subsidiary, Alliancetransoil, is generally responsible for the transportation of the Group’s crude oil and petroleum products by tank rail cars to and from the Khabarovsk Refinery. The Group currently owns more than 1,400 railcars for transportation of petroleum products and rents additional railcars when required. Alliancetransoil services the Group’s internal logistic needs and generates substantial benefits to the Group’s main business as there are generally no third-party providers in the Russian Far Eastern market offering similar services. These services enable the Group to deliver petroleum products directly to its customers by rail due to the specific features of the market where the Group operates, including its poor infrastructure, underdeveloped road network and remoteness. As the transportation system in the Russian Far East is undeveloped, Alliancetransoil also provides transportation services to a limited extent to third parties. The Khabarovsk Refinery’s expected connection to the ESPO oil pipeline in 2014 will gradually replace railway deliveries and allow the refinery better access to crude supplies and significantly minimise transportation costs. By the end of 2014, the Group expects that railway deliveries will be reduced by approximately 40% due to the connection to the ESPO oil pipeline.

Transshipment and Storage Oil and Petroleum Products Terminals The Group owns and operates a rail and water transshipment terminal in Vladivostok that has a transshipment capacity of 2.5 million tonnes per year. The Vladivostok terminal includes 31 storage tanks with a net volume of 129,000 cubic metres and four railroad discharge ramps that can simultaneously accommodate 56 tank rail cars. The Group has 21 oil terminals in the Russian Far East with a combined storage capacity of approximately 373,000 cubic metres. Among them, the Khabarovsk and Blagoveshensk oil terminal wharfs on the Amur river are connected with light and dark petroleum products pipelines, which accommodates barges with capacities of up to 5,000 tonnes. In accordance with Vaarwater programme recommendations, the Group seeks to optimise its oil terminals network for more efficient storage and delivery of petroleum products with lower transportation costs. Khabarovsk Refinery’s Storage and Transshipment The Khabarovsk Refinery has 50 tanks to store crude oil and petroleum products, with a total capacity of 266,500 cubic metres, including eight tanks for crude oil with a total capacity of 130,200 cubic metres, 32 tanks for light petroleum products with a total capacity of 91,400 cubic metres and ten tanks for dark petroleum products with a total capacity of 44,900 cubic metres.

Competition The oil industry in Russia is highly competitive. In refining, the Group competes principally with the Komsomolsk oil refinery owned by Rosneft. The retail sale of petroleum and non fuel goods in Russia through filling stations is also increasingly competitive, and changing demographics and consumer preferences in individual geographic locations may greatly impact the operations of filling stations in those locations. The Group’s business strategy depends in part on its ability to compete by assessing locations and successfully opening filling stations in new locations or remodelling existing filling stations to add facilities for non-fuel sales, such as shops and car wash facilities. Furthermore, the Group may face increased competition from companies that have more established brand names or more experience in combining fuel and non-fuel sales. The Group’s principal competitor in the petroleum products retail sector is Rosneft. While the Group believes that it currently has greater brand awareness than its competitors in the Russian Far East, there can be no guarantee that this position will not change in the future. See ‘‘Risk Factors – Risks Relating to the Group and the Oil and Gas Industry – The petroleum products retail sector is highly competitive, and the Group may be unable to compete in the petroleum products retail sector or find suitable locations to open new filling stations or it may encounter delays or greater than anticipated costs in remodeling existing filling stations’’ and ‘‘Risk Factors – Risks Relating to the Group and the Oil and Gas Industry – The Group faces intense competition from other oil and gas companies in all areas of its operations, including the acquisition of licences, exploratory prospects and producing properties, and it may encounter competition from suppliers of alternative forms of energy sources’’. The Group also faces competition in the acquisition of subsoil licences at auctions or tenders run by governmental authorities and obtaining desirable licences for future exploration and production, a key

111 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA for growth. The Group must compete with other players for the acquisition of companies that already own licences or existing hydrocarbon-producing assets as well. In addition, competition exists for participation in foreign exploration and development projects.

The oil industry is currently subject to several important influences which impact the industry’s competitive landscape. In recent years, the oil industry has experienced consolidation, as well as increased deregulation and integration in strategic markets. In addition, the Group’s ability to remain competitive will require, among other things, management’s continued focus on reducing unit costs and improving efficiency, maintaining long-term growth in the Group’s reserves and production through continued technological innovation. In the face of intense competition, oil companies are also facing increasing demands to conduct their operations in a manner consistent with environmental and social goals. Investors, customers and governments are more actively following the oil industry’s performance on environmental responsibility and human rights, including performance with respect to the development of alternative and renewable fuel resources. As a result of these influences and other factors, competition will continue to intensify. A number of other Russian oil companies, as well as foreign oil companies, are permitted to compete for licences and to offer services in Russia, increasing the competition which the Group faces. Competition will also continue to grow due to the limited quantities of unexploited and unallocated oil reserves.

Health, Safety and Environment The operations of the Group are subject to a number of environmental laws and regulations. These laws govern, among other things, air emissions, wastewater discharges and discharges to the sea, the use, handling and disposal of hazardous substances and wastes, soil and groundwater contamination and employee health and safety. As with other oil and gas companies, environmental liability risks are inherent in the operations of the Group. The Group aims to ensure that it conducts its operations with due regard for health, safety and the surrounding environment. In addition to complying with the environmental laws and regulations concerning its products, operations and activities, the Group seeks to comply with its health, safety and environmental policy (the ‘‘HSE Policy’’). The HSE Policy provides the strategic framework for the Group to strive to conduct its operations in accordance with international standards of environmental protection and to monitor its compliance with these principles.

The Group continuously seeks to minimise the impact of its operations on the environment by reducing waste, emissions and discharges. The Group’s subsidiaries aim to observe the prescribed limits and exercise control over the emissions and formation and disposal of hazardous substances and waste. To limit soil and ground pollutant emissions, the Group strives to promptly undertake measures aimed at diminishing oil spills. The Group and its subsidiaries construct special containers to hold petroleum products that may spill as the result of an accident. The Group aims to ensure that the chemically hazardous and flammable explosive materials are fully equipped with accident prevention systems, including emergency stoppage of equipment, localisation of the source of the accident and emergency sources for energy provision. Some subsidiaries of the Group enter into agreements on the transfer of wastewater to municipal facilities for advanced treatment. To contain accidental spills of petroleum products from the Group’s oil terminals, the Group tries to ensure that oil terminals with wharfs for oil-loading of water-carriers are equipped for oil-spill containment and skimming. In 2008, the Group launched various investment projects aimed at limiting adverse environmental impact at the Group’s facilities, including the construction of an automated dark oil loading dock, implementation of the second stage of reconstruction of a treating facility at the Khabarovsk Refinery and construction of tank pontoons.

The Group is currently introducing (i) a complex of technologies to detect, evaluate, monitor and eliminate oil pollution in the ground and in ground water, (ii) systems to recover vapours emanating from petroleum products, (iii) closed loading and unloading systems for petroleum products, (iv) modern systems for treating waste water for reuse and (v) technologies for more efficient recycling of oil-containing wastes. While there is no regulatory requirement to do so in Russia, the Group’s long- term goal is to ensure that the system of environmental protection management at the Group and each of its subsidiaries meets the requirements of the International Standards Organisation. The Group did not have a significant oil or waste spill or other environmental incident during the financial years ended 31 December 2012, 2011 and 2010, and the Group is not aware of any claims or penalties from Russian domestic environmental authorities that have not been corrected and/or settled.

112 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA Intellectual Property As of 31 December 2012, the Group held 14 trademarks.

Insurance The Group has obtained insurance policy covering property damage and business interruption for number of assets, which provides protection against loss of revenues and assets due to an accident, fire, explosion, special perils or operational failure from LLC Paritet Insurance Company (‘‘Paritet’’), a Russian insurance company. Paritet insures the Group’s assets and operations including property belonging to production and development subsidiaries, property belonging to the Khabarovsk Refinery and property belonging to trading companies. Paritet’s policy also covers environmental risks in case of spills and other unexpected or dangerous conditions or accidents. Paritet insures the Group for construction and assembling works performed at refining facilities and for life insurance of employees working at hazardous facilities, as such insurance is mandatory under Russian law. The Group also provides mandatory health insurance to its employees. In addition, the Group obtains re-insurance coverage from AIG Europe S.A., ACE Europe, XL Insurance Company, Allianz SE, Munich Re, Zurich Insurance Ireland, Hannover Re, China Re, Korean Re, Lloyd’s Syndicates AES, MKL, TAL, AML and others.

Employees The Group views its employees as its main asset. As of 31 December 2012, 2011 and 2010, the Group employed 7,710, 7,535 and 7,143 employees, respectively. The average monthly salary of the Group’s employees was USD 1,550, USD 1,300 and USD 1,050 for the years ended 31 December 2012, 2011 and 2010, respectively, and total personnel costs were USD 181,907 thousand, USD 168,069 thousand and USD 131,423 thousand, respectively. In addition, the Group spent USD 23,101 thousand, USD 15,039 thousand and USD 13,602 thousand in 2012, 2011 and 2010, respectively, for Russian employee pensions. The majority of the Group’s operating subsidiaries enter into collective bargaining agreements with trade unions for a term of three years. The Group holds regular open dialogue with worker trade unions to address social issues. As of 31 December 2012, approximately 86% of the Group’s employees are members of the trade unions. As at the date of this Prospectus, the Group is not involved in any labour disputes, which the Group considers to be material, or strikes at its oil production, refining or distribution subsidiaries. The Board of Directors of the Issuer considers employee relations to be good. The Group did not experience any material work stoppages in the years ended 31 December 2012, 2011 and 2010. The following table sets forth the approximate number of the Group’s employees by employment area as of 31 December 2012, 2011 and 2010.

As of 31 December

2012 2011 2010

Upstream ...... 2,067 1,973 1,760 Refining...... 1,470 1,431 1,376 Marketing and sales...... 3,939 3,914 3,746 Managing company ...... 234 217 200 Others ...... 0 0 61

Total...... 7,710 7,535 7,143

Litigation From time to time, the Group is involved in litigation in the ordinary course of its business activities. The Group believes that such ordinary course litigation is immaterial and is unlikely to affect the Group’s operating results or financial position significantly. The Group believes that there are no governmental, legal or arbitral proceedings (including any such proceedings which are pending or threatened or of which the Group is aware) that may have or have in the recent past had material effects on the Group’s financial position and profitability.

113 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA MANAGEMENT

Board of Directors The Board of Directors has the overall responsibility for the management of the Issuer’s and its subsidiaries’ affairs. The Board of Directors is appointed annually at the annual general shareholders’ meeting, for the period until the closing of the next annual general shareholders’ meeting. The Issuer’s bye-laws stipulate that the Board of Directors shall consist of no less than three and no more than 15 members. Any general shareholders’ meeting of the Issuer may elect a person or persons to act as a director in the alternative to any one or more of the members of the Board of Directors. The Board of Directors consists of seven directors with no alternate director. The names, position titles, birth years and dates of first appointment of each member of the Board of Directors as of the date of this Prospectus are set out in the table below:

Date of First Name of Director Position Born Appointment

Eric Forss Chairman 1965 July 2004 Arsen E. Idrisov Director and Managing Director 1970 May 2008 Raymond Liefooghe Director 1942 May 2008 Claes Levin Director 1941 July 2004 Fred Boling Director 1940 July 2004 Fernando Martinez-Fresneda Director 1951 May 2009 Isa Bazhaev Director 1962 May 2009 The office address of the members of the Board of Directors is c/o Alliance Oil Company Ltd., Clarendon House, 2 Church Street, Hamilton HM11, Bermuda. No member of the Board of Directors has been involved in any bankruptcy, receivership or liquidation in his capacity as member of the Board of Directors or senior executive in the past five years. In the past five years, none of the members of the Board of Directors has been convicted of fraud or been the subject of public incrimination or sanctions by a supervisory or legislative authority and none of them has been prohibited by court of law from serving as a member of the Board of Directors or manager, or prohibited in any other way from engaging in business operations. The Issuer has not provided any loans or extended or issued any warranties or security in favour of any member of the Board of Directors. None of the members of the Board of Directors have either directly or indirectly through any related individual’s natural person or legal entity had any business relations with the Issuer or the Group that have not been available to non-related individuals on the market. Set out below is certain biographical information regarding the members of the Board of Directors, including any relevant education and experience and certain current employment commitments and business interests outside of their role with the Group.

Eric Forss, Chairman Mr. Forss is independent in relation to the Issuer, management and major shareholders. Mr. Forss’ holding in the Issuer: 86,700 SDRs (including 3,700 preference SDRs) and 1,088,905 options, see ‘‘ – Incentive Programmes – Global Share Option Plan’’. Mr. Forss, a Swedish citizen, was born in 1965. He has been a member of the board of directors since July 2004. Mr. Forss holds a B.Sc. degree in Finance from Babson College, Wellesley, Massachusetts. He has served as chief executive officer of Forssgruppen since 1998 and of Forsinvest AB since 2010. Between 1991 and 1998, Mr. Forss served as president of Forcenergy AB, a public Swedish oil and gas corporation, where he also served as vice president between 1990 and 1991. Mr. Forss is chairman of the board of directors of Mediagruppen Stockholm MGS AB, as well as a member of the board of directors of Forcenergy AB, Forsinvest AB, Consortum Capital Investments AB and S.O.G. Energy AB. He has also served as a director of and advisor to several public and private Swedish and international companies.

Arsen E. Idrisov, Director and Managing Director Mr. Idrisov is not independent in relation to the Issuer or management, nor in relation to major shareholders.

114 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA Mr. Idrisov’s holding in the Issuer: 147,730 options, see ‘‘ – Incentive Programmes – Global Share Option Plan’’. Mr. Idrisov, a Russian citizen, was born in 1970. He has been a member of the Board of Directors since May 2008 and managing director of the Issuer since November 2008. Mr. Idrisov graduated with Honours from the Russian Economic Academy named after G. V. Plekhanov in 1993, majoring in international economic relations. In 1992 and 1993, Mr. Idrisov studied at the Otto Beisheim School of Management/WHU (Vallendar, Germany) and had training with Marquard & Bahls AG and with Deutsche Shell AG. Between 1993 and 1997, he held a number of senior positions in international trading business including a Swiss trading company LIA OIL S.A. and Russian oil major Sidanco. In 1998, Mr. Idrisov became the general director of Alliance Capital Investment Company and joined the board of directors of OJSC Alliance Group. Since 2002, he has served as a vice president for corporate finance at OJSC Alliance Group. Mr. Idrisov was President/CEO of NK Alliance from 2002 until July 2006. Within this period NK Alliance advanced to the top 50 Russian largest companies. He has been a member of NK Alliance’s board of directors since its establishment (2001) and served as the chairman of its board of directors between 2006 and 2008.

Raymond Liefooghe, Director Mr. Liefooghe is independent in relation to the Issuer, management and major shareholders. Mr. Liefooghe’s holding in the Issuer: 8,000 SDRs and 149,311 options, see ‘‘ – Incentive Programmes – Global Share Option Plan’’. Mr. Liefooghe, a Swiss resident with Swiss and French nationalities, was born in 1942. He has been a member of the Board of Directors since May 2008. Mr. Liefooghe served as a member of the board of directors of NK Alliance between 2006 and 2008. Mr. Liefooghe graduated from the International Trade Institute in Paris in 1973. Between 1974 and 1991, Mr. Liefooghe worked in BNP New York, Montreal, Geneva and Paris. From 1992 to 2002, he worked for the United European Bank (Geneva) and in 1999 he was elected as its chief executive officer. Mr. Liefooghe founded a consulting company in 2002 that mainly worked for the BNP Paribas Group until July 2005. Between 2002 and 2005, he was the chairman of the supervisory board of BNP Paribas Bank ZAO in Moscow. Mr. Liefooghe also holds a position of director at Diamond Capital Fund, Diamond Growth Fund, Diamond Fixed Income Ltd, Diamond Asia Ltd, Nutrimenta Finance & Investments Ltd, Sucafina S.A., Sucafina Ingredients S.A., Lia Oil and Metinvest International.

Claes Levin, Director Mr. Levin is independent in relation to the Issuer, management and major shareholders. Mr. Levin’s holding in the Issuer: 53,718 SDRs and 143,091 options, see ‘‘ – Incentive Programmes – Global Share Option Plan’’. Mr. Levin, a Swedish citizen, was born in 1941. He has been a member of the Board of Directors since July 2004. Mr. Levin has a law degree and a B.A. degree in Economics from the University of Lund. From 1971 to 1980, Mr. Levin held various management positions with Skandinaviska Enskilda Banken AB (publ). He was the managing director for Diligentia between 1980 and 1983, Reinhold Bygg AB between 1983 and 1985 and Platzer Bygg between 1986 and 1998, all listed companies. Today, Mr. Levin holds board of director chairman positions with several companies including Broderna Falk AB, SH Forvaltning AB and Variant Fastighets AB. Mr Levin is also member of the board of directors of First Baltic Property Ltd.

Fred Boling, Director Mr. Boling is independent in relation to the Issuer, management and major shareholders. Mr. Boling’s holding in the Issuer: 80,000 SDRs and 178,018 options, see ‘‘ – Incentive Programmes – Global Share Option Plan’’. Mr. Boling, a U.S. citizen, was born in 1940. He has been a member of the Board of Directors since July 2004. Mr. Boling holds B.Sc. and M.Sc. degrees from the Georgia Institute of Technology where he also lectured. He was formerly an executive with Sinclair Oil, Atlantic Richfield, BP Oil Corp., Gibbs Oil and Astroline Oil Trading Corp. In addition to 41 years’ experience in the oil industry, Mr. Boling has been active in banking and was president of Security National Bank, a director of Bank of New England and a director of Pacific National Bank, Massachusetts. Also, Mr. Boling is a director of Energi Insurance Co. and Harbor Fuel Oil Corporation.

115 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA Fernando Martinez-Fresneda, Director Mr. Martinez-Fresneda is independent in relation to the Issuer, management and major shareholders. Mr. Martinez-Fresneda’s holding in the Issuer: 109,595 options, see ‘‘ – Incentive Programmes – Global Share Option Plan’’. Mr. Martinez-Fresneda, a Spanish citizen, was born in 1951. He has been a member of the Board of Directors since May 2009. Mr. Martinez-Fresneda is a Mining Engineer from the ETSIM, Mining Engineer School at the Polytechnic University of Madrid and has a PDD in Business Administration from the INALDE in Bogota. Mr. Martinez-Fresneda formerly was Petroleos Sudamericanos’ general manager in Ecuador. Since 1981, he has held various positions in the Repsol organisation including being Repsol’s general manager in Colombia and Bolivia. He is currently the managing director of Repsol’s office and operations in the Russian Federation.

Isa Bazhaev, Director Mr. Bazhaev is not independent in relation to the Issuer or management, nor in relation to major shareholders. Mr. Bazhaev’s holding in the Issuer: 120,155 options, see ‘‘ – Incentive Programmes – Global Share Option Plan’’. Mr. Bazhaev, a Russian citizen, was born in 1962. He has been a member of the Board of Directors since May 2009. In 1985, Mr. Bazhaev graduated from the Grozny Oil Institute with a degree in Engineering and Construction. From 1993 to 2000, he was a marketing director with Lia Oil SA (Switzerland) in Ukraine, and from 2000 to 2002, at Lia Oil’s representative office in Russia. From 2002 to 2005, Mr. Bazhaev held the position of director of OJSC Alliance Group’s finance department. From April 2008 to March 2009, Mr. Bazhaev was a board member at NK Alliance. Since 2005, he has served as the vice president for finance of Alliance-Prom and also a board member at Alliance-Prom.

Group Management The names, position titles, birth years and dates of first appointment of each member of the Group’s senior management (‘‘Group Management’’) are set out in the table below:

Date of First Name of Senior Manager Position Born Appointment

Arsen E. Idrisov Director and Managing Director 1970 November 2008 Angelika Adieva Chief Financial Officer 1975 December 2008 Yevgeny Vorobeichik Chief Operating Officer 1958 January 2009 Alexander Sutyagin CEO Downstream 1958 January 2009 No member of the Group Management has been involved in any bankruptcy, receivership or liquidation in his/her capacity as member of the Board of Directors or senior executive in the past five years. In the past five years, no members of the Group Management has been convicted of fraud or been the subject of public incrimination or sanctions by a supervisory or legislative authority and none of them has been prohibited by court of law from serving as a member of the board of directors or manager, or prohibited in any other way from engaging in business operations. Set out below is certain biographical information regarding the members of the Group Management, including any relevant education and experience and certain current employment commitments and business interests outside of their role with the Group.

Arsen E. Idrisov, Director and Managing Director See ‘‘ – Board of Directors’’.

Angelika Adieva, Chief Financial Officer Ms. Adieva’s holding in the Issuer: 60,708 options, see ‘‘ – Incentive Programmes – Global Share Option Plan’’. Ms. Adieva, a Russian citizen, was born in 1975. She joined the Issuer in 2008. Ms. Adieva holds a Bachelor’s degree in Economics from the Institute of Practical Oriental Studies in Moscow and an MBA from the McCombs School of Business at the University of Texas at Austin with a

116 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA concentration in Finance and specialisation in Energy Finance. Her previous experience includes international oil and gas investment banking, as well as downstream and upstream project management. She started in the oil and gas industry in 1998 with Fluor Corporation. Prior to joining the Group, Ms. Adieva most recently held a management position in the European Energy and Power Investment Banking team at Merrill Lynch International in London.

Yevgeny Vorobeichik, Chief Operating Officer Mr. Vorobeichik’s holding in the Issuer: 113,048 options, see ‘‘ – Incentive Programmes – Global Share Option Plan’’. Mr. Vorobeichik, a Russian citizen, was born in 1958. He has served as president of NK Alliance since July 2006. Mr. Vorobeichik graduated from the Kuibyshev Polytechnic Institute in 1980 after majoring in chemical technologies related to oil and gas. He won the honorary title of a Merited Oil Industry Worker in 1997. Mr. Vorobeichik spent more than 15 years with the Kuibyshev Oil Refinery, working his way up from an operator and the supervisor of an installation to deputy head of the production and sales office. Between 1996 and 1998, Mr. Vorobeichik headed the petroleum and petroleum product sales department at Sidanco. He has been with NK Alliance since 1999, serving as a vice president (from 2002 to July 2006) and then the president.

Alexander Sutyagin, CEO Downstream Mr. Sutyagin’s holding in the Issuer: 70,191 options, see ‘‘ – Incentive Programmes – Global Share Option Plan’’. Mr. Sutyagin, a Russian citizen, was born in 1958. He has served as first vice president and vice president for development and coordination of commercial activity of NK Alliance since 2006. Mr Sutyagin graduated from the Kuibyshev Polytechnic Institute and holds a doctorate in Engineering. He served as head of a Swiss trading company LIA OIL S.A. representative office in Samara in 1995- 1998. In 2003-2006, he served as general director of Far Eastern Alliance.

CEO Upstream Sergey Brezitskiy, who previously served as CEO of upstream operations for two years, recently left his position, and the Group is actively looking for a replacement.

Conflict of Interest No member of the Board of Directors or member of the Group Management has any family relationships with other members of the Board of Directors or members of the Group Management. No conflict of interest exists in respect of any of the members of the Board of Directors or members of the Group Management, their duties to the Issuer, their personal interests or other duties. All members of the Board of Directors and four of the members of the Group Management have financial interests in the Group due to ownership of shares or options to subscribe for shares.

Remuneration The general shareholders’ meeting resolves on remuneration to the members of the Board of Directors. At the annual general shareholders’ meeting of the Issuer in 2012, it was resolved that remuneration to the currently elected members of the Board of Directors shall be USD 180,000 per annum to the Chairman and USD 120,000 per annum to each of the remaining members of the Board of Directors, except the Managing Director who does not receive additional remuneration for being a member of the Board of Directors. In addition, the annual general shareholders’ meeting in 2012 resolved that each member of the Audit Committee and each member of the Remuneration Committee shall receive additional remuneration of USD 10,000 per annum. From 2006, the Issuer has adopted the following principles for executive remuneration, which were approved by the shareholders at the annual general shareholders’ meeting in 2008. The executive remuneration consists of a base salary, an annual bonus and participation in the Issuer’s long-term incentive plan. The annual bonus is individually capped at 50% to 100% of the salary and is determined based on the Issuer’s performance which is measured by several performance indicators, both operations and financial. Annual option grants are based on the employee’s total compensation and the value of granted options may amount from 100% to 200% of annual compensation, but lower amounts can be granted.

117 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA Notice periods are not to exceed 12 months, during which the employee is entitled to full compensation. The members of the Board of Directors are not entitled to any severance payments when they leave their position as directors. Members of the Group Management of the Issuer received a total remuneration of USD 16,103 thousand during 2012 of which the managing director received a total remuneration of USD 3,501 thousand. The managing director’s employment contract may be terminated by the Issuer upon six months written notice. Should the managing director decide to leave the Group, he must give the Issuer six months’ notice. The managing director is entitled to a bonus in an amount not exceeding 50% of his annual salary and may be awarded a bonus of up to 100% of the annual salary, including performance bonus for specific projects as determined by the Board of Directors.

Incentive Programmes – Global Share Option Plan At the Issuer’s general shareholders’ meeting held on 14 November 2000, it was resolved to adopt a Global Share Option Plan (the ‘‘Option Plan’’). An amended Option Plan was adopted on 31 January 2006. The Option Plan allows for managers and directors of the Group (eligible employees) to be granted call options each entitling the holder to acquire one ordinary share in the Issuer. The Option Plan is administered by the Remuneration Committee which has been authorised, from time to time, to make and vary such regulations for the implementation and administration of the Option Plan as it deems fit. In connection to option grants, the Remuneration Committee is to determine what performance conditions must be satisfied for the options to become exercisable. Initial grants are determined based on the employee’s position in the Issuer. Annual option grants are based on the employee’s total compensation for the current year and the value of granted options may amount to between 100% and 200% of the annual compensation. 749,522 options were granted in 2012. A total of 1,363,700 options and 225,000 options expired in January and April 2011, with no options being exercised. 578,850 and 50,000 options expired in February and May 2012, with no options being exercised. As of 31 December 2012, the total number of the outstanding options amounted to 2,736,551 corresponding to 1.6% of the outstanding shares. Exercise prices range from SEK 81.80 to SEK 124.00. All options are exercisable after three years subject to certain non-market conditions and expire in five years from the date of the grant.

Corporate Governance The Issuer’s corporate governance is based on the Issuer’s bye-laws, the listing agreement with NASDAQ OMX Stockholm and other applicable laws and regulations. In the absence of a Bermuda corporate governance code, the Issuer implemented the Swedish Code of Corporate Governance (the ‘‘Corporate Governance Code’’) in 2006. The Corporate Governance Code is based on the principle ‘‘comply or explain’’, i.e. a company may deviate from individual rules of the Corporate Governance Code, provided that it reports each deviation, describes its own solution and explains the reasons for the deviation. The Issuer deviates from Clause 9.8 of the Corporate Governance Code: ‘‘Non-executive members of the board are not to participate in programmes designed for the executive management or other employees. Remuneration of non-executing board members is not to include share options.’’ The Issuer explains the deviation as follows: Directors are eligible for and have participated in the Issuer’s shareholder approved Option Plan since its adoption in 2006. The Option Plan was approved prior to the Issuer’s listing on NASDAQ OMX Stockholm and implementation of the Corporate Governance Code, and has a term of 10 years. The Issuer does not deviate from any other clauses of the Corporate Governance Code. Since 2006, the Issuer has developed and implemented an application of the Corporate Governance Code that also corresponds to Bermudian law and Issuer’s practice. The Issuer implements Corporate Governance Code revisions and references to the Swedish Companies Act when applicable and reports corporate governance matters accordingly. According to the Corporate Governance Code, at least half of the members of the Board of Directors must be independent in relation to the company and the management. In order to determine whether a director is independent, an overall assessment is to be made of all the circumstances that may give reason to question the director’s independence in relation to the company and management. A director’s independence may, for example, be questioned if the director, directly or indirectly, has

118 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA substantial business relationships or any other major financial relationship with the company. An overall assessment of the director’s independence must be made in each individual case. Furthermore, according to the Corporate Governance Code, at least two of the directors who are independent in relation to the company and management must also be independent in relation to major shareholders. Shareholders who, directly or indirectly, control 10% or more of the issued shares or votes of the Issuer are according to the Corporate Governance Code considered major shareholders. A director is not considered independent in relation to a major shareholder if she or he represents a major shareholder or is an employee or a director of a company that is a major shareholder. A director’s direct or indirect relations to a major shareholder is decisive when assessing if the director is to be considered independent in relation to the major shareholder. See ‘‘ – Board of Directors’’ for information about each director’s independence. Five of the seven members of the Board of Directors are independent in relation to the Issuer, senior management and major shareholders.

Board of Directors Committees Audit Committee The Corporate Governance Code provides that the Board of Directors is to establish an Audit Committee consisting of at least three directors. The majority of the Audit Committee members are to be independent in relation to the Issuer and its management. At least one member of the committee is to be independent in relation to the Issuer’s major shareholders. No director who holds a management position may be appointed as a member of the Audit Committee. The Board of Directors of the Issuer has appointed an Audit Committee consisting of three directors who are independent in relation to the Issuer, management and major shareholders. The Audit Committee consists of Fred Boling (Chairman), Raymond Liefooghe and Claes Levin. In the Board of Directors’ opinion, the Issuer complies with the requirements of the Corporate Governance Code regarding the composition of the Audit Committee. The Audit Committee is responsible for ensuring the quality of the Group’s financial statements, including considering all critical accounting policies, regulatory compliance, the Group’s system of internal control and unadjusted errors brought to the attention of the committee by the external auditors. The Audit Committee shall also review related party transactions. Furthermore, the Audit Committee evaluates the performance of the external auditor, makes recommendations to the Nomination Committee on the appointment of the external auditor and meets with the Issuer’s auditors on a regular basis to understand the scope and findings of their work and to ensure that the auditors are independent of the Group. The Audit Committee reviews the quarterly and annual financial statements before they are published and discusses them with the management and external auditors. The Audit Committee’s review concerns the conformity with IFRS, the reasonableness of significant estimates and judgments made in the preparation of the financial statements, as well as the quality of disclosures in the financial statements.

Remuneration Committee The Corporate Governance Code provides that the Board of Directors is to establish a Remuneration Committee consisting of at least three directors. The Board of Directors of the Issuer has appointed three directors to form the Remuneration Committee. The Corporate Governance Code stipulates that the chairman of the Board of Directors may also be the chairman of the Remuneration Committee and that the additional members must be independent in relation to the Issuer and the management. The members of the Remuneration Committee must according to the Corporate Governance Code have the necessary knowledge and competence with regard to questions relating to remuneration to directors and management. The Remuneration Committee establishes principles and makes recommendations to the Board of Directors for executive remuneration and contracts, determines remuneration packages and manages the Issuer’s long-term incentive plan. The Board of Directors may delegate to the Remuneration Committee to approve individual employment contracts, compensation agreements and option grants within approved policies, provided any actions taken by the committee are reported to the Board of Directors. The Remuneration Committee consists of Eric Forss (Chairman), Fred Boling and Isa Bazhaev.

119 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA In the Board of Director’s opinion, the Issuer complies with the requirements stipulated in the Corporate Governance Code regarding the composition of the Remuneration Committee.

Nomination Committee The Corporate Governance Code provides that the Issuer must have a Nomination Committee. In accordance with a resolution at the annual general shareholders’ meeting in 2012, the Issuer’s Nomination Committee shall be appointed by its four largest shareholders, which at that time were Betino Investments Limited, OJSC Alliance Group, CJSC Alliance Capital and Repsol Exploracion S.A. These four shareholders appointed the following representatives together with the Issuer’s Chairman of the Board of Directors, to constitute the Nomination Committee for the annual general shareholders’ meeting in 2013: (i) Carl Svernlo¨v (Chairman of the Nomination Committee representing Betino Investments Limited), (ii) Fred Boling (representing OJSC Alliance Group), (iii) Andrei Sletov (representing CJSC Alliance Capital), (iv) Ignacio Marroquin (representing Repsol Exploracion S.A.), and (v) Eric Forss (Chairman of the Board of Directors). The Nominating Committee presents a proposal for election of the members of the Board of Directors as well as related questions for adoption at the annual general shareholders’ meeting and completes the tasks and considers the independence of the members of the Board of Directors as set out in the Corporate Governance Code. The annual general shareholders’ meeting will be held in Stockholm on 22 May 2013.

120 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA PRINCIPAL SHAREHOLDERS

Share Capital The Issuer has two listed classes of shares: ordinary and preference. Both shares are traded as SDRs on NASDAQ OMX Nordic. The Issuer’s preference shares issued in December 2012 carry each one tenth (1/10) of a vote at general shareholders’ meetings of the Issuer and pay a yearly dividend of SEK 30, while each ordinary share carries one vote. The total number of shares is 176,528,414, of which 171,528,414 are common shares and 5,000,000 are preference shares. The total number of votes in the Issuer is 172,028,414. The Issuer’s share capital is USD 176,528,414.

2009 Convertible Bonds In July 2009, the Group issued USD 265 million convertible bonds with a coupon of 7.25% per annum maturing in July 2014. The bonds are convertible into SDRs (with respect to ordinary shares) at an initial conversion price of SEK 121.1250 per SDR. The Group has the option to call the convertible bonds after the first three years at their principal amount, together with accrued interest, if the market price of the SDRs deliverable on conversion of the bonds exceeds 130% of the principal amount of the bonds over a specified period.

Ownership Structure As of 28 March 2013, the number of the Issuer’s shareholders was approximately 35,085. As of the same date, the 15 largest shareholders represented approximately 63.8% of the Issuer’s share capital. As of the date of this Prospectus, the Issuer’s major beneficiary shareholder is the Bazhaev family holding approximately 44.1% of the voting rights and 43.3% of the issued share capital of Alliance Oil Company Limited through Betino Investments (Cyprus) Limited (holding 22.05% of the voting rights and 21.5% of the issued share capital), OJSC Alliance Group (holding 17.9% of the voting rights and 17.5% of the issued share capital), CJSC Investment Company Alliance Capital (holding 3.9% of the voting rights and 3.8% of the issued share capital), Daumier Investments Limited (Cyprus) (holding 0.28% of the voting rights and 0.27% of the issued share capital) and Central Clearing Finance S.A. (holding 0.03% of the voting rights and 0.28% of the issued share capital). BNP Paribas (Suisse) S.A., W8IMY holds the interests of Betino Investments (Cyprus) Limited, Daumier Investments Limited (Cyprus) and Central Clearing Finance S.A.

Largest Shareholders The following table sets forth information regarding the ownership of shares in the Issuer as of 28 March 2013.

Number of Number of preference Share capital, Voting rights, Shareholder SDRs shares % %

BNP Paribas (Suisse) S.A., W8IMY ...... 39,865,225 504,700 22.9% 23.2% OJSC Alliance Group...... 30,816,997 0 17.5% 17.9% CJSC Investment Company Alliance Capital.. 6,637,129 0 3.8% 3.9% Repsol Exploracion S.A...... 5,495,136 0 3.1% 3.2% JPM Chase NA...... 5,042,610 0 2.9% 2.9% Fo¨rsa¨kringsaktiebolaget, Avanza Pension...... 3,752,466 187,393 2.25 2.2% JPM Chase NA...... 2,955,769 0 1.7% 1.7% Swedbank Robur Folksams LO Sverige ...... 2,823,314 0 1.6% 1.6% SSB CL Omnibus AC OM07 (15 PCT) ...... 2,785,047 12,500 1.6% 1.6% Catella Reavinstfond ...... 2,600,611 0 1.5% 1.5% Afa Sjukfo¨rsa¨krings AB...... 2,015,217 0 1.1% 1.2% BK Julius Baer & Co Sweden Main AC...... 1,998,065 0 1.1% 1.2% Euroclear Bank S.A./N.V, W8-IMY ...... 1,745,690 123,929 1.1% 1.0% JPM Chase NA...... 1,803,486 0 1.0% 1.0% SIX SIS AG, W8IMY ...... 1,519,586 42,050 0.9% 0.9% 15 LARGEST SHAREHOLDERS ...... 111,856,348 870,572 63.8% 65.1%

Other owners ...... 59,672,066 4,129,428 36.2% 34.9%

Total...... 171,528,414 5,000,000 100% 100%

121 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA Distribution of Shareholders The following table sets forth information regarding share distribution by size of holdings as of 28 February 2013:

No. of No. of preference Share capital, Shareholding Size (in SDRs) Shareholders No. of SDRs shares %

1 – 500 ...... 26,577 3,700,533 251,597 2.2% 501 – 1000...... 3,950 3,052,496 196,182 1.8% 1,001 – 5,000 ...... 3,760 8,119,805 449,920 4.9% 5,001 – 10,000 ...... 489 3,503,083 182,885 2.1% 10,001 – 15,000 ...... 128 1,513,142 87,691 0.9% 15,001 – 20,000 ...... 79 1,352,913 65,576 0.8% 20,001 and more ...... 296 150,286,442 3,766,149 87.3%

Total...... 35,279 171,528,414 5,000,000 100%

The following table sets forth information regarding geographical distribution of the Issuer’s shareholders as of 31 January 2013:

No. of No. of preference Share capital, Shareholding Size (in SDBs) Shareholders No. of SDBs shares %

Russia...... 4 37,455,376 0 21.2% Sweden ...... 34,284 51,312,455 1,748,008 30.1% Switzerland...... 56 44,280,524 602,920 25.4% UK ...... 87 14,428,336 347,531 8.3% USA ...... 75 9,440,956 159,339 5.5% Spain ...... 20 5,539,952 1,450 3.1% Luxembourg...... 32 1,223,666 1,898,490 1.8% Ten largest countries...... 34,558 163,681,265 4,757,738 95.4%

Other countries ...... 721 7,847,149 242,262 4.5%

Total...... 35,279 171,528,414 5,000,000 100%

Except as set forth above, the Issuer is not directly or indirectly owned or controlled by any person, corporation or government, and except as set forth above, none of the Issuer’s shareholders has voting rights different from any other holders of the Issuer’s shares. The beneficial owners may be able to exert a significant influence on the Issuer. See ‘‘Risk Factors – The Bazhaev Family owns a significant stake in the Group; its interests may conflict with those of other shareholders and the Noteholders’’.

122 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA RELATED PARTY TRANSACTIONS

Interested Party Transactions under Russian Law The Joint Stock Companies Law sets forth certain requirements with respect to transactions involving interested parties. An interested party is any of the following: (i) a member of the board of directors, (ii) a person performing functions of the sole executive body (e.g. the Chairman of the Management Committee), (iii) a member of the collective executive body (e.g. the Management Committee), (iv) a shareholder who owns, together with any of its affiliates, at least 20% of the company’s voting shares, or (v) any person who has the rights to issue mandatory instructions to the company, so long as any of the abovementioned persons and/or their spouse, parents, children, adoptive parents or children, brothers or sisters or their affiliates: * is a party to, or beneficiary of, a transaction with the company, whether directly or as a representative or intermediary; * owns, individually or collectively, at least 20% of the shares of a legal entity that is a party to, or beneficiary of, a transaction with the company, whether directly or as a representative or intermediary; or holds offices in any of the company’s management bodies (or in any management body of the managing company of such company) that is a party to, or beneficiary of, a transaction with the company, whether directly or as a representative or intermediary; and * in other cases, as provided by Russian law. The Joint Stock Companies Law requires that an interested party transaction must be approved by a majority vote of the directors (sufficient in number to constitute a quorum) who are not interested in the transaction or by a shareholders meeting. For companies with more than 1,000 shareholders, an interested party transaction must be approved by a majority vote of the independent directors of the company who are not interested in the transaction. For purposes of this rule, an ‘‘independent director’’ is a member of the board of directors who is not, and within the year preceding the decision to approve the transaction was not: * a member of any executive body; * a member of any management body of the company’s management organisation; * a person whose relatives held positions on management bodies of the company or the managing company or were sole manager of such company; or * an affiliate of the company, except for being its director. An interested party transaction must be approved by a decision of the majority of disinterested shareholders holding voting shares, if: * the value of such a transaction, or series of related transactions, is 2% or more of the balance sheet value of the company’s assets as of the last reporting date; * the transaction, or series of interrelated transactions, involves the issuance by subscription or disposal of, ordinary shares in an amount exceeding 2% of the earlier issued existing ordinary shares or securities convertible into such shares; * the transaction, or series of related transactions, involves the issuance by subscription of securities convertible into shares, which may be converted into ordinary shares, in an amount exceeding 2% of the earlier issued existing ordinary shares or ordinary shares into which the above-mentioned convertible securities may be converted; * all members of the board of directors are interested parties, and/or none of them is an independent director; or * the number of the disinterested directors is not sufficient to constitute a quorum. The approval of interested party transactions of an open joint stock company is not required if: * the company has only one shareholder that simultaneously performs the functions of the executive body of a company; * all shareholders are interested in such transactions; * the transactions arise from the shareholders executing their pre-emptive rights to purchase newly issued shares; * the company is purchasing or buying out its issued shares;

123 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA * the company is undergoing reorganisation in the form of a merger or accession; or * the company is required by federal legislation to enter into the transactions, and settlements under such transactions are made pursuant to fixed tariffs and prices established by competent state authorities. Any interested party transaction must be approved prior to its execution. An interested party transaction entered into in breach of the above-mentioned rules may be invalidated by a court pursuant to an action of a company or any of its shareholders only if the other party to the transaction knew or should have known of its interested party nature and if the transaction resulted in losses to the company or a shareholder. The interested party is liable to a company for any loss incurred by the company.

Related Party Transactions for the Years Ended 31 December 2012, 2011 and 2010 For additional information on related party transactions for the years ended 31 December 2012, 2011 and 2010, see ‘‘Note 37 to the 2012 Financial Statements and Note 36 to the 2011 Financial Statements’’. Related parties include shareholders, associates, other related parties representing entities under common ownership and control with the Group and members of key management personnel. In May 2011, the Group completed the acquisition of 40% of the share capital of Lia Oil from a related party for cash consideration of USD 20,000 thousand. From the acquisition, Lia Oil has been treated as an associate of the Group and accounted for using the equity method. Prior to the acquisition, transactions with Lia Oil were treated as transactions with other related parties. The table below shows significant balances with related parties at 31 December 2012, 2011 and 2010:

For the years ended 31 December

2012 2011 2010

(USD thousand) Shareholders Trade and other accounts receivable...... 1,153 886 — Associates Trade and other accounts receivable...... 19,112 20,076 — Advances paid and prepaid expenses ...... 2,002 — — Advances received and accrued expenses ...... 55,057 79,670 — Other related parties Other non-current...... — — 20,000 Trade and other accounts receivable...... 9 1,400 869 Advances paid and prepaid expenses ...... 1,999 1,403 1,729 Other financial assets...... — 26,159 30,264 Trade and other accounts receivable...... — 11 699 Advances received and accrued expenses ...... — 20 74,230

124 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA The table below shows significant transactions with related parties for the years ended 31 December 2012, 2011 and 2010:

For the years ended 31 December

2012 2011 2010

(USD thousand) Associates Revenue ...... 917,508 482,840 — Purchase of petroleum products...... 28,052 7,482 19,450 Purchase of services ...... 1,531 341 — Loans provided...... 24,786 16,588 5,897 Loans repaid...... 24,786 16,588 5,897 Other related parties Revenue ...... 253 385,327 575,883 Purchase of services ...... 18,583 35,377 35,755 Charity contributions to the Fund named by Z. Bazhaev (for participation in Russian federal national projects) ...... 9,736 10,333 5,252 Interest income ...... 3,370 3,111 2,379 Short-term deposits placed ...... — 30,015 — Proceeds from deposits withdrawn...... 27,030 30,076 — Revenue from sales to related parties includes sales of crude oil and petroleum products in the domestic and export markets. Purchase of services from related parties mainly includes insurance services and rent. The charity contributions to the Bazhaev charity fund were made with the purpose of their further transfer to the federal treasury of the Russian Federation and other governmental organisations. Transactions with shareholders with significant influence, associates and other related parties relate to transactions in the ordinary course of business with terms and conditions, that the Group believes similar to transactions with third parties. All related party balances are unsecured and will be settled in cash under normal commercial credit terms. No guarantees have been given or received in relation to any related party balance. Disclosure of transactions in relation to members of key management personnel is presented in ‘‘Note 35 to the 2012 Financial Statements’’.

125 c108210pu040 Proof 9: 29.4.13_14:33 B/L Revision: 0 Operator PutA TERMS AND CONDITIONS OF THE NOTES

The U.S.$500,000,000 7.000 per cent. guaranteed notes due 2020 of Alliance Oil Company Ltd. (the ‘‘Issuer’’) (the ‘‘Notes’’, which expression, where the context so admits, shall include an unrestricted global note (the ‘‘Unrestricted Global Note’’) and one or more restricted global notes (together, the ‘‘Restricted Global Note’’ and, together with the Unrestricted Global Note, the ‘‘Global Notes’’ and each a ‘‘Global Note’’) are guaranteed unconditionally and irrevocably, on a joint and several basis, by Closed Joint-Stock Company Alliance Oil, Open Joint Stock Company Oil Company Alliance, Limited Liability Company ‘‘Alliance-Bunker’’, Closed Joint-Stock Company Alliancetransoil, Closed Joint Stock Company Khvoinoye, Kolvinskoe Limited Liability Company, Open Joint Stock Company ‘‘Eastern Transnational Company’’ and Limited Liability Company SN-Gasproduction (the ‘‘Fully Owned Guarantors’’) and Open Joint Stock Company ‘‘Amurnefteproduct’’, OPEN Joint Stock Company ‘‘Khabarovsknefteproduct’’, Open Joint Stock Company ‘‘Pechoraneft’’, ‘‘Potential Oil’’ Limited Liability Partnership and Public Joint Stock Company ‘‘Primornefteprodukt’’ (the ‘‘Partly Owned Guarantors’’ and, together with the Fully Owned Guarantors, the ‘‘Guarantors’’). The Notes were authorised by the unanimous written resolution of the Board of Directors of the Issuer passed on 22 April 2013. The Guarantees (as defined below) of the Notes were authorised by a resolution of the shareholders of each Guarantor passed between 1 and 25 April 2013. The Notes are constituted by a trust deed dated 3 May 2013 (the ‘‘Trust Deed’’) between the Issuer, the Fully Owned Guarantors and BNY Mellon Corporate Trustee Services Limited (the ‘‘Trustee’’, which expression shall include all persons for the time being who are the trustee or trustees under the Trust Deed) as trustee for the holders of the Notes. Each of the Partly Owned Guarantors have entered into a separate deed of guarantee with the Trustee, dated on or about the date of the Trust Deed (each a ‘‘Deed of Guarantee’’ and together the ‘‘Deeds of Guarantee’’). These terms and conditions (the ‘‘Conditions’’) include summaries of, and are subject to, the detailed provisions of the Trust Deed and the Deeds of Guarantee. The Issuer and the Fully Owned Guarantors have entered into an agency agreement dated 3 May 2013 (the ‘‘Agency Agreement’’) with the Trustee, The Bank of New York Mellon, London Branch, as principal paying agent and transfer agent (the ‘‘Principal Paying Agent’’ and ‘‘Transfer Agent’’, respectively, together with any other paying agents appointed under the Agency Agreement, the ‘‘Paying Agents’’) and the Registrar and other Transfer Agents named therein. The Registrar, Paying Agents and Transfer Agents are together referred to herein as the ‘‘Agents’’. Copies of the Trust Deed, the Deeds of Guarantee and the Agency Agreement are available for inspection during normal business hours at the specified office of the Trustee, being at the date hereof One Canada Square, London E14 5AL, and at the specified offices of the Agents. The Noteholders (as defined below) are entitled to the benefit of, are bound by, and are deemed to have notice of, all the provisions of the Trust Deed and the Deeds of Guarantee and are deemed to have notice of those provisions of the Agency Agreement applicable to them. Capitalised terms used but not defined in these Conditions shall have the respective meanings given to them in the Trust Deed and the Deeds of Guarantee.

1 Form and Denomination The Notes are issued in fully registered form, without interest coupons attached, in denominations of U.S.$200,000 or integral multiples of U.S.$1,000 in excess thereof (each an ‘‘Authorised Denomination’’). The Notes may be transferred only in amounts not less than an Authorised Denomination. Title to the Notes shall pass by registration in the register (the ‘‘Register’’) which the Issuer shall procure to be kept by the Registrar. The Notes are initially issued in global, fully registered form, and will only be exchangeable for Notes in definitive, fully registered form (‘‘Definitive Notes’’) in the limited circumstances set forth in the Agency Agreement.

126 2 Guarantee and Status 2.1 Guarantee The Fully Owned Guarantors and Partly Owned Guarantors have each separately, pursuant to the Trust Deed and Deeds of Guarantee, respectively, unconditionally and irrevocably, on a joint and several basis, guaranteed the payment when due of all sums expressed to be payable by, and all other obligations of, the Issuer under the Trust Deed and the Notes (each a‘‘Guarantee’’ and together the ‘‘Guarantees’’).

2.2 Status The Notes constitute senior, unsubordinated and unsecured obligations of the Issuer and shall at all times rank pari passu and without any preference among themselves. Each Guarantee constitutes senior, unsubordinated and unsecured obligations of the relevant Guarantor. Each of the Issuer and the Guarantors shall ensure that at all times the claims of the Noteholders against them under the Notes and the Guarantees, respectively, rank in right of payment at least pari passu with the claims of all their other present and future unsecured and unsubordinated creditors, save those whose claims are preferred by any mandatory operation of law.

3 Register, Title and Transfers 3.1 Register The Registrar shall maintain a Register at the specified office for the time being of the Registrar in respect of the Notes in accordance with the provisions of the Agency Agreement and shall record in such Register the names and addresses of the holders of the Notes, particulars of the Notes and all transfers and redemptions thereof. In these Conditions, the ‘‘Holder’’ of a Note means the person in whose name such Note is for the time being registered in a Register (or, in the case of a joint holding, the first named thereof) and ‘‘Noteholder’’ shall be construed accordingly.

3.2 Title Title to the Notes will pass by and upon registration in the Register. The Holder of each Note shall (except as otherwise required by a court of competent jurisdiction or applicable law) be treated as the absolute owner of such Note for all purposes (whether or not it is overdue and regardless of any notice of ownership, trust or any other interest therein, any writing on the Definitive Note relating thereto (other than the endorsed form of transfer) or any notice of any previous loss or theft of such Definitive Note) and no person shall be liable for so treating such Holder.

3.3 Transfers Subject to Conditions 3.6 and 3.7 below, a Note may be transferred in whole or in part in an Authorised Denomination upon surrender of the relevant Definitive Note representing that Note, together with the form of transfer (including any certification as to compliance with restrictions on transfer included in such form of transfer endorsed thereon) (the ‘‘Transfer Form’’), duly completed and executed, at the specified office of a Transfer Agent or of the Registrar, together with such evidence as such Agent or the Registrar may reasonably require to prove the title of the transferor and the authority of the persons who have executed the Transfer Form. Where not all the Notes represented by the surrendered Definitive Note are the subject of the transfer, a new Definitive Note in respect of the balance not transferred will be delivered by the Registrar to the transferor in accordance with Condition 3.4. Neither the part transferred nor the balance not transferred may be less than U.S.$200,000.

3.4 Registration and delivery of Definitive Notes Within five Business Days of the surrender of a Definitive Note in accordance with Condition 3.3 above, the Registrar shall register the transfer in question and deliver a new Definitive Note to each relevant Holder at the specified office of the Registrar or (at the request of the relevant Noteholder) at the specified office of a Transfer Agent or (at the request and risk of such relevant Holder) send it by uninsured first class mail (airmail if overseas) to the address specified for the purpose by such relevant Holder.

127 c108210pu050 Proof 9: 29.4.13_14:34 B/L Revision: 0 Operator PutA 3.5 No Charge The registration of the transfer of a Note shall be effected without charge to the Holder or transferee thereof, but against such indemnity from the Holder or transferee thereof as the Registrar may require in respect of any tax or other duty of whatsoever nature which may be levied or imposed in connection with such transfer.

3.6 Closed periods Noteholders may not require the transfer of a Note to be registered during the period of 15 days ending on the due date for any payment of principal or interest in respect of such Note.

3.7 Regulations concerning Transfer and Registration All transfers of Notes and entries on a Register are subject to the detailed regulations concerning the transfer and registration of Notes set out in Schedule 1 to the Agency Agreement. The regulations may be changed by the Issuer with the prior written approval of the Trustee, the Transfer Agents and the Registrar. A copy of the current regulations will be sent by the Registrar free of charge to any person who so requests and who can confirm they are a Holder to the satisfaction of the Registrar and will also be available at the specified office of the Registrar.

4 Covenants 4.1 Limitation on Indebtedness 4.1.1 The Issuer will not, and will not permit any Subsidiary to, Incur, directly or indirectly, any Indebtedness; provided, however, that the Issuer and its Subsidiaries will be entitled to Incur Indebtedness if: (i) after giving effect to such Incurrence and the application of the proceeds thereof, on a pro forma basis, no actual or potential Default or Event of Default would occur or be continuing; and (ii) on the date of such Incurrence and after giving effect thereto, on a pro forma basis, the Consolidated Leverage Ratio does not exceed 3.5 to 1.0. 4.1.2 Notwithstanding the foregoing Condition 4.1.1, the following Indebtedness (each, ‘‘Permitted Indebtedness’’) may be incurred: (i) intercompany indebtedness owed to and held by the Issuer or a Subsidiary in respect of the Issuer or a Subsidiary; provided, however, that (A) any subsequent disposition, pledge or transfer of such intercompany Indebtedness (other than to the Issuer or a Subsidiary) shall be deemed, in each case, to constitute the Incurrence of such Indebtedness by the relevant obligor in respect of such Indebtedness and (B) if a Guarantor is the obligor in respect of such Indebtedness, such Indebtedness is unsecured and is expressly subordinated to the prior payment in full in cash of all obligations of such Guarantor with respect to its Guarantee; (ii) Indebtedness represented by the Notes and the Guarantees of the Notes; (iii) Indebtedness outstanding on the Issue Date; (iv) Indebtedness of the Issuer or a Subsidiary Incurred and outstanding on or prior to the date on which such Subsidiary was acquired by the Issuer (other than Indebtedness Incurred in connection with, or to provide all or any portion of the funds or credit support utilised to consummate, the transaction or series of related transactions pursuant to which such Subsidiary became a Subsidiary or was acquired by the Issuer); provided, however, that on the date of such acquisition and after giving pro forma effect thereto, either (1) the Issuer would have been entitled to Incur at least U.S.$1.00 of additional Indebtedness pursuant to Condition 4.1.1 or (2) the Consolidated Leverage Ratio would be less than it was immediately prior to giving pro forma effect to the incurrence of such Indebtedness pursuant to this paragraph (iv); (v) Permitted Refinancing Indebtedness; (vi) Hedging Obligations Incurred in the ordinary course of business of the Issuer or any Subsidiary and not entered into for speculative purposes;

128 c108210pu050 Proof 9: 29.4.13_14:34 B/L Revision: 0 Operator PutA (vii) obligations in respect of performance, bid and surety bonds, completion guarantees, letters of credit, veksels or similar obligations provided by the Issuer or any Subsidiary in the ordinary course of business, provided that, upon demand being made under such obligations, such obligations are reimbursed or the Indebtedness thereunder repaid within 30 Business Days following such payment or disbursement in respect of such demand; (viii) Indebtedness arising from the honouring by a bank or other financial institution of a check, draft or similar instrument inadvertently drawn against insufficient funds in the ordinary course of business; provided, however, that such Indebtedness is extinguished within five Business Days of its Incurrence; (ix) Indebtedness arising from agreements of the Issuer or a Subsidiary providing for indemnification, adjustment of purchase price or similar obligations, in each case, incurred or assumed in connection with the acquisition or disposition of any business, assets or Capital Stock of the Issuer or any Subsidiary; provided that the maximum aggregate liability in respect of all such Indebtedness shall at no time exceed the gross proceeds (including the Fair Market Value of non-cash consideration) actually received by (or held in escrow as a collateral for such Indebtedness for later release to) the Issuer and the Subsidiaries in connection with such disposition (without giving effect to any subsequent changes in value); (x) Indebtedness in respect of workers’ compensation claims or claims arising under similar legislation, or pursuant to self-insurance obligations and not in connection with the borrowing of money or the obtaining of advances or credit; (xi) customer deposits received from customers in the ordinary course of business; and (xii) Indebtedness in an aggregate principal amount at any one time outstanding under this Condition 4.1 not to exceed U.S.$200 million. 4.1.3 Notwithstanding the foregoing, neither the Issuer nor any Subsidiaries will Incur any Indebtedness pursuant to Condition 4.1 if the proceeds thereof are used, directly or indirectly, to Refinance any Subordinated Obligations of the Issuer or any Guarantor unless such Indebtedness shall be subordinated to the Notes or the applicable Guarantee to at least the same extent as such Subordinated Obligations.

4.1.4 For purposes of determining compliance with this Condition 4.1: (i) in the event that an item of Indebtedness (or any portion thereof) meets the criteria of more than one of the types of Indebtedness described in Conditions 4.1.1 or 4.1.2, the Issuer, in its sole discretion, will classify such item of Indebtedness (or any portion thereof) at the time of Incurrence and will only be required to include the amount and type of such Indebtedness in one of the above sub-Conditions; and (ii) the Issuer will be entitled to divide and classify an item of Indebtedness in more than one of the types of Indebtedness described in Conditions 4.1.1 or 4.1.2 and may change the classification of an item of Indebtedness (or any portion thereof) to any other type of Indebtedness described in Conditions 4.1.1 or 4.1.2 at any time. The outstanding principal amount of any particular Indebtedness shall be counted only once and any obligations arising under any guarantees, Lien, letters of credit or similar instrument supporting such Indebtedness shall not be double counted. 4.1.5 For purposes of determining compliance with any U.S. dollar denominated restriction on the Incurrence of Indebtedness where the Indebtedness Incurred is denominated in a different currency, the amount of such Indebtedness will be the U.S. Dollar Equivalent determined on the date of the Incurrence of such Indebtedness; provided, however, that if any such Indebtedness denominated in a different currency is subject to a Currency Agreement with respect to U.S. dollars covering all principal, premium, if any, and interest payable on such Indebtedness, the amount of such Indebtedness expressed in U.S. dollars will be as provided in such Currency Agreement. The principal amount of any Permitted Refinancing Indebtedness Incurred in the same currency as the Indebtedness being Refinanced will be the U.S. Dollar Equivalent, as appropriate, of the Indebtedness Refinanced, except to the extent that (A) such U.S. Dollar Equivalent was determined based on a Currency Agreement, in which case the Permitted Refinancing Indebtedness will be determined in accordance with the preceding sentence, and (B) the principal amount of the Permitted Refinancing Indebtedness exceeds the principal amount of the Indebtedness being Refinanced, in which case the U.S.

129 c108210pu050 Proof 9: 29.4.13_14:34 B/L Revision: 0 Operator PutA Dollar Equivalent of such excess, as appropriate, will be determined on the date such Permitted Refinancing Indebtedness is Incurred. Notwithstanding any other provision of this Condition 4.1, the maximum amount that the Issuer or a Subsidiary may Incur pursuant to this Condition 4.1 shall not be deemed to be exceeded, with respect to outstanding Indebtedness, due solely as a result of fluctuations in the exchange rates of currencies.

4.2 Limitation on Sales of Assets and Material Subsidiary Stock 4.2.1 The Issuer will not, and will not permit any Material Subsidiary to, directly or indirectly, consummate any Asset Disposition having an aggregate value exceeding U.S.$15 million in any 12 month period to any person or entity that is not a member of the Group unless: (i) the Issuer or such Material Subsidiary receives consideration at the time of such Asset Disposition at least equal to the Fair Market Value (including as to the value of all non-cash consideration) of the Capital Stock and assets subject to such Asset Disposition; and (ii) if such Asset Disposition involves an amount in excess of US$50 million, the Board of Directors shall also have received a written opinion from an Independent Qualified Party to the effect that such Asset Disposition is fair, from a financial standpoint, to the Issuer and its Material Subsidiaries or is not less favourable to the Issuer and its Material Subsidiaries than could reasonably be expected to be obtained at the time in an arm’s length transaction with a Person who was not an Affiliate; and (iii) an amount equal to at least 75 per cent. of the Net Available Cash from such Asset Disposition is applied by the Issuer or such Material Subsidiary, as the case may be, within 180 days of receipt: (a) to the extent the Issuer or any Material Subsidiary elects (or is required by the terms of any Indebtedness), to prepay, repay, redeem or purchase Indebtedness which in the case of the Issuer of any Guarantor is senior to or pari passu with the Notes or the Guarantees, as the case may be; or (b) as an investment of assets or equity in the Core Business or to finance the acquisition, merger, reorganisation or other combination of a business of the Group with the business of a Person that is similar to the Core Business; or (c) to invest in Cash or Cash Equivalents (defined as cash or short term paper held with highly rated banks in an Approved Jurisdiction), provided, however, that if the use of Net Available Cash is applied under sub-Condition (iii)(c) above, such Net Available Cash must be applied pursuant to sub-Condition (iii)(a) or (iii)(b) within 360 days from the date of the receipt of such Net Available Cash. 4.2.2 For the purposes of this Condition 4.2, the following are deemed to be ‘‘Cash Equivalents’’: (i) securities received by the Issuer or any Material Subsidiary from the transferee that are converted within 120 days by the Issuer or such Material Subsidiary into cash, to the extent of the cash received in that conversion; and (ii) Temporary Cash Investments.

4.3 Limitation on Affiliate Transactions 4.3.1 The Issuer will not, and will not permit any Material Subsidiary to, enter into or permit to exist any transaction or a series of related transactions (including the purchase, sale, lease or exchange of any property, employee compensation arrangements or the rendering of any service) with, or for the benefit of, any Affiliate of the Issuer (an ‘‘Affiliate Transaction’’) unless such transaction or series of related transactions is entered into in good faith and in writing and: (i) the terms of the Affiliate Transaction are no less favourable to the Issuer or such Material Subsidiary than those that could be obtained at the time of the Affiliate Transaction in arm’s length dealings with a Person who is not an Affiliate and at Fair Market Value; (ii) if such Affiliate Transaction involves an amount in excess of U.S.$10 million, the terms of the Affiliate Transaction are set forth in writing and a majority of the directors of the Issuer disinterested with respect to such Affiliate Transaction (or, in the event that

130 c108210pu050 Proof 9: 29.4.13_14:34 B/L Revision: 0 Operator PutA there is only one disinterested director, by the resolution of such disinterested director or, in the event that there are no disinterested directors, by unanimous resolution of the entire Board of Directors) have determined in good faith that the criteria set forth in sub-Condition (i) above are satisfied and have approved the relevant Affiliate Transaction as evidenced by a resolution of the Board of Directors; and (iii) if such Affiliate Transaction involves an amount in excess of U.S.$20 million, the Board of Directors shall also have received a written opinion from an Independent Qualified Party to the effect that such Affiliate Transaction is fair, from a financial standpoint, to the Issuer and its Material Subsidiaries or is not less favourable to the Issuer and its Material Subsidiaries than could reasonably be expected to be obtained at the time in an arm’s length transaction with a Person who was not an Affiliate.

4.3.2 The provisions of Condition 4.3.1 above will not apply to: (i) any transaction or series of related transactions in an aggregate amount not exceeding U.S.$5 million (or the equivalent thereof in any other currency) in any 12 month period; (ii) any payments for a charitable or social purpose in an aggregate amount not exceeding U.S.$20 million (or the equivalent thereof in any other currency) in any 12 month period (iii) transactions between or among all or any of the Issuer and a Subsidiary or between Subsidiaries; (iv) employment agreements and arrangements, compensation or employee benefit arrangements, customary directors’ fees, indemnification and similar arrangements (including the payment of directors’ and officers’ insurance premiums), employee salaries and bonuses, including stock options entered into in the ordinary course of business; (v) any issuance of securities, or other payments, awards or grants in cash, securities or otherwise pursuant to, or the funding of, employment arrangements, insurance plans, deferred compensation plans, retirement and savings plans, stock options and stock ownership plans that are customary and are approved by the Board of Directors in good faith and deemed the services theretofore or thereafter to be performed for such compensation or payments to be fair consideration therefor; (vi) loans or advances or guarantees of third party loans (but not any forgiveness of such loans or advances or guarantees) to employees, directors, officers and consultants in the ordinary course of business in accordance with the past practices of the Issuer or its Subsidiaries, but in any event not to exceed U.S.$5 million in the aggregate outstanding at any one time; (vii) the issuance or sale of any Capital Stock of the Issuer or the issuance and sale of any Capital Stock of a Subsidiary to the Issuer or any Subsidiary of the Issuer; (viii) consulting fees, so long as the Board of Directors of the Issuer or a Subsidiary, as appropriate, has approved the terms thereof in good faith and deemed the services theretofore or thereafter to be performed for such compensation or payments to be fair consideration therefore and in the ordinary course of a Core Business of the Issuer or such Subsidiary, but in any event, not to exceed U.S.$5 million in any 12-month period; (ix) agreements and arrangements existing on the Issue Date and any amendment, extension, renewal, refinancing, modification or supplement thereof, provided that following such amendment, extension, renewal, refinancing, modification or supplement, the terms of any such agreement or arrangement so amended, modified or supplemented are not materially more disadvantageous to the Noteholders and to the Issuer and the Subsidiaries, as applicable, than the original agreement or arrangement as in effect on the Issue Date and provided, further, that such amendment or modification is in the case of any transaction having a Fair Market Value of greater than U.S.$20 million (or the equivalent thereof in any other currency), approved by the Issuer’s Board of Directors (including a majority of the disinterested directors or, in the event that there is only one disinterested director, by the resolution of such disinterested director or, in the event that there are no disinterested directors, by unanimous resolution of the entire Board of Directors);

131 c108210pu050 Proof 9: 29.4.13_14:34 B/L Revision: 0 Operator PutA (x) transactions in the ordinary course of business with a Person that is an Affiliate of the Issuer solely because the Issuer owns, directly or through one or more Subsidiaries, Capital Stock in, or controls, such Person; and (xi) transactions with customers, clients, suppliers or purchasers or sellers of goods or services consistent with past practice (including without limitation (i) any and all sales and/or purchases of crude oil and/or oil products between any Subsidiary and an Affiliate of the Issuer and (ii) the lease of real property entered into between any Subsidiary and an Affiliate of the Issuer), in each case, in the ordinary course of business and otherwise in compliance with these Conditions, which are fair to the Issuer or the relevant Subsidiary in the reasonable determination of the Board of Directors or the senior management of the Issuer, in each case, that are disinterested with respect to such Affiliate Transaction or are on terms no less favourable than those that could reasonably have been obtained at such time from an unaffiliated party.

4.4 Limitation on Liens Each of the Issuer and the Guarantors will not, and will not permit any Subsidiary to, directly or indirectly, create, incur, assume or suffer to exist any Lien (other than a Permitted Lien (as defined below)) of any nature whatsoever on any of its properties or assets (including Capital Stock of a Subsidiary), whether owned at the Issue Date or thereafter acquired, or on any income, revenue or profits therefrom, securing any Indebtedness without at the same time or prior thereto effectively providing that the Issuer’s obligations under the Notes or the relevant Guarantor’s obligation under the Guarantee, as the case may be, shall be secured equally and rateably with the Indebtedness secured by such Lien. Any Lien created in favour of the holders of the Notes under this Condition 4.4 will be automatically and unconditionally released and discharged upon (a) the release and discharge of the initial Lien to which it relates; (b) repayment in full of the Notes or; (c) a sale, lease, conveyance or other disposition to any person other than the Issuer or a Subsidiary of the Issuer of the property or assets to which the initial Lien relates.

4.5 Limitation on Lines of Business The Issuer shall procure that no material change is made to the general nature of the business of itself or any Material Subsidiary as at the Issue Date, such business to include, without limitation, all activities related to the oil and gas industry that the Issuer or a Material Subsidiary currently performs or may perform in the future (the ‘‘Core Business’’). The Issuer shall procure that no material change is made to the business of the Khabarovsk Refinery (as defined below) as conducted at the Issue Date (the ‘‘Khabarovsk Core Business’’).

4.6 Merger and Consolidation The Issuer will not, and will not permit any Guarantor to, consolidate with or merge with or into, or convey, transfer or lease, in one transaction or a series of transactions, all or substantially all of its assets to any Person if such consolidation or merger could result in a Material Adverse Effect.

4.7 Reports 4.7.1 As long as any Notes are outstanding, the Issuer will furnish to the Noteholders and the Trustee: (i) within 120 days following the first financial year ending December 31, 2012 and the end of each financial year thereafter, annual reports containing audited consolidated balance sheets of the Issuer as of the end of the two most recent financial years and audited consolidated income statements and statements of cash flow of the Issuer for the two most recent financial years, in each case prepared in accordance with IFRS, and including complete footnotes to such financial statements and the report of the independent auditors on the financial statements; (ii) within 90 days following the end of each quarterly reporting period, interim financial statements containing an unaudited condensed consolidated balance sheet as of the end of such interim period and unaudited condensed statements of income and cash flow for the interim period ending on the unaudited condensed balance sheet date, and the

132 c108210pu050 Proof 9: 29.4.13_14:34 B/L Revision: 0 Operator PutA comparable prior year periods, in each case prepared in accordance with IFRS, together with complete footnotes to such financial statements and, for either each six months period ended 30 June or each nine months period ended 30 September (the applicable period to be determined by the Issuer in its sole discretion on an annual basis), such interim financial statements shall include an independent auditors’ review report; and (iii) upon reasonable request, further information about the business and financial condition of the Group, and as may be required by the Stock Exchange in connection with listing or admission to trading. 4.7.2 The Issuer shall provide to the Trustee an Officers’ Certificate of the Issuer on each interest payment date with respect to compliance with the Conditions and stating that the Issuer is not in default in the performance or observance of any of the terms, provisions and conditions hereof (or, if a potential Event of Default or Event of Default shall have occurred, describing all such potential Events of Default or Events of Default of which he may have knowledge). 4.7.3 In addition, so long as any of the Notes are restricted securities (as defined in Rule 144 under the Securities Act) and during any period during which the Issuer is not subject to the reporting requirements of the Exchange Act or exempt therefrom pursuant to Rule 12g3-2(b), the Issuer will furnish to any Holder or beneficial owner of Notes initially offered and sold in the United States to Qualified Institutional Buyers pursuant to Rule 144A under the Securities Act, and to prospective purchasers in the United States designated by such Holder or beneficial owners, upon request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

4.8 Payment of Taxes and Other Claims So long as any amount remains outstanding under the Notes, the Issuer shall, and shall cause each Material Subsidiary to, pay or discharge or cause to be paid or discharged, before the same shall become overdue and without incurring penalties, (a) all taxes, assessments and governmental charges levied or imposed upon, or upon the income, profits or assets of the Issuer or any of the Issuer’s Material Subsidiaries (which, in the context of any entity incorporated in the Russian Federation, shall mean the earlier of either a ruling of the tax inspection based on an act of audit (reshenie, vynesennoye po aktu proverki) or a request to pay taxes (trebovanie ob uplate naloga)) and (b) all lawful claims for labour, materials and supplies which, if unpaid, might by law become an Lien (other than a Permitted Lien) upon the property of the Issuer or any of the Issuer’s Material Subsidiaries; provided, however, that none of the Issuer nor any of the Issuer’s Material Subsidiaries shall be required to pay or discharge or cause to be paid or discharged any such tax, assessment or charge (which, in the context of any entity incorporated in the Russian Federation, shall mean the earlier of either a ruling of the tax inspection based on an act of audit (reshenie, vynesennoye po aktu proverki) or a request to pay taxes (trebovanie ob uplate naloga)) or any such claim (x) whose amount, applicability or validity is being contested in good faith by appropriate proceedings and for which adequate reserves in accordance with IFRS or other appropriate provision has been made or (y) where such non-payment or failure to discharge, together with any non- payment or failure to discharge any other such unpaid or undischarged tax, assessment, charge, request to pay taxes or claim, does not have in the aggregate a Material Adverse Effect.

4.9 Maintenance of Authorisations 4.9.1 The Issuer and each of its Material Subsidiaries shall obtain or make, and procure the continuance or maintenance of, all registrations, recordings, filings, consents, licences, approvals and authorisations, which may at any time be required to be obtained or made in Russia, Bermuda, Kazakhstan, or any other relevant jurisdiction for the purposes of the execution, delivery or performance of the Notes, the Deeds of Guarantee and the Trust Deed and for the validity and enforceability thereof; and 4.9.2 The Issuer and each of its Material Subsidiaries shall take all necessary action to obtain and do or cause to be done all things necessary, in the opinion of the Issuer or the relevant Material Subsidiary, to ensure the continuance of its corporate existence, its business and intellectual property relating to its business.

133 c108210pu050 Proof 9: 29.4.13_14:34 B/L Revision: 0 Operator PutA 4.10 Maintenance of Property The Issuer shall, and shall cause each of its Material Subsidiaries to, cause all property used in the conduct of its or their business to be maintained and kept in good condition, repair and working order and supplied with all necessary equipment and shall cause to be made all necessary repairs, renewals, replacements and improvements thereof, all as, in the judgment of the Issuer or the relevant Material Subsidiary, may be reasonably necessary so that the business carried on in connection therewith may be properly conducted at all times.

4.11 Additional Guarantors 4.11.1 The Issuer shall ensure that on each date which is 10 days after the publication of the semi- annual and annual financial statements referred to in Condition 4.7 (each a ‘‘Relevant Date’’) the consolidated total net assets or revenues of the Guarantors (calculated in accordance with IFRS), comprise 75 per cent. or more of the consolidated total net assets or revenues of the Group (calculated in accordance with IFRS), respectively, in each case with reference to the last available balance sheet and statement of income of the Guarantors and of the Group immediately preceding the Relevant Date. 4.11.2 In the event that the test in Condition 4.11.1 is not satisfied on any Relevant Date, the Issuer will cause additional Subsidiaries (save as set out in Condition 4.11.3) to execute and deliver to the Trustee a deed of guarantee in the same form as the Deeds of Guarantee, pursuant to which each such Subsidiary will unconditionally and irrevocably, on a joint and several basis with each other Guarantor, guarantee the payment of all moneys payable under the Trust Deed and the Notes and will become vested with all the duties and obligations of a Guarantor as if originally named a Guarantor under a Deed of Guarantee, as soon as practicable (but in any event no later than 90 days), such that, following such Relevant Date, if such additional Subsidiaries had been included as Guarantors prior to or as of such date the test in Condition 4.11.1 would have been satisfied.

4.11.3 Notwithstanding Condition 4.11.2, the Issuer will not be required to add: (i) OJSC Khabarovsk Oil Refinery (‘‘Khabarovsk Refinery’’) as a Guarantor, subject to compliance with Condition 4.5; (ii) any Subsidiary which accounts for less than 1 per cent. of the Group’s net assets or revenues on an unconsolidated basis after disallowing intra-group transactions in accordance with IFRS; or (iii) any Subsidiary to the extent that such guarantee by such Subsidiary would reasonably be expected to give rise to or result in a violation of applicable law (as certified in a legal opinion from a reputable legal counsel in the relevant jurisdiction that is reasonably acceptable to the Trustee) which cannot be prevented or otherwise avoided through measures reasonably available to the Issuer or the Subsidiary. 4.11.4 The Issuer may remove a Guarantor or Guarantors at its discretion if the remaining Guarantors in the aggregate constitute at least 75 per cent. of the Group’s consolidated total net assets and revenues under the test set forth in Condition 4.11.1. 4.11.5 The Issuer will give prior written notice to the Trustee of, and to Holders in accordance with Condition 16 hereof forthwith upon, any Guarantor ceasing to be a Guarantor, any additional Subsidiary of the Issuer becoming a Guarantor and, so long as the Notes are listed on the Stock Exchange and/or any other stock exchange on which the Notes may be listed or quoted from time to time, shall comply with applicable rules of the Stock Exchange and/or such other exchange (including preparation of a supplemental prospectus) in relation to any Guarantor ceasing to be a Guarantor or any of the Subsidiaries of the Issuer becoming Guarantors. 4.11.6 The Issuer shall also procure that there is delivered to the Trustee (at the expense of the Issuer) on the date of the execution of each such deed of guarantee an opinion of counsel of recognised standing acceptable to the Trustee, in form and substance satisfactory to the Trustee, stating that all legal conditions precedent in relation to such substitution or addition have been complied with and that such Deed of Guarantee, constitutes legal, valid and binding obligations of the respective additional Guarantor, enforceable in accordance with its terms, subject to customary exceptions, qualifications and limitations.

134 c108210pu050 Proof 9: 29.4.13_14:34 B/L Revision: 0 Operator PutA 4.12 Claims Pari Passu The Issuer and each Guarantor shall ensure at all times the claims of the Noteholders against it under the Notes and the Guarantees shall rank at least pari passu with claims of all other present and future unsecured and unsubordinated creditors, save those whose claims are preferred by any mandatory operation of law.

4.13 Maintenance of Insurance The Issuer and each Material Subsidiary shall maintain insurance with an insurer or insurers of sufficient standing on its insurable property against such losses and risks and in such amounts as are prudent and to the extent customary in its respective industry and jurisdiction.

4.14 Environmental Compliance The Issuer shall, and shall ensure each of its Material Subsidiaries will, comply with all environmental laws and obtain and maintain any environmental licenses and take all reasonable steps in anticipation of known or expected future changes to or obligations under the same.

5 Interest The Notes bear interest on their outstanding principal amount from and including the Issue Date at the rate of 7.000 per cent. per annum, payable semi-annually in arrear in equal instalments of U.S.$35 per U.S.$1,000 of the principal amount of the Notes on 4 May and 4 November in each year (each an ‘‘Interest Payment Date’’), except that the first payment of interest, to be made on 4 November 2013, will be in respect of the period from and including the Issue Date to but excluding 4 November 2013 and will amount to U.S.$35.19 per U.S.$1,000 of the principal amount of the Notes. Each Note will cease to bear interest from the due date for redemption unless, upon due presentation, payment of principal is improperly withheld or refused. In such event it shall continue to bear interest at such rate (both before and after judgment) until whichever is the earlier of (a) the day on which all sums due in respect of such Note up to that day are received by or on behalf of the relevant Holder, and (b) the day seven days after the Trustee or the Principal Paying Agent has notified Noteholders of receipt of all sums due in respect of all the Notes up to that seventh day (except to the extent that there is failure in the subsequent payment to the relevant Holders under these Conditions). If interest is required to be calculated for a period of less than a complete Interest Period (as defined below), (a) the relevant day-count fraction will be determined 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, and (b) the amount of interest shall be calculated by rounding the resulting figure to the nearest cent (half a cent being rounded upwards). In these Conditions, 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 is called an ‘‘Interest Period’’.

6 Redemption and Purchase 6.1 Final redemption Unless previously redeemed, or purchased and cancelled, the Notes will be redeemed at their principal amount on 4 May 2020 (the ‘‘Maturity Date’’). The Notes may not be redeemed at the option of the Issuer or any Guarantor other than in accordance with this Condition 6.

6.2 Optional redemption At any time prior to the Maturity Date, but on one occasion only, the Issuer may, at its option, on giving not less than 30 nor more than 60 days’ irrevocable notice to the Noteholders (the ‘‘Call Option Notice’’) repay the Notes in whole but not in part, at the price which shall be the following: (i) the principal amount; plus (ii) the Make Whole Premium; plus

135 (iii) interest and any additional amounts or other amounts that may be due thereon (if any) accrued but unpaid to but excluding the date on which the call option is to be settled (the ‘‘Call Settlement Date’’). The Call Option Notice shall specify the Call Settlement Date. For the purposes of this Condition: ‘‘Make Whole Premium’’ means, with respect to a Note at any time, the excess of (a) the present value of the Notes at the Call Settlement Date, plus any required interest payments that would otherwise be due to be paid on such Notes from the Call Settlement Date through to the Maturity Date calculated using a discount rate equal to the Treasury Rate at the Call Settlement Date plus 50 basis points, over (b) the outstanding aggregate principal amount of the Notes at the Call Settlement Date, provided that if the value of the Make Whole Amount at any time would otherwise be less than zero, then in such circumstances, the value of the Make Whole Amount will be equal to zero. ‘‘Treasury Rate’’ means the yield to maturity at the time of computation of United States Treasury securities with a constant maturity most nearly equal to the period from the Call Settlement Date to the Maturity Date. The Issuer will obtain such yield to maturity from information compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) which has become publicly available at least two Business Days (but not more than five Business Days) prior to the Call Settlement Date (or, if such Statistical Release is not so published or available, any publicly available source of similar market data selected by the Issuer in good faith)); provided, however, that if the period from the Call Settlement Date to the Maturity Date is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the Call Settlement Date to the Maturity Date is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used.

6.3 Redemption for tax reasons The Notes may be redeemed at the option of the Issuer in whole, but not in part, at any time, on giving not less than 30 nor more than 60 days’ notice to the Noteholders (which notice shall be irrevocable) at the principal amount thereof, together with interest accrued to the date fixed for redemption, if the Issuer satisfies the Trustee immediately prior to the giving of such notice that (i) the Issuer has or will become obliged to pay additional amounts as provided or referred to in Condition 8 as a result of any change in, or amendment to, the laws, treaties or regulations of any Relevant Jurisdiction, or any change in the application or official interpretation of such laws or regulations, which change or amendment becomes effective on or after the Issue Date and (ii) such obligation cannot be avoided by the Issuer taking reasonable measures available to it; provided that no such notice of redemption shall be given earlier than 90 days prior to the earliest date on which the Issuer would be obliged to pay such additional amounts were a payment in respect of the Notes then due. Prior to the publication of any notice of redemption pursuant to this Condition, the Issuer shall deliver to the Trustee (x) a certificate signed by two directors of the Issuer stating that the obligation referred to in (i) above cannot be avoided by the Issuer taking reasonable measures available to it and the Trustee shall be entitled to accept such certificate as sufficient evidence of the satisfaction of the conditions precedent set out in (ii) above, in which event it shall be conclusive and binding on the Noteholders and (y) an opinion of independent legal advisers of recognised standing to the effect that the Issuer has or will become obliged to pay such additional amounts as a result of such change or amendment. All Notes in respect of which any such notice of redemption is given under and in accordance with this Condition shall be redeemed on the date specified in such notice in accordance with this Condition.

6.4 Purchase The Issuer, each Guarantor and any of their respective Subsidiaries may at any time purchase Notes in the open market or otherwise at any price.

136 6.5 Cancellation All Notes redeemed or purchased pursuant to this Condition 6 shall be cancelled forthwith and may not be held or resold. Any Notes so cancelled may not be reissued.

7 Payments 7.1 Principal and other amounts Payment of principal and interest in respect of the Notes will be made to the persons shown in the Register at the close of business on the Record Date (as defined below). Payments of all amounts other than as provided in this Condition 7.1 will be made as provided in these Conditions.

7.2 Payments Each payment in respect of the Notes pursuant to Condition 7.1 will be made by transfer to a U.S. dollar account maintained by or on behalf of the payee with a bank in New York City. Payment instructions (for value on the due date or, if that is not a business day (as defined below), for value the first following day which is a business day) will be initiated on the business day preceding the due date for payment (for value the next business day).

7.3 Payments subject to laws All payments in respect of the Notes are subject in all cases to any applicable fiscal or other laws, regulations and directives in the place of payment or other laws to which the Issuer agrees to be subject to, and the Issuer will not be liable for any taxes or duties of whatever nature imposed by such laws, regulations, directives or agreements, but without prejudice to the provisions of Condition 8. No commissions or expenses shall be charged to the Noteholders in respect of such payments.

7.4 Payments on business days If the due date for any payment of principal or interest under this Condition 7 is not a business day, the Holder of a Note shall not be entitled to payment of the amount due until the next following business day and shall not be entitled to any further interest or other payment in respect of any such delay. In this Condition 7 only, ‘‘business day’’ means any day on which banks are open for business in the place of the specified office of the relevant Paying Agent and, in the case of payment by transfer to a U.S. dollar account as referred to above, on which dealings in foreign currencies may be carried on both in New York City and in such other place.

7.5 Record date ‘‘Record Date’’ means the seventh business day, in the place of the specified office of the Registrar, before the due date for the relevant payment.

7.6 Agents The initial Agents and their initial specified offices are listed above and in the Agency Agreement. The Issuer reserves the right to vary or terminate the appointment of all or any of the Paying Agents at any time (with the written approval of the Trustee) and appoint additional or other payment or transfer agents, provided that they will maintain (i) a Principal Paying Agent, (ii) a Paying Agent and a Transfer Agent having specified offices in at least one major European city approved by the Trustee and (iii) a Paying Agent with a specified office in a European Union member state that will not be obliged to withhold or deduct tax pursuant to any law implementing European Council Directive 2003/48/EC (as amended from time to time) on the taxation of savings income or any other Directive implementing the conclusions of the ECOFIN Council meeting of 26-27 November 2000. Notice of any such change will be provided to Noteholders as described in Condition 16.

8 Taxation All payments of principal and interest in respect of the Notes by or on behalf of the Issuer or under the Guarantees by the Guarantors shall be made free and clear of, and without withholding or deduction for, any taxes, duties, assessments or governmental charges of whatsoever nature imposed, levied, collected, withheld or assessed by or within the Relevant

137 Jurisdiction, unless such withholding or deduction is required by law. If any withholding or deduction for any taxes, duties, assessments or governmental charges of whatsoever nature is imposed, levied, collected, withheld or assessed by or within the Relevant Jurisdiction the Issuer or (as the case may be) the relevant Guarantor shall increase the relevant payment so as to result in the receipt by the Noteholders of such amounts as would have been received by them if no such withholding or deduction had been required, except that no such additional amounts shall be payable in respect of any Note presented for payment: (a) by or on behalf of a Holder which is liable to such taxes, duties, assessments or governmental charges in respect of such Note or the Guarantees by reason of its (or its beneficial owners) having some connection with any Relevant Jurisdiction other than the mere holding of such Note or the benefit of the Guarantees; or (b) where (in the case of a payment of principal or interest on redemption) the relevant Definitive Note is surrendered for payment more than 30 days after the Relevant Date except to the extent that the relevant Holder would have been entitled to such additional amounts if it had surrendered the relevant Definitive Note on the last day of such period of 30 days; or (c) where such withholding or deduction is imposed on a payment to an individual and is required to be made pursuant to any law implementing European Council Directive 2003/48/EC (as amended from time to time) on the taxation of savings income or any other Directive implementing the conclusions of the ECOFIN Council meeting of 26- 27 November 2000; or (d) by or on behalf of a Noteholder who would have been able to avoid such withholding or deduction by presenting the relevant Definitive Note to another Paying Agent in a member state of the European Union; or (e) any combination of items (a) through (d) above. In these Conditions, ‘‘Relevant Date’’ means whichever is the later of (a) the date on which the payment in question first becomes due and (b) if the full amount payable has not been received by or for the account of the Principal Paying Agent or the Trustee on or prior to such due date, the date on which (the full amount having been so received) notice to that effect has been given to the Noteholders. Any reference in these Conditions to principal or interest shall be deemed to include any additional amounts in respect of principal or interest (as the case may be) which may be payable under this Condition or any undertaking given in addition to or in substitution for it under the Trust Deed. If the Issuer or any Guarantor becomes subject at any time to any taxing jurisdiction other than (or in addition to) Bermuda or the Russian Federation or Kazakhstan, respectively, references in these Conditions to Bermuda or the Russian Federation or Kazakhstan shall be construed as references to Bermuda or (as the case may be) the Russian Federation or Kazakhstan and/or such other jurisdiction.

9 Events of Default The Trustee at its discretion may, and if so requested in writing by the Holders of not less than one-quarter of the principal amount of the Notes then outstanding or if so directed by an Extraordinary Resolution (as defined in the Trust Deed) shall (subject in each case to its being indemnified and/or secured and/or pre-funded to its satisfaction), give notice to the Issuer that the Notes are immediately due and repayable at their principal amount together with accrued interest if any of the following events occurs and is continuing (each an ‘‘Event of Default’’): (a) the Issuer fails to pay the principal of or any interest on any of the Notes when due (whether at its stated maturity, on optional redemption, on required purchase, on declaration of acceleration or otherwise) and such failure continues in the opinion of the Trustee for a period of five business days in the case of principal or seven business days in the case of interest; or (b) the Issuer or any of the Guarantors, as the case may be, defaults in the performance or observance of any covenant or any of their respective other obligations under the Notes, the Trust Deed or in a Deed of Guarantee, as the case may be, and except where such

138 default is not capable of remedy in the opinion of the Trustee, such default in the opinion of the Trustee remains unremedied for 30 calendar days after written notice thereof, addressed to the Issuer or the relevant Guarantor, as the case may be, has been delivered by or on behalf of the Trustee to the Issuer or such Guarantor, as the case may be; or (c) (i) any Indebtedness of the Issuer or any Subsidiary is not paid when due or payable (as the case may be) within any originally applicable grace period; or (ii) any such Indebtedness becomes due and payable prior to its stated maturity otherwise than at the option of the Issuer, such Subsidiary or (provided that no event of default, howsoever described, has occurred) any Person entitled to such Indebtedness; provided that the amount of Indebtedness referred to in sub-paragraph (i) and/or sub-paragraph (ii) above individually or in the aggregate is equal to or exceeds U.S.$20 million (or the equivalent thereof in any other currency); or (d) the amount of unsatisfied final judgments, decrees or orders of courts or dispute resolution bodies of competent jurisdiction for the payment of money against the Issuer, any Guarantor or any Subsidiary in the aggregate at any given moment of time exceeds U.S.$10 million (or the equivalent thereof in any other currency) and is not discharged or stayed within 30 calendar days; or (e) the Issuer or any Material Subsidiary is unable or admits inability to pay its debts as they fall due, generally suspends making payments on any of its debts or, by reason of actual or anticipated financial difficulties, commences negotiations with one or more of its creditors with a view to rescheduling any of its Indebtedness; and/or a moratorium is declared in respect of any Indebtedness of any of the Issuer or any Material Subsidiary; or

(f) the occurrence of any of the following events, other than in each case a transaction that complies with Condition 4.6: (i) the Issuer or any Material Subsidiary ceases to have corporate existence or is seeking or consenting to (or an order is made or an effective resolution is passed for) the introduction of proceedings for its winding up, liquidation or dissolution or the appointment of a liquidator or liquidation commission (likvidatsionnaya komissiya) or a similar officer of the Issuer or any Material Subsidiary, as the case may be, or a petition in relation to the Issuer or any Material Subsidiary for winding up, liquidation or dissolution (otherwise in each case than, in the case of a Material Subsidiary that is not a Guarantor, for the purposes of or pursuant to an amalgamation, reorganisation or restructuring whilst solvent); (ii) the institution of bankruptcy, insolvency, voluntary or judicial liquidation, composition with creditors, reprieve from payment, controlled management, fraudulent conveyance, general settlement with creditors, reorganisation or similar laws affecting the rights of creditors generally which, in the case of any entity in the Russian Federation and without limitation, shall include the institution of supervision (nablyudeniye), financial rehabilitation (finansovoye ozdorovleniye), external management (vneshneye upravleniye), bankruptcy management (konkursnoye proizvodstvo) over the relevant entity in the Russian Federation; (iii) the entry by the Issuer or any Material Subsidiary into, or the agreeing by the Issuer or any Material Subsidiary to enter into any amicable settlement which, in the case of any entity in the Russian Federation and without limitation, shall include amicable settlement (mirovoye soglasheniye) with its creditors, as such terms are defined in the Federal Law of the Russian Federation No. 127-FZ ‘‘On Insolvency (Bankruptcy)’’ dated 26 October 2002 (as amended or replaced from time to time); (iv) any judicial liquidation in respect of the Issuer or any Material Subsidiary; or (g) any Guarantee is finally held in any judicial proceedings to be unenforceable or invalid or ceases to be in full force and effect (other than in accordance with, the terms of such Guarantee) or any Guarantor denies, disaffirms, repudiates (or purports to repudiate) its obligations under its Guarantee; or (h) any expropriation, attachment, sequestration, execution, Lien or distress is levied against or becomes enforceable and is enforced against, or an encumbrancer takes possession of or sells, the whole or, in the opinion of the Trustee, any material part of, the property, undertaking, revenues or assets of the Issuer or any of its Material Subsidiaries; or

139 (i) all or any substantial part of the undertaking, assets and revenues of the Issuer or any Material Subsidiary is condemned, seized, compulsorily acquired, expropriated, nationalised or otherwise appropriated by any person acting under the authority of any national, regional or local government or the Issuer or any Material Subsidiary is prevented by any such person from exercising normal control over all or any substantial part of its undertaking, assets and revenues; or (j) any governmental authorisation necessary for the performance of the obligations of the Issuer or a Guarantor under the Notes or a Guarantee, as the case may be, ceases to be in full force and effect; or (k) any action, condition or thing (including the obtaining or effecting of any necessary consent, approval, authorisation, exemption, filing, licence, order, recording or registration) at any time required to be taken, fulfilled or done in order (i) to enable the Issuer or a Guarantor lawfully to enter into, exercise their respective rights and perform and comply with its obligations under the Notes, the Guarantees and the Trust Deed, (ii) to ensure that such obligations are legally binding and enforceable and (iii) to make the Notes, the Guarantees and the Trust Deed admissible in evidence in arbitration penal or the courts of the United Kingdom is not taken, fulfilled or done; or (l) it is or will become unlawful for the Issuer or any Guarantor to perform or comply with any one or more of its obligations under any of the Notes, the Deed of Guarantee or the Trust Deed or any of such obligations are not, or cease to be, legal, valid, binding and enforceable or the Issuer or a Guarantor contests the validity thereof or repudiates (or purports to repudiate) them; or (m) any event occurs which under the laws of any relevant jurisdiction has an analogous effect to any of the events referred to in any of the foregoing paragraphs.

10 Prescription Claims for the payment of principal and interest in respect of any Definitive Note shall be prescribed unless made within 10 years (for claims for the payment of principal) or five years (for claims for the payment of interest) of the appropriate Relevant Date.

11 Replacement of Definitive Notes If any Definitive Note is lost, stolen, mutilated, defaced or destroyed, it may be replaced at the specified office of the Registrar, subject to all applicable laws and stock exchange requirements, upon payment by the claimant of the expenses incurred in connection with such replacement and on such terms as to evidence, security, indemnity and otherwise as the Registrar may reasonably require. Mutilated or defaced Definitive Notes must be surrendered before replacements will be issued.

12 Meetings of Noteholders, Modification, Waiver and Substitution 12.1 Meetings of Noteholders The Trust Deed contains provisions for convening meetings of Noteholders to consider matters affecting their interests, including the sanctioning by Extraordinary Resolution of a modification of any of these Conditions or any provisions of the Trust Deed. Such meetings shall be held in accordance with the provisions set out in the Trust Deed. Such a meeting may be convened by Noteholders holding not less than 10 per cent. in principal amount of the Notes for the time being outstanding. The quorum at any meeting convened to vote on an Extraordinary Resolution will be two or more persons holding or representing a clear majority in principal amount of the Notes for the time being outstanding, or at any adjourned meeting two or more persons being or representing Noteholders whatever the principal amount of the Notes held or represented, unless the business of such meeting includes consideration of proposals, inter alia, (i) to modify the maturity of the Notes or the dates on which interest is payable in respect of the Notes, (ii) to reduce or cancel the principal amount of, or interest on, the Notes, (iii) to alter the method of calculating the amount of any payment in respect of the Notes, (iv) to change the currency of payment of the Notes, (v) to modify the provisions in Schedule 3 of the Trust Deed concerning the quorum required at any meeting of Noteholders or the majority required to pass an Extraordinary Resolution, (vi) to modify or cancel the Guarantees, or (vii) to sanction the

140 exchange or substitution for the Notes of, or the conversion of the Notes into, shares, bonds or other obligations or securities of the Issuer, the Guarantors or any other entity, in which case the necessary quorum will be two or more persons holding or representing not less than 75 per cent., or at any adjourned meeting not less than 25 per cent., in principal amount of the Notes for the time being outstanding. Any Extraordinary Resolution duly passed shall be binding on Noteholders (whether or not they were present at the meeting at which such resolution was passed). A written resolution signed by or on behalf of the Holders of not less than 90 per cent. of the aggregate principal amount of Notes outstanding shall be as valid and effective as a duly passed Extraordinary Resolution.

12.2 Modification and Waiver The Trustee may agree with the Issuer and the Guarantors, without the consent of the Noteholders, to (i) any modification of any of the provisions of the Trust Deed, the Deeds of Guarantee or the Notes which is, in the opinion of the Trustee, of a formal, minor or technical nature or is made to correct a manifest error, and (ii) any other modification (except as mentioned in the Trust Deed), and any waiver or authorisation of any breach or proposed breach of any of the provisions of the Notes or the Trust Deed or the Deeds of Guarantee, which is in the opinion of the Trustee not materially prejudicial to the interests of the Noteholders. Any such modification, authorisation or waiver shall be binding on the Noteholders and, if the Trustee so requires, shall be notified to the Noteholders as soon as practicable.

12.3 Substitution The Trust Deed contains provisions permitting the Trustee to agree, subject to such amendment of the Trust Deed and such other conditions as the Trustee may require, but without the consent of the Noteholders, to the substitution of certain other entities in place of the Issuer or Guarantor, or of any previous substituted company, as principal debtor or guarantor under the Trust Deed and the Notes. In the case of such a substitution the Trustee may agree, without the consent of the Noteholders, to a change of the law governing the Notes and/or the Trust Deed provided that such change would not in the opinion of the Trustee be materially prejudicial to the interests of the Noteholders.

12.4 Entitlement of the Trustee In connection with the exercise of its functions (including but not limited to those referred to in this Condition) the Trustee shall have regard to the interests of the Noteholders as a class and shall not have regard to the consequences of such exercise for individual Noteholders and the Trustee shall not be entitled to require, nor shall any Noteholder be entitled to claim, from the Issuer, the Guarantors, the Trustee or any other Person, any indemnification or payment in respect of any tax consequences of any such exercise upon individual Noteholders.

13 Enforcement At any time after the Notes become due and payable, the Trustee may, at its discretion and without further notice, institute such steps, actions or proceedings against the Issuer and/or any Guarantor as it may think fit to enforce the terms of the Trust Deed, the Notes and/or the Deeds of Guarantee, but it need not take any such steps, actions or proceedings and nor shall the Trustee be bound to take, or omit to take any step or action (including instituting such proceedings) unless (a) it shall have been so directed by an Extraordinary Resolution or so requested in writing by Noteholders holding at least one-quarter in principal amount of the Notes outstanding and (b) it shall have been indemnified and/or secured and/or prefunded to its satisfaction. No Noteholder may proceed directly against the Issuer or any Guarantor unless the Trustee, having become bound so to proceed, fails to do so within a reasonable time and such failure is continuing.

14 Indemnification and Removal of the Trustee The Trust Deed contains provisions for the indemnification of the Trustee and for its relief from responsibility. The Trustee is entitled to enter into business transactions with the Issuer, each Guarantor and any entity related to the Issuer or each Guarantor without accounting

141 for any profit. The Trustee may rely without liability to Noteholders on any certificate or report prepared by auditors, accountants or any other expert pursuant to the Trust Deed, whether or not addressed to the Trustee and whether or not the auditors’, accountants’ or expert’s liability in respect thereof is limited by a monetary cap or otherwise. The Trust Deed provides that the Noteholders shall together have the power, exercisable by Extraordinary Resolution, to remove the Trustee (or any successor trustee or additional trustees) provided that the removal of the Trustee or any other trustee shall not become effective unless there remains a Trustee in office after such removal.

15 Further Issues The Issuer may from time to time, without the consent of the Noteholders, create and issue further securities having the same terms and conditions as the Notes in all respects (or in all respects except for the first payment of interest) and so that such further issue shall be consolidated and form a single series with the outstanding Notes. References in these Conditions to the Notes include (unless the context requires otherwise) any other securities issued pursuant to this Condition and forming a single series with the Notes. Any such other securities shall be constituted by a deed supplemental to the Trust Deed and will benefit from guarantees substantially in the form of the Deeds of Guarantee given in respect of these Notes. The Trust Deed contains provisions for convening a single meeting of the Noteholders for the holders of securities of other series where the Trustee so decides.

16 Notices Notices to the Noteholders shall be valid if sent to them by first class mail (airmail if overseas) at their respective addresses on the Register or, so long as the Notes are listed on the Stock Exchange, by any means permitted by the rules and guidelines of such exchange. Any such notice shall be deemed to have been given on the fourth day after the date of mailing. In addition, so long as the Notes are listed on the Stock Exchange and the rules or guidelines of that exchange so require, notices will be published in a leading newspaper having general circulation in Dublin or, if in the opinion of the Trustee such publication shall not be practicable, in any English language newspaper of general circulation in Europe. Any such notice shall be deemed to have been given on the date of such publication or, if published more than once or on different dates, on the first date on which publication is made.

17 Currency Indemnity If any sum due from the Issuer in respect of the Notes or any order or judgment given or made in relation thereto has to be converted from the currency (the ‘‘first currency’’) in which the same is payable under these Conditions or such order or judgment into another currency (the ‘‘second currency’’) for the purpose of (a) making or filing a claim or proof against the Issuer or any Guarantor, (b) obtaining an order or judgment in any court or other tribunal or (c) enforcing any order or judgment given or made in relation to the Notes, the Issuer, failing whom the Guarantors jointly and severally, shall indemnify each recipient, on the written demand of such recipient addressed to the Issuer and the Guarantors and delivered to the Issuer and the Guarantors or to the specified office of the Registrar, against any loss suffered as a result of any discrepancy between (i) the rate of exchange used for such purpose to convert the sum in question from the first currency into the second currency and (ii) the rate or rates of exchange at which such recipient may in the ordinary course of business purchase the first currency with the second currency upon receipt of a sum paid to it in satisfaction, in whole or in part, of any such order, judgment, claim or proof.

This indemnity constitutes a separate and independent obligation of the Issuer or, as the case may be, the Guarantors and shall give rise to a separate and independent cause of action, will apply irrespective of any indulgence granted by any Noteholder or any other person and will continue in full force and effect despite any judgment, order, claim or proof for a liquidated amount in respect of any sum due under the Trust Deed, the Deeds of Guarantee and/or the Notes or any other judgment or order.

142 18 Contracts (Rights of Third Parties) Act 1999 No person shall have any right to enforce any term or condition of the Notes under the Contracts (Rights of Third Parties) Act 1999 except and to the extent, if any, that the Notes expressly provide for such Act to apply to any of their terms.

19 Governing Law, Jurisdiction and Arbitration 19.1 The Trust Deed, the Notes, the Deeds of Guarantee and these Conditions and any non- contractual obligations arising out of or in connection therewith shall be governed by and construed in accordance with English law. 19.2 19.2.1 Any dispute arising out of or in connection with the Notes, the Trust Deed, the Deeds of Guarantee and these Conditions (including a dispute regarding the existence, validity or termination hereof or thereof and a dispute relating to non- contractual obligations arising out of or in connection herewith or therewith) (a ‘‘Dispute’’) shall be referred to and finally resolved by arbitration under the LCIA Arbitration Rules (the ‘‘Rules’’), which Rules are deemed incorporated by reference into these Conditions, as amended herein; 19.2.2 The arbitral tribunal shall consist of three arbitrators. The claimant(s), irrespective of number, shall nominate jointly one arbitrator; the respondent(s), irrespective of number, shall nominate jointly the second arbitrator; and a third arbitrator, who shall serve as chairman, shall be nominated by either of the two party-nominated arbitrators within 15 days of the confirmation of the appointment of the second arbitrator, or, in default of such agreement, shall be appointed by the LCIA court as soon as possible; 19.2.3 In the event the claimant(s), irrespective of number, or a respondent (in circumstances in which it is the sole respondent) fail (or fails) to nominate an arbitrator within the time limits specified in the Rules, such arbitrator shall be appointed by the LCIA Court as soon as possible. In the event that multiple respondents or both claimant(s) and multiple respondents fail to nominate an arbitrator within the time limits specified in the Rules, all three arbitrators shall be appointed by the LCIA Court as soon as possible, and the LCIA Court shall designate one of them as chairman; 19.2.4 If all the parties to an arbitration so agree, there shall be a sole arbitrator appointed by the LCIA Court, as soon as possible; 19.2.5 The seat of arbitration shall be London, England and the language of the arbitration shall be English. The procedural law for any reference to arbitration shall be English law.; 19.2.6 Where related Disputes arise hereunder or under these Conditions and any other Contract, upon the application of any party to an arbitration pursuant to Condition 19.2, the arbitral tribunal may consolidate the arbitration with any other arbitration or proposed arbitration involving any of the parties and relating to these Conditions and/or any other Contract (whether or not such other proceedings have yet been instituted), provided that no date for the final hearing of the arbitration or any other such arbitration has been fixed. The arbitral tribunal shall not consolidate such arbitrations unless it determines in its reasonable opinion that: (a) the relevant Disputes sought to be consolidated are so closely connected that it is expedient for them to be resolved in the same arbitration proceedings; and (b) no party to the proceedings sought to be consolidated would be materially prejudiced as a result of such consolidation through undue delay or otherwise; 19.2.7 Save as otherwise agreed by all of the parties to the consolidated proceedings or as determined by the arbitral tribunal which ordered consolidation, the parties to each Dispute which is a subject of an order for consolidation shall be treated as having consented to that Dispute being finally decided: (i) by the arbitral tribunal which ordered the consolidation (and, where more than one arbitral tribunal orders consolidation of the same Dispute, the arbitral tribunal which was also first formed), unless the LCIA Court

143 determines that that arbitral tribunal would not be suitable or impartial in which case the LCIA Court shall determine the procedure for appointing the arbitral tribunal to determine the consolidated proceedings by reference to the procedure set out above and having given the parties a reasonable opportunity to state their views; and (ii) in accordance with the procedure, at the seat and in the language specified in the arbitration agreement in the Contract under which the arbitral tribunal which ordered the consolidation (and, where more than one arbitral tribunal orders consolidation of the same Dispute, the arbitral tribunal which was also first formed) was appointed; 19.2.8 In the event of inconsistent rulings on consolidation by differently constituted arbitral tribunals, unless that LCIA Court determines that any party would be unduly prejudiced as a result, the ruling of the arbitral tribunal first formed shall be determinative and shall be final and binding on the parties to the arbitrations sought to be consolidated; and 19.2.9 Any provision in the LCIA Rules which is void, unenforceable or otherwise impermissible under English law shall not be deemed to be incorporated into these Conditions. 19.2.10 The Issuer and Guarantors have undertaken, pursuant to the Trust Deed or Deed of Guarantee, as applicable, irrevocably to appoint Law Debenture Corporate Services Limited, Fifth Floor, 100 Wood Street, London EC2V 7EX as agent to accept service of process in England in any legal action or proceedings arising out of or in connection with this Deed (the ‘‘Process Agent’’), provided that: (i) service upon the Process Agent shall be deemed valid service upon the Issuer and the Guarantors whether or not the process is forwarded to or received by the Issuer and the Guarantors; (ii) the Issuer and the Guarantors shall inform the Trustee, in writing, of any change in the address of the Process Agent within 28 days of such change; (iii) if the Process Agent ceases to be able to act as a process agent or to have an address in England, the Issuer and the Guarantors irrevocably agree to appoint a new process agent in England acceptable to the Trustee and to deliver to the Trustee within 14 days a copy of a written acceptance of appointment by the new process agent; and (iv) nothing in this Deed shall affect the right to serve process in any other manner permitted by law. 19.3 To the extent that the Issuer and/or any Guarantor may now or hereafter be entitled, in any jurisdiction in which any legal action or proceeding may at any time be commenced pursuant to or in accordance with these Conditions, to claim for itself or any of its undertaking, properties, assets or revenues present or future any immunity (sovereign or otherwise) from suit, jurisdiction of any court, attachment prior to judgment, attachment in aid of execution of a judgment, execution of a judgment or award or from set-off, banker’s lien, counterclaim or any other legal process or remedy with respect to its obligations under these Conditions and/or to the extent that in any such jurisdiction there may be attributed to the Issuer any such immunity (whether or not claimed), the Issuer and the Guarantors hereby irrevocably agree not to claim, and hereby waive, any such immunity. 19.4 The Issuer and the Guarantors irrevocably and generally consent in respect of any proceedings anywhere to the giving of any relief or the issue and service on it of any process in connection with those proceedings including, without limitation, the making, enforcement or execution against any assets whatsoever (irrespective of their use or intended use) of any order or judgment which may be made or given in those proceedings

20 Definitions In these Conditions the following terms have the meaning given to them in this Condition 20. ‘‘Affiliate’’ of any specified Person means (i) any other Person, directly or indirectly, controlling or controlled by or under direct or indirect common control with such specified Person or (ii) any other Person who is a director or officer (a) of such specified Person, (b) of

144 any Subsidiary of such specified Person or (c) of any Person described in (i) above. For the purposes of this definition, ‘‘control’’ when used with respect to any Person means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms ‘‘controlling’’ and ‘‘controlled’’ have meanings correlative to the foregoing. ‘‘Asset Disposition’’ means any sale, lease, transfer or other disposition (or series of related sales, leases, transfers or dispositions) by the Issuer or any Subsidiary, including any disposition by means of a merger, consolidation or similar transaction (each referred to for the purposes of this definition as a ‘‘disposition’’), of: (a) any Capital Stock of a Subsidiary (other than directors’ qualifying shares or shares required by applicable law to be held by a Person other than the Issuer or a Subsidiary); (b) all or substantially all the assets of any division or line of business of the Issuer or any Subsidiary; or (c) any other assets of the Issuer or any Subsidiary outside of the ordinary course of business of the Issuer or such Subsidiary, other than, in the case of paragraphs (a), (b) and (c) above, A. sales and other disposals of stock in trade on arm’s length basis in the ordinary course of business, including disposals under product delivery contracts. B. a disposition by a Subsidiary to the Issuer or by the Issuer or a Subsidiary to a Subsidiary; C. a disposition of assets in a single transaction or a series of related transactions with a Fair Market Value of less than U.S.$5 million in any 12 month period to any Person that is not a member of the Group; D. a disposition of cash or Temporary Cash Investments; E. the creation of a Lien (but not the sale or other disposition of the property subject to such Lien); F. the licensing or sublicensing of rights to intellectual property or other intangibles in the ordinary course of business; G. any disposition constituting or resulting from the enforcement of a Lien Incurred in compliance with Condition 4.4; H. the sale, lease or other disposition of obsolete, worn out, negligible, surplus or outdated equipment or machinery or inventory in the ordinary course of business; I. the lease, assignment or sublease of any real or personal property in the ordinary course of the business; J. sales or other dispositions of assets or property received by the Issuer or any Subsidiary upon the foreclosure on a Lien granted in favour of the Issuer or any Subsidiary or any other transfer of title with respect to any ordinary course secured investment in default; and K. the surrender or waiver of contract rights or the settlement, release, or surrender of contract, tort or other claims, in the ordinary course of the business. ‘‘Authorised Signatories’’ means, in relation to the Issuer, any Person who is duly authorised (in such manner as may be acceptable to the Trustee) and in respect of whom the Trustee has received a certificate signed by a director or another Authorised Signatory of the Issuer setting out the name and signature of such Person and confirming such Person’s authority to act. ‘‘Average Life’’ means, as of the date of determination, with respect to any Indebtedness, the quotient obtained by dividing (a) the sum of the products of the numbers of years from the date of determination to the dates of each successive scheduled principal payment of, or redemption or similar payment with respect to, such Indebtedness multiplied by the amount of such payment by (b) the sum of all such payments. ‘‘Board of Directors’’ means the Board of Directors of the Issuer or any committee thereof duly authorised to act on behalf of such Board.

145 ‘‘Business Day’’ means, other than for the purposes of Condition 7, a day on which, if on that day a payment is to be made hereunder, commercial banks generally are open for business in Stockholm, Bermuda, Moscow, Astana, New York City and in the city where the specified office (as defined in the Agency Agreement) of the Principal Paying Agent is located. ‘‘Capital Lease Obligation’’ means an obligation that is required to be classified and accounted for as a capital lease for financial reporting purposes in accordance with IFRS, and the amount of Indebtedness represented by such obligation shall be the capitalised amount of such obligation determined in accordance with IFRS; and the Stated Maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be terminated by the lessee without payment of a penalty. For purposes of Condition 4.4, a Capital Lease Obligation will be deemed to be secured by a Lien on the property being leased. ‘‘Capital Stock’’ of any Person means any and all shares, interests (including partnership interests), rights to purchase, warrants, options, participations or other equivalents of or interests in (however designated) equity of such Person, including any Preferred Stock, but excluding any debt securities convertible into such equity. ‘‘Cash and Cash Equivalents’’ means, at any time, and without duplication, any amounts and investments shown as cash and cash equivalents in the most recent consolidated balance sheet of the Issuer and its consolidated Subsidiaries prepared in accordance with IFRS, in each case that is not recorded as ‘‘restricted cash’’ on such balance sheet. ‘‘Consolidated Leverage Ratio’’ as of any date of determination, means the ratio of (x) the aggregate amount of Consolidated Net Indebtedness outstanding on such date to (y) the aggregate amount of EBITDA for the period of the most recent four consecutive quarterly periods ending prior to the date of such determination for which financial statements are available, as determined in good faith by a responsible financial or accounting officer of the Issuer, whose determination will be conclusive (in the absence of manifest error); provided, however, that: (a) if the Issuer or any Subsidiary has Incurred any Indebtedness since the beginning of such period that remains outstanding or if the transaction giving rise to the need to calculate the Consolidated Leverage Ratio is an Incurrence of Indebtedness, or both, the Consolidated Leverage Ratio for such period shall be calculated after giving effect on a pro forma basis to the incurrence of such Indebtedness and the use of proceeds therefrom as if such Indebtedness had been Incurred on the first day of such period; provided that no pro forma effect shall be given to any Cash and Cash Equivalents received by the Issuer or any Subsidiary as proceeds of such Indebtedness that gave rise to the need to calculate the Consolidated Leverage Ratio; (b) if the Issuer or any Subsidiary has repaid, repurchased, defeased or otherwise discharged any Indebtedness since the beginning of such period or if any Indebtedness is to be repaid, repurchased, defeased or otherwise discharged (in each case other than Indebtedness Incurred under any revolving credit facility unless such Indebtedness has been permanently repaid and has not been replaced) on the date of the transaction giving rise to the need to calculate the Consolidated Leverage Ratio, the Consolidated Leverage Ratio shall be calculated on a pro forma basis as if such discharge had occurred on the first day of such period and as if the Issuer or such Subsidiary had not earned the interest income actually earned during such period in respect of cash or Temporary Cash Investments used to repay, repurchase, defease or otherwise discharge such Indebtedness; (c) if since the beginning of such period the Issuer or any Subsidiary shall have made any Asset Disposition, EBITDA for such period shall be reduced by an amount equal to EBITDA (if positive) directly attributable to the assets which are the subject of such Asset Disposition for such period, or increased by an amount equal to EBITDA (if negative), directly attributable thereto for such period; (d) if since the beginning of such period the Issuer or any Subsidiary (by merger or otherwise) shall have made an Investment in any Subsidiary (or any Person which becomes a Subsidiary) or an acquisition of assets, including any acquisition of assets occurring in connection with a transaction requiring a calculation to be made hereunder, which constitutes all or substantially all of an operating unit of a business, EBITDA for

146 such period shall be calculated after giving pro forma effect thereto (including the Incurrence of any Indebtedness) as if such Investment or acquisition had occurred on the first day of such period; and (e) if since the beginning of such period any Person (that subsequently became a Subsidiary or was merged with or into the Issuer or any Subsidiary since the beginning of such period) shall have made any Asset Disposition, any Investment or acquisition of assets that would have required an adjustment pursuant to paragraph (c) or (d) above if made by the Issuer or a Subsidiary during such period, the Consolidated Leverage Ratio shall be calculated after giving pro forma effect thereto as if such Asset Disposition, Investment or acquisition had occurred on the first day of such period. For purposes of this definition, whenever pro forma effect is to be given to an acquisition of assets and the amount of income or earnings relating thereto, the pro forma calculations shall be determined in good faith by a responsible financial or accounting officer of the Issuer, whose determination will be conclusive (in the absence of manifest error). ‘‘Consolidated Net Indebtedness’’ means at any date of determination (and without duplication) an amount equal to (a) all consolidated Indebtedness of the Issuer and its consolidated Subsidiaries shown upon the then most recent consolidated balance sheet of the Issuer and its consolidated Subsidiaries prepared in accordance with IFRS, less (b) the aggregate Cash and Cash Equivalents of the Issuer and its consolidated Subsidiaries shown upon the then most recent consolidated balance sheet of the Issuer and its consolidated Subsidiaries prepared in accordance with IFRS. ‘‘Consolidated Total Assets’’ means at any date of determination the total assets of the Issuer and its consolidated Subsidiaries as shown in the most recently available balance sheet of the Issuer prepared in accordance with IFRS. ‘‘Credit Facilities’’ means one or more debt facilities, indentures or arrangements or commercial paper facilities and overdraft facilities with banks or other institutional lenders, providing for revolving credit loans, notes, term loans, performance guarantees, Receivables Financing (including through the sale of receivables to such institutions or to special purpose entities formed to borrow from such institutions against such receivables), letters of credit or other forms of guarantees and assurances or other credit facilities or extensions of credit, in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced in whole or in part from time to time (whether or not with the original administrative agent and lenders or another administrative agent or agents or other banks or institutions and whether provided under one or more other credit or other agreements, indentures, financing agreements or otherwise) and, in each case, including all agreements, instruments and documents executed and delivered pursuant to or in connection with the foregoing. ‘‘Currency Agreement’’ means any foreign exchange contract, currency swap agreement or other similar agreement with respect to currency values. ‘‘Default’’ means any condition, event or act which, with the lapse of time and/or the issue, making or giving of any notice, certification, declaration, demand, determination and/or request and/or the taking of any similar action and/or the fulfilment of any similar condition, could constitute an Event of Default. ‘‘Disqualified Stock’’ means, with respect to any Person, any Capital Stock which by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable at the option of the holder) or upon the happening of any event: (a) matures or is mandatorily redeemable (other than redeemable only for Capital Stock of such Person which is not itself Disqualified Stock) pursuant to a sinking fund obligation or otherwise; (b) is convertible or exchangeable at the option of the holder for Indebtedness or Disqualified Stock; or (c) is mandatorily redeemable or must be purchased upon the occurrence of certain events or otherwise, in whole or in part, in each case on or prior to the first anniversary of the Stated Maturity of the Notes.

147 The amount of any Disqualified Stock that does not have a fixed redemption, repayment or repurchase price will be calculated in accordance with the terms of such Disqualified Stock as if such Disqualified Stock were redeemed, repaid or repurchased on any date on which the amount of such Disqualified Stock is to be determined pursuant to these Conditions; provided, however, that if such Disqualified Stock could not be required to be redeemed, repaid or repurchased at the time of such determination, the redemption, repayment or repurchase price will be the book value of such Disqualified Stock as reflected in the most recent financial statements of such Person. ‘‘EBITDA’’ means, for any period, profit for the period of the Issuer and its consolidated Subsidiaries prepared in accordance with IFRS, adjusted by adding back (to the extent deducted in calculating such profit) or deducting (to the extent added when calculating such profit) income tax expense, interest income and finance costs, gain/loss on derivatives classified as held for trading, currency exchange gain/loss, depletion, depreciation and amortisation, impairment of oil and gas assets, reversal of impairment, gain/loss on disposal of shares in subsidiaries and other significant one-off items in the consolidated statement of profit or loss for the period of the Issuer and its consolidated Subsidiaries prepared in accordance with IFRS. ‘‘Exchange Act’’ means the U.S. Securities Exchange Act of 1934, as amended. ‘‘Extraordinary Resolution’’ means a resolution passed at a meeting duly convened and held in accordance with the Trust Deed by a majority of at least 75 per cent. of the votes cast. ‘‘Fair Market Value’’ means, with respect to any asset or property, the price which could be negotiated in an arm’s length, free market transaction between a willing seller and a willing and able buyer, neither of whom is under undue pressure or compulsion to complete the transaction. Fair Market Value will, in relation to any transaction or series of related transactions with an aggregate value in excess of U.S.$5 million be determined in good faith by the competent management body of the Issuer or the relevant competent management body of the Subsidiary of the Issuer (including a majority of the disinterested directors, if applicable) whose determination shall be conclusive if evidenced by a resolution of such relevant competent management body. ‘‘Group’’ means the Issuer and its consolidated Subsidiaries taken as a whole. ‘‘guarantee’’ means any financial obligation, contingent or otherwise, of any Person directly or indirectly guaranteeing any Indebtedness or other obligation of any other Person and any obligation, direct or indirect, contingent or otherwise, of such Person (a) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness or other obligation of such other Person (whether arising by virtue of partnership arrangements, or by agreement to keep-well, to purchase assets, goods, securities or services, to take-or-pay or to maintain financial statement conditions or otherwise) or (b) entered into for purposes of assuring in any other manner the obligee of such Indebtedness or other obligation of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part); provided, however, that the term ‘‘guarantee’’ will not include endorsements for collection or deposit in the ordinary course of business. The term ‘‘guarantee’’ used as a verb has a corresponding meaning. ‘‘Hedging Obligations’’ of any Person means the obligations of such Person pursuant to: (a) any interest rate swap agreements (whether from fixed to floating or from floating to fixed), interest rate cap agreements and interest rate collar agreements; (b) other agreements or arrangements designed to manage interest rates or interest rate risk; and (c) other agreements or arrangements designed to protect such Person against fluctuations in currency exchange rates or commodity or other prices or margins. ‘‘IFRS’’ means International Financial Reporting Standards (IFRS and IFRIC interpretation) as issued by the International Accounting Standards Board, consistently applied and which are in effect from time to time. ‘‘Incur’’ means issue, assume, guarantee, incur or otherwise become liable for; provided, however, that any Indebtedness of a Person existing at the time such Person becomes a Subsidiary (whether by merger, consolidation, acquisition or otherwise) shall be deemed to be

148 Incurred by such Person at the time it becomes a Subsidiary. The term ‘‘Incurrence’’ when used as a noun shall have a correlative meaning. Solely for purposes of determining compliance with Condition 4.1: (a) amortisation of debt discount or the accretion of principal with respect to a non interest bearing or other discount security; (b) the payment of regularly scheduled interest in the form of additional Indebtedness of the same instrument or the payment of regularly scheduled dividends on Capital Stock in the form of additional Capital Stock of the same class and with the same terms; and (c) the obligation to pay a premium in respect of Indebtedness arising in connection with the issuance of a notice of redemption or the making of a mandatory offer to purchase such Indebtedness, will not be deemed to be the Incurrence of Indebtedness. ‘‘Indebtedness’’ means, with respect to any Person on any date of determination (without duplication): (a) the principal in respect of (A) indebtedness of such Person for monies borrowed and (B) indebtedness evidenced by notes, debentures, bonds or other similar instruments for the payment of which such Person is responsible or liable, including, in each case, any premium on such indebtedness to the extent such premium has become due and payable; (b) all Capital Lease Obligations of such Person; (c) all obligations of such Person issued or assumed as the deferred purchase price of property which excludes, for the avoidance of doubt, (i) post-closing payment adjustments or earn-out or similar obligation to which the buyer may become obliged to pay to the extent such payment is determined by a financial closing balance sheet or such payment depends on the performance of such business after the closing, provided however, that the at the time of closing, the amounts of any such payment is not determinable and, to the extent such payment thereafter becomes fixed and determined, the amount is paid within 30 days thereafter, (ii) all conditional sale obligations of such Person and (iii) all obligations of such Person under any title retention agreement (but excluding any accounts payable or other liability to trade creditors (as defined in accordance with IFRS) arising in the ordinary course of business); (d) all obligations of such Person for the reimbursement of any obligor on any letter of credit, performance bonds or surety bonds, bankers’ acceptance or similar credit transaction (other than obligations with respect to letters of credit securing obligations (other than obligations described in paragraphs (a), (b) and (c)) entered into in the ordinary course of business of such Person to the extent such letters of credit are not drawn upon or, if and to the extent drawn upon, such drawing is reimbursed no later than the thirtieth Business Day following receipt of a demand for reimbursement); (e) the amount of all obligations of such Person with respect to the redemption, repayment or other repurchase of any Disqualified Stock of such Person or, with respect to any Preferred Stock of any Subsidiary of such Person, the principal amount of such Preferred Stock to be determined in accordance with these Conditions (but excluding, in each case, any accrued dividends); (f) all obligations of the type referred to in paragraphs (a) to (e) of other Persons and all dividends of other Persons for the payment of which, in either case, such Person is responsible or liable, directly or indirectly, as obligor, guarantor or otherwise, including by means of any guarantee; (g) all obligations of the type referred to in paragraphs (a) to (f) of other Persons secured by any Lien on any property or asset of such Person (whether or not such obligation is assumed by such Person), the amount of such obligation being deemed to be the lesser of the Fair Market Value of such property or assets and the amount of the obligation so secured; (h) to the extent not otherwise included in this definition, the net Hedging Obligations of such Person (and, when calculating the value thereof, only the net marked-to-market value shall be taken into account);

149 (i) if and to the extent any of the preceding items (a) through (e) would appear as a liability upon a balance sheet of the Issuer and its consolidated Subsidiaries prepared in accordance with IFRS. The amount of Indebtedness of any Person at any date shall be the outstanding balance at such date of all unconditional obligations as described above; provided, however, that in the case of Indebtedness sold at a discount, the amount of such Indebtedness at any time will be the accreted value thereof at such time. Notwithstanding the foregoing, ‘‘Indebtedness’’ shall not include (a) advance payments (as defined in accordance with IFRS) by customers in the ordinary course of business for services or products to be provided or delivered in the future, (b) any lease of property which would be considered an operating lease under IFRS, (c) any contingent obligations in respect of workers’ compensation claims, early retirement or termination obligations, pension fund obligations or contributions or similar claims, obligations or contributions or social security or wage Taxes, or (d) deferred Taxes. ‘‘Independent Qualified Party’’ means an independent investment banking firm, accounting firm or appraisal firm of recognised international standing; provided, however, that such firm is not an Affiliate of the Issuer. ‘‘Issue Date’’ means 3 May 2013. ‘‘Khabarovsk Loan’’ means extensions of credit by Vnesheconombank or another financial institution or institutions to a Subsidiary, in an aggregate principal amount not exceeding U.S$1 billion (or its equivalent in other currencies in which such extensions of credit are denominated, calculated on the basis of the currency exchange rate of such currencies into U.S. dollars as of the Issue Date) and having a maturity or maturities of not less than six months after the Maturity Date, provided in connection with capital improvements projects of the Khabarovsk Refinery. ‘‘Lien’’ means any mortgage, pledge, encumbrance, easement, restriction, covenant, right-of- way, servitude, lien, charge or other security interest or adverse claim of any kind (including, without limitation, anything analogous to any of the foregoing under the laws of any jurisdiction and any conditional sale or other title retention agreement or lease in the nature thereof). ‘‘Material Adverse Effect’’ means any material adverse effect on the business, results of operations, property, assets, prospects or condition (financial or otherwise) of the Issuer or any Subsidiary (including as the case may be each Guarantor) or the Issuer’s or a Guarantor’s ability to perform its obligations under the Notes or the relevant Guarantee or the validity, legality or enforceability of the Notes or the relevant Guarantee, provided that, to the extent that the Trustee is instructed to take any action pursuant to (i) the instructions of Noteholders holding at least one-quarter in principal amount of the Notes then outstanding or (ii) an Extraordinary Resolution of Noteholders, and any such action requires the determination of whether an event or occurrence has had a Material Adverse Effect, the Trustee shall have no duty to enquire or satisfy itself as to the existence of an event or occurrence having a Material Adverse Effect and shall be entitled to rely conclusively upon such instructions by, or Extraordinary Resolution of, the Noteholders regarding the same, and shall bear no liability of any nature whatsoever to the Issuer or the Guarantor for acting upon such written instructions or Extraordinary Resolution of the Noteholders. ‘‘Material Subsidiary’’ means each Guarantor and at any relevant time a Subsidiary of the Issuer: (a) whose total assets or gross revenues (or, where the Subsidiary in question prepares consolidated accounts, whose total consolidated assets or gross consolidated revenues, as the case may be) represent not less than 5 per cent. of the total consolidated assets or the gross consolidated revenues of the Issuer and its Subsidiaries, all as calculated by reference to the most recent available audited accounts or consolidated accounts, as the case may be (in each case, produced on the basis of IFRS, consistently applied) of such Subsidiary and the then most recent available audited consolidated accounts of the Issuer and its consolidated Subsidiaries, produced on the basis of IFRS, consistently applied; or

150 (b) to which is transferred all or substantially all of the assets of a Subsidiary which immediately prior to such transfer was a Material Subsidiary. ‘‘Net Available Cash’’ from an Asset Disposition means cash payments received therefrom (including any cash payments received by way of deferred payment of principal pursuant to a note or instalment receivable or otherwise and proceeds from the sale or other disposition of any securities received as consideration, but only as and when received, but excluding any other consideration received in the form of assumption by the acquiring Person of Indebtedness or other obligations relating to such properties or assets or received in any other non-cash form), in each case net of: (a) all legal, title and recording tax expenses, commissions and other fees and expenses incurred, and all federal, state, provincial, foreign and local taxes paid or required to be accrued as a liability under IFRS, as a consequence of such Asset Disposition; (b) all payments made on any Indebtedness which is secured by any assets subject to such Asset Disposition, in accordance with the terms of any Lien upon or other security agreement of any kind with respect to such assets, or which must by its terms, or in order to obtain a necessary consent to such Asset Disposition, or by applicable law, be repaid out of the proceeds from such Asset Disposition; (c) all distributions and other payments required to be made to minority interest holders in Subsidiaries as a result of such Asset Disposition; (d) the deduction of appropriate amounts provided by the seller as a reserve, in accordance with IFRS, against any liabilities associated with the property or other assets disposed in such Asset Disposition and retained by the Issuer or any Subsidiary after such Asset Disposition; and (e) any portion of the purchase price from an Asset Disposition placed in escrow, whether as a reserve for adjustment of the purchase price, for satisfaction of indemnities in respect of such Asset Disposition or otherwise in connection with that Asset Disposition; provided, however, that upon the termination of that escrow, Net Available Cash will be increased by any portion of funds in the escrow that are released to the Issuer or any Subsidiary. ‘‘Officers’ Certificate’’ means, in the case of the Issuer, a certificate signed on behalf of the Issuer by two Authorised Signatories of the Issuer at least one of whom shall be the principal executive officer, principal accounting officer or principal financial officer of the Issuer or, in the case of any Guarantor, a certificate signed by two officers of the Guarantor, both of whom shall be a member of such Guarantor’s management board. ‘‘Permitted Liens’’ means: (a) any Liens existing on the Issue Date; (b) any Lien granted by any Subsidiary of the Issuer in favour of the Issuer or a Guarantor; (c) Liens granted by a Subsidiary to secure the Khabarovsk Loan; (d) Liens Incurred, or pledges and deposits in connection with workers’ compensation, unemployment insurance and other social security benefits, and leases, appeal bonds and other obligations of like nature in the ordinary course of business; (e) Liens for ad valorem, income or property Taxes or assessments and similar charges which either are not delinquent or are being contested in good faith by appropriate proceedings for which the Issuer has set aside in its books of account reserves to the extent required by IFRS, as consistently applied; (f) with respect to any Person, minor survey exceptions, minor encumbrances, easement or reservations of, or rights of others, licences, rights of way, sewers, electrical lines, telegraph or telephone lines and other similar purposes, or zone or other restrictions as to the use of real property or Liens incidental to the conduct of the business of such Person or to the ownership of its properties which do not act in the aggregate materially adversely effect the value of the property or materially impair their use in the operation of the business of such person;

151 (g) any bankers’ Liens in respect of deposit accounts, statutory landlords’ Liens and deposits to secure bids, contracts, leases, and other similar obligations (provided such Liens do not secure obligations constituting Indebtedness and are incurred in the ordinary course of business), any netting or set-off arrangement entered into by any member of the Group in the normal course of its banking arrangements for the purpose of netting debit and credit balances and judgment Liens not giving rise to a Default or an Event of Default so long as such Lien is adequately bonded and any appropriate legal proceedings that may have been duly initiated for the review of such judgment have not been finally terminated or the period within which such proceedings may be initiated has not expired; (h) any title transfer or retention of title arrangement entered into by any member of the Group in the ordinary course of its trading activities on the counterparty’s standard or usual terms or otherwise any Lien arising by operation of law and in the ordinary course of business; (i) any extension, renewal of or substitution for any Lien permitted by any of the preceding paragraphs (a) through (h), provided, however, that such extension, renewal or replacement shall be no more restrictive in any material respect than the original Lien; with respect to Liens incurred pursuant to this paragraph (i) the principal amount secured has not increased (other than any increase representing costs, fees, expenses or commission associated with such extension, renewal or substitution) and the Liens have not been extended to any additional property or assets (other than proceeds of the property or assets in question); (j) Liens on property or Capital Stock of another Person at the time such other Person becomes a Subsidiary; provided, however, that such Liens are not created, Incurred or assumed in connection with, or in contemplation of, such Person becoming a Subsidiary and provided further that the Liens may not extend to any other property owned by the Issuer or a Subsidiary (other than assets and property affixed or appurtenant thereto); (k) Liens on property at the time such Person or any of its Subsidiaries acquires the property, including any acquisition by means of a merger or consolidation with or into the Issuer or a Subsidiary; provided, however, that such Liens are not created, Incurred or assumed in connection with, or in contemplation of, such acquisition and provided further, that the Liens may not extend to any other property owned by such Person or any of its Subsidiaries (other than assets and property affixed or appurtenant thereto); (l) Liens securing Indebtedness represented by credit facilities ; provided that the aggregate principal amount at any time outstanding of Indebtedness that is secured by such Liens hereof shall not exceed US$500 million; (m) Liens to secure any Permitted Refinancing Indebtedness which Refinances Indebtedness that is secured by a Permitted Lien; provided, however that such new Lien shall be limited to all or part of the same property and assets that secured or, under the written agreements pursuant to which the original Lien arose, could secure, the original Lien (plus improvements and accessions to such property, or proceeds or distributions thereof); and (n) any Liens (other than those contemplated in paragraphs (a) to (m) above) where the aggregate value of the assets or revenues subject to such Liens at any one time outstanding do not exceed 10 per cent. of Consolidated Total Assets. ‘‘Permitted Refinancing Indebtedness’’ means Indebtedness or the portion thereof that is incurred solely in order to, and serves to, Refinance within two years after the Incurrence of such Indebtedness (and prior to any such Refinancing the proceeds of such Permitted Refinancing Indebtedness are only held in the form of Cash and Cash Equivalents or Temporary Cash Investments) of the Issuer, any Subsidiary or the Khabarovsk Refinery existing on the Issue Date or incurred in compliance with the terms and conditions of the Notes, including Indebtedness that serves to Refinance Permitted Refinancing Indebtedness; provided, however, that: (a) such Permitted Refinancing Indebtedness has a Stated Maturity no earlier than the Stated Maturity of the Indebtedness being Refinanced;

152 (b) such Permitted Refinancing Indebtedness has an Average Life at the time such Refinancing Indebtedness is incurred that is equal to or greater than the Average Life of the Indebtedness being Refinanced; (c) such Permitted Refinancing Indebtedness has an aggregate principal amount (or if incurred with original issue discount, an aggregate issue price) that is equal to or less than the aggregate principal amount (or if incurred with original issue discount, the aggregate accreted value) then outstanding (plus fees and expenses, including any premium or defeasance costs) under the Indebtedness being Refinanced; and (d) if the Indebtedness being Refinanced is subordinated in right of payment to the Notes, such Permitted Refinancing Indebtedness is subordinated in right of payment to the Notes at least to the same extent as the Indebtedness being Refinanced. ‘‘Person’’ means any individual, company, corporation, firm, partnership, joint venture, association, organisation, state or agency of a state or other entity, whether or not having separate legal personality. ‘‘Preferred Stock’’, as applied to the Capital Stock of any Person, means Capital Stock of any class or classes (however designated) which is preferred as to the payment of dividends or distributions, or as to the distribution of assets upon any voluntary or involuntary liquidation or dissolution of such Person, over Capital Stock of any other class of such Person. ‘‘Receivables Financing’’ means any financing of any accounts receivable, inventory, royalty or revenue streams from sales of inventory (including, in each case, related assets and proceeds) of the Issuer or any Subsidiary. ‘‘Refinance’’ means, in respect of any Indebtedness, to refinance, extend, renew, refund, repay, prepay, purchase, redeem, defease or retire, or to issue other Indebtedness in exchange or replacement for, such Indebtedness. ‘‘Refinances’’, ‘‘Refinanced’’ and ‘‘Refinancing’’ shall have correlative meanings. ‘‘Relevant Jurisdiction’’ means (in the case of payment by the Issuer) Bermuda or any political subdivision or any authority thereof or therein having power to tax or (in the case of payments by the Guarantors) Bermuda, Kazakhstan and the Russian Federation or any political subdivision or any authority thereof or therein having power to tax or in any case any other jurisdiction or any political subdivision or any authority thereof or therein having power to tax to which the Issuer or any Guarantor becomes subject in respect of payments made by it of principal or interest on the Notes. ‘‘Securities Act’’ means the U.S. Securities Act of 1933, as amended. ‘‘Senior Indebtedness’’ means, with respect to any Person: (a) Indebtedness of such Person, whether outstanding on the Issue Date or thereafter Incurred; and (b) all other obligations of such Person (including interest accruing on or after the filing of any petition in bankruptcy or for reorganisation relating to such Person whether or not post filing interest is allowed in such proceeding) in respect of Indebtedness described in clause (a) above, unless, in the case of paragraphs (a) and (b), in the instrument creating or evidencing the same or pursuant to which the same is outstanding, it is provided that such Indebtedness or other obligations are subordinate in right of payment to the Notes or the Guarantees of such Person, as the case may be; provided, however, that Senior Indebtedness shall not include: (i) any obligation of such Person to the Issuer or any Subsidiary of the Issuer; (ii) any liability for federal, state, local or other taxes owed or owing by such Person; (iii) accounts payable or other liability to trade creditors arising in the ordinary course of business; (iv) any Indebtedness or other obligation of such Person which is subordinate or junior in any respect to any other Indebtedness or other obligation of such Person; or (v) that portion of any Indebtedness which at the time of Incurrence is Incurred in violation of these Conditions.

153 ‘‘Stated Maturity’’ means, with respect to any security, the date specified in such security as the fixed date on which the final payment of principal of such security is due and payable, including pursuant to any mandatory redemption provision (but excluding any provision providing for the repurchase of such security at the option of the holder thereof upon the happening of any contingency unless such contingency has occurred). ‘‘Stock Exchange’’ means the Irish Stock Exchange Limited. ‘‘Subordinated Obligation’’ means, with respect to a Person, any Indebtedness of such Person (whether outstanding on the Issue Date or thereafter Incurred) which is subordinate or junior in right of payment to the Notes or a Guarantee of such Person, as the case may be, pursuant to a written agreement to that effect. ‘‘Subsidiary’’ of any specified person means any corporation, partnership, joint venture, association or other business or entity, whether now existing or hereafter organised or acquired: (a) in the case of a corporation, of which more than 50 per cent. of the total voting power of the Voting Stock is held by such first-named person and/or any of its Subsidiaries and such first-named person or any of its Subsidiaries has the power to direct the management, policies and affairs thereof; or (b) in the case of a partnership, joint venture, association, or other business or entity, with respect to which such first-named person or any of its Subsidiaries has the power to direct or cause the direction of the management and policies of such entity by contract or otherwise, if (in each case in (a) and (b)) in accordance with IFRS, as consistently applied, such entity would be consolidated with the first-named person for financial statement purposes. ‘‘Taxes’’ means any taxes (including interest or penalties thereon) which are now or at any time hereafter imposed, assessed, charged, levied, collected, demanded, withheld or claimed by a Relevant Jurisdiction or any tax authority thereof or therein and the term ‘‘Taxation’’ shall be construed accordingly. ‘‘Temporary Cash Investments’’ means any of the following: (a) any investment in direct obligations of a member of the European Union, the Russian Federation, the United States or any agency thereof or obligations guaranteed by a member of the European Union, the Russian Federation, or the United States or any agency thereof; (b) investments in demand and time deposit accounts, certificates of deposit and money market deposits with a maturity of one year or less from the date of acquisition thereof issued by a bank or trust company which is organised under (i) the laws of a member state of the European Union or the United States or any state thereof, and which bank or trust company has capital, surplus and undivided profits aggregating in excess of U.S.$500 million (or the foreign currency equivalent thereof) and has outstanding debt which is rated ‘‘BBB-’’ or ‘‘Baa3’’ (or such similar equivalent rating) or higher by at least one nationally recognised statistical rating organisation or (ii) the laws of the Russian Federation, provided that in the case of (ii) such bank or trust company is either (a) a controlled Affiliate of a bank or trust company meeting the conditions of sub-clause (i) or (b) a bank or trust company (including successors thereto) which, at any time during 2012 through the Issue Date, has issued to the Issuer or any Subsidiary overnight bank deposits, time deposit accounts, certificates of deposit, banker’s acceptances and money market deposits with maturities (and similar instruments) of one year or less from the date of acquisition; (c) repurchase obligations with a term of not more than 30 days for underlying securities of the types described in paragraph (a) entered into with a bank meeting the qualifications described in paragraph (b); (d) investments in commercial paper with a maturity of one year or less from the date of acquisition, issued by a corporation (other than an Affiliate of the Issuer) organised and in existence under the laws of a member of the European Union, the United States or

154 the Russian Federation with a rating at the time as of which any investment therein is made of ‘‘P 1’’ (or higher) according to Moody’s Investors Service, Inc. or ‘‘A1’’ (or higher) according to Standard & Poor’s Ratings Group; (e) investments in securities with maturities of six months or less from the date of acquisition issued or fully guaranteed by any state, commonwealth or territory of a member of the European Union, the United States, or the Russian Federation or by any political subdivision or taxing authority thereof, and rated at least ‘‘BBB-’’ by Standard & Poor’s Ratings Group or ‘‘Baa3’’ by Moody’s Investors Service, Inc.; and (f) investments in money market funds that invest substantially all their assets in securities of the types described in paragraphs (a) to (e). ‘‘U.S. Dollar Equivalent’’ means with respect to any monetary amount in a currency other than U.S. dollars, at any time for determination thereof, the amount of U.S. dollars obtained by converting such foreign currency involved in such computation into U.S. dollars at the spot rate for the purchase of U.S. dollars with the applicable foreign currency as published in The Wall Street Journal in the ‘‘Exchange Rates’’ column under the heading ‘‘Currency Trading’’ on the date two Business Days prior to such determination. ‘‘Voting Stock’’ of a Person means all classes of Capital Stock of such Person then outstanding and normally entitled (without regard to the occurrence of any contingency) to vote in the election of the Board of Directors, managers or trustees (or Persons performing similar functions) thereof.

155 THE ISSUER AND GUARANTORS

The principal activities of each operating entity in the Group, including each Guarantor, are oil exploration, production, refining, oil and petroleum products transportation, natural gas and gas condensate production. See ‘‘Business’’ and below for the principal activity of each guarantor entity within the Group. The business address of each director of the Issuer and each Guarantor in such capacity is the registered office of the relevant entity as set out below. Under Russian corporate legislation, participants of limited liability companies and shareholders of joint stock companies with less than 50 shareholders are not required to establish a board of directors. With the exception of the Partly Owned Guarantors, the Group holds 100% stakes in the Guarantors. Among the Partly Owned Guarantors, the remaining interest in Amurnefteproduct is held by 181 individuals and one legal entity; the remaining interest in Khabarovsknefteproduct is held by 1,328 individuals and 10 legal entities; the remaining interest in Pechoraneft is held by 29 individuals and one legal entity; the remaining interest in Primornefteproduct is held by 262 individuals and six legal entities; and the remaining interest in Potential Oil is held by First International Oil Corporation Limited. As at the date of this Prospectus, neither the Issuer nor any of the Guarantors is aware of any potential conflict of interests between the duties their directors owe and their private interests or the duties owed by any of them to any other person.

Issuer Legal and commercial name Alliance Oil Company Ltd. Registration number 25413 Date and place of incorporation 1 September 1998, Bermuda Duration of existence Unlimited Place of domicile Bermuda Legal form Exempted company limited by shares Registered office Clarendon House, 2 Church Street, Hamilton HM11, Bermuda Issued Share Capital USD 171,528,414 common shares; USD 5,000,000 preference shares Principal place of business Russia and Kazakhstan

Directors Name Relevant other activities Mr. Eric Forss Chairman of the board of directors of D.O.Y. AB and Mediagruppen Stockholm MGS AB Member of the board of directors of Forcenergy AB, Forsinvest Aktiebolag. S.O.G. Energy Deputy board member of Betalt och Klart i Stockholm AB and Forsinvest Fastighetskapital AB Mr. Arsen E. Idrisov None Mr. Raymond Liefhooge Director at Diamond Capital Fund, Diamond Growth Fund, Sucafina S.A., Sucafina Ingredients SA and Metinvest International Mr. Claes Levin Chairman of the board of directors of Bro¨ derna Falk AB, Sh-Bygg AB, Strict AB, Want AB and Variant Fastighets AB och Wiking Mineral AB Member of the board of directors of First Baltic Property Ltd, Norrlands Industrier AB and Amok Studios AB Mr. Fred Boling President and director of Commonwealth Oil Refining, Wyatt Energy, Springs Land Company and Investors Life Insurance Company

156 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA Mr. Fernando Martinez-Fresneda Managing director of Repsol YPF’s office and operations in the Russian Federation Mr. Isa Bazhaev Vice president for finance of Alliance- Prom Board member at Alliance-Prom General director of Alliance Capital Investment Company Management Name Relevant other activities Mr. Arsen E. Idrisov Mr. Fred Boling Mr. Eric Forss Mr. Christopher Garrod Mr. Malcolm S Mitchell Ms. Susie Grant Principal activities Production and sales of crude oil and petroleum products; holding company of the Group.

Guarantors Fully Owned Guarantors NK Alliance Legal and commercial name Open Joint Stock Company Oil Company Alliance Registration number 1027700513334 Date and place of incorporation 26 November 2001, Russian Federation Duration of existence Indefinite Place of domicile Russian Federation Legal form Open Joint Stock Company Charter Capital RUB 888,000,000 Group ownership as of the date of this 100% of charter capital (100% voting Prospectus rights) Registered office 39 Sivtsev Vrazhek Lane, Moscow, Russian Federation, 119002 Principal place of business Russian Federation Directors Not applicable Management LLC Alliance Oil MC Statutory auditors CJSC Audit Consult Financial year Corresponds to the calendar year Principal activities Production, sales and transportation of petroleum products Alliance-Bunker Legal and commercial name Limited Liability Company ‘‘Alliance- Bunker’’ Registration number 1022502256700 Date and place of incorporation 13 August 2002, Russian Federation Duration of existence Indefinite Place of domicile Russian Federation Legal form Limited Liability Company Charter Capital RUB 50,000 Group ownership as of the date of this 100% of charter capital (100% voting Prospectus rights) Registered office Office 301, 55, Fontannaya str., Vladivostok, Russian Federation, 690091 Principal place of business Russian Federation Directors Not applicable Management Name Relevant other activities Mr. Anatoly B. Makarov None Statutory auditors CJSC Audit Consult Financial year Corresponds to the calendar year Principal activities Wholesale of fuel, including aviation gasoline

157 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA Alliancetransoil Legal and commercial name Closed Joint-Stock Company Alliancetransoil Registration number 1027700544376 Date and place of incorporation 6 December 2001, Russian Federation Duration of existence Indefinite Place of domicile Russian Federation Legal form Closed Joint Stock Company Charter Capital RUB 500,300,000 Group ownership as of the date of this 100% of charter capital (100% voting Prospectus rights) Registered office 10, bld.1, Kaloshin Lane, Moscow, Russian Federation, 119002 Principal place of business Russian Federation Directors Not applicable Management Name Relevant other activities Mr. Boris B. Titov None Statutory auditors CJSC Audit Consult Financial year Corresponds to the calendar year Principal activities Transportation of petroleum products

Khvoinoye Legal and commercial name Closed Joint Stock Company Khvoinoye Registration number 1117017016401 Date and place of incorporation 3 October 2011, Russian Federation Duration of existence Indefinite Place of domicile Russian Federation Legal form Limited Liability Company Charter Capital RUB 10,000 Group ownership as of the date of this 100% of charter capital (100% voting Prospectus rights) Registered office 70/1 Komsomolsky avenue, Tomsk, Russian Federation, 634041 Principal place of business Nenetsk Autonomous District, Russian Federation Directors Not applicable Management LLC Alliance Oil MC Statutory auditors CJSC Audit Consult Financial year Corresponds to the calendar year Principal activities Crude oil production

Kolvinskoe Legal and commercial name Kolvinskoe Limited Liability Company Registration number 1088383000298 Date and place of incorporation 29 April 2008, Russian Federation Duration of existence Indefinite Place of domicile Russian Federation Legal form Limited Liability Company Charter Capital RUB 10,000 Group ownership as of the date of this 100% of charter capital (100% voting Prospectus rights) Registered office Office 17, 23A, Lenina str., Naryan-Mar, Nenetsk Autonomous District, Russian Federation, 166000 Principal place of business Nenetsk Autonomous District, Russian Federation Directors Not applicable Management LLC Alliance Oil MC Statutory auditors CJSC Audit Consult Financial year Corresponds to the calendar year Principal activities Crude oil and natural gas production

158 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA VTK Legal and commercial name Open Joint Stock Company ‘‘Eastern Transnational Company’’ Registration number 1027000854638 Date and place of incorporation 16 July 1993, Russian Federation Duration of existence Indefinite Place of domicile Russian Federation Legal form Open Joint Stock Company Charter Capital RUB 17,929,511 Group ownership as of the date of this 100% of charter capital (100% voting Prospectus rights) Registered office 70/1, Komsomolsky avenue, Tomsk, Russian Federation, 634041 Principal place of business Tomsk region, Russian Federation Directors Not applicable Management LLC Alliance Oil MC Statutory auditors CJSC Audit Consult Financial year Corresponds to the calendar year Principal activities Crude oil production Alliance Oil Legal and commercial name Closed Joint-Stock Company Alliance Oil Registration number 1035006460224 Date and place of incorporation 24 July 1998, Russian Federation Duration of existence Indefinite Place of domicile Russian Federation Legal form Closed Joint Stock Company Charter Capital RUB 42,500,010 Group ownership as of the date of this 100% (100% voting rights) Prospectus Registered office Building 2, 101, Prospect Mira, Moscow, Russian Federation, 129085 Principal place of business Russian Federation Directors Not applicable Management LLC Alliance Oil MC Statutory auditors CJSC Audit Consult Financial year Corresponds to the calendar year Principal activities Fuel wholesale

SN-Gasproduction Legal and commercial name Limited Liability Company SN- Gasproduction Registration number 1087017028372 Date and place of incorporation 27 October 2008, Russian Federation Duration of existence Indefinite Place of domicile Russian Federation Legal form Limited Liability Company Charter Capital RUB 1,415,035,600 Group ownership as of the date of this 100% (100% voting rights) Prospectus Registered office 70/1, Komsomolsky prospect, Tomsk, Russian Federation, 634041 Principal place of business Tomsk region, Russian Federation Directors Name Relevant other activities Ms. Anastasia Vorotyntseva None Mr. Dmitriy Degtyarev Mr. Alexey Dubinkin Mr. Victor Melesko Mr. Vyacheslav Okhotin Management Name Relevant other activities Mr. Mikhail Telizhin None Statutory auditors LLC Tomaudit Financial year Corresponds to the calendar year Principal activities Natural gas and gas condensate production

159 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA Partly Owned Guarantors Khabarovsknefteproduct Legal and commercial name OPEN Joint Stock Company ‘‘Khabarovsknefteproduct’’ Registration number 1022700910704 Date and place of incorporation 23 May 1994, Russian Federation Duration of existence Indefinite Place of domicile Russian Federation Legal form Open Joint Stock Company Charter Capital RUB 392,184.30 Group ownership as of the date of this 88.89% of charter capital (92.85% voting Prospectus rights) Registered office 22 Mukhina str., Khabarovsk, Russian Federation, 680030 Principal place of business Khabarovsk region, Russian Federation Director Name Relevant other activities Ms. Galina Grishina Member of the board of directors of Amurnefteproduct Mr. Igor Muraviev Member of the board of directors of and OJSC Khabarovsk Oil Refinery Mr. Sergey Revkov Member of the board of directors of Primornefteproduct Mr. Ramil Khabibullin Member of the board of directors of Amurnefteproduct; Mr. Alexander Shashkov None Mr. Vsevolod Sutyagin None Mr. Dmitry Karmanov Member of the board of directors of Amurnefteproduct and Primornefteproduct Management Name Relevant other activities Mr. Alexandr Popov None Statutory auditors CJSC Audit Consult Financial year Corresponds to the calendar year Principal activities Wholesale of fuel, including aviation gasoline

Pechoraneft Legal and commercial name Open Joint Stock Company ‘‘Pechoraneft’’ Registration number 1021100873870 Date and place of incorporation 28 September 1998, Russian Federation Duration of existence Indefinite Place of domicile Russian Federation Legal form Open Joint Stock Company Charter Capital RUB 957,881 Group ownership as of the date of this 99.00% of charter capital (99.93% voting Prospectus rights) Registered office 17 D, Montazhnikov str., Iskateley village, Naryan-Mar, Nenetsk Autonomous District, Russian Federation, 166700 Principal place of business Nenetsk Autonomous District, Russian Federation Directors Not applicable Management LLC Alliance Oil MC Statutory auditors CJSC Audit Consult Financial year Corresponds to the calendar year Principal activities Subsoil exploration

160 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA Amurnefteproduct Legal and commercial name Open Joint Stock Company ‘‘Amurnefteproduct’’ Registration number 1022800514890 Date and place of incorporation 29 January 1993, Russian Federation Duration of existence Indefinite Place of domicile Russian Federation Legal form Open Joint Stock Company Charter Capital RUB 4,111,629 Group ownership as of the date of this 96.19% of charter capital (96.36% voting Prospectus rights) Registered office Liter A, 1, Pervomayskaya str., Blagoveshchensk, Russian Federation, 675002 Principal place of business Amur region, Russian Federation Directors Name Relevant other activities Ms. Galina Grishina Member of the board of directors of Khabarovsknefteproduct and OJSC Khabarovsk Oil Refinery Mr. Dmitry Karmanov Member of the board of directors of Primornefteproduct and Khabarovsknefteproduct Mr. Alexander Goryunov General director of Amurnefteproduct Mr. Konstantin Turdazov Director of Potential Oil Mr. Ramil Khabibullin Member of the board of directors of Khabarovsknefteproduct Management Name Relevant other activities Mr. Alexander Goryunov Member of the board of directors of Amurnefteproduct Statutory auditors CJSC Audit Consult Financial year Corresponds to the calendar year Principal activities Sale of fuel, including aviation gasoline

Potential Oil Legal and commercial name ‘‘Potential Oil’’ Limited Liability Partnership Registration number 7175-1915-TOO /ИУ/ Date and place of incorporation 31 December 2000, Kazakhstan Duration of existence Indefinite Place of domicile Kazakhstan Legal form Limited liability partnership Charter Capital 72,500 Tenge Group ownership as of the date of this 80% of charter capital (80% voting rights) Prospectus Registered office 102, Vladimirskogo str., Atyrau, Kazakhstan, 060009 Principal place of business Kazakhstan Directors Name Relevant other activities Mr. G.S. Zhukov Member of the board of directors of Primornefteproduct, OJSC Khabarovsk Oil Refinery and OJSC Tatnefteotdacha Mr. K.E. Turdazov Member of the board of directors of Amurnefteproduct Mr. Li Yunlin None Mr. Dzan Lindun None Mr. Sergey Brezitskiy None Management Name Relevant other activities Mr. Abdrkhan Utesinov None Statutory auditors Group Min Tax Financial year Corresponds to the calendar year Principal activities Prospecting and developing of oil and gas fields

161 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA Primornefteproduct Legal and commercial name Public Joint Stock Company ‘‘Primornefteprodukt’’ Registration number 1022501287126 Date and place of incorporation 11 May 1994, Russian Federation Duration of existence Indefinite Place of domicile Russian Federation Legal form Open Joint Stock Company Charter Capital RUB 328,460.40 Group ownership as of the date of this 95.04% of charter capital (98.61% voting Prospectus rights) Registered office 55, Fontannaya str., Vladivostok, Russian Federation, 690091 Principal place of business Primorie region, Russian Federation Directors Name Relevant other activities Mr. Anatoly Gromov Member of the board of directors of OJSC Tatnefteotdacha Mr. Grigory Zhukov General director of Alliance Oil Member of the board of directors of OJSC Tatnefteotdacha, OJSC Khabarovsk Oil Refinery and Potential Mr. Dmitry Karmanov Oil Member of the board of directors of Amurnefteproduct and Khabarovsknefteproduct Mr. Dmitry Maslovsky None Mr. Sergey Revkov Member of the board of directors of Khabarovsknefteproduct Management Name Relevant other activities Mr. Dmitry Maslovsky None Statutory auditors CJSC Audit Consult Financial year Corresponds to the calendar year Principal activities Sale of fuel, including aviation gasoline

162 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA TRANSFER RESTRICTIONS

Rule 144A Notes Each purchaser of Rule 144A Notes and Guarantees, by purchasing such Notes, will be deemed to have represented, agreed and acknowledged that it has received such information as it deems necessary to make an investment decision and that: (a) It is (i) a QIB, (ii) acquiring the Notes and Guarantees for its own account or for the account of one or more QIBs, (iii) not acquiring the Notes and Guarantees with a view to further distribute such Notes and Guarantees and (iv) aware, and each beneficial owner of such Notes and Guarantees has been advised, that the sale of such Notes and Guarantees to it is being made in reliance on Rule 144A. (b) It understands that such Notes and Guarantees have not been and will not be registered under the Securities Act and may not be offered, sold, pledged or otherwise transferred except (i) pursuant to a registration statement that has been declared effective under the Securities Act; (ii) in reliance on Rule 144A to a person that the holder and any person acting on its behalf reasonably believe is a QIB purchasing for its own account or the account of another QIB; (iii) in an offshore transaction in accordance with Regulation S; (iv) pursuant to Rule 144 under the Securities Act (if available); or (v) pursuant to any other available exemption from the registration requirements of the Securities Act, in each case in accordance with any applicable securities laws of any state of the United States. (c) It acknowledges that the Notes and Guarantees offered and sold hereby in the manner set forth in paragraph (a) are ‘‘restricted securities’’ within the meaning of Rule 144(a)(3) under the Securities Act, are being offered and sold in a transaction not involving any public offering in the United States within the meaning of the Securities Act and that no representation is made as to the availability of the exemption provided by Rule 144 for resales of the Notes. (d) It understands that any offer, sale, pledge or other transfer of the Notes and Guarantees made other than in compliance with the above-stated restrictions may not be recognised by the Issuer. (e) It understands that such Notes, unless otherwise agreed between the Issuer and the Trustee in accordance with applicable law, will bear a legend to the following effect: THIS SECURITY AND THE GUARANTEE IN RESPECT HEREOF HAVE NOT BEEN AND WILL NOT BE REGISTERED UNDER THE U.S. SECURITIES ACT OF 1933 (THE ‘‘SECURITIES ACT’’) OR WITH ANY SECURITIES REGULATORY AUTHORITY OF ANY STATE OR OTHER JURISDICTION OF THE UNITED STATES AND MAY NOT BE OFFERED, SOLD, PLEDGED OR OTHERWISE TRANSFERRED EXCEPT (1) IN ACCORDANCE WITH RULE 144A UNDER THE SECURITIES ACT (‘‘RULE 144A’’) TO A PERSON THAT THE HOLDER AND ANY PERSON ACTING ON ITS BEHALF REASONABLY BELIEVES IS A QUALIFIED INSTITUTIONAL BUYER WITHIN THE MEANING OF RULE 144A (A ‘‘QIB’’) PURCHASING FOR ITS OWN ACCOUNT OR FOR THE ACCOUNT OF A QIB WHOM THE HOLDER HAS INFORMED, IN EACH CASE, THAT SUCH OFFER, SALE, PLEDGE OR OTHER TRANSFER IS BEING MADE IN RELIANCE ON RULE 144A, (2) IN AN OFFSHORE TRANSACTION IN ACCORDANCE WITH RULE 903 OR RULE 904 OF REGULATION S UNDER THE SECURITIES ACT (‘‘REGULATION S’’) OR (3) PURSUANT TO AN EXEMPTION FROM THE REGISTRATION REQUIREMENTS OF THE SECURITIES ACT PROVIDED BY RULE 144 THEREUNDER, IF AVAILABLE, AND IN EACH CASE IN ACCORDANCE WITH ANY APPLICABLE SECURITIES LAWS OF ANY STATE OF THE UNITED STATES, AND THE HOLDER WILL, AND EACH SUBSEQUENT HOLDER IS REQUIRED TO, NOTIFY ANY PURCHASER FROM IT OF THE NOTES IN RESPECT HEREOF OF THE RESALE RESTRICTIONS REFERRED TO ABOVE. NO REPRESENTATION CAN BE MADE AS TO THE AVAILABILITY OF THE EXEMPTION PROVIDED BY RULE 144 UNDER THE SECURITIES ACT FOR RESALES OF THIS SECURITY. BY ACCEPTANCE OF THIS NOTE BEARING THE ABOVE LEGEND, WHETHER UPON ORIGINAL ISSUANCE OR SUBSEQUENT TRANSFER, EACH HOLDER OF THIS NOTE ACKNOWLEDGES THE RESTRICTIONS ON THE TRANSFER OF THIS NOTE SET FORTH ABOVE AND AGREES THAT IT SHALL TRANSFER THIS NOTE ONLY AS PROVIDED HEREIN AND IN THE TRUST DEED.

163 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA (f) If it is acquiring any Notes for the account of one or more QIBs, it represents that it has sole investment discretion with respect to each such account and that it has full power to make (and does make) the foregoing acknowledgments, representations and agreements on behalf of each such account. The Issuer, the Registrar, the Managers and their respective affiliates, and others will rely upon the truth and accuracy of the foregoing acknowledgments, representations and agreements. (g) It understands that the Notes offered in reliance on Rule l44A will be represented by the Rule 144A Global Note. Before any interest in the Rule 144A Global Note may be offered, sold, pledged or otherwise transferred to a person who takes delivery in the form of an interest in the Regulation S Global Note, it will be required to provide a Transfer Agent with a written certification (in the form provided in the Agency Agreement) as to compliance with applicable securities laws. (h) Any purchaser, including, without limitation, any fiduciary purchasing on behalf of (i) an employee benefit plan (as defined in Section 3(3) of the Employee Retirement Income Security Act of 1974, as amended (‘‘ERISA’’)) subject to the provisions of part 4 of subtitle B of Title I of ERISA, a plan to which Section 4975 of the Internal Revenue Code of 1986, as amended (the ‘‘Code’’) applies (each, a ‘‘Plan’’), (ii) an entity whose underlying assets include ‘‘plan assets’’ by reason of a Plan’s investment in such entity (each, a ‘‘Benefit Plan Investor’’), or (iii) a governmental, church or non-U.S. plan which is subject to any federal, state, local, non-U.S. or other laws or regulations that are substantially similar to the fiduciary responsibility or prohibited transaction provisions of ERISA or the provisions of Section 4975 of the Code (‘‘Similar Laws’’), transferee, or holder of the Notes will be deemed to have represented, in its corporate and fiduciary capacity, that: (i) With respect to the acquisition, holding and disposition of the Notes, or any interest therein, (1) either (A) it is not, and it is not acting on behalf of (and for so long as it holds such Notes or any interest therein will not be, and will not be acting on behalf of), a Plan, a Benefit Plan Investor, or a governmental, church or non-U.S. plan which is subject to Similar Laws, and no part of the assets used or to be used by it to acquire or hold the Notes or any interest therein constitutes the assets of any such Plan, Benefit Plan Investor or governmental, church or non-U.S. plan which is subject to Similar Laws, or (B) (i) its acquisition, holding and disposition of such Notes or any interest therein does not and will not constitute or otherwise result in a nonexempt prohibited transaction under Section 406 of ERISA and/or Section 4975 of the Code (or, in the case of a governmental, church or non-U.S. plan, a non-exempt violation of any Similar Laws); and (ii) none of the Issuer, the Guarantors, the Trustees or any of their respective affiliates, is a sponsor of, or a fiduciary (within the meaning of Section 3(21) of ERISA or, with respect to a governmental, church or non-U.S. plan, any definition of ‘‘fiduciary’’ under Similar Laws) with respect to, the acquirer, transferee or holder in connection with any exchange, acquisition or holding of such Notes, or as a result of any exercise by the Issuers or any of their affiliates of any rights in connection with such Notes, and no advice provided by the Issuers or any of their affiliates has formed a primary basis for any investment or other decision by or on behalf of the acquirer or holder in connection with such Notes and the transactions contemplated with respect to such Notes; and (2) it will not sell or otherwise transfer such Notes or any interest therein otherwise than to a purchaser or transferee that is deemed (or, if required by the Trust Deed, certified) to make these same representations, warranties and agreements with respect to its acquisition, holding and disposition of such Notes or any interest therein. (ii) The acquirer and any fiduciary causing it to acquire an interest in any Notes agrees to indemnify and hold harmless the Issuers, the Guarantors, the Trustees, and their respective affiliates, from and against any cost, damage or loss incurred by any of them as a result of any of the foregoing representations and agreements being or becoming false. (iii) Any purported acquisition or transfer of any Note or interest therein to an acquirer or transferee that does not comply with the requirements of the above provisions shall be null and void ab initio. Prospective purchasers are hereby notified that the sellers of the Notes may be relying on the exemption from the provisions of Section 5 of the Securities Act provided by Rule 144A.

164 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA Regulation S Securities Each purchaser of Regulation S Notes, by purchasing such Notes and Guarantees, will be deemed to have represented, agreed and acknowledged that it has received such information as it deems necessary to make an investment decision and that: (a) It understands that the Notes and Guarantees have not been and will not be registered under the Securities Act, and such Notes and Guarantees are being offered and sold in accordance with Regulation S. (b) It or any person on whose behalf it is acting is, or at the time the Notes and Guarantees are purchased will be, the beneficial owner of such Notes and Guarantees and (i) it is purchasing the Notes and Guarantees in an offshore transaction (within the meaning of Regulation S) and (ii) it is not an affiliate of the Issuer or a person acting on behalf of such an affiliate. (c) It will not offer, sell, pledge or otherwise transfer Notes, except in accordance with the Securities Act and any applicable securities laws of any state of the United States. (d) The Issuer, the Registrar, the Managers and their affiliates, and others will rely upon the truth and accuracy of the foregoing acknowledgments, representations and agreements. (e) Any purchaser, including, without limitation, any fiduciary purchasing on behalf of (i) an employee benefit plan (as defined in Section 3(3) of the Employee Retirement Income Security Act of 1974, as amended (‘‘ERISA’’)) subject to the provisions of part 4 of subtitle B of Title I of ERISA, a plan to which Section 4975 of the Internal Revenue Code of 1986, as amended (the ‘‘Code’’) applies (each, a ‘‘Plan’’), (ii) an entity whose underlying assets include ‘‘plan assets’’ by reason of a Plan’s investment in such entity (each, a ‘‘Benefit Plan Investor’’), or (iii) a governmental, church or non-U.S. plan which is subject to any federal, state, local, non-U.S. or other laws or regulations that are substantially similar to the fiduciary responsibility or prohibited transaction provisions of ERISA or the provisions of Section 4975 of the Code (‘‘Similar Laws’’), transferee, or holder of the Notes will be deemed to have represented, in its corporate and fiduciary capacity, that: (i) With respect to the acquisition, holding and disposition of the Notes, or any interest therein, (1) either (A) it is not, and it is not acting on behalf of (and for so long as it holds such Notes or any interest therein will not be, and will not be acting on behalf of), a Plan, a Benefit Plan Investor, or a governmental, church or non-U.S. plan which is subject to Similar Laws, and no part of the assets used or to be used by it to acquire or hold the Notes or any interest therein constitutes the assets of any such Plan, Benefit Plan Investor or governmental, church or non-U.S. plan which is subject to Similar Laws, or (B) (i) its acquisition, holding and disposition of such Notes or any interest therein does not and will not constitute or otherwise result in a nonexempt prohibited transaction under Section 406 of ERISA and/or Section 4975 of the Code (or, in the case of a governmental, church or non-U.S. plan, a non-exempt violation of any Similar Laws); and (ii) none of the Issuer, the Guarantors, the Trustees or any of their respective affiliates, is a sponsor of, or a fiduciary (within the meaning of Section 3(21) of ERISA or, with respect to a governmental, church or non-U.S. plan, any definition of ‘‘fiduciary’’ under Similar Laws) with respect to, the acquirer, transferee or holder in connection with any exchange, acquisition or holding of such Notes, or as a result of any exercise by the Issuers or any of their affiliates of any rights in connection with such Notes, and no advice provided by the Issuers or any of their affiliates has formed a primary basis for any investment or other decision by or on behalf of the acquirer or holder in connection with such Notes and the transactions contemplated with respect to such Notes; and (2) it will not sell or otherwise transfer such Notes or any interest therein otherwise than to a purchaser or transferee that is deemed (or, if required by the Trust Deed, certified) to make these same representations, warranties and agreements with respect to its acquisition, holding and disposition of such Notes or any interest therein. (ii) The acquirer and any fiduciary causing it to acquire an interest in any Notes agrees to indemnify and hold harmless the Issuers, the Guarantors, the Trustees, and their respective affiliates, from and against any cost, damage or loss incurred by any of them as a result of any of the foregoing representations and agreements being or becoming false. (iii) Any purported acquisition or transfer of any Note or interest therein to an acquirer or transferee that does not comply with the requirements of the above provisions shall be null and void ab initio.

165 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA CLEARING AND SETTLEMENT

The Global Notes Each Series of Notes will be evidenced on issue by (i) in the case of Regulation S Notes, a Regulation S Global Note deposited with, and registered in the name of a nominee for, a common depositary for Euroclear and Clearstream, Luxembourg and (ii) in the case of Rule 144A Notes, a Rule 144A Global Note deposited with a custodian for, and registered in the name of, Cede & Co. as nominee of DTC. Beneficial interests in a Regulation S Global Note may be held only through Euroclear or Clearstream, Luxembourg. See ‘‘ –Book-Entry Procedures for the Global Notes’’. By acquisition of a beneficial interest in a Regulation S Global Note, the purchaser thereof will be deemed to represent, among other things, that it is not a U.S. person and that, if it determines to transfer such beneficial interest prior to the expiration of 40 days after completion of the distribution of the Series of which such Notes are a part (the ‘‘distribution compliance period’’), it will not offer, sell, pledge or otherwise transfer such interest except to a person (a) who is a non-U.S. person in an offshore transaction in accordance with Rule 903 or Rule 904 of Regulation S or (b) who is a person who takes delivery in the form of an interest in a Rule 144A Global Note (as applicable). See ‘‘Transfer Restrictions’’. Beneficial interests in a Rule 144A Global Note may only be held through DTC at any time. See ‘‘ – Book-Entry Procedures for the Global Notes’’. By acquisition of a beneficial interest in a Rule 144A Global Note, the purchaser thereof will be deemed to represent, among other things, that it is a QIB that is also a QP and that, if in the future it determines to transfer such beneficial interest, it will transfer such interest in accordance with the procedures and restrictions contained in the Paying Agency Agreement. See ‘‘Transfer Restrictions’’. Beneficial interests in each Global Note will be subject to certain restrictions on transfer set forth therein and in the Trust Deed, and with respect to the Rule 144A Global Note, as set forth in Rule 144A, and the Rule 144A Notes will bear the legends set forth thereon regarding such restrictions set forth under ‘‘Transfer Restrictions’’. Any beneficial interest in a Regulation S Global Note that is transferred to a person who takes delivery in the form of an interest in a Rule 144A Global Note will, upon transfer, cease to be an interest in the Regulation S Global Note and become an interest in the Rule 144A Global Note, and, accordingly, will thereafter be subject to all transfer restrictions and other procedures applicable to beneficial interests in the Rule 144A Global Note for as long as it remains such an interest. Any beneficial interest in a Rule 144A Global Note that is transferred to a person who takes delivery in the form of an interest in a Regulation S Global Note will, upon transfer, cease to be an interest in the Rule 144A Global Note and become an interest in the Regulation S Global Note and, accordingly, will thereafter be subject to all transfer restrictions and other procedures applicable to beneficial interests in the Regulation S Global Note for so long as it remains such an interest. No service charge will be made for any registration of transfer or exchange of Notes, but the Registrar may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection therewith. Except in the limited circumstances described below, owners of beneficial interests in Global Notes will not be entitled to receive physical delivery of certificated Notes in definitive form (the ‘‘Definitive Notes’’). The Notes are not issuable in bearer form. So long as the Notes are represented by a Global Note and the relevant clearing systems(s) so permit, the Notes shall be tradable only in principal amounts of at least the minimum denomination specified in this Prospectus (or if more than one, the lowest minimum denomination).

Amendments to Conditions Each Global Note contains provisions that apply to the Notes that they represent, some of which modify the effect of the Terms and Conditions of the Notes. The following is a summary of those provisions: Payments. All payments in respect of Notes represented by a Global Note will be made against presentation for endorsement and, if no further payment falls to be made in respect of the Notes, surrender of that Global Note to or to the order of the Principal Paying Agent or such other Paying Agent as shall have been notified to the Noteholders for such purpose. A record of each payment so made will be endorsed on each Global Note, which endorsement will be prima facie evidence that such payment has been made in respect of the Notes. For the purpose of any payments made in respect of a Global Note, the relevant place of presentation shall be disregarded in the definition of ‘‘business day’’ set out in Condition 7.4 of the Terms and Conditions of the Notes.

166 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA All payments in respect of Notes represented by a Global Note will be made to, or to the order of, the person whose name is entered on the Register at the close of business on the record date which shall be on the Clearing System Business Day immediately prior to the date for payment, where ‘‘Clearing System Business Day’’ means Monday to Friday inclusive, except 25 December and 1 January. Notices. So long as any Notes are evidenced by a Global Note and such Global Note is held by or on behalf of a clearing system, notices to Noteholders may be given by delivery of the relevant notice to that clearing system for communication by it to entitled account holders in substitution for delivery thereof as required by the Terms and Conditions of such Notes, provided that for so long as the Notes are listed and admitted to trading on the Irish Stock Exchange and the Guidelines for Asset Backed Securities (the ‘‘Guidelines’’) so require, notices will also be filed at the Companies Announcements Office of the Irish Stock Exchange. Meetings. The holder of each Global Note will, at a meeting of Noteholders, be treated as having one vote in respect of Notes for which the relevant Global Note may be exchangeable. Trustee’s Powers. In considering the interests of Noteholders while the relevant Global Note is held on behalf of a clearing system, the Trustee, to the extent it considers it appropriate to do so in the circumstances, may have regard to any information provided to it by such clearing system or its operator as to the identity (either individually or by category) of its accountholders with entitlements to such Global Note and may consider such interests as if such accountholders were the holders of such Global Note. Cancellation. Cancellation of any Note required by the Terms and Conditions of the Notes to be cancelled will be effected by reduction in the principal amount of the applicable Global Note. Redemption at the Option of the Issuer. Any Call Option provided for in the Conditions shall be exercised by the Issuer giving notice to the Noteholders within the time limits set out in and containing the information required by the Conditions. Redemption at the Option of Noteholders. Any Put Option provided for in the Conditions may be exercised by the holder of the Global Note (i) giving notice to the Issuer within the time limits relating to the deposit of Notes set out in the Conditions substantially in the form of the notice available from any Paying Agent, the Registrar or any Transfer Agent (except that the notice shall not be required to contain the certificate numbers of the Notes in respect of which the option has been exercised) stating the nominal amount of Notes in respect of which the option is exercised and (ii) at the same time depositing the Global Note with the Registrar or any Transfer Agent at its specified office.

Exchange for Definitive Notes Exchange Each Global Note will be exchangeable, free of charge to the holder, in whole but not in part, for Notes in definitive, registered form if: (i) a Global Note is held by or on behalf of (a) DTC, and DTC notifies the Issuer that it is no longer willing or able to discharge properly its responsibilities as depositary with respect to the Global Note or ceases to be a ‘‘clearing agency’’ registered under the Exchange Act or if at any time it is no longer eligible to act as such, and the Issuer is unable to locate a qualified successor within 90 days of receiving notice or becoming aware of such ineligibility on the part of DTC or (b) Euroclear or Clearstream, Luxembourg, as the case may be, is closed for business for a continuous period of 14 days (other than by reason of holidays, statutory or otherwise) or announces an intention permanently to cease business or does in fact do so, by the holder giving notice to the Registrar or any Transfer Agent, or (ii) if the Issuer would suffer a material disadvantage in respect of the Notes as a result of a change in the laws or regulations (taxation or otherwise) of any jurisdiction referred to in Condition 8 which would not be suffered were the Notes in definitive form and a notice to such effect signed by two authorised signatories of the Issuer is delivered to the Trustee, by the Issuer giving notice to the Registrar or any Transfer Agent and the Noteholders, of its intention to exchange the relevant Global Note for Definitive Notes on or after the Exchange Date (as defined below) specified in the notice. On or after the Exchange Date, the holder of the relevant Global Note may surrender such Global Note to or to the order of the Registrar or any Transfer Agent. In exchange for the relevant Global Note, as provided in the Paying Agency Agreement, the Registrar will deliver, or procure the delivery of, an equal aggregate amount of duly executed and authenticated Definitive Notes in or substantially in the form set out in the relevant schedule to the Trust Deed.

167 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA The Registrar will not register the transfer of, or exchange of interests in, a Global Note for definitive Notes for a period of 15 calendar days ending on the date for any payment of principal or interest or on the date of optional redemption in respect of the Notes. ‘‘Exchange Date’’ means a day falling not later than 90 days after that on which the notice requiring exchange is given and on which banks are open for business in the city in which the specified office of the Registrar or the Transfer Agent is located.

Delivery In such circumstances, the relevant Global Note shall be exchanged in full for Definitive Notes and the Issuer will, at the cost of the Issuer (but against such indemnity as the Registrar or any relevant Transfer Agent may require in respect of any tax or other duty of whatever nature which may be levied or imposed in connection with such exchange), cause sufficient Definitive Notes to be executed and delivered to the Registrar for completion, authentication and dispatch to the relevant Noteholders. A person having an interest in a Global Note must provide the Registrar with (i) a written order containing instructions and such other information as the Issuer and the Registrar may require to complete, execute and deliver such Notes and (ii) in the case of a Rule 144A Global Note only, a fully completed, signed certification substantially to the effect that the exchanging holder is not transferring its interest at the time of such exchange or, in the case of simultaneous sale pursuant to Rule 144A, a certification that the transfer is being made in compliance with the provisions of Rule 144A to a QIB that is also a QP. Definitive Notes issued in exchange for a beneficial interest in a Rule 144A Global Note shall bear the legend applicable to transfers pursuant to Rule 144A, as set out under ‘‘Transfer Restrictions’’.

Legends The holder of a Definitive Note may transfer the Notes evidenced thereby in whole or in part in the applicable minimum denomination by surrendering it at the specified office of the Registrar or any Transfer Agent, together with the completed form of transfer thereon. Upon the transfer, exchange or replacement of a Rule 144A Definitive Note bearing the legend referred to under ‘‘Transfer Restrictions’’, or upon specific request for removal of the legend on a Rule 144A Definitive Note, the Issuer will deliver only Rule 144A Definitive Notes that bear such legend, or will refuse to remove such legend, as the case may be, unless there is delivered to the Issuer and the Registrar such satisfactory evidence, which may include an opinion of counsel, as may reasonably be required by the Issuer that neither the legend nor the restrictions on transfer set forth therein are required to ensure compliance with the provisions of the Securities Act and the applicable exemption from registration under the Investment Company Act.

Book-Entry Procedures for the Global Notes For each Series of Notes evidenced by both a Regulation S Global Note and a Rule 144A Global Note, custodial and depositary links are to be established between DTC, Euroclear and Clearstream, Luxembourg to facilitate the initial issue of the Notes and cross-market transfers of the Notes associated with secondary market trading. See ‘‘ – Book-Entry Ownership – Settlement and Transfer of Notes’’.

Euroclear and Clearstream, Luxembourg Euroclear and Clearstream, Luxembourg each hold securities for their customers and facilitate the clearance and settlement of securities transactions through electronic book-entry transfer between their respective accountholders. Indirect access to Euroclear and Clearstream, Luxembourg is available to other institutions which clear through or maintain a custodial relationship with an accountholder of either system. Euroclear and Clearstream, Luxembourg provide various services including safekeeping, administration, clearance and settlement of internationally-traded securities and securities lending and borrowing. Euroclear and Clearstream, Luxembourg also deal with domestic securities markets in several countries through established depositary and custodial relationships. Euroclear and Clearstream, Luxembourg have established an electronic bridge between their two systems across which their respective customers may settle with each other. Their customers are worldwide financial institutions including underwriters, securities brokers and dealers, banks, trust companies and clearing corporations. Investors may hold their interests in such Global Notes directly through Euroclear or Clearstream, Luxembourg if they are accountholders (‘‘Direct Participants’’) or indirectly (‘‘Indirect Participants’’ and together with Direct Participants ‘‘Participants’’) through organisations which are accountholders therein.

168 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA DTC DTC has advised the Issuer as follows: DTC is a limited purpose trust company organised under the law of the State of New York, a ‘‘banking organisation’’ under the laws of the State of New York, a member of the U.S. Federal Reserve System, a ‘‘clearing corporation’’ within the meaning of the New York Uniform Commercial code and a ‘‘clearing agency’’ registered pursuant to the provisions of Section 17A of the Exchange Act. DTC was created to hold securities for its Participants and facilitate the clearance and settlement of securities transactions between Participants through electronic computerised book entry changes in accounts of its Participants, thereby eliminating the need for physical movement of certificates. Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organisations. Indirect access to DTC is available to others, such as banks, securities brokers, dealers and trust companies, that clear through or maintain a custodial relationship with a DTC Direct Participant, either directly or indirectly. Investors may hold their interests in Rule 144A Global Notes directly through DTC if they are Direct Participants in the DTC system or as Indirect Participants through organisations which are Direct Participants in such system. DTC has advised the Issuer that it will take any action permitted to be taken by a holder of Notes only at the direction of one or more Direct Participants and only in respect of such portion of the aggregate principal amount of the relevant Rule 144A Global Notes as to which such Participant or Participants has or have given such direction. However, in the circumstances described under ‘‘Exchange for Definitive Notes’’, DTC will surrender the relevant Rule 144A Global Notes for exchange for individual Rule 144A Definitive Notes (which will bear the legend applicable to transfers pursuant to Rule 144A).

Book-Entry Ownership Euroclear and Clearstream, Luxembourg The Regulation S Global Note representing Regulation S Notes of any Series will have an International Securities Identification Number (‘‘ISIN’’) and a Common Code and will be registered in the name of a nominee for, and deposited with a common depositary on behalf of, Euroclear and Clearstream, Luxembourg. The address of Euroclear is 1 Boulevard due Roi Albert II, B-12201 Brussels, Belgium and the address of Clearstream, Luxembourg is 42 Avenue J.F. Kennedy, L-1855, Luxembourg.

DTC The Rule 144A Global Note representing Rule 144A Notes of any Series will have an ISIN, Common Code and CUSIP number and will be deposited with a custodian (the ‘‘Custodian’’) for, and registered in the name of Cede & Co. as nominee of, DTC. The Custodian and DTC will electronically record the principal amount of the Notes held within the DTC system. The address of DTC is 55 Water Street, New York, New York 10041, United States of America.

Relationship of Participants with Clearing Systems Each of the persons shown in the records of Euroclear, Clearstream, Luxembourg or DTC as the holder of a Note evidenced by a Global Note must look solely to Euroclear, Clearstream, Luxembourg or DTC (as the case may be) for his share of each payment made by the Issuer to the holder of such Global Note and in relation to all other rights arising under such Global Note, subject to and in accordance with the respective rules and procedures of Euroclear, Clearstream, Luxembourg or DTC (as the case may be). The Issuer expects that, upon receipt of any payment in respect of Notes evidenced by a Global Note, the common depositary by whom such Note is held, or nominee in whose name it is registered, will immediately credit the relevant participants’ or accountholders’ accounts in the relevant clearing system with payments in amounts proportionate to their respective beneficial interests in the principal amount of the relevant Global Note as shown on the records of the relevant clearing system or its nominee. The Issuer also expects that payments by Direct Participants in any clearing system to owners of beneficial interests in any Global Note held through such Direct Participants in any clearing system will be governed by standing instructions and customary practices. Save as aforesaid, such persons shall have no claim directly against the Issuer in respect of payments due on the Notes for so long as the Notes are evidenced by such Global Note and the obligations of the Issuer will be discharged by payment to the registered holder, as the case may be, of such Global Note in respect of each amount so paid. None of the Issuer, the Trustee or any Agent will have any responsibility or liability for any aspect of the records relating to or

169 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA payments made on account of ownership interests in any Global Note or for maintaining, supervising or reviewing any records relating to such ownership interests.

Settlement and Transfer of Notes Subject to the rules and procedures of each applicable clearing system, purchases of Notes held within a clearing system must be made by or through Direct Participants, which will receive a credit for such Notes on the clearing system’s records. The ownership interest of each actual purchaser of each such Note (the ‘‘Beneficial Owner’’) will in turn be recorded on the Direct and Indirect Participants’ records. Beneficial Owners will not receive written confirmation from any clearing system of their purchase, but Beneficial Owners are expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the Direct or Indirect Participant through which such Beneficial Owner entered into the transaction. Transfers of ownership interests in Notes held within the clearing system will be affected by entries made on the books of Participants acting on behalf of Beneficial Owners. Beneficial Owners will not receive certificates representing their ownership interests in such Notes, unless and until interests in any Global Note held within a clearing system are exchanged for Definitive Notes. No clearing system has knowledge of the actual Beneficial Owners of the Notes held within such clearing system and their records will reflect only the identity of the Direct Participants to whose accounts such Notes are credited, which may or may not be the Beneficial Owners. The Participants will remain responsible for keeping account of their holdings on behalf of their customers. Conveyance of notices and other communications by the clearing systems to Direct Participants, by Direct Participants to Indirect Participants, and by Direct Participants and Indirect Participants to Beneficial Owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time. The laws of some jurisdictions may require that certain persons take physical delivery in definitive form of securities. Consequently, the ability to transfer interests in a Global Note to such persons may be limited. Because DTC can only act on behalf of Direct Participants, who in turn act on behalf of Indirect Participants, the ability of a person having an interest in a Rule 144A Global Note to pledge such interest to persons or entities that do not participate in DTC, or otherwise take actions in respect of such interest, may be affected by a lack of physical certificate in respect of such interest.

Trading Between Euroclear and/or Clearstream, Luxembourg Participants Secondary market sales of book-entry interests in the Notes held through Euroclear or Clearstream, Luxembourg to purchasers of book-entry interests in the Notes held through Euroclear or Clearstream, Luxembourg will be conducted in accordance with the normal rules and operating procedures of Euroclear and Clearstream, Luxembourg and will be settled using the procedures applicable to conventional Notes.

Trading Between DTC Participants Secondary market sales of book-entry interests in the Notes between DTC participants will occur in the ordinary way in accordance with DTC rules and will be settled using the procedures applicable to United States corporate debt obligations in DTC’s same-day funds settlement system in same day funds, if payment is effected in U.S. dollars, or free of payment, if payment is not effected in U.S. dollars. Where payment is not effected in U.S. dollars, separate payment arrangements outside DTC are required to be made between the DTC participants.

Trading Between DTC Seller and Euroclear/Clearstream, Luxembourg Purchaser When book-entry interests in Notes are to be transferred from the account of a DTC participant holding a beneficial interest in a Rule 144A Global Note to the account of a Euroclear or Clearstream, Luxembourg accountholder wishing to purchase a beneficial interest in a Regulation S Global Note (subject to the certification procedures provided in the Trust Deed), the DTC participant will deliver instructions for delivery to the relevant Euroclear or Clearstream, Luxembourg accountholder to DTC by 12:00 noon, New York time, on the settlement date. Separate payment arrangements are required to be made between the DTC participant and the relevant Euroclear or Clearstream, Luxembourg participant. On the settlement date, the custodian of the Rule 144A Global Note will instruct the Registrar to (i) decrease the amount of Notes registered in the name of Cede & Co. and evidenced by the Rule 144A Global Note of the relevant class and (ii) increase the amount of Notes registered in the name of the nominee of the common depositary for Euroclear and

170 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA Clearstream, Luxembourg and evidenced by the Regulation S Global Note. Book-entry interests will be delivered free of payment to Euroclear or Clearstream, Luxembourg, as the case may be, for credit to the relevant accountholder on the first business day following the settlement date. Trading Between Euroclear and Clearstream, Luxembourg Seller and DTC Purchaser When book-entry interests in the Notes are to be transferred from the account of a Euroclear or Clearstream, Luxembourg accountholder to the account of a DTC participant wishing to purchase a beneficial interest in a Rule 144A Global Note (subject to the certification procedures provided in the Trust Deed), the Euroclear or Clearstream, Luxembourg participant must send to Euroclear or Clearstream, Luxembourg delivery free of payment instructions by 7:45 p.m., Brussels or Luxembourg time, one business day prior to the settlement date. Euroclear or Clearstream, Luxembourg, as the case may be, will in turn transmit appropriate instructions to the common depositary for Euroclear and Clearstream, Luxembourg and the Registrar to arrange delivery to the DTC participant on the settlement date. Separate payment arrangements are required to be made between the DTC participant and the relevant Euroclear or Clearstream, Luxembourg accountholder, as the case may be. On the settlement date, the common depositary for Euroclear and Clearstream, Luxembourg will (i) transmit appropriate instructions to the custodian of the Rule 144A Global Note who will in turn deliver such book entry interests in the Notes free of payment to the relevant account of the DTC participant and (ii) instruct the Registrar to (a) decrease the amount of Notes registered in the name of the nominee of the common depositary for Euroclear and Clearstream, Luxembourg and evidenced by a Regulation S Global Note and (b) increase the amount of Notes registered in the name of Cede & Co. and evidenced by a Rule 144A Global Note. Although Euroclear, Clearstream, Luxembourg and DTC have agreed to the foregoing procedures in order to facilitate transfers of beneficial interest in Global Notes among participants and accountholders of Euroclear, Clearstream, Luxembourg and DTC, they are under no obligation to perform or continue to perform such procedures, and such procedures may be discontinued at any time. None of the Issuer, the Trustee or any Agent will have the responsibility for the performance by Euroclear, Clearstream, Luxembourg or DTC or their respective Direct or Indirect Participants of their respective obligations under the rules and procedures governing their operations. Pre-issue Trades Settlement It is expected that the delivery of Notes will be made against payment therefor on the closing date thereof, which could be more than three business days following the date of pricing. Under Rule 15c6-l under the Exchange Act, trades in the United States secondary market generally are required to settle within three business days (T+3), unless the parties to any such trade expressly agree otherwise. Accordingly, purchasers who wish to trade Notes in the United States on the date of pricing or the next succeeding business days until three days prior to the relevant closing date will be required, by virtue of the fact that the Notes initially will settle beyond T+3, to specify an alternate settlement cycle at the time of any such trade to prevent a failed settlement. Settlement procedures in other countries will vary. Purchasers of Notes may be affected by such local settlement practices, and purchasers of Notes between the relevant date of pricing and the relevant closing date should consult their own advisers.

171 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA SUBSCRIPTION AND SALE

Deutsche Bank AG, London Branch Goldman Sachs International, GPB-Financial Services Ltd, Raiffeisen Bank International AG, Carnegie Investment Bank AB (publ), OTKRITIE Bank JSC and UniCredit Bank AG (together, the ‘‘Managers’’) have, pursuant to a Subscription Agreement dated 30 April 2013, and the Subscription Support Agreement of even date, as applicable, severally and not jointly agreed with the Issuer, subject to the satisfaction of certain conditions, to subscribe for the Notes at 99.32% of their principal amount in the following amounts:

Principal Manager Amount of Notes

Deutsche Bank AG, London Branch...... USD 124,850,000 Goldman Sachs International ...... USD 124,850,000 GPB-Financial Services Ltd...... USD 124,850,000 Raiffeisen Bank International AG...... USD 124,850,000 Carnegie Investment Bank AB (publ)...... USD 200,000 OTKRITIE Bank JSC ...... USD 200,000 UniCredit Bank AG...... USD 200,000 Total ...... USD 500,000,000 The Issuer, failing whom the Guarantors, has agreed to pay to the Managers a combined management, underwriting and selling commission of up to 1% of such principal amount. In addition, the Issuer, failing whom the Guarantors, have agreed to reimburse the Managers for certain of their expenses in connection with the issue of the Notes. The Subscription Agreement entitles the Managers to terminate it in certain circumstances prior to payment being made to the Issuer. The Issuer and the Guarantors have in the Subscription Agreement agreed to indemnify the Managers against certain liabilities incurred in connection with the issue of the Notes. One or more of the Managers and their affiliates have engaged in transactions with the Issuer and the Guarantors (including, in some cases, credit agreements and credit lines) in the ordinary course of its banking business and one or more of the Managers have performed various investment banking, financial advisory, and other services for the Issuer and (or) the Guarantors, for which it received customary fees, and the Managers and their affiliates may provide such services in the future. Each of the Managers and their respective affiliates may, from time to time, engage in further transactions with, and perform services for, the Issuer and the Group in the ordinary course of their respective businesses. An affiliate of one of the Joint Lead Managers owns a small minority interest in a company the acquisition of which the Group is currently evaluating. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments – Current Trading’’.

No Securities and Exchange Commission Approval The Notes and the Guarantees have not been approved or disapproved by the SEC, any state securities commission in the United States or any other U.S. regulatory authority, nor have any of the foregoing authorities passed upon or endorsed the merits of the offering of the Notes or the accuracy or adequacy of this Prospectus. Any representation to the contrary is a criminal offence in the United States.

Selling Restrictions United States The Notes and the Guarantees (together, the ‘‘Securities’’) have not been and will not be registered under the Securities Act and may not be offered or sold within the United States or to, or for the account or benefit of, U.S. persons (as defined in Regulation S) except pursuant to an exemption from, or a transaction not subject to, the registration requirements of the Securities Act. Each Manager severally and not jointly nor jointly and severally represents and agrees that it, its affiliates (as defined in Rule 501(b) of Regulation D under the Securities Act (‘‘Regulation D’’)) and any person acting on its or their behalf has offered and sold the Securities, and agrees that it will offer and sell the Securities (i) as part of their distribution at any time and (ii) otherwise until 40 days after the later of the commencement of the offering and the Closing Date, only in accordance with Rule 903 of Regulation S. Accordingly, neither it, nor its affiliates nor any persons acting on its or their behalf have engaged or will engage in any directed selling efforts with respect to the Securities,

172 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA and it and they have complied and will comply with the offering restrictions requirement of Regulation S. Each Manager agrees that at or prior to confirmation of sale of Securities (other than a sale of Securities pursuant to Rule 144A under the Securities Act), it shall have sent to each distributor, dealer or person receiving a selling concession, fee or other remuneration that purchases Securities from it during the distribution compliance period (within the meaning of Regulation S) a confirmation or notice to substantially the following effect: ‘‘The Securities covered hereby have not been registered under the U.S. Securities Act of 1933 (the ‘‘Securities Act’’) and may not be offered or sold within the United States or to, or for the account or benefit of, U.S. persons (i) as part of their distribution at any time or (ii) otherwise until 40 days after the later of the commencement of the offering and the date of closing of the offering, except in either case in accordance with Regulation S or Rule 144A under the Securities Act to a person that the seller reasonably believes is a qualified institutional buyer (within the meaning of Rule 144A under the Securities Act). Terms used in this paragraph have the meanings given to them by Regulation S under the Securities Act’’. Each Manager severally and not jointly nor jointly and severally represents and agrees that neither it nor any of its affiliates, nor any person acting on its or their behalf has engaged or will engage in any form of general solicitation or general advertising (within the meaning of Regulation D) in connection with any offer and sale of the Securities in the United States. The Managers may directly or through their respective U.S. broker-dealer affiliates arrange for the offer and resale of Securities in the United States only to qualified institutional buyers in accordance with Rule 144A. Each Manager severally and not jointly nor jointly and severally represents that it has not entered and agrees that it will not enter into any contractual arrangement with any distributor (as that term is defined in Regulation S) with respect to the distribution or delivery of the Securities, except with its affiliates or with the prior written consent of the Issuer.

United Kingdom Each of the Managers severally and not jointly nor jointly and severally represents and agrees that: (a) it has only communicated or caused to be communicated and will only communicate or cause to be communicated any invitation or inducement to engage in investment activity (within the meaning of section 21 of the Financial Services and Markets Act 2000 (‘‘FSMA’’)) received by it in connection with the issue or sale of any Notes in circumstances in which section 21(1) of the FSMA does not apply to the Issuer or any Guarantor; and (b) it it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the Notes in, from or otherwise involving the United Kingdom.

Russian Federation Each of the Managers severally and not jointly nor jointly and severally acknowledges that no Russian prospectus has been registered or is intended to be registered with respect to the Notes and the Notes have not been and are not intended to be registered in the Russian Federation, and, consequently, severally and not jointly nor jointly and severally represents, warrants and agrees that it and its affiliates have not offered or sold or otherwise transferred, and will not offer or sell or otherwise transfer as part of their initial distribution or at any time thereafter, any Notes to or for the benefit of any persons (including legal entities) resident, incorporated, established or having their usual residence in the Russian Federation, or to any person located within the territory of the Russian Federation unless and to the extent otherwise permitted under Russian law.

Ireland Each Manager has represented, warranted and agreed that: (a) it will not underwrite the issue of, or place the Notes, otherwise than in conformity with the provisions of the European Communities (Markets in Financial Instruments) Regulations 2007 (Nos. 1 to 3) (as amended), including, without limitation, Regulations 7 and 152 thereof and any codes of conduct issued in connection therewith and the provisions of the Investor Compensation Act 1998;

173 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA (b) it will not underwrite the issue of, or place, the Notes, otherwise than in conformity with the provisions of the Companies Acts 1903 – 2012, the the Central Bank Acts 1942 – 2011 and any codes of conduct rules made under Section 117(1) of the Central Bank Act 1989; (c) it will not underwrite the issue of, place or do anything in Ireland in respect of the Notes otherwise than in conformity with the provisions of the Prospectus (Directive 2003/71/EC, as amended) Regulations 2005 (as amended) and any rules issued under Section 51 of the Investment Funds, Companies and Miscellaneous Provisions Act 2005, by the Central Bank of Ireland; and (d) it will not underwrite the issue of, place or otherwise act in Ireland in respect of the Notes, otherwise than in conformity with the provisions of the Market Abuse (Directive 2003/6/ EC) Regulations 2005 (as amended) and any rules issued under Section 34 of the Investment Funds, Companies and Miscellaneous Provisions Act 2005 by the Central Bank of Ireland.

Bermuda Each of the Managers severally and not jointly nor jointly and severally agrees that, to the extent that any Notes are offered or sold in Bermuda, such offer or sale will be made in accordance with the Investment Business Act 2000 of Bermuda. Additionally, non-Bermudian persons may not carry on or engage in any trade or business in Bermuda unless such persons are authorised to do so under applicable Bermuda legislation. Engaging in the activity of offering or marketing the notes in Bermuda to persons in Bermuda may be deemed to be carrying on business in Bermuda.

Republic of Kazakhstan Each Manager severally and not jointly nor jointly and severally agrees that it will not, directly or indirectly, offer for subscription or purchase or issue invitations to subscribe for or buy or sell the Notes or distribute any draft or definitive document in relation to any such offer, invitation or sale in the Republic of Kazakhstan, except in compliance with the applicable securities laws of the Republic of Kazakhstan.

General None of the Managers, the Issuer or any Fully Owned Guarantor makes any representation that any action will be taken in any jurisdiction by the Managers, the Issuer or any Fully Owned Guarantor that would permit a public offering of the Notes, or the possession or distribution of the Prospectus or any other material relating to the offering or the Notes, where action for such purpose is required. Accordingly, each Manager, the Issuer and each Fully Owned Guarantor represents severally and not jointly nor jointly and severally that it will comply to the best of its knowledge and belief in all material respects with all applicable laws and regulations in each jurisdiction in which it acquires, offers, sells or delivers Notes or has in its possession or distributes this Prospectus or any other offering material or advertisement in connection with the Notes. These selling restrictions may be modified by the agreement of the Issuer, the Guarantors and the Managers following a change in a relevant law, regulation or directive.

174 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA REGULATION OF THE RUSSIAN OIL AND GAS INDUSTRY

Applicable Legislation The oil and gas industry in Russia is governed primarily by the following laws: * Parts One and Two of the Civil Code, No. 51-FZ dated 30 November 1994 and No. 14- FZ dated 26 January 1996, respectively, as amended; * The Subsoil Law; * Federal Law No. 147-FZ ‘‘On the Natural Monopolies’’, dated 17 August 1995, as amended (the ‘‘Natural Monopolies Law’’); * Federal Law No. 187-FZ ‘‘On the Continental Shelf of the Russian Federation’’, dated 30 November 1995, as amended (the ‘‘Continental Shelf Law’’); * Federal Law No. 225-FZ ‘‘On Production Sharing Agreements’’, dated 30 December 1995, as amended (the ‘‘PSA Law’’); * Federal Law No. 69-FZ ‘‘On Gas Supply in the Russian Federation’’, dated 31 March 1999, as amended (the ‘‘Gas Supply Law’’); and * Parts One and Two of the Tax Code of the Russian Federation, No. 146-FZ dated 31 July 1998 and No. 117-FZ dated 5 August 2000, respectively, as amended (the ‘‘Russian Tax Code’’). A number of other laws and regulations also apply to the Russian oil and gas industry. In particular, the Russian Government has adopted a number of regulations which set out in detail the subsoil licensing procedure, reporting requirements for subsoil users, subsoil protection rules, the classification of oil reserves and resources, and a subsoil use payments regime.

Principal Regulatory Authorities The principal authorities with regulatory oversight over the Russian oil and gas industry include the following: * Ministry of Natural Resources, which determines governmental policy and prepares legal acts in the area of natural resources use and protection, including geological survey of natural resources, is in charge of budgetary accounting for natural resources, issuance and transfer of subsoil licences, classifying and evaluating natural resources, and use of the geological information which belongs to the state; * Rosnedra, an agency subordinate to the Ministry of Natural Resources, that organises the state geological studies, issues and revokes Exploration and Production Licences (defined below), organises geological exploration of the subsoil by the state, maintains the federal and territorial funds of geological data on the subsoil, organises the tenders and auctions for the right to use subsoil, and maintains the state cadastre of deposits; * Rosprirodnadzor, an entity subordinate to the Ministry of Natural Resources, that supervises the compliance by licence holders with the terms of subsoil licences, monitors the environmental protection and the rational use of the subsoil, and performs regular audits of subsoil licence holders; * the Federal Service for Ecological, Technological and Nuclear Supervision of the Russian Federation (‘‘Rostekhnadzor’’), an entity subordinate to the Ministry of Natural Resources, that oversees compliance with the industrial safety, and ecological standards in the area of subsoil use, conducts ecological expert review at the federal level, and performs regular audits of subsoil licence holders; * the Ministry of Energy of the Russian Federation, which determines the governmental policy and prepares legal acts governing the energy sector, including the power industry, oil and gas production, transportation and refining industries, and performs the function of management of the state property in the energy sector; * FTS, an entity directly subordinate to the Government, that establishes, among other things, oil and gas transportation tariffs; and

175 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA * the Federal Tax Service of the Russian Federation is the federal executive authority which controls and supervises the observance of the legislation of the Russian Federation on taxes and levies, correctness of their calculation, completeness and timeliness of their payment to the budget. The structure of the federal executive bodies is established by the President of Russia and is subject to frequent change. The regional authorities also have certain jurisdiction over the matters of subsoil use.

Regulation of Oil and Gas Production In order to produce oil and (or) gas, a company must obtain a number of licences and permits including, in particular, a subsoil licence, a mining allotment, land use permits, operating licences and a favorable environmental assessment.

Subsoil Licensing Procedure The licensing regime for use of subsoil for geological research, exploration and production of mineral resources is established primarily by the Subsoil Law. Pursuant to the Subsoil Law, the subsoil is considered the property of the state and can be used only upon grant of a subsoil licence. Natural resources extracted from the subsoil become property of the subsoil user upon extraction. There are several types of licences granted in relation to exploration, development and production of natural resources, including: * licences for geological exploration and assessment within the licenced area (which is defined in terms of latitude, longitude and depth) (‘‘Exploration Licences’’); * licences for the development and production of natural resources within the licenced area (‘‘Production Licences’’); and * combined licences for the exploration, assessment, development and production of natural resources within the licenced area (‘‘Combined Licences’’). Until January 2000, when important amendments to the Subsoil Law were introduced, Exploration Licences were typically granted for up to five years, while Production Licences were granted for up to 20 years and Combined Licences were granted for up to 25 years. Under the Subsoil Law, as currently in effect, the maximum term of an Exploration Licence generally remains five years (the term is ten years if geological survey works are carried out on subsoil plots located within internal sea waters, territorial sea and the continental shelf of the Russian Federation), and a Production Licence may be issued for the useful life of the mineral reserves field, calculated on the basis of a feasibility study for exploration and production that ensures rational use and protection of the subsoil. Besides, there is no longer any express term for combined geological survey/exploration and production in the Subsoil Law. Most of the subsoil licences are issued by tender or auction. The tenders or auctions for licences with respect to the subsoil deposits other than strategic deposits are conducted by special tender or auction commissions which should include both representatives of the state authorities concerned and specialists in the area of subsoil use. While such auction or tender commission may include a representative of the relevant region, such representative has no veto right and, therefore, issuance of subsoil licences is not conditional upon the formal consent of regional authorities. The tender commission selects the winner based on several factors, including the technical quality of the exploration and/or production programme, potential contribution to the social and economic development of the region and impact on the environment. In limited circumstances, Production Licences may also be issued without an auction or tender: for instance, to holders of Exploration Licences that discover natural resource deposits through exploration work at their own expense. The Subsoil Law also provides that a subsoil licencee may request the federal authority to extend its Production Licence, if the extension is necessary to finish production in the field or to vacate the field once its use is complete provided that the licence holder’s field development program has been approved in accordance with proper procedure and the licence holder has not violated the terms of its licence. The Group believes that its existing production licences will be extended at or prior to their scheduled expiration. See ‘‘Risk Factors – The Group’s subsoil licences may be suspended or revoked prior to their expiration and the Group may be unable to obtain or maintain various licences, permits or authorisations’’.

176 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA Licences cannot be sold or transferred to another entity except in certain limited circumstances specified by the Subsoil Law. They include, among other things, (i) reorganisation or liquidation of the former licence holder, (ii) transfer to a newly formed company by its founder who holds a 50% or more share in the charter capital of the newly formed company; (iii) transfer from a parent company to its subsidiary, (iv) transfer from a subsidiary to its parent company, and (v) transfer between two subsidiaries of a common parent company where such transfer is effected at the direction of such parent company. Moreover, the transfer is possible only if the transferee possesses all the property and authorisations necessary to carry out the licenced activity.

Subsoil Plots of Federal Importance In May 2008, the Subsoil Law was amended to provide a list of criteria for determining subsoil plots of federal importance and define grounds for establishment and termination of rights to use subsoil plots of federal importance. The criteria distinguishing subsoil plots of federal importance include the following: * containing recoverable oil reserves of 70 million tonnes or more and (or) gas reserves of 50 million cubic metres or more, as evidenced by the State Register of Reserves, as at 1 January 2006; * located in internal sea waters, territorial sea waters or on the continental shelf of the Russian Federation; or * that can only be developed using land designated for defence and security purposes. According to Federal Law No. 323-FZ dated 30 December 2012 ‘‘On Amendments to the Subsoil Law and Certain Other Legislative Acts of the Russian Federation’’ effective from 11 January 2013, licences for the right to use subsoil plots of federal importance are granted only on the basis of an auction. In an auction, the bidder who submits the highest price wins. Prior to this legislative amendment, licences for subsoil plots of federal importance could also be granted on the basis of a tender where the criteria of a winning bid are not limited to the highest price, but can include e.g. technical competency and environmental soundness of a bid. The subsoil in the subsoil areas of federal importance located in the continental shelf of the Russian Federation, and in the subsoil areas of federal significance located in the territory of the Russian Federation and partially located in its continental shelf, may be used by legal entities, which are organised under the laws of the Russian Federation, have at least five years of experience in the development of subsoil areas located in the continental shelf of the Russian Federation and in which the Russian Federation holds an equity or voting interest of more than 50%. The Subsoil Law prohibits the transfer of a subsoil area of federal importance to any entity in which a foreign investor has the ability to (i) directly or indirectly control 10% or more of its voting shares, (ii) control its management by contract or otherwise, or (iii) appoint its chief executive officer or more than 10% of its executive officers or members of its board of directors or other management committee. Such transfer is only permitted in limited circumstances pursuant to a decision of the Russian Government. As of the date of this Prospectus, the Group does not operate any subsoil plots classified as subsoil plots of federal importance, however, the risk of future discovery of such deposits at one of the Group’s current oil and (or) gas fields or acquisition of such deposits cannot be excluded. In case of acquisitions of new oil and (or) gas fields classified as subsoil plots of federal importance, the Group may be required to obtain the prior consent of the Russian Government. See ‘‘Risk Factors – Risks Relating to the Group and the Oil and Gas Industry – The Foreign Strategic Investments Law may affect the Group’s ability to undertake future acquisitions or access equity capital markets’’.

Maintenance and Termination of a Subsoil Licence A licence granted under the Subsoil Law is generally accompanied by a licensing agreement. There are typically three parties to any subsoil licensing agreement: the regional authority of the region where the licence area is located, the federal authorities and the licencee. The licensing agreement sets forth the terms and conditions for the use of the subsoil licence, including: * certain environmental, safety and production commitments; * annual extraction targets; * agreed drilling and other exploratory and development activities; * the provision of geological information and data to the relevant authorities;

177 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA * regular submission of progress reports to regional authorities; and * tax commitments. Governmental authorities may undertake periodic reviews for ensuring compliance by subsoil licence users with the terms of their licences and applicable legislation. If the licence holder fails to fulfill the licence conditions, upon notice, the licence may be terminated by the governmental authorities that issued the licence. However, if a licence holder cannot meet certain deadlines or achieve certain volumes of exploration work or production output as set forth in the licence due to material changes in circumstances, it may move to amend the relevant licence conditions. The circumstances under which a licencee can be fined for failing to comply with the subsoil production licence and the subsoil production licence can be revoked, include the following: * breach or violation by the licencee of material terms and conditions of the licence; * repeated and systematic violation by the licencee of the established subsoil use rules; * failure by the licencee to commence operations within a required period of time and at required levels, both as specified in the licence; * occurrence of an emergency situation; * upon the emergence of a direct threat to the life or health of people working or residing in the area affected by operations conducted under the licence; * liquidation of the licencee; and * failure to submit data reports, as required by law, or submission of false information. The Group has received notices from regional authorities that have alleged areas of non-compliance with the terms of the Group’s licences, such as the failure to perform scheduled drilling and geological exploration activities and violations of ecological standards established by local ordinances. In response to such notices, the Group has engaged the authorities in negotiations over the timing and focus of certain investments and activities in an effort to remedy any such non-compliance. However, the Group cannot assure you that one or more of its licences will not be revoked, suspended or limited, notwithstanding the remedial actions the Group has taken or proposes to take in the future. Any such revocation, suspension or limitation of the Group’s rights under its licences may result in a reduction in the size of the Group’s reserves and/or have a material adverse effect on the Group’s business, financial condition, results of operations and prospects and, therefore, the Issuer’s ability to meet its obligations under the Notes and the Guarantors’ ability to meet their obligations under the Guarantees. See ‘‘Risk Factors – The Group’s subsoil licences may be suspended or revoked prior to their expiration and the Group may be unable to obtain or maintain various licences, permits or authorisations’’. When a licence expires, the licencee must return the land to a condition which is adequate for future use. Although most of the conditions set out in a licence are based on mandatory rules contained in Russian legislation, certain provisions in a licensing agreement leave room for discretion of the licensing authorities and are often negotiated between the parties. Nevertheless, commitments relating to safety and environment are generally not negotiated. If the licence holder does not agree with a decision of the licensing authorities, including a decision to revoke a licence or refusal to re-issue an existing licence, the licencee may appeal the decision through administrative or judicial proceedings. In certain cases, the licencee has right to attempt to cure the breaches of licence conditions within three months of being notified of the breaches. If the licencee manages to cure its violations within this term, no licence revokation or other administrative action may be taken.

Land Use Pursuant to the Subsoil Law, subsoil licences are issued subject to the land resources management authorities’ preliminary consent to the allotment of a land plot covering the surface of the licence area. The boundaries of the land plot are determined upon approval of a development plan based on an agreement between the owner of the land plot and the subsoil user. Russian legislation prohibits any commercial activity, including mineral extraction activities, on a land plot without appropriate land use rights. Under the Land Code of the Russian Federation No. 136-FZ, dated 25 October 2001, as amended (the ‘‘Land Code’’), companies may have one of the following rights with regard to land in the

178 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA Russian Federation: (i) ownership; (ii) lease; (iii) right of free use for a fixed term; or (iv) right of perpetual use. However, rights of free use for a fixed term are now less common, and those companies that have obtained a right of perpetual use over land prior to the enactment of the Land Code were required, by 1 July 2012, either to purchase the land from, or to enter into a land lease agreement with, the relevant federal, regional or municipal authority owning the land. Those companies that have a right of perpetual use over land containing linear facilities (such as power transmission lines, communication lines, pipelines, railway lines, etc.) may either purchase such land or enter into a land lease agreement by 1 January 2015. Most land in the Russian Federation is owned by federal, regional or municipal authorities, which can sell, lease or grant other use rights to the land to third parties through public auctions or tenders or private negotiations. Under the Land Code, land that is owned by state or municipal authorities and is required for subsoil use is leased to subsoil users without holding an auction or a tender. Surface rights are typically granted for specified areas, upon the submission of standardised reports, technical studies, pre-feasibility studies, budgets and impact statements. Documents that grant surface rights generally require that the holder make lease payments and return the land plot to a condition sufficient for future use, at the licence holder’s expense, upon the expiry of the permit.

Mining Allotment Pursuant to the Subsoil Law, a subsoil area is provided to a subsoil user as a ‘‘mining allotment,’’ i.e. a geometric block of subsoil. Preliminary mining allotment boundaries are determined at the time the licence is issued. Exact mining allotment boundaries are established upon preparation of a development plan and its approval by state mining supervision authorities and an environmental examination committee and are certified in a mining allotment act issued to the licence holder. Currently, Rostekhnadzor has authority to approve development plans.

Payments for Subsoil Use The Subsoil Law provides for the following types of payments related to the use of subsoil: * one-off payments in the circumstances specified in the licence; * regular payments for subsoil use, such as rent payments for the right to conduct prospecting, appraising and exploration work; and * fees for the right to participate in tenders and auctions. The rates for such payments are generally set forth in the relevant licence by the federal authorities within a range of minimum and maximum rates established by the Subsoil Law. Fees for geological information on subsoil resources were abolished as at 1 January 2011. In addition, subsoil users pay other taxes and tariffs as established by legislation of the Russian Federation.

Operational Licences Certain types of activity that are inherent to the production, storage, transportation, processing and sale of gas remain subject to licensing requirements. These types of activity may include, inter alia, the operation of fire-hazardous facilities and assembly and maintenance of fire-prevention devices. Most operational licences are issued by Rostekhnadzor. Such licences are issued for a minimum term of five years. In addition to other documents, to receive the licence, the applicant must provide evidence that it meets the operational licence requirements, which include, inter alia, availability of qualified personnel and equipment required for operations, as well as adequate environmental, health and safety measures. In addition, all equipment used at the oil and gas extracting facilities must be certified by Rostekhnadzor for such use.

Technical Regulation of Petroleum products Technical regulation governing the safety, quality and other requirements, including environmental requirements, for petroleum products in the Russian Federation is primarily established by Federal Law No. 184-FZ ‘‘On Technical Regulation’’, dated 27 December 2002, as amended (the ‘‘Technical Regulation Law’’). The Technical Regulation Law sets forth a system of technical regulations, standards, certification and standardisation procedures. Pursuant to the Technical Regulation Law, depending on the nature of the regulated good, regulations may be adopted in the form of mandatory standards, which set forth minimal requirements for, among other things, radiation, biological, explosive and industrial safety or

179 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA voluntary standards, which are national standards adopted in part to enhance the safety and marketability of goods and improve compliance with technical regulations. On 18 October 2011, the Customs Union by its decision No. 826 adopted the Technical Regulation ‘‘On Requirements for Motor and Aviation Gasoline, Diesel and Ship Fuel, Aviation Fuel and Fuel Oil,’’ which came into effect on 31 December 2012 (the ‘‘Customs Union Regulations’’) and replaced the Technical Regulation ‘‘On Specifications of Motor and Aviation Gasoline, Diesel and Ship Fuel, Aviation Fuel and Fuel Oil’’ adopted by the Russian Government on 27 February 2008. The Customs Union Regulations set forth obligatory requirements to motor and aviation gasoline, diesel and ship fuel, aviation fuel and fuel oil which are to be released into the common customs area of the Customs Union.

Health and Safety The principal laws regulating industrial safety are the following: the Federal Law No. 116-FZ ‘‘On Industrial Safety of Dangerous Industrial Facilities’’, dated 21 July 1997, as amended (the ‘‘Safety Law’’); the Technical Regulation No. 123-FZ ‘‘On Fire Safety Requirements,’’ dated 22 July 2008, as amended; and the Federal Law No. 256-FZ ‘‘On the Safety of Fuel and Energy Facilities’’, dated 21 July 2011 (the ‘‘Facilities’ Safety Law’’). The Safety Law applies, in particular, to industrial facilities and sites where certain activities are carried out with respect to the usage, production, processing, storage, transportation or utilisation of fuels and explosive, toxic and environmentally dangerous substances. The Safety Law also contains a list of dangerous substances and in case of critical concentration of these dangerous substances at the industrial facility or site, a company is obliged to adopt an industrial safety declaration. The Facilities’ Safety Law applies to facilities in the power, oil producing, refining, petrochemical, gas supply and other fuel and energy industries, with the exception of nuclear energy facilities. The Facilities’ Safety Law requires, among other things, that owners of a fuel and energy facility maintain safety logs of the facility and prevent and mitigate the effect of unlawful acts that threaten safety at the facility. It also sets forth a list of requirements related to the ownership of such facilities. For example, facilities considered to be highly hazardous can only be owned by Russian entities and may not be leased without prior approval of the authorities. The Group’s activities also include the operation of certain hazardous industrial sites registered with and regulated by Rostekhnadzor. Any construction, exploitation, liquidation or other activities in relation to such hazardous industrial sites and hazardous industrial equipment is subject to Rostekhnadzor’s oversight. Companies that operate regulated industrial sites have a wide range of obligations under the Safety Law and the Labour Code of the Russian Federation No. 197-FZ of 30 December 2001, as amended (the ‘‘Labour Code’’). In particular, they must limit access to such sites to qualified specialists, maintain industrial safety controls and carry mandatory civil liability insurance for damage resulting from accidents. The Safety Law also requires these companies to enter into contracts with professional accident-rescue service companies or create their own accident-rescue services in certain cases, conduct personnel training programmes, create systems to cope with and inform Rostekhnadzor of accidents and maintain these systems in good working order. In certain cases, companies operating regulated industrial sites must also prepare declarations of industrial safety that summarise the risks associated with operating such sites and the measures the company has taken and will take to mitigate such risks. Such declarations must be adopted by the chief executive officer of the company, who is personally responsible for the completeness and accuracy of the data contained therein. Both an industrial safety declaration and an industrial safety expert review are required for the issuance of a licence permitting the operation of a dangerous industrial facility. In the case of an accident, a special commission led by a representative of Rostekhnadzor conducts a technical investigation of the cause. The company operating the industrial facility where the accident took place bears all costs of such investigation. Rostekhnadzor has the right to access industrial sites and may inspect documents to ensure a company’s compliance with safety rules. Rostekhnadzor may also impose administrative liability on a company or its officials, as well as suspend a company’s operations. Any company or individual violating industrial safety rules may incur administrative and/or civil liability and individuals may also incur criminal liability. A company that violates safety rules in a way that negatively impacts the health of an individual may also be liable to compensate the individual for lost earnings and health-related damages and, in certain cases, its activity may be suspended.

180 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA Environmental Protection Russian environmental legislation, including, in particular, the Federal Law No. 7-FZ ‘‘On Environmental Protection,’’ dated 10 January 2002, as amended (the ‘‘Environmental Protection Law’’) establishes a pay-to-pollute regime administered by federal and local authorities. The Ministry of Natural Resources establishes standards relating to resource extraction and its permissible impact on the environment, while Rosprirodnadzor sets forth limits on emissions and disposal of substances and waste. A company may obtain approval for exceeding these statutory limits from federal or regional authorities, depending on the type and scale of the environmental impact. To be granted such approval, the company must develop a plan for the reduction of emissions or disposals and clear it with the appropriate governmental authority. Fees, as set forth in the Decree of the Russian Government No. 344 ‘‘On Rates of Payments for Pollutant Emissions into the Air by Stationary and Mobile Sources, Pollutant Disposals into Surface and Underground Waters, Disposal of Production and Consumption Waste’’ dated 12 June 2003, as amended, are assessed on a sliding scale for both the statutory and individually approved limits on emissions and effluents and for pollution in excess of these limits, whereby the lowest fees are imposed for pollution within the statutory limits, higher fees are imposed for pollution within the individually approved limits and the highest fees are imposed for pollution exceeding such limits. Payments of such fees do not relieve a company from its responsibility to take environmental protection measures and undertake restoration and clean-up activities. Subsoil licences generally require certain environmental commitments. Although the commitments may be stringent in a particular licence, the penalties for failing to comply with such commitments are generally low and clean-up requirements are generally insignificant. Natural resource development matters are subject to periodic environmental evaluation. While in the past these evaluations generally have not resulted in substantial limitations on natural resource exploration and development activities, they are expected to become increasingly strict in the future. In addition, Federal Law No. 99-FZ ‘‘On Licensing of Certain Types of Activities’’, dated 4 May 2011, as amended, Federal Law No. 96-FZ ‘‘On Protection of the Atmospheric Air’’, dated 4 May 1999, as amended, Federal Law No. 89-FZ ‘‘On Industrial and Consumption Waste’’, dated 24 June 1998, as amended, and other laws and regulations on environmental protection collectively list activities that can only be performed subject to a special permit or licence issued by the relevant Russian authorities and establish the procedures for issuing such licences and permits. In particular, to conduct its operations, a company may be required to hold the following licences and permits: * permit for emissions of harmful substances into the atmosphere; * permit for the discharge of polluting substances into bodies of water; * licence for the collection, use, neutralization, transportation or placement of hazardous waste; * permit approving limits for disposal of production and consumption waste; * licence for operation of explosive/inflammable or chemically hazardous industrial facilities; and * licence for fire extinguishing. Furthermore, an ecological expert review (‘‘EER’’) must be conducted prior to the implementation of any project that could result in environmental harm. EERs are carried out by a commission appointed by Rostekhnadzor or by the competent regional authority, depending on the nature of the project. If a company does not obtain an EER approving the relevant project, its implementation will be prohibited. The Group has received, and anticipates receiving in the future, notices and meeting minutes from regional authorities that allege that the Group has violated certain environmental regulations. The Group has worked and will continue to work with each of these authorities to address such allegations. The Subsoil Law also provides that a subsoil licence must include a provision establishing the procedure for the restoration of the site and recultivation of the land plot upon termination of the subsoil licence. This procedure generally requires the licencee to submit, for the approval of regional authorities, a proposed plan detailing the timeframe and actions the licencee will undertake to restore the site and recultivate the land plot. Additional requirements in respect of restoration of the environment, recultivation of land and compensation of damage to the environment are prescribed by the Environmental Protection Law.

181 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA Gas Flaring Operations The Group is currently flaring a portion of the gas produced in its fields, for which the Group is subject to insignificant state-imposed charges for excess gas flared. These charges are levied in accordance with regulations of the Ministry of Natural Resources and regulations of the Russian Government. Limitations on gas flaring may be established in the Group’s licences. On 8 November 2012, the Russian Government issued Resolution No. 1148 ‘‘On the Particularities of Calculating Payments for Emissions of Polluting Substances Arising in the Process of Burning on Flare Units and (or) Dissipating of Associated Gas’’, effective from 1 January 2013 (‘‘Resolution No. 1148’’), according to which no more than 5% of associated gas produced may be flared. Resolution No. 1148 provides that the 5% threshold does not apply to fields where the depletion of oil reserves does not exceed 0.01, and until the earlier of either: (i) the depletion of oil reserves has exceeded 0.01 for three years, or (ii) the depletion of oil reserves amounts to 0.05. Any associated gas flared in excess of the limits prescribed by Resolution No. 1148 will result in a 12-time increase in emission charges in 2013, and a 25-time increase starting in 2014. However, the increased emission charges do not apply if the annual volume of associated gas does not exceed five million cubic metres, or if the extracted associated gas contains more than 50% of non-hydrocarbon components. Also, should a subsoil user fail to maintain a proper system of accounting for associated gas volumes, the subsoil user will be subject to a 120- time increase in emission fees.

Transportation Crude Oil and Petroleum products Transportation Crude oil and petroleum products are transported by means that include pipeline – and railway transportation.

Pipeline Transport Transneft and its subsidiary Transnefteproduct control the trunk pipelines for the transportation of crude oil and petroleum products in Russia, respectively. Both companies are state-controlled monopolies. Access to Transneft’s pipeline system is regulated by the Natural Monopolies Law and the Resolution of the Russian Government No. 218 dated 29 March 2011 (‘‘Resolution No. 218’’), which approves the rules for securing non-discriminatory access to Transneft’s pipeline network. Crude oil is transported pursuant to transportation services agreements, which are concluded with the applicable pipeline operator on an annual basis. A transportation service agreement sets forth, inter alia, the procedure for accepting, transporting and transferring crude oil, the quality and quantity of crude oil to be delivered, delivery and destination points, payment procedures and other rights and obligations of the parties. According to Resolution No. 218, in case of insufficient pipeline capacity, the pipeline operator shall prioritise domestic deliveries over export deliveries. The Ministry of Energy allocates Transneft pipeline network and sea terminal capacity to oil producers for export deliveries on a quarterly basis, generally in proportion to: * the volume of crude oil that such producers declare they will deliver in the upcoming quarter; * the volume of crude oil that such producers delivered to the Transneft pipeline system in the previous quarter; and * Transneft’s overall capacity. Following this rule, a Russian oil company is usually given an allocation for export that equals approximately 40% of its crude oil produced and delivered in the previous quarter. Once the access rights are allocated, oil producers generally cannot increase their allotted capacity in the export pipeline system, although they have limited flexibility in altering delivery routes. Oil producers are generally allowed to assign their access rights to others. Deliveries through Transnefteproduct are based on the applications of oil companies in proportion to the Transnefteproduct pipeline capacity. The FST sets the tariffs for the use of Transneft and Transnefteproduct pipelines. Transneft has very limited ability to transport individual batches of crude oil, which results in the blending of crude oil of differing qualities. Transneft does not currently operate a ‘‘quality bank’’ system. Under a quality bank system, oil companies that supply heavy and sour (with high sulphur content) crude oil to the system pay more for the use of pipelines than those who supply higher- quality (lighter) crude oil. (Alternatively, suppliers of lower-quality crude oil might directly

182 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA compensate suppliers of higher-quality crude oil for the deterioration in crude quality due to blending.) Although Transneft and the Russian Government have for several years been discussing the introduction of a quality bank for the Transneft system, such proposals are generally met with aggressive resistance by producers with lower-quality reserves, as well as regional authorities where such reserves are located. Railway Transport The Group relies on railway transportation to deliver its petroleum products to end-users, as well as to provide crude oil to its Khabarovsk Refinery. The State-owned monopoly Russian Railways provides railway transportation services and is a major owner of rolling stock. Railway tariffs are set by the FTS on an annual or semi-annual basis and are indexed to account for certain factors, such as inflation. Tariffs are denominated in Rubles and take into consideration certain factors, such as the type of product being transported, the distance of transportation and the delivery volume. Railway transport in the Russian Federation is regulated by the Federal Law No. 17-FZ ‘‘On Railway Transport in the Russian Federation’’ dated 10 January 2003, as amended, the Federal Law No. 18-FZ ‘‘Railway Transport Charter’’ dated 10 January 2003, as amended, and regulatory acts of the Russian Government. The Russian Federation is also a party to the Convention Concerning International Carriage by Rail of 9 May 1980 and the Agreement on the International Transport of Goods by Rail of 1 November 1951.

Natural Gas Supply and Transportation The Unified Gas Supply System The Gas Supply Law defines the Unified Gas Supply System (the ‘‘UGSS’’) as the nation’s centrally managed, technologically and economically regulated system of gas production, processing, transportation, storage and supply. OAO Gazprom is currently the owner of the UGSS. To ensure reliable gas supply and compliance with international treaties of the Russian Federation and gas delivery contracts, OAO Gazprom, as the owner of the UGSS, is obliged to: maintain and develop the UGSS network; monitor the function of its facilities; procure the use of equipment and process for energy efficiency and environmental safety for the UGSS; take action to ensure industrial and ecological safety within the UGSS; and operate disaster management systems. In accordance with Government Resolution No. 858 ‘‘On Provision of Access of Independent Companies to the Gas Transportation System of OAO Gazprom’’, dated 14 July 1997, OAO Gazprom, as the owner of the UGSS, is obligated to provide independent gas producers access to its natural gas transportation system in Russia subject to the availability of capacity in the UGSS, the compliance of the gas being transported with established quality and technical parametres and the availability of connecting and branch pipelines to end customers. Similar access rights to regional gas supply systems are established pursuant to Government Resolution No. 1370 ‘‘On Approval of Regulation on Ensuring Access of Organisations to Local Gas Supply Systems’’, dated 24 November 1998. According to this Resolution, any legal entity within the territory of the Russian Federation has the right of non-discriminatory access to the regional gas supply systems for transportation of gas to customers. Government Resolution No. 872 dated 29 October 2010 established the standards for disclosure of information by OAO Gazprom as operator of the UGSS. Transportation and Supply of Gas The relationship between natural gas suppliers and off-takers is governed by the Regulation on Natural Gas Supplies in the Russian Federation approved by Government Resolution No. 162 ‘‘On Approval of Rules of Gas Supplies in the Russian Federation’’, dated 5 February 1998, as amended. A right of priority to enter into natural gas supply agreements is given to off-takers that purchase natural gas for state needs and municipal/domestic services and to certain off-takers wishing to extend their existing natural gas supply agreements. In accordance with the Gas Supply Law, consumers are obliged to pay for natural gas supplies and transportation services. If consumers fail to make such payments, suppliers have the right to limit or suspend natural gas supplies to such consumers in accordance with specific procedures provided for by several Government resolutions (although the Government has issued resolutions regulating the restriction or suspension of suppliers to certain customers, such as military institutions and fire prevention services).

183 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA Export of Gas Pursuant to the Gas Export Law, OAO Gazprom, as the owner of the UGSS, or its wholly owned subsidiary, OOO Gazprom Export has the exclusive right to export gas outside the Russian Federation. The law covers the export of gas both in gaseous form and in the form of liquefied natural gas (LNG). The law does not apply to the export of gas produced in accordance with production sharing agreements that were entered into prior to the entry into force of this law.

Gas Prices and Tariffs Natural gas prices and transportation tariffs in Russia are regulated pursuant to the Natural Monopolies Law and the Gas Supply Law, as well as pursuant to several Government resolutions. Government Resolution No. 1021 ‘‘On State Regulation of Gas Prices and Tariffs for Gas Transportation within the Territory of the Russian Federation’’, dated 29 December 2000, as amended, sets forth the main provisions for regulating the wholesale price of natural gas and transportation tariffs. FTS regulates (i) the price of gas extracted by OAO Gazprom and its affiliates (including any entity in which it has 20% or more equity ownership) – but not the wholesale price of natural gas produced by independent gas suppliers – and (ii) the tariff charged to independent gas producers to transport their gas through the UGSS. The principles of pricing include the recovery of economically reasonable expenses by suppliers and transportation companies, maintenance of reasonable operating margins and satisfaction of the demand for gas.

Production Sharing Agreements The PSA Law sets forth general principles for investment in the exploration and production of minerals on a ‘‘production sharing’’ basis. A production sharing agreement is a contract between the Russian Government and an investor in which the investor agrees to bear the costs and risks of exploration and production of a mineral resource and the parties agree predetermined shares of the output. The PSA Law governs petroleum operations carried out pursuant to PSAs. It came into force in January 1996 and established the principal legal framework for state regulation of PSAs relating to oil and gas field development and production. Under the PSA Law, the Russian Federation is represented (in its relations with investors under PSAs) by the Government or the state bodies authorised by it. The PSA Law contains stabilisation rules purporting to protect investors against adverse changes in federal and regional laws and regulations, including certain uncertainties in tax laws and regulations. The PSA Law provides that operations conducted under a PSA pursuant to the PSA Law will be governed by the PSA itself and will not be affected by contrary provisions of any other laws, including the Subsoil Law. Since the PSA Law was enacted, the legislature has approved a number of oil and gas fields as eligible for production sharing agreements. Currently, none of these fields are subject to effective production sharing agreements. The Group does not currently participate in a PSA in Russia.

Continental Shelf and the Exclusive Economic Zone Offshore hydrocarbon operations in areas on the continental shelf (generally within a 200 nautical mile limit) are separately governed by the Continental Shelf Law. Activities that take place on the continental shelf, including the drilling and laying of pipelines and the operation of oil and gas extraction facilities, fall under the jurisdiction of not only the Ministry of Natural Resources, but also several other governmental entities. The Group does not currently perform activities governed by the Continental Shelf Law.

Antimonopoly and Related Regulation Antimonopoly Approval of Certain Transactions The antimonopoly regulation of the Russian Federation is based on the Competition Law and other federal laws and regulations governing antimonopoly issues. Antimonopoly regulation of the Russian Federation is aimed at the prevention and termination of monopolistic activity and control over economic concentration and governs relations that involve, among others, Russian legal entities, foreign legal entities, state agencies of the Russian Federation and local government authorities. Antimonopoly restrictions include prohibitions on the conclusion of

184 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA anti-competitive agreements, the exercise of anti-competitive coordinated actions, acts resulting in unfair competition and the abuse of a dominant position. Compliance with antimonopoly legislation in the Russian Federation is monitored by the FAS. Russian legislation grants the FAS the powers necessary for the performance of its functions and for dealing with violations of antimonopoly legislation. The FAS is, among other things, authorised: (i) to initiate or examine cases regarding the violation of antimonopoly legislation; (ii) to issue binding orders to business entities in cases specified in the Competition Law; (iii) to hold commercial and non-commercial organizations and their officers to account for violating antimonopoly laws in the instances and by the procedure established by Russian legislation; and (iv) to file with a court or an arbitration court applications in respect of violations of antimonopoly laws, including, among other things, invalidating in full or in part any agreements that do not comply with antimonopoly legislation. (i) The Competition Law provides for antimonopoly control over economic concentration and requires prior approval by the FAS of the following transactions: * acquisition by a person (or its group) of more than 25%, 50%, or 75% of the voting shares of a Russian joint stock company (or more than 1/3, 1/2 or 2/3 participation interest in a Russian limited liability company); * acquisition by a person (or its group) of the core production assets (with certain exceptions) located in the territory of the Russian Federation and/or intangible assets of an entity if the balance sheet value of such assets exceeds 20% of the total balance sheet value of the core production and/or intangible assets of such entity, as applicable; * obtaining rights to determine the business activity of a Russian entity or to exercise the powers of its executive body by a person (or its group); or * acquisition by a person (or its group) of more than 50% of the voting shares (participation interest) of a foreign legal entity or obtaining other rights to determine its business activity or to exercise the powers of its executive body. in each case, if any of the following thresholds are met: * the aggregate asset value of the acquirer (or its group) together with the target (or its group) exceeds RUB 7 billion; * the total annual revenues of the acquirer (or its group) and the target (or its group) for the preceding calendar year exceed RUB 10 billion and the total asset value of the target (or its group) exceeds RUB 250 million; or * the acquirer and/or the target and/or any entity within the acquirer’s group or the target’s group are included in the register of entities having a market share in excess of 35% on a particular market or having a dominant position on a particular market maintained by the FAS (the ‘‘FAS Register’’). (ii) Furthermore, the Competition Law provides for prior approval by the FAS of the following actions: mergers and consolidations of entities, if any of the following thresholds are met: * the aggregate asset value of such entities (or of the groups of persons to which they belong) exceeds RUB 7 billion; * the total annual revenues of such entities (or of the groups of persons to which they belong) for the preceding calendar year exceed RUB 10 billion; or * one or more of these entities is included in the FAS Register; or formation of an entity, if any the following thresholds are met: * its charter capital is paid by the shares (or participation interest) and/or the assets of another entity (save for monetary funds) or the newly founded entity acquires the rights in respect of such shares (or participation interest) and/or assets as specified in the Competition Law, provided that the aggregate asset value of the founders (or group of persons to which they belong) and the newly founded entity (or groups of persons to which they belong) exceeds RUB 7 billion;

185 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA * the total annual revenues of the founders (or group of persons to which they belong) and the newly founded entity (or groups of persons to which they belong) for the preceding calendar year exceed RUB 10 billion; or * the entity, the shares (or participation interest) and/or assets of which are contributed to the charter capital of the newly founded entity, is included in the FAS Register. The Competition Law provides for a mandatory post-transaction notification (within 45 days of the closing) of the antimonopoly authorities in connection with actions specified in item (i) above if the aggregate asset value or total annual revenues of an acquirer (and its group) and a target (and its group) for the preceding calendar year exceed RUB 400 million and at the same time the total asset value of the target (and its group) exceeds RUB 60 million; and in connection with actions specified in item (ii) above if their aggregate asset value or total annual revenues of the relevant companies for the preceding calendar year exceed RUB 400 million. In March 2013, the State Duma adopted in the first reading a draft law amending the Competition Law, which, if enacted, will eliminate the above post-transaction notification requirement. The Competition Law expressly provides for extraterritorial application to transactions which are made outside of the Russian Federation but lead, or may lead, to the restriction of competition in the Russian Federation and which relate to assets located in the Russian Federation or to the shares (or participation interests) in Russian companies or rights in relation to such companies. Under the Competition Law, if an acquirer has acted in violation of the merger control rules and acquired, for example, shares without obtaining the prior approval of the FAS, the transaction may be invalidated by a court order initiated by the FAS, provided that such transaction has led or may lead to the restriction of competition, for example, by means of strengthening of a dominant position in the relevant market. More generally, Russian legislation provides for civil, administrative and criminal liability for the violation of antimonopoly legislation.

Regulation of Dominant Position in a Particular Market The antimonopoly regulation is aimed at the prevention of the abuse of a dominant position. According to the Competition Law, an entity or a group of entities is deemed to have a dominant position in a particular commodity market if: (a) the entity (or the group of entities) has a market share in a particular commodity market in excess of 50%, unless it is specifically established by the FAS that the entity (or the group of entities) does not have a dominant position; (b) the entity has a market share in a particular commodity market which is less than 50% but more than 35% and the dominant position of the entity (or the group of entities) is specifically established by FAS based on (i) the stability or near stability of such entity’s (or such group of entities’) share in the particular commodity market, and (ii) certain characteristics of the relevant commodity market (such as the accessibility of the commodity market to new competitors); or (c) even if the entity has a market share of less than 35% in certain specific circumstances. The Competition Law also provides the possibility of several unrelated entities being considered to collectively have a dominant position. In particular, each of three business entities collectively having a market share exceeding 50%, or each of five business entities collectively having a market share exceeding 70%, provided that the market share of each entity in any case is not less than 8%, may be considered as having a dominant position provided that: (i) market shares of relevant entities have been stable or nearly stable during a significant period of time; (ii) the access of new competitors into the particular commodity market is hindered; (iii) the relevant commodity cannot be easily substituted; and (iv) the increase of the price for the commodity does not lead to decrease of demand for it. The Competition Law establishes a regulatory framework for companies having dominant positions in certain markets, aimed at protection of competition in the relevant markets. In particular, an entity having a dominant position is prohibited from abusing such a position through, among others, the following activities: (i) fixing and/or maintaining a monopolistic high or low price of goods; (ii) withdrawing goods from circulation, which results in price increases; (iii) dictating to a counterparty the terms of an agreement unfavourable to it or not relevant to the subject-matter of the agreement; (iv) economically or technologically unjustified reduction or termination of the production of certain goods; (v) economically or technologically unjustified refusal to enter into an agreement with certain buyers (customers) or avoiding such agreement; (vi) economically or technologically unjustified fixing of various prices (tariffs) for the same goods; (vii) creating discriminatory conditions; (viii) creating

186 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA impediments for other entities to either access or exit a particular commodity market; and (ix) violation of established pricing rules. If a company having a dominant position systematically carries out any monopolistic activities a court, based on a claim brought by the FAS, may decide that such company is subject to forcible division or spin-off. In addition, the FAS is authorised to issue binding orders to stop abuse of a dominant market position and to transfer to the federal budget profits obtained as a result of abusing a dominant position. Certain subsidiaries of the Group have been included in a special public register as entities potentially having a dominant position in their market sector, which makes them subject to relevant provisions of the Competition Law. See ‘‘Risk Factors – Risks Relating to the Russian Legal System and Russian Legislation – If FAS were to conclude that the Group has conducted its business in contravention of antimonopoly legislation, it could impose administrative sanctions on the Group’’.

187 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA TAXATION

The following is a general description of certain tax considerations relating to the Notes and does not purport to be a comprehensive discussion of the tax treatment of the Notes. Prospective purchasers of the Notes are advised to consult their own tax advisers as to the consequences arising in their particular circumstances under the tax laws of countries of which they are residents of a purchase and holding of Notes, including, but not limited to, the consequences of the receipt of interest and the sale or redemption of Notes. This summary is based upon the law as in effect on the date of this Prospectus. The information and analysis contained within this section are limited to tax issues, and prospective investors should not apply any information or analysis set out below to other areas, including (but not limited to) the legality of transactions involving the Notes .

Russian Taxation The following is an overview of certain Russian tax considerations relevant to payments under the Guarantee. The overview is based on the laws of the Russian Federation in effect on the date of this Prospectus, which are subject to potential change (possibly with retroactive effect). The overview does not seek to address the applicability of, and procedures in relation to, taxes levied by regions, municipalities or other non-federal authorities of the Russian Federation. Nor does the overview seek to address the availability of double tax treaty relief in respect of the Notes, and it should be noted that there may be practical difficulties, including satisfying certain documentation requirements, involved in claiming double tax treaty relief. Prospective investors should consult their own advisers regarding the tax consequences of investing in the Notes. No representations with respect to the Russian tax consequences of investing, owning or disposing of the Notes to any particular Noteholder is made hereby. The provisions of the Russian Tax Code applicable to Noteholders and transactions involving the Notes are ambiguous and lack interpretive guidance. Both the substantive provisions of the Russian Tax Code applicable to financial instruments and the interpretation and application of those provisions by the Russian tax authorities may be more inconsistent and subject to more rapid and unpredictable change than in jurisdictions with more developed capital markets or more developed taxation systems. In particular, the interpretation and application of such provisions will in practice rest substantially with local tax inspectorates. In practice, interpretation by different tax inspectorates may be inconsistent or contradictory and may constitute the imposition of conditions, requirements or restrictions not provided for by the existing legislation. Similarly, in the absence of binding precedents, court rulings on tax or related matters by different Russian courts relating to the same or similar circumstances may also be inconsistent or contradictory. According to the Russian Tax Code, a tax resident is an individual who spent in Russia not less than 183 days within 12 consecutive months (days of medical treatment and education outside of the Russian Federation are also counted as Russian days if the individual departed from the Russian Federation for these purposes for less than six months). The interpretation of this definition by the Ministry of Finance of the Russian Federation states that for purposes an individual’s status should be determined on the date of income payment (based on the number of Russian days in the 12-month period preceding the date of payment). The individual’s final tax liability in the Russian Federation for the reporting calendar year should be determined based on his/her tax residence status for such calendar year, i.e. based on the number of Russian days in the 12-month period as of the end of such period. For the purposes of this overview, a ‘‘non-resident Noteholder’’ means (i) an individual Noteholder who has not established a Russian tax residence status for the reporting calendar year as discussed above; or (ii) a legal entity or organisation in each case not organised under Russian law that holds and disposes of the Notes otherwise than through a permanent establishment in Russia. For the purposes of this overview, a ‘‘Russian resident Noteholder’’ means (i) an individual Noteholder who has established a Russian tax residence status for the reporting calendar year as discussed above; or (ii) a legal entity or organisation which is a Noteholder but is not qualified a non-resident Noteholder as defined in the previous paragraph.

188 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA Russian withholding tax Non-Resident Noteholders Payments following enforcement of the Guarantee to be made by the Guarantor to the non-resident Noteholder to the extent relating to interest on the Notes are likely to be characterised as Russian source income. Accordingly, such payments should be subject to withholding tax at a rate of 20% in the event that a payment under the Guarantee is made to a non-resident Noteholder that is a legal entity or organisation which in each case is not organised under Russian law and which holds the Notes otherwise than through a permanent establishment in Russia, subject to any available double tax treaty relief. In the event a payment under the Guarantee is made to a non-resident individual Noteholder, such payment should be subject to withholding tax at a rate of 30%, subject to any available double tax treaty relief. The Issuer and the Guarantor cannot offer any assurance that: (i) double tax treaty advance relief or refund of any taxes withheld will be available for a non-resident Noteholder with respect to payments under the Guarantee or (ii) that such withholding tax would not be imposed upon the entire payment under the Guarantee, including with respect to the principal amount of the Notes. The imposition or possibility of imposition of this withholding tax could adversely affect the value of the Notes. If the payments under the Guarantee are subject to any withholding taxes for any reason (as a result of which the Guarantor would reduce the payments to be made under the Guarantee by the amount of such taxes to be withheld), the Guarantor, except in certain circumstances, is required to increase the payments as may be necessary so that the net amounts received in respect of such payments after such withholding or deduction will equal the respective amounts that would have been received in respect of such payments in the absence of such withholding or deduction. It is currently unclear whether the provisions obliging the Guarantor to gross-up payments will be enforceable in the Russian Federation. As indicated above, it is currently unclear whether the provisions obliging the Guarantor to gross-up payments will be enforceable in the Russian Federation. There is a risk that the tax gross-up for withholding tax will not take place and that the full amount of the payments made by the Guarantor will be subject to reduction by the Russian income tax at a rate of 20% (or potentially, 30% in respect of individual Noteholders). Non-resident Noteholders should consult their own tax advisors with respect to the tax consequences of the receipt of payments under the Guarantee, including applicability of any available double tax treaty relief. Resident Noteholders A Russian resident Noteholder is subject to all applicable Russian taxes and responsible for complying with any documentation requirements that may be established by law or practice in respect of payments to be received by such Noteholder under the Guarantee. Resident Noteholders should consult their own tax advisers with respect to the tax consequences of the receipt of payments under the Guarantee.

Russian VAT The applicable Russian tax law does not establish specific rules for VAT treatment of payments under the Guarantee, the additional tax gross-up amounts, as described above, and the payments under Guarantee attributable to compensation of other expenses. Based on the analysis of the general provisions of the Russian tax law, payments under the Guarantee attributable to the principal amount or interest under the Notes and the additional tax gross-up amounts, as described above, should likely not be subject to Russian VAT. In turn, the payments under the Guarantee attributable to compensation of other expenses (if any) could be subject to the Russian VAT based on application of the specific ‘‘place of supply’’ rules established by the applicable Russian tax law. Noteholders should consult their own tax advisers with respect to the Russian VAT consequences of the receipt of payments under the Guarantee.

Tax Treaty Relief Advance Treaty Relief Where the payments under the Guarantee are received from a Russian source, in order for the non- resident Noteholders to receive the benefits of an applicable double tax treaty, documentary evidence is required to confirm the applicability of the double tax treaty for which benefits are claimed.

189 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA Currently, a non-resident Noteholder that is a legal entity or organisation should present to the payer of income an apostilled or legalised confirmation of its tax residence, attaching a notarised translation in Russian. The confirmation should be presented before any payment is made and should be certified by the competent authority of the country of the Noteholder’s tax residence. Such confirmation is valid for the calendar year in which it is issued.

For non-resident individual Noteholders, procedures for advance treaty clearance are not specifically provided for by current Russian legislation. Therefore, from a practical point of view, it is unlikely that for non-resident individual Noteholders an advance reduction of the Russian withholding income tax or advance exemption from such tax provided by a respective double tax treaty between Russia and the country of the tax residence of such non-resident individual Noteholder could be obtained. Non-resident Noteholders should consult their own tax advisers with respect to the possibilities to enjoy any double tax treaty relief or and the relevant Russian procedures.

Refund of Tax Withheld For a non-resident Noteholder which is not an individual and for which double tax treaty relief is available, if Russian withholding tax on income was withheld by the source of payment, a refund of such tax is possible within three years from the end of the tax period in which the tax was withheld. In order to obtain a refund, the tax documentation confirming the right of the non-resident recipient of the income to double tax treaty relief is required. However, there could be no assurance that the refund of any taxes withheld or double tax treaties reliefs (as described above) will be available for such non-resident Noteholders which are not individuals.

If non-resident individual Noteholders do not obtain double tax treaty relief at the time the proceeds from a disposal of the Notes are paid to such non-resident individual Noteholders and income tax is withheld by a Russian payer of the income, such non-resident individual Noteholders may apply for a refund within one year from the end of the tax period in which the tax was withheld. The documentation requirements to obtain such a refund would include an apostilled or legalised confirmation of the individual’s residence in a state having an effective double tax treaty, and confirmation of the income received and the taxes paid in the country of tax residence of the non- resident individual Noteholders as confirmed by the relevant tax authorities of such countries as well as a notarised translation in Russian. However, there can be no assurance that the refund of any taxes withheld or double tax treaty relief (as described above) will be available for such non-resident individual Noteholders.

The Russian tax authorities may, in practice, require a wide variety of documentation confirming the right to benefits under a double tax treaty. Such documentation, in practice, may not be explicitly required by the Russian Tax Code.

Obtaining a refund of Russian tax withheld may be a time consuming process and can involve considerable practical difficulties, including the possibility that a tax refund may be denied for various reasons.

European Union Directive on the Taxation of Savings Income Under Council Directive 2003/48/EC on the taxation of savings income (the ‘‘EU Savings Directive’’), each Member State of the EU is required to provide to the tax authorities of another Member State details of payments of interest or other similar income paid by a person within its jurisdiction to, or secured by such a person for, an individual beneficial owner resident in, or certain limited types of entities established in, that other Member State. However, for a transitional period, Austria and Luxembourg will (unless during such period they elect otherwise) instead operate a withholding system in relation to such payments. Under such a withholding system, the beneficial owner of the interest payment must be allowed to elect that certain provision of information procedures should be applied instead of withholding. The rate of withholding is 35%. The transitional period is to terminate at the end of the first full fiscal year following agreement by certain non-EU countries to exchange of information procedures relating to interest and other similar income. Luxembourg has announced that it will elect out of the withholding system in favour of automatic exchange of information with effect from 1 January 2015.

A number of non-EU countries and certain dependent or associated territories of certain Member States have adopted similar measures to the EU Savings Directive.

190 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA A proposal for amendments to the EU Savings Directive has been published, including a number of suggested changes which, if implemented, would broaden the scope of the rules described above. Investors who are in any doubt as to their position should consult their professional advisers. If a payment under a Note were to be made by a person in a Member State or another country or territory which has opted for a withholding system and an amount of, or in respect of, tax were to be withheld from that payment pursuant to the EU Savings Directive or any law implementing or complying with, or introduced in order to conform to the EU Savings Directive, neither the Issuer nor any Paying Agent nor any other person would be obliged to pay additional amounts under the terms of such Notes as a result of the imposition of such withholding tax. The Issuer is, however, required, for so long as any of the Notes are outstanding, to maintain a Paying Agent in a Member State that will not be obliged to withhold or deduct tax pursuant to the EU Savings Directive or any such law.

United Kingdom Provision of Information Requirements The comments below are of a general nature and are based on current United Kingdom (‘‘UK’’) tax law and published practice of HM Revenue & Customs (‘‘HMRC’’), the UK tax authorities. Such law may be repealed, revoked or modified (possibly with retrospective effect) and such practice may change, resulting in UK tax consequences different from those discussed below. The comments below deal only with UK rules relating to information that may need to be provided to HMRC in respect of certain payments on the Notes. They do not deal with any other UK tax consequences of acquiring, owning or disposing of the Notes. Each prospective investor should seek advice based on its particular circumstances from an independent tax adviser. Persons in the UK (i) paying interest to or receiving interest on behalf of another person who is an individual or a partnership containing individuals, or (ii) paying amounts due on redemption of any Notes which constitute deeply discounted securities as defined in Chapter 8 of Part 4 of the Income Tax (Trading and Other Income) Act 2005 to or receiving such amounts on behalf of another person who is an individual or a partnership containing individuals, may be required to provide certain information to HMRC regarding the identity of the payee or person entitled to the interest and, in certain circumstances, such information may be exchanged with tax authorities in other jurisdictions. However, in relation to amounts payable on the redemption of any Notes which constitute deeply discounted securities, HMRC published guidance indicates that HMRC will not exercise its power to obtain information where such amounts are paid on or before 5 April 2014. There is no guarantee that equivalent guidance will be published in respect of future years.

United States The following is a summary of certain U.S. federal income tax considerations that may be relevant to a beneficial owner of a Note that is, for U.S. federal income tax purposes, a citizen or resident of the United States, a domestic corporation or an entity otherwise subject to U.S. federal income taxation on a net income basis in respect of the Note (a ‘‘U.S. Holder’’). This summary addresses only U.S. Holders that purchase Notes as part of the initial offering, and that hold such Notes as capital assets. The summary does not address tax considerations applicable to investors that may be subject to special tax rules, such as banks or other financial institutions, tax-exempt entities, partnerships (or entities or arrangements treated as partnerships for U.S. federal income tax purposes) or partners therein, insurance companies, dealers in securities or currencies, traders in securities electing to mark to market, persons that will hold the Notes as a position in a ‘‘straddle’’ or conversion transaction, or as part of a ‘‘synthetic security’’ or other integrated financial transaction or persons that have a ‘‘functional currency’’ other than the U.S. Dollar. This summary is based on the Internal Revenue Code of 1986, as amended, (the ‘‘U.S. Tax Code’’) existing, proposed and temporary U.S. Treasury regulations and judicial and administrative interpretations thereof, in each case as of the date hereof. All of the foregoing are subject to change (possibly with retroactive effect) or to differing interpretations, which could affect the U.S. federal income tax consequences described herein. INVESTORS SHOULD CONSULT THEIR OWN TAX ADVISORS REGARDING THE TAX CONSEQUENCES OF THE ACQUISITION, OWNERSHIP AND DISPOSITION OF THE NOTES, INCLUDING THE APPLICATION TO THEIR PARTICULAR CIRCUMSTANCES OF THE U.S. FEDERAL INCOME TAX CONSIDERATIONS DISCUSSED BELOW, AS WELL AS THE APPLICATION OF U.S. FEDERAL ESTATE, GIFT AND ALTERNATIVE MINIMUM TAX LAWS, U.S. STATE AND LOCAL TAX LAWS AND FOREIGN TAX LAWS.

191 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA Payments of Interest and Additional Amounts Payments of interest on a Note (which may include additional amounts (see ‘‘Terms and Conditions of the Notes – Taxation’’)) generally will be taxable to a U.S. Holder as ordinary interest income when such interest is accrued or received, in accordance with the U.S. Holder’s regular method of accounting for U.S. federal income tax purposes. It is expected that the Notes will not be considered as issued with original issue discount (‘‘OID’’) in excess of a de minimis amount. In general, however, if the Notes are issued with OID that is more than a de minimis amount, regardless of a U.S. Holder’s regular method of accounting for U.S. federal income tax purposes, such holder will have to include OID as ordinary gross income under a ‘‘constant yield method’’ before the receipt of cash attributable to such income. Interest income in respect of the Notes generally will constitute foreign-source income for purposes of computing the foreign allowable under the U.S. federal income tax laws. The limitation on foreign income taxes eligible for credit is calculated separately with respect to specific classes of income. Such income generally will constitute ‘‘passive category income’’ for purposes for most U.S. Holders. The calculation and availability of foreign tax credits and, in the case of a U.S. Holder that elects to deduct foreign income taxes, the availability of such deduction involves the application of complex rules that depend on the U.S. Holder’s particular circumstances. In addition, foreign tax credits generally will not be allowed for certain short-term or hedged positions in the Notes. U.S. Holders should consult their own tax advisors regarding the availability of foreign tax credits or deductions in respect of foreign taxes and the treatment of additional amounts.

Sale or Disposition of Notes A U.S. Holder generally will recognise capital gain or loss upon the sale, exchange, retirement or other taxable disposition of a Note in an amount equal to the difference between the amount realised upon such disposition (other than amounts attributable to accrued but unpaid interest, which will be taxed as ordinary income to the extent not previously included in gross income) and such U.S. Holder’s tax basis in the Note. A U.S. Holder’s tax basis in the Note will generally equal such U.S. Holder’s purchase price of the Note. Subject to the discussion in the next paragraph, gain or loss realised by a U.S. Holder on the disposition of a Note generally will be long-term capital gain or loss if, at the time of the disposition, the Note has been held for more than one year. The net amount of long-term capital gain realised by an individual U.S. Holder generally is subject to tax at a reduced rate. The deductibility of capital losses is subject to limitations. Capital gain or loss recognised by a U.S. Holder generally will be U.S.-source gain or loss. Consequently, if any such gain is subject to foreign withholding tax, a U.S. Holder may not be able to credit the tax against its U.S. federal income tax liability unless such credit can be applied (subject to the applicable limitation) against tax due on other income treated as derived from foreign sources. U.S. Holders should consult their own tax advisors as to the foreign tax credit implications of a disposition of the Notes.

Backup Withholding and Information Reporting Payments in respect of the Notes that are paid within the United States or through certain U.S.- related financial intermediaries are subject to information reporting, and may be subject to backup withholding, unless the U.S. Holder (i) is a corporation or other exempt recipient, and demonstrates this fact when so required, or (ii) provides a correct taxpayer identification number, certifies that it is not subject to backup withholding and otherwise complies with applicable requirements of the backup withholding rules. The amount of any backup withholding collected from a payment to a U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal income tax liability, and may entitle the U.S. Holder to a refund, provided that certain required information is timely furnished to the U.S. Internal Revenue Service. U.S. Holders may be subject to other U.S. information reporting requirements. Holders should consult their own advisors regarding the application of U.S. information reporting rules in light of their particular circumstances. TO COMPLY WITH UNITED STATES TREASURY DEPARTMENT CIRCULAR 230, PROSPECTIVE INVESTORS ARE HEREBY NOTIFIED THAT: (A) ANY DISCUSSION OF FEDERAL TAX ISSUES IN THIS PROSPECTUS IS NOT INTENDED OR WRITTEN TO BE USED, AND CANNOT BE USED BY ANY TAXPAYER, FOR THE PURPOSE OF AVOIDING PENALTIES THAT MAY BE IMPOSED ON THE TAXPAYER UNDER THE UNITED STATES INTERNAL REVENUE CODE; (B) ANY SUCH DISCUSSION IS INCLUDED

192 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA HEREIN IN CONNECTION WITH THE PROMOTION OR MARKETING (WITHIN THE MEANING OF CIRCULAR 230) OF THE TRANSACTIONS OR MATTERS ADDRESSED HEREIN; AND (C) A TAXPAYER SHOULD SEEK ADVICE BASED ON THE TAXPAYER’S PARTICULAR CIRCUMSTANCES FROM AN INDEPENDENT TAX ADVISOR.

Bermuda taxation Under existing Bermuda laws, there will be no Bermuda income or profits tax, withholding tax, , capital , estate duty or payable by the Issuer or by holders of the Notes. The Issuer has obtained an assurance from the Minister of Finance of Bermuda under the Exempted Undertakings Tax Protection Act 1966 that, in the event that any legislation is enacted in Bermuda imposing any tax computed on profits or income, or computed on any capital asset, gain or appreciation or any tax in the nature of estate duty or inheritance tax, such tax shall not, until 31 March 2035, be applicable to the Issuer or to any of its operations or shares, debentures or other obligations except insofar as such tax applies to persons ordinarily resident in Bermuda or is payable by the Issuer in respect of real property owned or leased by the Issuer in Bermuda.

Kazakh taxation The following is a general summary of Kazakhstan tax consequences as at the date hereof in relation to payments made under the Notes and in relation to the sale or transfer of the Notes. It is not exhaustive and purchasers are urged to consult their professional advisers as to the tax consequences to them of holding or transferring Notes.

Interest Under Kazakhstan law as presently in effect, payments of principal or interest on the Notes by the Issuer to an individual who is a tax non-resident of Kazakhstan or to a legal entity that is neither established in accordance with the legislation of Kazakhstan, nor has its actual governing body (place of actual management) in, nor maintains a permanent establishment in, Kazakhstan or otherwise has no legal taxable presence in Kazakhstan (together, ‘‘Non-Kazakhstan Holders’’) will not be subject to taxation in Kazakhstan, and no withholding of any Kazakhstan tax will be required on any such payments. Interest payable by the Issuer to residents of Kazakhstan or to tax non-residents who maintain a permanent establishment in Kazakhstan (together, ‘‘Kazakhstan Holders’’), other than to individuals (who are exempt), will be subject to Kazakhstan income tax unless the Notes are admitted, as at the date of accrual of interest, to the official list of a stock exchange operating in the territory of Kazakhstan.

Gains Gains realised by Non-Kazakhstan Holders derived from the disposal, sale, exchange or transfer of the Notes will not be subject to Kazakhstan income tax. Gains realised by Kazakhstan Holders, other than individuals, are subject to corporate income tax at a rate of 20%. Kazakhstan individuals are taxed on such gains at a rate of 10%. Any gain realised by Kazakhstan Holders in relation to sale of Notes which are admitted, as at the date such sale, to the official list of a stock exchange operating in the territory of Kazakhstan and sold through open trades on such stock exchange are exempt from Kazakhstan income tax.

Payments under the Guarantees The Kazakhstan tax laws are unclear on how to treat transactions under the Guarantees for tax purposes, and there is no interpretive guidance in place on the subject in question. However, we believe that payments following enforcement of a Guarantee should be treated for tax purposes in the same manner as ordinary payments under a debt security. Payments to Non-Kazakhstan Holders under the Guarantees issued by non-resident Guarantors are not subject to taxation in Kazakhstan. Interest payments to Non-Kazakhstan Holders under the Potential Oil’s Guarantee are likely to be subject to withholding tax at a rate of 15% unless reduced by an applicable double taxation treaty. Payments of interest under the Guarantee issued by Potential Oil to Non-Kazakhstan Holders registered in countries with a favourable tax regime which appear in a list published from time to time by the Kazakhstan Government (these countries currently include Cyprus, Liechtenstein, Luxembourg, Nigeria, Malta, Aruba and others) will be subject to withholding tax in Kazakhstan at a rate of 20% unless reduced by an applicable double taxation treaty.

193 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA Payments of interest to Kazakhstan Holders, other than to individuals and Kazakhstan pension, social security and investment funds (the ‘‘Exempt Holders’’), under the Guarantee issued by Potential Oil, will be subject to withholding tax at a rate of 15%. Interest payable by the Guarantors, other than Potential Oil, to Kazakhstan Holders, other than the Exempt Holders, will be subject to corporate income tax at a rate of 20%. As a general rule, repayment of principal under notes to a note-holder does not give rise to income tax implications. Normally, interest payments on notes admitted, as of the date of accrual of interest, to the official list of a stock exchange operating in the territory of Kazakhstan are exempt from Kazakhstan income tax. However, in the absence of any interpretive guidance on application of the relevant provisions of the Kazakhstan tax laws, the Issuer and Potential Oil cannot provide assurance that: (i) income tax would not be imposed upon the entire payment under the Guarantees, including with respect to the principal amount of the Notes (safe for payments between non-residents), and in such a case not 15% tax rate, but 20%, would be applied; and (ii) that the above tax relief which is generally available for payments under notes admitted to trading on a Kazakh stock exchange would be in practice available for the interest payments on the Notes under the Guarantees. The Guarantors will agree under their Guarantees in the Trust Deed to pay Amounts or Claims (as defined in the Trust Deed) in respect of any such withholding, subject to certain exceptions set out in full in ‘‘Terms and Conditions of the Notes – Taxation’’. The amendments to the Kazakhstan Tax Code, effective from 1 January 2012, provide that a Kazakhstan income-payer being a tax agent is allowed to pay withholding tax calculated on the income payable to a non-resident income-receiver from its own funds, without any deductions from the amounts payable. Although there is an element of doubt, and so far as the Group is aware there has been no case in Kazakhstan in which tax gross- up provisions have been considered by Kazakhstan courts, the Group is of the view that such provisions of the Trust Deed should be considered as contractual obligations on Potential Oil to pay withholding tax from its own funds rather than constitute an obligation to pay taxes imposed on the payee.

194 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA CERTAIN U.S. EMPLOYEE BENEFIT PLAN CONSIDERATIONS

Subject to certain restrictions described below, Notes are permitted to be acquired by employee benefit plans as described in Section 3(3) of ERISA that are subject to Title I of ERISA (collectively, ‘‘ERISA Plans’’), plans not subject to ERISA but subject to Section 4975 of the U.S. Tax Code, including IRAs, Keogh Plans which cover only self-employed persons and their spouses and other employee benefit plans which cover only the owners of a business (collectively, ‘‘4975 Plans’’ and together with ERISA Plans, ‘‘Plans’’), or by entities whose underlying assets include plan assets by reason of an investment in the entity by ERISA Plans or 4975 Plans or otherwise (collectively, ‘‘Plan Asset Entities’’). Plans and Plan Asset Entities are collectively referred to as ‘‘Benefit Plan Investors’’. Subject to certain restrictions described below, Notes are also permitted to be acquired by governmental plans and non-electing church plans that are not subject to ERISA or Section 4975 of the U.S. Tax Code (collectively, ‘‘Non-ERISA Plans’’). Section 406 of ERISA and Section 4975 of the Code prohibit certain transactions involving the assets of an ERISA Plan or 4975 Plan and certain persons (referred to as ‘‘parties in interest’’ under ERISA or ‘‘disqualified persons’’ under the Code) having certain relationships to such Plans, unless a statutory or administrative exemption is applicable to the transaction. The types of transactions between Plans and parties in interest that are prohibited include: (a) sales, exchanges or leases of property; (b) loans or other extensions of credit and (c) the furnishing of goods and services. A party in interest or disqualified person who engages in a prohibited transaction may be subject to excise taxes under ERISA and the Code. In addition, the persons involved in the prohibited transaction may have to rescind the transaction and pay an amount to the Plan for any losses realised by the Plan or profits realised by such persons and certain other liabilities could result that have a significant adverse effect on such persons. Certain exemptions from the prohibited transaction provisions of Section 406 of ERISA and Section 4975 of the Code may apply depending in part on the type of Plan fiduciary making the decision to acquire a Note and the circumstances under which such decision is made. Included among these exemptions are Section 408(b)(17) of ERISA and Section 4975(d)(20) of the Code (relating to certain transactions between a plan and a non-fiduciary service provider), Prohibited Transaction Class Exemption (‘‘PTCE’’) 95-60 (relating to investments by insurance company general accounts), PTCE 91-38 (relating to investments by bank collective investment funds), PTCE 84-14 (relating to transactions effected by a ‘‘qualified professional asset manager’’), PTCE 90-1 (relating to investments by insurance company pooled separate accounts) and PTCE 96-23 (relating to transactions determined by an in-house asset manager). There can be no assurance that any of these class exemptions or any other exemption will be available with respect to any particular transaction involving the Notes. Non-ERISA Plans are generally not subject to ERISA nor do the prohibited transaction provisions of ERISA or Section 4975 of the Code apply to these types of plans. However, such plans are subject to prohibitions on related party transactions under Section 503 of the Code, which prohibitions operate similarly to the prohibited transaction rules under ERISA or Section 4975 of the Code. In addition, the fiduciary of a Non-ERISA Plan must consider applicable state or local laws, if any, imposed upon such plan before purchasing the Notes or any interest therein. BY ITS PURCHASE AND HOLDING OF A NOTE OR ANY INTEREST THEREIN, THE PURCHASER AND/OR HOLDER THEREOF AND EACH TRANSFEREE WILL BE DEEMED TO HAVE REPRESENTED AND WARRANTED AT THE TIME OF ITS PURCHASE AND THROUGHOUT THE PERIOD THAT IT HOLDS SUCH NOTE OR INTEREST THEREIN, THAT (1) EITHER (A) IT IS NOT, AND IT IS NOT ACTING ON BEHALF OF (AND FOR SO LONG AS IT HOLDS SUCH NOTES OR ANY INTEREST THEREIN WILL NOT BE, AND WILL NOT BE ACTING ON BEHALF OF), A PLAN, A BENEFIT PLAN INVESTOR, OR A GOVERNMENTAL, CHURCH OR NON-U.S. PLAN WHICH IS SUBJECT TO SIMILAR LAWS, AND NO PART OF THE ASSETS USED OR TO BE USED BY IT TO ACQUIRE OR HOLD THE NOTES OR ANY INTEREST THEREIN CONSTITUTES THE ASSETS OF ANY SUCH PLAN, BENEFIT PLAN INVESTOR OR GOVERNMENTAL, CHURCH OR NON-U.S. PLAN WHICH IS SUBJECT TO SIMILAR LAWS, OR (B) (I) ITS ACQUISITION, HOLDING AND DISPOSITION OF SUCH NOTES OR ANY INTEREST THEREIN DOES NOT AND WILL NOT CONSTITUTE OR OTHERWISE RESULT IN A NONEXEMPT PROHIBITED TRANSACTION UNDER SECTION 406 OF ERISA AND/OR SECTION 4975 OF THE CODE (OR, IN THE CASE OF A GOVERNMENTAL, CHURCH OR NON-U.S. PLAN, A NON- EXEMPT VIOLATION OF ANY SIMILAR LAWS); AND (II) NONE OF THE ISSUER, THE GUARANTORS, THE TRUSTEES OR ANY OF THEIR RESPECTIVE AFFILIATES, IS A

195 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA SPONSOR OF, OR A FIDUCIARY (WITHIN THE MEANING OF SECTION 3(21) OF ERISA OR, WITH RESPECT TO A GOVERNMENTAL, CHURCH OR NON-U.S. PLAN, ANY DEFINITION OF ‘‘FIDUCIARY’’ UNDER SIMILAR LAWS) WITH RESPECT TO, THE ACQUIRER, TRANSFEREE OR HOLDER IN CONNECTION WITH ANY EXCHANGE, ACQUISITION OR HOLDING OF SUCH NOTES, OR AS A RESULT OF ANY EXERCISE BY THE ISSUERS OR ANY OF THEIR AFFILIATES OF ANY RIGHTS IN CONNECTION WITH SUCH NOTES, AND NO ADVICE PROVIDED BY THE ISSUERS OR ANY OF THEIR AFFILIATES HAS FORMED A PRIMARY BASIS FOR ANY INVESTMENT OR OTHER DECISION BY OR ON BEHALF OF THE ACQUIRER OR HOLDER IN CONNECTION WITH SUCH NOTES AND THE TRANSACTIONS CONTEMPLATED WITH RESPECT TO SUCH NOTES; AND (2) IT WILL NOT SELL OR OTHERWISE TRANSFER SUCH NOTES OR ANY INTEREST THEREIN OTHERWISE THAN TO A PURCHASER OR TRANSFEREE THAT IS DEEMED (OR, IF REQUIRED BY THE TRUST DEED, CERTIFIED) TO MAKE THESE SAME REPRESENTATIONS, WARRANTIES AND AGREEMENTS WITH RESPECT TO ITS ACQUISITION, HOLDING AND DISPOSITION OF SUCH NOTES OR ANY INTEREST THEREIN. The foregoing is not intended to be exhaustive and the law governing investments by Benefit Plan investors and Non-ERISA Plans is subject to extensive administrative and judicial interpretations. The foregoing discussion should not be construed as legal advice. Any potential purchaser of Notes should consult counsel with respect to issues arising under ERISA, the U.S. Tax Code and other applicable laws and make their own independent decisions.

196 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA GENERAL INFORMATION

(1) Application has been made to the Irish Stock Exchange for the Notes to be admitted to the Official List and to trading on the Main Securities Market, through the Listing Agent, Arthur Cox Listing Services Limited (‘‘ACLSL’’). ACLSL is acting solely in its capacity as listing agent for the Issuer in relation to the Notes and is not itself seeking admission to the Official List of the Irish Stock Exchange or to trading on the Main Securities Market for the purposes of the Prospectus Directive. It is expected that the admission of the Notes to the Official List and to trading on the Main Securities Market will take place on or about 30 April 2013, subject to the issuance of the Global Notes. (2) The Issuer and Guarantors have each obtained all necessary consents, approvals and authorisations in connection with the issue and performance of the Notes and the Guarantees. The issue of the Notes was authorised by the resolution passed on 24 April 2013 by the Pricing Committee of the Issuer duly appointed by and pursuant to the unanimous written resolution of the Board of Directors of the Issuer passed on 22 April 2013 duly appointed. Each Guarantee was or is expected to be authorised by resolutions of the authorised corporate body of the relevant Guarantor passed between 1 and 25 April 2013. (3) The Issuer was incorporated in Bermuda on 1 September 1998 for an unlimited duration with registered number 25413. The registered office of the Issuer is located at Clarendon House, 2 Church Street, Hamilton HM11, Bermuda. The Issuer’s telephone number is +7 (495) 777-18-08. (4) Except as disclosed in this Prospectus, there has been no significant change in the financial or trading position of the Issuer, the Guarantors or the Group since 31 December 2012 and no material adverse change in the prospects of the Issuer, the Guarantors or the Group since 31 December 2012. (5) Except as disclosed in this Prospectus, neither the Issuer nor any of its subsidiaries has been involved in any governmental, legal or arbitration proceedings (including any such proceedings which are pending or threatened of which the Issuer is aware) during the 12 months preceding the date of this Prospectus that may have or have had in the recent past significant effects on the financial position or profitability of the Issuer or the Group. (6) Deloitte & Touche has rendered unqualified audit reports on the consolidated annual accounts of the Issuer prepared according to IFRS as of and for the years ended 31 December 2012, 2011 and 2010. ZAO Deloitte & Touche is a member of the Institute of Professional Accountants of Russia and the Audit Chamber of Russia. (7) The Notes have been accepted for clearance through Euroclear, Clearstream, Luxembourg and DTC. The Common Code for the Regulation S Notes is 092504310. The ISIN for the Regulation S Notes is XS0925043100. The CUSIP number of the Rule 144A Notes is 018760AB4 and the ISIN of the Rule 144A Notes is US018760AB41. The Common Code for the Rule 144A Notes is 092517772. (8) Neither the Issuer nor any of the Guarantors has entered into any material contracts outside the ordinary course of business, which could result in it being under an obligation or entitlement that is material to its ability to make payments under the Notes. (9) Until the maturity date or earlier repayment of the Notes, copies of the following documents in physical form will be available from the date hereof, during usual business hours on any weekday (Saturdays and public holidays excepted), for inspection at the registered office of the Principal Paying Agent: * the Memorandum of Association of the Issuer; * the Trust Deed (which includes the form of the Global Notes and the Definitive Notes); * the Deeds of Guarantee * the audited consolidated financial statements of the Issuer as of and for the years ended 31 December 2012, 2011 and 2010, in each case together with the audit reports thereon; * the Reserves Report; and

197 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA * a copy of this Prospectus together with any supplement to this Prospectus or further Prospectus. (10) Save for the fees payable to the Managers, the Trustee, the Principal Paying Agent and the Registrar, so far as the Issuer is aware, no person involved in the issue of the Notes has an interest that is material to the issue of the Notes. (11) The total expenses related to the admission to trading are approximately EUR 5,000. (12) Any website referred to in this document does not form part of this Prospectus.

198 c108210pu060 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA INDEX TO FINANCIAL STATEMENTS

IFRS Consolidated Financial Statements for Alliance Oil Company Ltd. for the year ended 31 December 2012 ...... F-2 Independent Auditor’s Report...... F-5 Consolidated Statement of Profit or Loss ...... F-7 Consolidated Statement of Profit or Loss and Comprehensive Income ...... F-8 Consolidated Statement of Financial Position ...... F-9 Consolidated Statement of Changes in Equity...... F-10 Consolidated Statement of Cash Flows...... F-11 Notes to the Consolidated Financial Statements ...... F-13

IFRS Consolidated Financial Statements for Alliance Oil Company Ltd. for the year ended 31 December 2011 ...... F-69 Independent Auditor’s Report...... F-72 Consolidated Income Statement ...... F-74 Consolidated Statement of Comprehensive Income ...... F-75 Consolidated Statement of Financial Position ...... F-76 Consolidated Statement of Changes in Equity...... F-77 Consolidated Statement of Cash Flows...... F-78 Notes to the Consolidated Financial Statements ...... F-80

F-1 c108210pu070 Proof 9: 29.4.13_14:35 B/L Revision: 0 Operator PutA

Alliance Oil Company Ltd and Subsidiaries

Consolidated Financial Statements for the years ended 31 December 2012 and 2011

F-2 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

CONTENTS

STATEMENT OF DIRECTORS’ RESPONSIBILITIES FOR THE PREPARATION AND APPROVAL OF THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED 31 DECEMBER 2012 AND 2011 1

INDEPENDENT AUDITOR’S REPORT 2-3

Consolidated Statements of Profit or Loss 4

Consolidated Statements of Profit or Loss and Other Comprehensive Income 5

Consolidated Statements of Financial Position 6

Consolidated Statements of Changes in Equity 7

Consolidated Statements of Cash Flows 8

Notes to the Consolidated Financial Statements 10-65

F-3 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

STATEMENT OF DIRECTORS’ RESPONSIBILITIES FOR THE PREPARATION AND APPROVAL OF THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED 31 DECEMBER 2012 AND 2011

The Board of Directors is responsible for the preparation of the consolidated financial statements that present fairly the financial position of Alliance Oil Company Ltd and its subsidiaries (the “Group”) as of 31 December 2012 and 2011, and the results of its operations, cash flows and changes in shareholders’ equity for the year then ended, in compliance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).

In preparing the consolidated financial statements, the Board of Directors is responsible for:

 Properly selecting and applying accounting policies;  Presenting information, including accounting policies, in a manner that provides relevant, reliable, comparable and understandable information;  providing additional disclosures when compliance with the specific requirements in IFRSs are insufficient to enable users to understand the impact of particular transactions, other events and conditions on the Group's consolidated financial position and financial performance; and  Making an assessment of the Group's ability to continue as a going concern.

The Board of Directors is also responsible for:

 Designing, implementing and maintaining an effective and sound system of internal controls, throughout the Group;  Maintaining adequate accounting records that are sufficient to show and explain the Group's transactions and disclose with reasonable accuracy the consolidated financial position of the Group, and which enable them to ensure that the consolidated financial statements of the Group comply with IFRS;  Maintaining statutory accounting records in compliance with local legislation and accounting standards in the respective jurisdictions in which the Group operates;  Taking such steps as are reasonably available to them to safeguard the assets of the Group; and  Preventing and detecting fraud and other irregularities.

The Board of directors authorised the Audit committee to approve and Chief Executive Officer to sign the consolidated financial statements of the Group for the years ended 31 December 2012 and 2011 on 5 April 2013. The consolidated financial statements of the Group for the years ended 31 December 2012 and 2011 were approved by the Audit committee on 11 April 2013.

On behalf of the Board of Directors:

______Arsen E. Idrisov, Chief Executive Officer

11 April 2013

1 F-4 ZAO “Deloitte & Touche CIS” 5 Lesnaya Street Moscow, 125047 Russia

Tel: +7 (495) 787 06 00 Fax: +7 (495) 787 06 01 www.deloitte.ru

INDEPENDENT AUDITOR’S REPORT

To: Shareholders and Board of directors of Alliance Oil Company Ltd.

We have audited the accompanying consolidated financial statements of Alliance Oil Company Ltd and its subsidiaries (collectively – the “Group”), which comprise the consolidated statements of financial position as at 31 December 2012 and 2011, the consolidated statements of profit or loss, profit or loss and other comprehensive income, changes in equity and cash flows for the years then ended, and notes 1-41 comprising a summary of significant accounting policies and other explanatory information.

Director’s Responsibility for the Consolidated Financial Statements

The Directors are responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of the consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on the fair presentation of these consolidated financial statements based on our audit. We conducted our audit in accordance with International Standards on Auditing. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated 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 consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by the Directors, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to express an opinion on the fair presentation of these consolidated financial statements.

Deloitte refers to one or more of Deloitte Touche Tohmatsu Limited, a UK private company limited by guarantee, and its network of member firms, each of which is a legally separate and independent entity. Please see www.deloitte.com/about for a detailed description of the legal structure of Deloitte Touche Tohmatsu Limited and its member firms. Please see www.deloitte.com/ru/about for a detailed description of the legal structure of Deloitte CIS.

© 2012 ZAO “Deloitte & Touche CIS”. All rights reserved.

Member of Deloitte Touche Tohmatsu Limited F-5 Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Alliance Oil Company Ltd and its subsidiaries as at 31 December 2012 and 2011, and its financial performance and its cash flows for the years ended 31 December 2012 and 2011 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Deloitte AB ZAO Deloitte & Touche CIS

______Svante Forsberg Natalia Golovkina Authorized public accountant Certified auditor

11 April 2013

3 F-6 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PROFIT OR LOSS in thousands of US Dollars (TUSD), except for earnings per share data

Year ended Year ended 31 December 31 December Note 2012 2011

Revenue Revenue from sales of crude oil 602,354 531,656 Revenue from sales of oil products 2,787,761 2,496,218 Revenue from other sales 55,124 54,786 3,445,239 3,082,660 Cost of sales Production costs of crude oil 9 (365,881) (353,047) Production costs of oil products 10 (1,898,780) (1,635,262) Cost of other sales (24,315) (23,911) Depletion and depreciation of oil and gas and refining assets (173,890) (156,170) Reversal of impairment of oil and gas assets 18 58,721 - Gross profit 1,041,094 914,270

Selling expenses 11 (314,587) (286,571) Administrative expenses 12 (95,740) (77,457) Depreciation and amortisation of marketing and other assets (18,484) (18,025) Other operating expenses, net 13 (19,485) (18,220) Share of profits of associates and joint venture 20 2,309 2,153 Loss on disposal of shares in subsidiaries 36 - (2,894) Operating income 595,107 513,256

Interest income 14,977 12,259 Finance costs 14 (95,034) (59,134) Gain/(loss) on derivatives classified as held for trading, net 15 7,678 (15,444) Currency exchange gain/(loss), net 21,688 (18,176) Profit before tax 544,416 432,761

Income tax expense 16 (123,646) (104,471) Profit for the year 420,770 328,290

Attributable to: Owners of the Company 402,833 318,873 Non-controlling interests 29 17,937 9,417 420,770 328,290

Earnings per share Basic (USD per share) 17 2.31 1.86 Diluted (USD per share) 17 2.18 1.74

4 F-7 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME in thousands of US Dollars (TUSD)

Year ended Year ended 31 December 31 December 2012 2011

Profit for the year 420,770 328,290

Other comprehensive income/(loss) Items that will not be reclassified subsequently to profit or loss: Currency exchange differences on translating foreign operations 7,276 2,413 7,276 2,413

Items that may be reclassified subsequently to profit or loss: Currency exchange differences on intercompany loans 48,160 (49,216) Currency exchange differences on translating foreign operations 100,001 (97,637) Income tax relating to currency exchange differences on intercompany loans (7,308) 7,574 140,853 (139,279)

Other comprehensive income/(loss) for the year, net of income tax 148,129 (136,866) Total comprehensive income for the year 568,899 191,424

Attributable to: Owners of the Company 543,686 179,594 Non-controlling interests 25,213 11,830

5 F-8 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION in thousands of US Dollars (TUSD)

31 December 31 December Note 2012 2011

ASSETS Non-current assets Property, plant and equipment 18 4,474,599 3,223,798 Intangible assets 871 1,917 Goodwill 19 20,394 19,239 Investments in associates and joint venture 20 187,191 21,826 Deferred tax assets 16 28,531 26,439 Other assets 22 2,991 30,045 4,714,577 3,323,264 Current assets Inventories 23 227,991 145,029 Trade and other accounts receivable 24 116,368 113,605 Value added tax and other taxes receivable 25 296,236 224,552 Income tax receivable 13,811 11,814 Advances paid and prepaid expenses 26 161,262 125,907 Other financial assets 21 49,821 93,263 Restricted cash 27 26,887 27,318 Cash and cash equivalents 27 384,933 160,483 1,277,309 901,971

TOTAL ASSETS 5,991,886 4,225,235

EQUITY AND LIABILITIES Capital and reserves Share capital 28 176,528 171,528 Additional paid-in capital 1,296,210 1,104,355 Translation reserve on intercompany loans (129,496) (170,348) Translation reserve on foreign operations (217,145) (332,302) Option premium on convertible bonds 22,271 22,271 Retained earnings 1,638,943 1,159,946 Equity attributable to owners of the Company 2,787,311 1,955,450 Non-controlling interests 29 245,699 37,983 TOTAL EQUITY 3,033,010 1,993,433

Non-current liabilities Loans and borrowings 30 1,669,014 1,514,263 Deferred tax liabilities 16 265,002 187,998 Provision for decommissioning and site restoration costs 31 73,195 15,440 Advances received 33 26,309 - Retirement benefit obligation 35 8,728 2,669 Derivatives classified as held for trading 15 - 11,114 2,042,248 1,731,484 Current liabilities Loans and borrowings 30 401,606 106,829 Trade and other accounts payable 32 129,864 144,184 Advances received and accrued expenses 33 296,065 170,466 Income tax payable 10,199 5,524 Other taxes payable 34 72,913 68,408 Derivatives classified as held for trading 15 5,981 4,907 916,628 500,318

TOTAL LIABILITIES 2,958,876 2,231,802

TOTAL EQUITY AND LIABILITIES 5,991,886 4,225,235

6 F-9 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY in thousands of US Dollars (TUSD)

Attributable to owners of the Company Translation Translation Option Additional reserve on reserve on premium on Non- paid-in intercompany foreign convertible Retained controlling Share capital capital loans operations bonds earnings Total interests Total equity

Balance at 1 January 2011 171,528 1,103,845 (128,706) (234,665) 22,271 839,716 1,773,989 31,307 1,805,296

Profit for the year - - - - - 318,873 318,873 9,417 328,290 Other comprehensive (loss)/income, net of income tax - - (41,642) (97,637) - - (139,279) 2,413 (136,866) Total comprehensive (loss)/income for the year - - (41,642) (97,637) - 318,873 179,594 11,830 191,424

Changes in ownership of subsidiaries (Note 36) - 510 - - - - 510 (1,864) (1,354) Disposal of subsidiaries (Note 36) ------(2,799) (2,799) Dividends to shareholders of non-controlling interests ------(491) (491) Share option plan (Note 28) - - - - - 1,357 1,357 - 1,357 Balance at 31 December 2011 171,528 1,104,355 (170,348) (332,302) 22,271 1,159,946 1,955,450 37,983 1,993,433 F-10 Profit for the year - - - - - 402,833 402,833 17,937 420,770 Other comprehensive income, net of income tax - - 40,852 100,001 - - 140,853 7,276 148,129 Total comprehensive income for the year - - 40,852 100,001 - 402,833 543,686 25,213 568,899

Issue of preference shares, net of issue costs (Note 28) 5,000 191,272 - - - - 196,272 - 196,272 Disposal of non-controlling interests (Note 20) - - - 15,156 - 80,265 95,421 183,572 278,993 Dividends on preference shares (Note 28) - - - - - (5,768) (5,768) - (5,768) Changes in ownership of subsidiaries (Note 36) - 583 - - - - 583 (1,069) (486) Share option plan (Note 28) - - - - - 1,667 1,667 - 1,667

Balance at 31 December 2012 176,528 1,296,210 (129,496) (217,145) 22,271 1,638,943 2,787,311 245,699 3,033,010

7 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS in thousands of US Dollars (TUSD)

Year ended Year ended 31 December 31 December 2012 2011

Operating activities Profit before tax 544,416 432,761

Adjustments for:

Depreciation, depletion and amortisation 192,374 174,195 Reversal of impairment of oil and gas assets (Note 18) (58,721) - Interest income (14,977) (12,259) Finance costs 95,034 59,134 (Gain)/loss on derivatives classified as held for trading, net (7,678) 15,444 Currency exchange (gain)/loss, net (21,688) 18,176 Share of profits of associates and joint venture (2,309) (2,153) Loss on disposal of shares in subsidiaries - 2,894 Loss on disposal of assets 5,948 3,196 Impairment of trade and other accounts receivable 8,323 753 Other non-cash items 20,777 2,518 Operating cash flows before changes in working capital 761,499 694,659

Movements in working capital Increase in inventories (72,905) (13,832) Increase in accounts receivable, advances paid and prepaid expenses (56,235) (144,624) Increase in accounts payable, advances received and accrued expenses 115,482 40,078 Cash generated from operations 747,841 576,281

Interest paid (82,136) (42,106) Income tax paid (95,829) (71,675) Total cash generated from operating activities 569,876 462,500

Investing activities Investments in oil and gas assets (359,843) (603,744) Investments in refining assets (328,267) (314,912) Investments in marketing and other assets (40,719) (28,194) Interest capitalised and paid (77,751) (78,268) Acquisition of controlling interest in subsidiaries, net of cash acquired (Note 36) (155,758) (15,636) Proceeds from disposal of assets 2,963 1,683 Interest received 8,984 5,582 Payments on settlement of swap contract, net of interest received (Note 15) (2,130) 188 Loans provided (56,417) (56,588) Loans repaid 57,903 19,169 Investments in promissory notes (15,621) - Proceeds from sale of promissory notes 7,209 - Short-term deposits placed (30,320) (30,015) Proceeds from deposits withdrawn 27,030 30,076

Total cash used in investing activities (962,737) (1,070,659)

8 F-11 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED) in thousands of US Dollars (TUSD)

Year ended Year ended 31 December 31 December (Expressed in USD thousands) 2012 2011

Financing activities Proceeds from loans and borrowings 758,151 1,111,272 Repayment of loans and borrowings (466,696) (478,913) Proceeds from issue of preference shares (Note 28) 201,527 - Proceeds from joint venture formation(Note 20) 116,728 - Acquisition of non-controlling interest in subsidiaries (1,551) (1,267) Dividends paid by subsidiaries - (397) Total cash generated from financing activities 608,159 630,695

Effect of exchange rate changes on cash balances held in foreign currencies (7,166) 4,148 Translation difference 15,887 (16,982) Change in cash, cash equivalents and restricted cash 224,019 9,702

Cash, cash equivalents and restricted cash at beginning of the year 187,801 178,099

Cash, cash equivalents and restricted cash at end of the year 411,820 187,801

9 F-12 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS in thousands of US Dollars (TUSD) unless indicated otherwise

1. ORGANISATION

Alliance Oil Company Limited (the “Parent company” or “Company”) was incorporated in Bermuda on 1 September 1998, as a tax exempted limited liability private company. The Company's registered office is located at: Clarendon House, 2 Church Street, Hamilton HM11, Bermuda.

The Group is an independent vertically integrated oil and gas company with upstream operations in the Russian Federation and Kazakhstan and downstream operations in the Russian Federation. The Group's upstream operations include crude oil and gas exploration, extraction and production in the Timano-Pechora, Volga-Urals and Tomsk regions of the Russian Federation and the Atyrau region of Kazakhstan. The downstream operations include oil refining, transportation, marketing and sales of oil products in the Russian Far East and Eastern Siberia.

The principal activities of the significant subsidiaries of the Company and voting power held by the Group at 31 December 2012 and 2011 were as follows:

Voting power held by the Group, % 31 December 31 December Activity/ Operating entity Country 2012 2011

Holding companies OJSC “Alliance” Oil Company Russian Federation 100.00 100.00 Vostol Oil (Cyprus) Limited Cyprus 100.00 100.00 Financing of subsidiaries O&G Credit Agency Ltd Cyprus 100.00 100.00 Management services LLC “Alliance” Oil Company MC Russian Federation 100.00 100.00 Oil and gas exploration and production OJSC Vostochnaya Transnationalnaya Russian Federation Kompaniya 100.00 100.00 CJSC Khvoinoye Russian Federation 100.00 100.00 OJSC Pechoraneft Russian Federation 99.66 99.66 LLC Kolvinskoye Russian Federation 100.00 100.00 LLC SN-Gasproduction Russian Federation 100.00 - LLP Potential Oil Kazakhstan 80.00 80.00 LLC Gusikhinskoye Russian Federation 100.00 100.00 LLC GeoInvestService Russian Federation 100.00 - CJSC Saneco Russian Federation 51.001 100.00 OJSC Tatnefteotdacha Russian Federation 50.771 99.54 Oil refining OJSC Khabarovsk Oil Refinery Russian Federation 98.83 98.82 Marketing and sales of oil products CJSC Alliance Oil Russian Federation 100.00 100.00 OJSC Khabarovsknefteproduct Russian Federation 92.85 92.56 OJSC Amurnefteproduct Russian Federation 96.36 96.36 OJSC Primornefteproduct Russian Federation 95.04 95.04 LLC Alliance - Baikalneftesbyt Russian Federation 100.00 100.00 LLC Alliance Bunker Russian Federation 100.00 100.00 CJSC Gavanbunker Russian Federation 100.00 100.00 Inventory and equipment supply LLC Naftatekhresource Russian Federation 100.00 100.00 Transportation services CJSC Alliancetransoil Russian Federation 100.00 100.00

1 Control over CJSC Saneco and OJSC Tatnefteotdacha is based on potential voting rights (Note 20).

10 F-13 2. STATEMENT OF COMPLIANCE

The accompanying consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). IFRS include standards and interpretations approved by the IASB, including International Accounting Standards (“IAS”) and interpretations issued by IFRS Interpretations Committee.

3. APPLICATION OF NEW AND REVISED INTERNATIONAL FINANCIAL REPORTING STANDARDS

New and revised IFRSs and IASs affecting the reported financial performance and/or financial position

A number of new and revised Standards which became effective or available for early adoption on 1 January 2012, have been applied for the preparation of the consolidated financial statements.

New and revised Standards on consolidation, joint arrangements, associates and disclosures

In May 2011, a package of five standards on consolidation, joint arrangements, associates and disclosures were issued including IFRS 10 “Consolidated Financial Statements”, IFRS 11 “Joint Arrangements”, IFRS 12 “Disclosures of Interests in Other Entities”, IAS 27 (as revised in 2011) “Separate Financial Statements” and IAS 28 (as revised in 2011) “Investments in Associates and Joint Ventures”. In 2012, the Group adopted these five standards in advance of their effective dates (annual periods beginning on or after 1 January 2013). The impact of the application of these standards was assessed by management as insignificant to the Group’s operations except for IFRS 10, IFRS 11 and IFRS 12.

Impact of the application of IFRS 10

IFRS 10 replaces the parts of IAS 27 “Consolidated and Separate Financial Statements” that deal with consolidated financial statements. IFRS 10 changes the definition of control such that an investor controls an investee when it is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. To meet the definition of control in IFRS 10, all of the three criteria, including (a) an investor has power over an investee, (b) the investor has exposure, or rights, to variable returns from its involvement with the investee, and (c) the investor has the ability to use its power over the investee to affect the amount of the investor’s returns, must be met. Previously, control was defined as the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities.

The application of IFRS 10 is relevant for the accounting for the Group’s subsidiaries CJSC Saneco and OJSC Tatnefteotdacha. In the year ended 31 December 2012, the Group contributed its ownership interest in these subsidiaries, or 100% in the case of CJSC Saneco and 99.54% in the case of OJSC Tatnefteotdacha, to a newly established joint venture, AR Oil & Gas B.V.

Based on the definition of control under IFRS 10, the Group considers that it has retained control over CJSC Saneco and OJSC Tatnefteotdacha and continues to consolidate the entities. This determination is made on the basis that the Group has a substantive potential voting right in respect of CJSC Saneco and OJSC Tatnefteotdacha through the existence of a buy-back option, which can be exercised at fair value determined by independent valuators. Management expects to obtain non- monetary benefits from exercise of the option and thus deems the option to be substantive, such that this is a determinative factor in retaining control.

Refer to Note 20 for additional information in respect of the joint venture and related accounting.

Impact of the application of IFRS 11

IFRS 11 replaces IAS 31 “Interests in Joint Ventures” and SIC-13 “Jointly Controlled Entities – Non- Monetary Contributions by Venturers”. IFRS 11 deals with how a joint arrangement of which two or more parties have joint control should be classified. Under IFRS 11, there are only two types of joint arrangements – joint operations and joint ventures. The classification of joint arrangements under IFRS 11 is determined based on the rights and obligations of parties to the joint arrangements by considering the structure, the legal form of the arrangements, the contractual terms agreed by the parties to the arrangement, and, when relevant, other facts and circumstances. A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement (i.e. joint venturers) have rights to the net assets of the arrangement. Previously, IAS 31 “Interests in Joint Ventures” had

11 F-14 three types of joint arrangements – jointly controlled entities, jointly controlled operations and jointly controlled assets. The classification of joint arrangements under IAS 31 was primarily determined based on the legal form of the arrangement (e.g. a joint arrangement that was established through a separate entity was accounted for as a jointly controlled entity).

The subsequent accounting of joint ventures and joint operations is different. Investments in joint ventures are accounted for using the equity method (proportionate consolidation is no longer allowed). Investments in joint operations are accounted for such that each joint operator recognises and measures the assets and liabilities (and the related revenues and expenses) in relation to its interest in the arrangement in accordance with the applicable Standards.

Under IFRS 11, a newly established entity, AR Oil & Gas B.V., has been determined as a joint venture and the Group’s interest in AR Oil & Gas B.V is required to be accounted for using the equity method. Refer to Note 20 for additional information in respect of the joint venture and related accounting.

Impact of the application of IFRS 12

IFRS 12 is a disclosure standard and is applicable to entities that have interests in subsidiaries, joint arrangements, associates and/or unconsolidated structured entities. In general, the application of IFRS 12 has resulted in more extensive disclosures in the consolidated financial statements.

Amendments to IAS 19 “Employee Benefits”

The Group early adopted amendments to IAS 19 “Employee Benefits” in advance of the effective date (annual period beginning on or after 1 January 2013). The most significant change relates to accounting for changes in defined benefit obligations and plan assets. The amendments require the recognition of changes in defined benefit obligations and in fair value of plan assets when they occur, and hence eliminate the ‘corridor approach’ permitted under the previous version of IAS 19 and accelerate the recognition of past service costs. The amendments require all actuarial gains and losses to be recognised immediately through other comprehensive income in order for the net pension asset or liability recognised in the consolidated statement of financial position to reflect the full value of the plan deficit or surplus. The amendments to IAS 19 require retrospective application.

Previously, the past service costs at the introduction of the plans were deferred and amortised on a straight-line basis over the expected average remaining working lives of the employees participating in the plans. After adoption of the amended standard, the Group recognised the past service costs in the amount of TUSD 4,718 in the consolidated statement of profit or loss. Due to immateriality, the amendments were not applied retrospectively.

Revised IFRSs applied with no or not material effect on amounts reported, presentation and disclosure

Amendments to IAS 1 “Presentation of Financial Statements” – Presentation of items of other comprehensive income

The Group has adopted the amendments to IAS 1 in advance of the effective date (annual periods beginning on or after 1 July 2012). The amendments introduce new terminology for the statement of comprehensive income and income statement. Under the amendments to IAS 1, the “statement of comprehensive income” is renamed to the “statement of profit or loss and other comprehensive income” and the “income statement” is renamed to the “statement of profit or loss”. The amendments to IAS 1 retain the option to present profit or loss and other comprehensive income in either a single statement or in two separate but consecutive statements. However, the amendments to IAS 1 require items of other comprehensive income to be grouped into two categories in the other comprehensive income section: (a) items that will not be reclassified subsequently to profit or loss and (b) items that may be reclassified subsequently to profit or loss when specific conditions are met. Income tax on items of other comprehensive income is required to be allocated on the same basis – the amendments do not change the option to present items of other comprehensive income either before tax or net of tax. The amendments have been applied retrospectively, and hence the presentation of items of other comprehensive income has been modified to reflect the changes. Other than the above mentioned presentation changes, the application of the amendments to IAS 1 does not result in any impact on profit or loss, other comprehensive income and total comprehensive income.

12 F-15 The following new and revised IFRSs have been adopted in these consolidated financial statements:

 Amendments to IFRS 1 “First-time Adoption of International Financial Reporting Standards”  Amendments to IFRS 7 “Financial Instruments: Disclosures”  Amendments to IAS 12 “Income Taxes”: Deferred tax  Amendments to IAS 1 as part of annual improvement to IFRS 2009-2011 Cycle issued in May 2012

The application of these new and revised IFRSs has not had any material impact on the amounts reported for the current and prior years but, with the exception of IFRS 1, may affect the accounting for future transactions or arrangements.

Standards, amendments and interpretations to existing standards that are not yet effective and have not been early adopted by the Group

At the date of approval of the Group’s consolidated financial statements, the following new, revised and amended Standards and Interpretations have been issued, but are not effective for the year ended 31 December 2012:

Effective for annual periods beginning on or after

Amendments to IFRS 7 “Financial Instruments: Disclosures” – Amendments enhancing disclosures about offsetting of financial assets and financial liabilities 1 January 2013 Amendments requiring disclosures about the initial application of IFRS 9 1 January 2015 IFRS 9 “Financial Instruments” 1 January 2015 IFRS 13 “Fair Value Measurement” 1 January 2013 Amendments to IAS 1 “Presentation of Financial Statements” – Amendments clarifying the difference between voluntary additional comparative information and the minimum required comparative information 1 January 2013 Amendments to IAS 16 “Property, Plant and Equipment” – Amendments clarifying the classification of major spare parts and servicing equipment 1 January 2013 Amendments to IAS 32 “Financial Instruments: Presentation” Amendments clarifying the accounting of income taxes arising from distributions to equity holders 1 January 2013 Amendments relating to the offsetting of financial assets and financial liabilities 1 January 2014 Amendments to IAS 34 “Interim Financial Reporting” - Amendments aligning the disclosure requirements for total segment assets with segment liabilities in interim financial statements 1 January 2013

Management is currently considering the potential impact of the adoption of these Standards, amendments and interpretations. However, it is not practicable to provide a reasonable estimate of their effect until a detailed review has been completed.

4. BASIS OF PREPARATION

Entities of the Group maintain their accounting records in accordance with the laws and accounting and reporting regulations of the countries of incorporation. Statutory accounting principles and procedures may differ substantially from those generally accepted under IFRS. Accordingly, the accompanying consolidated financial statements, which have been prepared from the Group entities statutory accounting records, reflect adjustments necessary for such financial statements to be presented in accordance with IFRS.

The consolidated financial statements have been prepared on the historical cost basis, except for certain financial instruments that are measured at fair values, as explained in the accounting policies below. Historical cost is generally based on the fair value of the consideration given in exchange for assets.

13 F-16 Going concern

In assessing its going concern status, management has taken account of the Group’s financial position, expected future trading performance, its borrowings and available credit facilities, anticipated additional borrowing facilities under negotiation and its capital expenditures commitments and plans, together with other risks facing the Group. Management considers that the Group has adequate resources to continue in operational existence for at least the next 12 months from the date of approval of these consolidated financial statements and that it is appropriate to adopt the going concern basis in preparing these consolidated financial statements.

5. SIGNIFICANT ACCOUNTING POLICIES

Basis of consolidation

The consolidated financial statements incorporate the financial statements of the Company and entities controlled by the Company (its subsidiaries). Control is achieved where the Company is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. Specifically, the Company controls an investee if and only if the Company has all the following:

 Power over the investee (i.e. existing rights that give it the current ability to direct the relevant activities of the investee);  Exposure, or rights, to variable returns from its involvement with the investee; and  The ability to use its power over the investee to affect the amount of its returns.

When the Company has less than a majority of the voting rights of an investee, it has a power over the investee when the voting rights are sufficient to give it the practical ability to direct the relevant activities of the investee unilaterally. The Company considers all relevant facts and circumstances in assessing whether or not the Company’s voting rights in an investee are sufficient to give it power, including:

 The size of the Company’s holding of voting rights relative to the size and dispersion of holdings of the other vote holders;  Potential voting rights held by the Company, other vote holders or other parties;  Rights arising from other contractual arrangements; and  Any additional facts and circumstances that indicate the Company has, or does not have, the current ability to direct the relevant activities at the time that decisions need to be made, including voting patterns at previous shareholders’ meetings.

The Company reassesses whether or not it controls an investee if facts and circumstances indicate that there are changes to one or more of the three elements of control list above.

Consolidation of a subsidiary begins when the Company obtains control over the subsidiary and ceases when the Company loses control of the subsidiary. Specifically, income and expenses of subsidiaries acquired or disposed of during the year are included in the consolidated statement of profit or loss from the date the Company gains control until the date when the Company ceases to control the subsidiary.

Profit or loss and each component of other comprehensive income are attributed to the Owners of the Company and to the non-controlling interests. Total comprehensive income of subsidiaries is attributed to the owners of the Company and to the non-controlling interests even if this results in the non-controlling interests having a deficit balance.

When necessary, adjustments are made to the financial statements of subsidiaries to bring their accounting policies into line with the Group’s accounting policies.

All intragroup assets and liabilities, equity, income, expenses and cash flows relating to transactions between members of the Group are eliminated in full on consolidation.

14 F-17 Changes in the Group's ownership interests in subsidiaries that do not result in the Group losing control over the subsidiaries are accounted for as equity transactions. The carrying amounts of the Group's interests and the non-controlling interests are adjusted to reflect the changes in their relative interests in the subsidiaries. Any difference between the amount by which the non-controlling interests are adjusted and the fair value of the consideration paid or received is recognised directly in equity and attributed to owners of the Company.

When the Group loses control of a subsidiary, a gain or loss is recognised in profit or loss and is calculated as the difference between (i) the aggregate of the fair value of the consideration received and the fair value of any retained interest and (ii) the previous carrying amount of the assets (including goodwill), and liabilities of the subsidiary and any non-controlling interests. Amounts previously recognised in other comprehensive income in relation to the subsidiary’s assets or liabilities are accounted for (i.e. reclassified to the consolidated statement of profit or loss or transferred directly to retained earnings) in the same manner as would be required if the relevant assets or liabilities were disposed of. The fair value of any investment retained in the former subsidiary at the date when control is lost is regarded as the fair value on initial recognition for subsequent accounting under IAS 39 “Financial Instruments: Recognition and Measurement” or, when applicable, the cost on initial recognition of an investment in an associate or a jointly controlled entity.

Business combinations

Acquisitions of businesses are accounted for using the acquisition method. The consideration transferred in a business combination is measured at fair value, which is calculated as the sum of the acquisition-date fair values of the assets transferred by the Group, liabilities incurred by the Group to the former owners of the acquiree and the equity interests issued by the Group in exchange for control of the acquiree. Acquisition-related costs are recognised in profit or loss as incurred.

At the acquisition date, the identifiable assets acquired and the liabilities assumed are recognised at their fair value, except that:

 Deferred tax assets or liabilities, and assets or liabilities related to employee benefit arrangements are recognised and measured in accordance with IAS 12 “Income Taxes” and IAS 19 “Employee Benefits”, respectively;  Liabilities or equity instruments related to share-based payment arrangements of the acquire or share-based payment arrangements of the Group entered into to replace share-based payment arrangements of the acquire are measured in accordance with IFRS 2 “Share-based Payment” at the acquisition date; and  Assets (or disposal groups) that are classified as held for sale in accordance with IFRS 5 “Non-current Assets Held for Sale and Discontinued Operations” are measured in accordance with that Standard.

Goodwill is measured as the excess of the sum of the consideration transferred, the amount of any non-controlling interests in the acquiree, and the fair value of the acquirer's previously held equity interest in the acquiree (if any) over the net of the acquisition-date amounts of the identifiable assets acquired and the liabilities assumed. If, after reassessment, the net of the acquisition-date amounts of the identifiable assets acquired and liabilities assumed exceeds the sum of the consideration transferred, the amount of any non-controlling interests in the acquiree and the fair value of the acquirer's previously held interest in the acquiree (if any), the excess is recognised immediately in profit or loss as a bargain purchase gain.

Non-controlling interests that are present ownership interests and entitle their holders to a proportionate share of the entity's net assets in the event of liquidation may be initially measured either at fair value or at the non-controlling interests' proportionate share of the recognised amounts of the acquiree's identifiable net assets. The choice of measurement basis is made on a transaction-by-transaction basis.

When the consideration transferred by the Group in a business combination includes assets or liabilities resulting from a contingent consideration arrangement, the contingent consideration is measured at its acquisition-date fair value and included as part of the consideration transferred in a business combination. Changes in the fair value of the contingent consideration that qualify as measurement period adjustments are adjusted retrospectively, with corresponding adjustments against the cost of acquisition. Measurement period adjustments are adjustments that arise from additional information obtained during the ‘measurement period’ (which cannot exceed one year from the acquisition date) about facts and circumstances that existed at the acquisition date.

15 F-18 The subsequent accounting for changes in the fair value of the contingent consideration that do not qualify as measurement period adjustments depends on how the contingent consideration is classified. Contingent consideration that is classified as equity is not remeasured at subsequent reporting dates and its subsequent settlement is accounted for within equity. Contingent consideration that is classified as an asset or a liability is remeasured at subsequent reporting dates in accordance with IAS 39, or IAS 37 “Provisions, Contingent Liabilities and Contingent Assets”, as appropriate, with the corresponding gain or loss being recognised in profit or loss.

When a business combination is achieved in stages, the Group's previously held equity interest in the acquiree is remeasured to fair value at the acquisition date (i.e. the date when the Group obtains control) and the resulting gain or loss, if any, is recognised in profit or loss. Amounts arising from interests in the acquiree prior to the acquisition date that have previously been recognised in other comprehensive income are reclassified to profit or loss where such treatment would be appropriate if that interest were disposed of.

If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the Group reports provisional amounts for the items for which the accounting is incomplete. Those provisional amounts are adjusted during the measurement period (see above), or additional assets or liabilities are recognised, to reflect new information obtained about facts and circumstances that existed at the acquisition date that, if known, would have affected the amounts recognised at that date.

Goodwill

Goodwill arising on an acquisition of a business is carried at cost as established at the date of acquisition of the business less accumulated impairment losses, if any.

For the purpose of impairment testing, goodwill is allocated to each of the Group’s cash generating units (“CGU”) that is expected to benefit from the synergies of the combination.

A cash generating unit to which goodwill has been allocated is tested for impairment annually, or more frequently when there is an indication that the unit may be impaired. If the recoverable amount of the CGU is less than its carrying amount, the impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the unit and then to the other assets of the unit pro rata on the basis of the carrying amount of each asset in the unit. Any impairment loss for goodwill is recognised directly in profit or loss. An impairment loss recognised for goodwill is not reversed in subsequent periods.

On disposal of the relevant CGU, the attributable amount of goodwill is included in the determination of the profit or loss on disposal.

The Group's policy for goodwill arising on the acquisition of an associate is described below.

Investments in associates and joint ventures

An associate is an entity over which the Group has significant influence. Significant influence is the power to participate in the financial and operating policy decisions of the investee but is not control or joint control over those policies.

A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.

The results and assets and liabilities of associates or joint ventures are incorporated in these consolidated financial statements using the equity method of accounting, except when the investment is classified as held for sale, in which case it is accounted for in accordance with IFRS 5 “Non-current Assets Held for Sale and Discontinued Operations”. Under the equity method, an investment in an associate or a joint venture is initially recognised in the consolidated statement of financial position at cost and adjusted thereafter to recognise the Group’s share of the profit or loss and other comprehensive income of the associate or joint venture. When the Group’s share of losses of an associate or a joint venture exceeds the Group’s interest in that associate or joint venture (which includes any long-term interests that, in substance, form part of the Group’s net investment in the associate or joint venture), the Group discontinues recognising its share of further losses. Additional losses are recognised only to the extent that the Group has incurred legal or constructive obligations or made payments on behalf of the associate or joint venture.

16 F-19 An investment is accounted for using the equity method from the date on which the investee becomes an associate or a joint venture. On acquisition of the investment in an associate or a joint venture, any excess of the cost of the investment over the Group’s share of the net fair value of the identifiable assets and liabilities of the investee is recognised as goodwill, which is included within the carrying amount of the investment. Any excess of the Group’s share of the net fair value of the identifiable assets and liabilities over the cost of the investment, after reassessment, is recognised immediately in profit or loss.

The requirements of IAS 39 are applied to determine whether it is necessary to recognise any impairment loss with respect to the Group’s investment in an associate or a joint venture. When necessary, the entire carrying amount of the investment (including goodwill) is tested for impairment in accordance with IAS 36 “Impairment of Assets” as a single asset by comparing its recoverable amount (higher of value in use and fair value less costs to sell) with its carrying amount. Any impairment loss recognised forms part of the carrying amount of the investment. Any reversal of that impairment loss is recognised in accordance with IAS 36 to the extent that the recoverable amount of the investment subsequently increases.

The Group discontinues the use of the equity method from the date when the investment ceases to be an associate or a joint venture. When the Group retains an interest in the former associate or joint venture and the retained interest is a financial asset, the Group measures the retained interest at fair value at that date and the fair value is regarded as its fair value on initial recognition in accordance with IAS 39. The difference between the carrying amount of the associate or joint venture at the date the equity method was discontinued, and the fair value of any retained interest and any proceeds from disposing of a part interest in the associate or joint venture is included in the determination of the gain or loss on disposal of the associate or joint venture. In addition, the Group accounts for all amounts previously recognised in other comprehensive income in relation to that associate or joint venture on the same basis as would be required if that associate or joint venture had directly disposed of the related assets or liabilities. Therefore, if a gain or loss previously recognised in other comprehensive income by that associate or joint venture would be reclassified to profit or loss on the disposal of the related assets or liabilities, the Group reclassifies the gain or loss from equity to profit or loss (as a reclassification adjustment) when the equity method is discontinued.

The Group continues to use the equity method when an investment in an associate becomes an investment in a joint venture or an investment in a joint venture becomes an investment in an associate. There is no remeasurement to fair value upon such changes in ownership interests.

When the Group reduces its ownership interest in an associate or a joint venture but the Group continues to use the equity method, the Group reclassifies to profit or loss the proportion of the gain or loss that had previously been recognised in other comprehensive income relating to that reduction in ownership interest if that gain or loss would be reclassified to profit or loss on the disposal of the related assets or liabilities.

When a group entity transacts with an associate or a joint venture of the Group, profits and losses resulting from the transactions with the associate or joint venture are recognised in the Group’s consolidated financial statements only to the extent of interests in the associate or joint venture that are not related to the Group.

Functional and presentation currency

Amounts presented in the financial statements of each of the Group’s entities are measured using the currency of the primary economic environment in which the entity operates (“functional currency”). The individual financial statements of each Group’s entity are prepared in its functional currency:

 For entities operating in the Russian Federation – Russian Rouble (“RUB”);  For entities operating in Kazakhstan – Kazakhstan Tenge (“KZT”);  For entities operating in Cyprus and Bermuda – US Dollar (“USD”).

17 F-20 The Group has chosen to present its consolidated financial statements in USD, as management believes it is a convenient presentation currency for international users of the consolidated financial statements of the Group as it is a common presentation currency in the oil and gas industry. The translation of balances and transactions of the Group’s entities from their functional currencies to the presentation currency is performed as follows:

 All assets and liabilities, both monetary and non-monetary, are translated at closing exchange rates at each reporting period end date;  All income and expenses are translated at the quarterly average exchange rates for the period, except for significant transactions that are translated at rates on the date of such transactions and in instances where exchange rates fluctuate significantly during the period;  Resulting exchange differences are recognised in other comprehensive income as “Currency exchange differences on translating foreign operations” and accumulated in equity (attributed to non-controlling interests as appropriate);  All cash flows are translated at the quarterly average exchange rates for the period, except for significant transactions that are translated at rates on the date of such transactions. Resulting exchange differences are presented as “Translation difference”.

On the disposal of a foreign operation (i.e. a disposal of the Group’s entire interest in a foreign operation, or a disposal involving loss of control over a subsidiary that includes a foreign operation, a partial disposal of an interest in a joint venture or an associate of which the retained interest becomes a financial interest that includes a foreign operation), all of the accumulated exchange differences in respect of that operation attributable to the owners of the Group are reclassified to profit or loss.

In addition, in relation to a partial disposal of a subsidiary that does not result in the Group losing control over the subsidiary, the proportionate share of accumulated exchange differences are re- attributed to non-controlling interests and are not recognised in profit or loss. For all other partial disposals (i.e. partial disposals of associates or joint arrangements that do not result in the Group losing significant influence or joint control), the proportionate share of the accumulated exchange differences is reclassified to profit or loss.

Goodwill and fair value adjustments on identifiable assets and liabilities acquired arising on the acquisition of a foreign operation are treated as assets and liabilities of the foreign operation and translated at the rate of exchange prevailing at the end of each reporting period. Exchange differences arising are recognised in other comprehensive income and accumulated in equity.

Foreign currencies

In preparing the financial statements of the individual entities, transactions in currencies other than the entity’s functional currency (foreign currencies) are recognised at the rates of exchange prevailing at the dates of the transactions. At the end of each reporting period, monetary items denominated in foreign currencies are retranslated at the rates prevailing at that date. Non-monetary items carried at fair value that are denominated in foreign currencies are retranslated at the rates prevailing at the date when the fair value was determined. Non-monetary items that are measured in terms of historical cost in a foreign currency are not retranslated.

Exchange differences are recognised in profit or loss in the period in which they arise except for:

 Exchange differences on foreign currency borrowings relating to assets under construction for future productive use, which are included in the cost of those assets when they are regarded as an adjustment to interest costs on those foreign currency borrowings;  Exchange differences on monetary items receivable from or payable to a foreign operation for which settlement is neither planned nor likely to occur (therefore forming part of the net investment in the foreign operation), which are recognised initially in other comprehensive income and reclassified from equity to profit or loss on disposal or partial disposal of the net investment.

18 F-21 Property, plant and equipment

The Group’s property, plant and equipment consist of oil and gas assets involved in crude oil and gas exploration and production (“oil and gas assets”), refining assets involved in oil refining (“refining assets”) and marketing and other assets involved in oil and oil products transportation and marketing of oil products (“marketing and other assets”).

Oil and gas assets

Exploration and evaluation assets

The Group follows the “successful efforts” method of accounting for its oil and gas assets, under which all costs for acquiring licenses and for the exploration and evaluation, survey, drilling and development of oil fields are initially capitalised in field area cost centres pending determination of oil and gas reserves. Costs incurred prior to having obtained the legal rights to explore an area are expensed directly to the consolidated statement of profit or loss as they are incurred. Capitalised expenditures incurred during the various exploration and appraisal phases are recognised through profit or loss unless commercial reserves have been established or the determination process has not been completed.

Exploration and evaluation assets are accounted for at historic cost less impairment losses if applicable.

When commercial reserves are discovered and plans to develop are approved, exploration and evaluation assets are transferred to oil and gas production assets.

Impairment of exploration and evaluation assets

Exploration and evaluation assets are assessed for impairment when facts and circumstances suggest that the carrying amount of an exploration and evaluation asset may exceed its recoverable amount. The following facts and circumstances, among other, indicate that exploration and evaluation assets must be tested for impairment:

 The term of exploration license in the specific area has expired during the reporting period or will expire in the near future, and is not expected to be renewed;  Substantive expenditure on further exploration for and evaluation of oil and gas resources in the specific area is neither budgeted nor planned;  Exploration for and evaluation of oil and gas resources in the specific area have not led to the discovery of commercially viable quantities of oil and gas resources and the decision was made to discontinue such activities in the specific area; and  Sufficient data exist to indicate that, although the development in the specific area is likely to occur, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale.

For the purpose of assessing exploration and evaluation assets for impairment, such assets are allocated to cash-generating units, being exploration license areas.

Any impairment loss is recognised as an expense in accordance with the policy on impairment of tangible assets set out below.

Oil and gas production assets

Oil and gas production assets are stated at cost less accumulated depletion and impairment losses, if applicable. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning obligation, reclassified exploration and evaluation assets and for qualifying assets, borrowing costs capitalised in accordance with the Group’s accounting policy. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.

19 F-22 Oil and gas production assets are depleted in accordance with the unit-of-production method over proved and probable reserves; the base for depletion includes management's best estimates of future development costs related to probable reserves. For this purpose, the Group has determined estimates of oil and gas reserves in accordance with definitions of Petroleum Resources Management System with involvement of internationally recognised reserve engineer, DeGolyer and MacNaughton. Depletion of a field area is charged to profit or loss when production commences.

Proved and probable reserves include oil and gas quantities which the Group expects to produce after the expiry dates of its current licenses. The Group’s current licenses for exploration, production and development of oil and gas fields expire between 2014 and 2034. Where the license term is shorter than the production phase of the oil and gas field, the oil and gas properties are depreciated over the production phase of the oil and gas fields, as management believes that such licenses will be renewed. The production phase of oil and gas fields is determined based on the estimate of commercially viable reserves.

Proved reserves are those volumes of oil and gas which, by analysis of geological and engineering data, are estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods and governmental regulations. Proved reserves can be categorised as developed or undeveloped.

Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable, under current economic conditions, operating methods and government regulations. In this context, when probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves.

Refining, marketing and other assets

Refining, marketing and other assets are measured at cost less accumulated depreciation and impairment losses, if applicable. Such cost include borrowing costs capitalised in accordance with the Group's accounting policy. Depreciation of these assets commences when the assets are ready for their intended use and is calculated on a straight-line basis over the estimated useful economic lives of assets, which are:

Buildings and Infrastructure 20-50 years Machinery and Equipment 8-20 years Vehicles 3-10 years Fixtures and Fittings 2-8 years

The estimated useful lives, residual values and depreciation method are reviewed at each year end, with the effect of any changes in estimate accounted for on a prospective basis.

An item of property, plant and equipment is derecognised upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on the disposal or retirement of an item of property, plant and equipment is determined as the difference between the sales proceeds and the carrying amount of the asset and is recognised in profit or loss.

Provision for decommissioning and site restoration costs

Decommissioning and site restoration provision relates primarily to the conservation and abandonment of wells, removal of pipelines and other oil and gas facilities together with site restoration related to the Group's license areas. Management estimates the obligation related to these costs based on internally generated engineering estimates, current statutory requirements and industry practices. Future decommissioning and site restoration costs, discounted to net present value, are capitalised within property, plant and equipment as oil and gas assets and a corresponding obligation recorded when a constructive obligation to incur such costs exists and the amount can be reliably estimated. The Group records the long-term portion of the obligation for decommissioning and site restoration costs as a separate line item in the consolidated statements of financial position.

The decommissioning asset is depleted using the unit-of-production method based on proved and probable reserves. The unwinding of the discount is recognised as finance costs.

20 F-23 The adequacy of the decommissioning and site restoration provision is periodically reviewed in the light of current laws and regulations, and adjustments made as necessary. Changes in the estimated expenditure are reflected as an adjustment to the provision and a corresponding adjustment to property, plant and equipment.

Impairment of tangible and intangible assets (excluding goodwill and exploration and evaluation assets)

At the end of each reporting period, the Group reviews the carrying amounts of its tangible and intangible assets to determine whether there is any indication that those assets have suffered an impairment loss. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment loss (if any). Where it is not possible to estimate the recoverable amount of an individual asset, the Group estimates the recoverable amount of the CGU to which the asset belongs.

Recoverable amount is the higher of fair value less costs to sell or value in use. In assessing value in use, the estimated future cash flows are discounted to their present value, using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset for which the estimates of future cash flows have not been adjusted.

If the recoverable amount of an asset (or CGU) is estimated to be less than its carrying amount, the carrying amount of the asset (or CGU) is reduced to its recoverable amount. An impairment loss is recognised immediately in profit or loss. After the recognition of an impairment loss depletion charge for impaired oil and gas assets is adjusted in the reporting periods following the date of impairment recognition.

Where an impairment loss subsequently reverses, the carrying amount of the asset (or CGU) is increased to the revised estimate of its recoverable amount but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset (or CGU) in prior years. A reversal of an impairment loss is recognised immediately in profit or loss.

Inventories

Inventories are stated at the lower of cost and net realisable value. Costs, including an appropriate portion of fixed and variable overhead expenses, are assigned to inventories held by the method most appropriate to the particular class of inventory, with the majority being valued on a first-in-first- out basis and crude oil stock being valued on a weighted average basis. Net realisable value represents the estimated selling price for inventories in the ordinary course of business less all estimated costs of completion and costs necessary to make the sale.

Provisions

Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that the Group will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation.

The amount recognised as a provision is the best estimate of the consideration required to settle the present obligation at the balance sheet date, taking into account the risks and uncertainties surrounding the obligation. Where a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows.

When some or all of the economic benefits required to settle a provision are expected to be recovered from a third party, a receivable is recognised as an asset if it is virtually certain that reimbursement will be received and the amount of the receivable can be measured reliably.

Financial instruments

Financial assets and financial liabilities are recognised when a Group’s entity becomes a party to the contractual provisions of the instrument.

Financial assets and financial liabilities are initially measured at fair value. Transaction costs that are directly attributable to the acquisition or issue of financial assets and financial liabilities (other than financial assets and financial liabilities at fair value through profit or loss) are added to or deducted from the fair value of the financial assets or financial liabilities, as appropriate, on initial recognition. Transaction costs directly attributable to the acquisition of financial assets or financial liabilities at fair value through profit or loss are recognised immediately in profit or loss.

21 F-24 Financial assets

Financial assets are classified into the following specified categories: financial assets ‘at fair value through profit or loss' (“FVTPL”) and ‘loans and receivables’. The classification depends on the nature and purpose of the financial assets and is determined at the time of initial recognition.

Financial assets at FVTPL

Financial assets are classified as at FVTPL when the financial asset is held for trading.

A financial asset is classified as held for trading if:

 It has been acquired principally for the purpose of selling it in the near term; or  On initial recognition it is part of a portfolio of identified financial instruments that the Group manages together and has a recent actual pattern of short-term profit-taking; or  It is a derivative that is not designated and effective as a hedging instrument.

Loans and receivables

Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. Loans and receivables (including trade and other receivables, bank balances and cash) are measured at amortised cost using the effective interest method, less any impairment.

Interest income is recognised by applying the effective interest rate, except for short-term receivables when the recognition of interest would be immaterial.

Effective interest method

The effective interest method is a method of calculating the amortised cost of a financial asset or liability and of allocating interest income or expense, respectively, over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash receipts or payments, as applicable (including all fees on points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the financial asset or liability, or, where appropriate, a shorter period, to the net carrying amount on initial recognition.

Income or expense is recognised on an effective interest basis for debt instruments other than those financial assets classified as at FVTPL.

Impairment of financial assets

Financial assets, other than those at FVTPL, are assessed for indicators of impairment at the end of each reporting period. Financial assets are considered to be impaired when there is objective evidence that, as a result of one or more events that occurred after the initial recognition of the financial asset, the estimated future cash flows of the investment have been affected.

Loans and receivables are reviewed and subsequently assessed for impairment on an individual basis. Objective evidence of impairment for an individual account receivable could include: significant financial difficulty of the issuer or counterparty; or breach of contract, such as default or delinquency in payments; or it becoming probable that the counterparty will enter bankruptcy or financial re-organisation.

For financial assets carried at amortised cost, the amount of the impairment loss recognised is the difference between the asset’s carrying amount and the present value of estimated future cash flows, discounted at the financial asset’s original effective interest rate.

The carrying amount of the financial asset is reduced by the impairment loss directly for all financial assets with the exception of accounts receivable, where the carrying amount is reduced through the use of an allowance account. When an account receivable is considered uncollectible, it is written off against the allowance account. Subsequent recoveries of amounts previously written off are credited against the allowance account. Changes in the carrying amount of the allowance account are recognised in profit or loss.

22 F-25 For financial assets measured at amortised cost, if, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognised, the previously recognised impairment loss is reversed through profit or loss to the extent that the carrying amount of the investment at the date the impairment is reversed does not exceed what the amortised cost would have been had the impairment not been recognised.

Derecognition of financial assets

The Group derecognises a financial asset only when the contractual rights to the cash flows from the asset expire, or when it transfers the financial asset and substantially all the risks and rewards of ownership of the asset to another entity. If the Group neither transfers nor retains substantially all the risks and rewards of ownership and continues to control the transferred asset, the Group recognises its retained interest in the asset and an associated liability for amounts it may have to pay. If the Group retains substantially all the risks and rewards of ownership of a transferred financial asset, the Group continues to recognise the financial asset and also recognises a collateralised borrowing for the proceeds received.

Cash, cash equivalents and restricted cash

Cash and cash equivalents comprise cash balances, cash deposits and highly liquid investments with maturities of three months or less at the date of investment, which are readily convertible to known amounts of cash and are subject to an insignificant risk of changes in value.

Restricted cash comprises cash deposited in special bank accounts that can be used only for the purpose intended.

Financial liabilities and equity instruments

Classification as debt or equity

Debt and equity instruments are classified as either financial liabilities or as equity in accordance with the substance of the contractual arrangement and the definitions of a financial liability and an equity instrument.

Equity instruments

An equity instrument is any contract that evidences a residual interest in the assets of an entity after deducting all of its liabilities. Equity instruments issued by the Group are recorded at the proceeds received, net of direct issue costs.

Convertible bonds

The component parts of compound instruments issued by the Group are classified separately as financial liabilities and equity in accordance with the substance of the contractual arrangement the definitions of a financial liability and an equity instrument. A conversion option that will be settled by the exchange of a fixed amount of cash or another financial asset for a fixed number of the Company's own equity instruments is an equity instrument.

At the date of issue, the fair value of the liability component is estimated using the prevailing market interest rate for a similar non-convertible instrument. This amount is recorded as a liability on an amortised cost basis using the effective interest method until extinguished upon conversion or at the instrument’s maturity date.

The conversion option classified as equity is determined by deducting the amount of the liability component from the fair value of the compound instrument as a whole. This is recognised and included in equity, net of income tax effects, and is not subsequently remeasured. In addition, the conversion option classified as equity will remain in equity until the conversion option is exercised, in which case, the balance recognised in equity will be transferred to additional paid-in-capital. Where the conversion option remains unexercised at the maturity date of the convertible note, the balance recognised in equity will be transferred to retained earnings. No gain or loss is recognised in profit or loss upon conversion or expiration of the conversion option.

23 F-26 Financial liabilities

Financial liabilities are classified as either financial liabilities ‘at FVTPL' or ‘other financial liabilities'.

Financial liabilities at FVTPL

Financial liabilities are classified as at FVTPL when the financial liability is held for trading. A financial liability is classified as held for trading if:

 It has been acquired principally for the purpose of repurchasing it in the near term; or  On initial recognition it is part of a portfolio of identified financial instruments that the Group manages together and has a recent actual pattern of short-term profit-taking; or  It is a derivative that is not designated and effective as a hedging instrument.

Other financial liabilities

Other financial liabilities (including borrowings and trade and other payables) are subsequently measured at amortised cost using the effective interest method.

Derecognition of financial liabilities

The Group derecognises financial liabilities when, and only when, the Group's obligations are discharged, cancelled or they expire. The difference between the carrying amount of the financial liability derecognised and the consideration paid and payable is recognised in profit or loss.

Derivative financial instruments

In order to manage its exposure to foreign exchange rate risks the Group enters into a derivative financial instrument such as cross currency interest swap. Further details of derivative financial instruments are disclosed in Note 15.

Derivatives are initially recognised at fair value at the date the derivative contracts are entered into and are subsequently remeasured to their fair value at the end of each reporting period. The resulting gain or loss is recognised in profit or loss immediately. Fair value is determined in the manner described in Note 39.

Borrowing costs

Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale.

Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalisation.

All other borrowing costs are recognised in profit or loss in the period in which they are incurred.

Employee benefits

Remuneration to employees, in respect of services rendered during the period is recognised as an expense in profit or loss in that reporting period.

Defined contribution plan

The Group’s entities are legally obliged to make defined contributions to the State Pension Funds of the Russian Federation and Kazakhstan where the Group operates (a defined contribution plan financed on a pay-as-you-go basis). In the Russian Federation all obligatory social contributions, including contributions to the Russian Federation State Pension Fund, are collected through social security charges at the rate of 30% for annual gross remuneration of each employee not exceeding certain amount, for remuneration exceeding the set amount the rate drops to 10%. The Group’s contributions to the State Pension Funds of the Russian Federation and Kazakhstan where the Group operates relating to defined contribution plans are charged to profit or loss in the period to which they relate.

24 F-27 Defined benefit plans

The Group has defined benefits plans, which are unfunded. The cost of providing benefits under these defined benefit plans is determined separately for each plan using the projected unit credit method. The past service costs are recognised as an expense at the earlier of the following dates:

 When the plan amendment or curtailment occurs;  When the entity recognises related restructuring costs or termination benefits.

Share based payments

The Group operates a share option plan. The fair value of the employee services received in exchange for the grant of the options is recognised as an expense. The total amount to be expensed over the vesting period is determined by reference to the fair value of the options granted, excluding the impact of non-market vesting conditions. Non-market vesting conditions are included in assumptions about the number of options that are expected to vest. At the end of reporting period, the Group revises its estimates of the number of options that are expected to vest. The Group recognises the impact of the revision of the original estimates in profit or loss with a corresponding entry to equity. The proceeds received net of any directly attributable transaction costs are credited to share capital (nominal value) and share premium when the options are exercised.

Revenue recognition

Revenue is measured at the fair value of the consideration received or receivable, net of discounts, value added tax and customs duties.

Revenue from the sale of crude oil, oil products and other goods is recognised when the following conditions are satisfied:

 Group has transferred to the buyer the significant risks and rewards of ownership;  Group retains neither continuing managerial involvement to the degree usually associated with ownership nor effective control over the goods sold;  Amount of revenue can be measured reliably;  It is probable that the economic benefits associated with the transaction will flow to the Group; and  Costs incurred or to be incurred in respect of the transaction can be measured reliably.

Sales of goods that result in award credits for customers, under the Group’s loyalty program, are accounted for as multiple element revenue transactions and the fair value of the consideration received or receivable is allocated between the goods supplied and the award credits granted. The consideration allocated to the award credits is measured by reference to their fair value – the amount for which the award credits could be sold separately. Such consideration is not recognised as revenue at the time of the initial sale transaction – but is deferred and recognised as revenue when the award credits are redeemed and the Group’s obligations have been fulfilled.

Incidental revenues from production of crude oil at the well’s development stage or revenues associated with initial test production are offset against capitalised costs of the related field area cost centre until quantities of proven and probable reserves are determined and commercial production has commenced.

Revenue from rendering of services is recognised at the time the services are provided to the customer.

Interest income from a financial asset is recognised when it is probable that the economic benefits will flow to the Group and the amount of income can be measured reliably. Interest income is accrued on a time basis, by reference to the principal outstanding and at the effective interest rate applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset's net carrying amount on initial recognition.

25 F-28 Leasing

Leases are classified as finance leases whenever the terms of the lease transfer substantially all the risks and rewards of ownership to the lessee. All other leases are classified as operating leases.

The Group as lessee

Operating lease payments are recognised as an expense on a straight-line basis over the lease term, except where another systematic basis is more representative of the time pattern in which economic benefits from the leased asset are consumed. Contingent rentals arising under operating leases are recognised as an expense in the period in which they are incurred.

In the event that lease incentives are received to enter into operating leases, such incentives are recognised as a liability. The aggregate benefit of incentives is recognised as a reduction of rental expense on a straight-line basis, except where another systematic basis is more representative of the time pattern in which economic benefits from the leased asset are consumed.

Income tax

Income tax expense represents the sum of the tax currently payable and deferred tax. Income taxes are computed in accordance with the laws of countries where the Group's entities operate.

Current tax

The tax currently payable is based on taxable profit for the period. Taxable profit differs from profit before tax as reported in the consolidated statement of profit or loss because of items of income or expense that are taxable or deductible in other years and items that are never taxable or deductible. The Group’s liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the end of reporting period.

Deferred tax

Deferred tax is recognised on temporary differences between the carrying amounts of assets and liabilities in the consolidated financial statements and the corresponding tax bases used in the computation of taxable profit. Deferred tax liabilities are generally recognised for all taxable temporary differences. Deferred tax assets are generally recognised for all deductible temporary differences to the extent that it is probable that taxable profits will be available against which those deductible temporary differences can be utilised. Such deferred tax assets and liabilities are not recognised if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the taxable profit nor the accounting profit.

Deferred tax liabilities are recognised for taxable temporary differences associated with investments in subsidiaries and associates, and interests in joint arrangements, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in foreseeable future. Deferred tax assets arising from deductible temporary differences associated with such investments and interests are only recognised to the extent that it is probable that there will be sufficient taxable profits against which to utilise the benefits of the temporary differences and they are expected to reverse in foreseeable future.

The carrying amount of deferred tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.

Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period in which the liability is settled or the asset realised, 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 liabilities and assets reflects the tax consequences that would follow from the manner in which the Group 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 same taxation authority and the Group intends to settle its current tax assets and liabilities on a net basis.

26 F-29 Current and deferred tax for the period

Current and deferred tax are recognised in profit or loss, except when they relate to items that are recognised in other comprehensive income or directly in equity, in which case, the current and deferred tax are also recognised in other comprehensive income or directly in equity respectively. Where current tax or deferred tax arises from the initial accounting for a business combination, the tax effect is included in the accounting for the business combination.

Segment information

Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision makers, who are responsible for allocating resources and assessing performance of the operating segments. The chief operating decision maker (“CODM”) has been identified as the management team of Managing Director, Chief Financial Officer, Chief Operating Officer, Chief Executive Officer Downstream, Chief Executive Officer Upstream.

6. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY

In the application of the Group’s accounting policies management is required to make judgements, estimates and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant. They are reviewed on an ongoing basis. Actual results could differ from those estimates.

Critical judgments in applying accounting policies

The following are critical judgments, apart from those involving estimations, that management has made in the process of applying the Group’s accounting policies and that have the most significant effect on the amounts recognised in the consolidated financial statements.

Control over CJSC Saneco and OJSC Tatnefteotdacha

During 2012, the Group contributed 100% of the shares of CJSC Saneco and 99.54% of the shares of OJSC Tatnefteotdacha into AR Oil & Gas B.V., a joint venture of the Group and Repsol Exploracion, S.A. registered in the Netherlands. However, based on the definition of control under IFRS 10 “Consolidated Financial Statements”, management of the Group considers that it has retained control over CJSC Saneco and OJSC Tatnefteotdacha despite contributing the shares to the joint venture entity. This determination is made on the basis that the Group has a substantive potential voting right in respect of CJSC Saneco and OJSC Tatnefteotdacha, through the existence of a buy-back option, which can be exercised at fair value determined by independent valuators. Management expects to obtain non-monetary benefits from exercise of the option and thus deems the option to be substantive, such that this is a determinative factor in retaining control.

Please refer to Note 20 for additional information in respect of the joint venture and related accounting.

Key sources of estimation uncertainty

The following are the key assumptions concerning the future, and other key sources of estimation uncertainty at the end of the reporting period, that have a significant risk causing a material adjustment to the carrying amounts of assets and liabilities within next financial year.

Useful economic lives of property, plant and equipment

Oil and gas assets

The Group’s oil and gas assets are depleted over the respective life of the oil and gas fields using the unit-of-production method based on proved and probable oil and gas reserves and incorporating the anticipated future capital cost for the development of those reserves.

27 F-30 When determining the life of the oil and gas field, assumptions that were valid at the time of estimation, may change when new information becomes available. The factors that could affect the estimation of the life of an oil and gas field include the following:

 Changes in the estimation of proved and probable oil and gas reserves;  Variances between actual and forecasted commodity prices used in the estimation of oil and gas reserves;  Unforeseen operational issues; and  Changes in capital, operating, processing and reclamation costs, discount rates and foreign exchange rates possibly adversely affecting the economic viability of oil and gas reserves.

Any of these changes could affect prospective depletion of oil and gas assets and their carrying value.

Anticipated future development costs are estimated using assumptions as to the number of wells required to produce the commercial reserves, the cost of such wells and associated production facilities, and other capital costs.

In 2012, the Group revised its procedure of depletion calculation: the updated proved and probable oil and gas reserves as at 31 December are to be used prospectively starting from 1 January of the following year. Depletion of oil and gas assets for the year ended 31 December 2012 amounted to TUSD 148,453 (Note 18), should the procedure remain the same as for the year ended 31 December 2011, depletion of oil and gas assets would have amounted to TUSD 161,293.

Refining, marketing and other assets

Property, plant and equipment other than oil and gas assets are depreciated on a straight-line basis over their useful economic lives. Management at the end of each reporting period reviews the appropriateness of the assets useful economic lives and residual values. The review is based on the current condition of the assets, the estimated period during which they will continue to bring economic benefits to the Group and the estimated residual value.

Impairment of goodwill and tangible assets

Impairment of goodwill

Goodwill acquired through business combinations has been allocated to a cash-generating unit “Downstream segment” which is also a reportable operating segment.

The recoverable amount of downstream segment assets was determined based on a value in use calculations using cash flow projections that were based on the following assumptions:

 Cash flows based on 2013 financial budget approved by the management;  Cash flows beyond 2013 extrapolated using a steady 1.2% per annum growth rate;  Prices of oil products were forecast on the basis of oil price and refining margins;  Costs included crude oil purchases, operating and administrative expenses;  Financial pre-tax discount rate of 9.85% per annum.

Management believes that any reasonable possible change in the key assumptions on which recoverable amount is based would not cause the aggregate carrying amount to exceed the aggregate recoverable amount of the cash-generating unit.

No impairment related to goodwill has been recognised in the consolidated statement of profit or loss for the years ended 31 December 2012 and 2011.

Impairment of tangible assets

At 31 December 2012, the Group assessed whether there was any indication that its tangible and intangible assets may be impaired. For the assets where such indicators were identified the Group estimated the recoverable amount for the respective CGUs.

28 F-31 The recoverable amounts of the above cash-generating units were determined based on a value in use calculations. The key assumptions used in the value in use calculations were as follows:

 Crude oil price Brent based on Intercontinental Exchange crude oil price futures data;  Production volumes based on a DeGolyer & McNaughton scenario regarding future oil production volumes;  Operating costs included production and other taxes, other controllable production and administrative expenses;  Capital expenditures included drilling costs and other capital expenditures expected to be incurred for field development;  Financial pre-tax discount rate of 9.85% per annum.

For each CGU tests were performed for the period of expected profitable operations but no longer than the field production period determined by the Group with involvement of internationally recognised reserve engineer, DeGolyer and MacNaughton.

Management believes that any reasonable possible change in the key assumptions on which recoverable amounts are based would not cause the aggregate carrying amounts to exceed the aggregate recoverable amounts of the Kolvinskoye and Tomsk cash-generating units determined for assessment of impairment of tangible assets.

At 31 December 2012, the Group reversed an impairment loss of TUSD 58,721 related to the Tomsk CGU (Note 18). Management’s judgment was primarily based on the significant increase in oil price projections and the relative stability of reserves for the two consecutive years.

Decommissioning and site restoration costs

In respect of fields where the Group is required to perform decommissioning and site restoration, a provision is recorded to recognise existing commitments (Note 31). The Group performs analysis in order to estimate the probability, timing and amount involved with probable required outflow of resources. Estimating the amounts and timing of those decommissioning and site restoration obligations that should be recorded requires significant judgment. The judgment is based on cost and engineering studies using currently available technology and is based on current environmental regulations. Liabilities for decommissioning and site restoration costs are subject to change because of change in laws and regulations, and their interpretation.

Taxation

The Group is subject to income tax and other taxes. Significant judgement is required in determining the provision for income tax and other taxes due to the complexity of the tax legislation of countries where the Group operates. There are many transactions and calculations for which the ultimate tax determination is uncertain. The Group recognises liabilities for anticipated tax audit issues based on estimates of whether additional taxes will be due. Where the final tax outcome of these matters is different from the amounts that were initially recorded, such differences will impact the amount of tax and tax provisions in the period in which such determination is made. Deferred tax assets are recognised for all unused tax losses to the extent that it is probable that taxable profit will be available against which the losses can be utilised. Significant management judgment is required to determine the amount of deferred tax assets that can be recognised, based upon the likely timing and the level of future taxable profits together with future tax planning strategies (Note 16).

Valuation of financial instruments

As described in Note 39, the Group uses valuation techniques that include inputs that are not based on observable market data to estimate the fair value of certain types of financial instruments. Note 39 provides detailed information about the key assumptions used in the determination of the fair value of financial instruments.

Management believes that the chosen valuation techniques and assumptions used are appropriate in determining the fair value of financial instruments.

29 F-32 Fair value of net assets acquired and liabilities assumed in business combinations

In accordance with the Group’s policy, the Group allocated the cost of the acquired entity to the assets acquired and liabilities assumed based on their fair value estimated on the date of acquisition. The Group exercises significant judgment in the process of identifying tangible and intangible assets and liabilities, valuing these assets and liabilities, and estimating their remaining useful life. The valuation of these assets and liabilities is based on assumptions and criteria that, in some cases, include estimates of discounted future cash flows. Valuation assumptions used in determination of fair values may differ from actual results.

If actual results are not consistent with estimates and assumptions considered, the Group may be exposed to losses that could be material.

7. RECLASSIFICATIONS

In prior reporting periods certain transportation costs were presented within “Selling expenses”. Beginning in 2012, transportation costs were reclassified and presented as part of “Production costs of oil products”. Comparative information for the year ended 31 December 2011 has been reclassified to achieve consistency with the method of presentation adopted in the year ended 31 December 2012. Reclassifications were based upon management’s decision to enhance disclosure of the Group’s results of operations through presentation of transportation costs related to oil products purchased for resale in accordance with their substance.

Before After reclassification reclassification Effect

Production costs of oil products (1,631,909) (1,635,262) (3,353) Selling expenses (289,924) (286,571) 3,353

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8. SEGMENT INFORMATION

For management purposes, the Group is organised into separate reporting segments based on the nature of the Group’s operations. There are two business segments: the upstream segment, which includes crude oil and gas exploration, extraction and production, and the downstream segment, which includes oil refining, transportation and sales of oil products. Management reviews and evaluates the performance of these segments on a regular basis. Operations of the Parent company and subsidiaries involved in non-core activities are disclosed as “Other companies”, none of which meet the criteria for separate reporting.

The CODM assesses the performance of the operating segments based on segment adjusted EBITDA (Earnings Before Interest, Tax, Depreciation and Amortisation). Segment financial information provided to the CODM is prepared using the management accounts and includes segment adjusted EBITDA as the measure of profitability used by the CODM to allocate finance and make operational decisions. Segment adjusted EBITDA is prepared on a basis that does not directly align with IFRS. The explanations of differences to IFRS are included below, as a reconciliation of segment adjusted EBITDA (on a non-IFRS basis) to adjusted EBITDA (on an IFRS basis), which in turn is reconciled to profit before tax.

Business segment assets and liabilities are not reviewed by the CODM and therefore are not disclosed in these consolidated financial statements.

30 F-33 Financial information by reportable segments is presented below:

Inter- segment Recon- Down- Other elimi- ciling Year ended 31 December 2012 Upstream stream companies nations items Total

Total segment revenue 1,017,934 2,984,585 45,611 (589,383) (13,508) 3,445,239 Less inter-segment revenue (396,290) (147,482) (45,611) 589,383 - - Revenue from external customers 621,644 2,837,103 - - (13,508) 3,445,239

Segment adjusted EBITDA 518,638 276,348 (46,403) (537) (13,950) 734,096

Supplemental information provided to CODM:

Depreciation, depletion and amortisation (149,528) (41,922) (332) - (592) (192,374) Reversal of impairment of oil and gas assets 59,362 - - - (641) 58,721 Interest income 7,023 51,801 76,680 (120,447) (80) 14,977 Finance costs (71,957) (73,974) (65,362) 86,671 29,588 (95,034)

Profit before tax 373,192 248,993 (28,872) (34,200) (14,697) 544,416 Income tax expense (84,889) (44,068) (3,925) - 9,236 (123,646) Profit for the year 288,303 204,925 (32,797) (34,200) (5,461) 420,770

Additions to property, plant and equipment 371,457 452,247 777 - - 824,481 Share of profits of associates and joint venture - 362 1,947 - - 2,309

Inter- segment Recon- Down- Other elimi- ciling Year ended 31 December 2011 Upstream stream companies nations items Total

Total segment revenue 883,074 2,843,125 40,432 (683,489) (482) 3,082,660 Less inter-segment revenue (342,944) (300,113) (40,432) 683,489 - - Revenue from external customers 540,130 2,543,012 - - (482) 3,082,660

Segment adjusted EBITDA 413,857 315,955 (23,116) (230) (16,121) 690,345

Supplemental information provided to CODM:

Depreciation, depletion and amortisation (134,699) (38,198) (449) - (849) (174,195) Interest income 5,560 6,927 106,256 (106,389) (95) 12,259 Finance costs (51,088) (28,041) (92,131) 93,044 19,082 (59,134)

Profit before tax 240,740 195,500 (15,140) (13,501) 25,162 432,761 Income tax expense (59,076) (39,110) (4,721) - (1,564) (104,471) Profit for the year 181,664 156,390 (19,861) (13,501) 23,598 328,290

Additions to property, plant and equipment 652,959 431,106 346 - - 1,084,411 Share of profits of associates - 256 1,897 - - 2,153

Upstream and downstream segment revenue includes revenue from sales of crude oil and oil products, respectively, and income from other non-core activities.

31 F-34 The Group has one customer that comprises more than 10% of the Group’s revenue. The total revenue from this customer for each segment was as follows:

Year ended 31 December 2012 Year ended 31 December 2011 % of segment % of segment Revenue revenue Revenue revenue Upstream 9,445 1% 66,108 7% Downstream 861,334 29% 775,602 27%

The reconciliation of segments’ adjusted EBITDA (on a non-IFRS basis) to adjusted EBITDA on an IFRS basis includes the following reconciling items:

 Elimination of unrealised gains/losses on intra-segment operations;  Effect of difference in exchange rates applied;  Tax effect on the above mentioned adjustments.

Prices used in transactions between reportable segments are determined on an arm’s length basis in a manner equal to transactions with third parties, except for interest-free loans provided and obtained.

Reconciliation of the segments’ adjusted EBITDA to adjusted EBITDA on an IFRS basis to profit before tax is presented below:

Year ended Year ended 31 December 31 December 2012 2011 Adjusted EBITDA of reportable segments 794,986 729,812 Adjusted EBITDA of other companies (46,403) (23,116) Inter-segment eliminations (537) (230) Effect of reconciling items (13,950) (16,121) Adjusted EBITDA (on an IFRS basis) 734,096 690,345 Depreciation, depletion and amortisation (192,374) (174,195) Reversal of impairment of oil and gas assets 58,721 - Loss on disposal of shares in subsidiaries - (2,894) Interest income 14,977 12,259 Finance costs (95,034) (59,134) Gain/(loss) on derivatives classified as held for trading, net 7,678 (15,444) Currency exchange gain/(loss), net 21,688 (18,176) Other (5,336) - Profit before tax 544,416 432,761

Geographical information

The Group operates in two geographical areas, Russia and Kazakhstan. For management accounting purposes activities in Kazakhstan are considered to be not significant.

The Group’s revenue from external customers by geographical location is as follows:

Year ended Year ended 31 December 31 December 2012 2011 Switzerland 1,039,230 983,177 Germany 79,453 19,461

China 77,102 37,193 Austria 76,620 56,265 Other foreign countries 332,994 152,119 1,605,399 1,248,215 Domestic revenue2 1,839,840 1,834,445 3,445,239 3,082,660

2 This relates to revenue in respect of Russia (from Russian subsidiaries) and Kazakhstan (from Kazakhstan subsidiary). The disclosure requirements of IFRS 8 dictate using a company’s country of domilice, but since no revenues are earned in Bermuda, this wouldn’t be useful disclosure. As such, the above has been presented instead.

32 F-35 9. PRODUCTION COSTS OF CRUDE OIL

Year ended Year ended 31 December 31 December 2012 2011

Production tax 203,059 201,847 Payroll and related taxes 48,887 47,397 Taxes other than income and production tax 35,501 29,425 Materials and fuel 19,430 17,183 Repairs and maintenance 17,231 12,921 Transportation 10,413 17,917 Oil preparation 6,835 3,752 Insurance 5,704 4,684 Energy 4,751 5,604 Rent 4,409 4,339 Other 9,661 7,978

365,881 353,047

Production costs of crude oil represent cost of crude oil sold both intragroup and to external customers. Production costs of crude oil sold intragroup amounted to TUSD 202,927 for the year ended 31 December 2012 (2011: TUSD 189,027).

10. PRODUCTION COSTS OF OIL PRODUCTS

Year ended Year ended 31 December 31 December 2012 2011

Crude oil purchased for refining 913,325 799,661 Transportation 528,725 513,426 Oil products purchased for re-sale 244,818 132,877 Taxes other than income tax 141,560 121,054 Payroll and related taxes 32,485 30,881 Other 37,867 37,363

1,898,780 1,635,262

Transportation costs include cost of delivery of crude oil to the Khabarovsk Oil Refinery and related insurance expenses.

11. SELLING EXPENSES

Year ended Year ended 31 December 31 December 2012 2011

Transportation 201,907 182,249 Payroll and related taxes 59,145 55,820 Repairs and maintenance 15,778 13,960 Energy and utilities 7,548 7,005 Taxes other than income tax 7,024 7,726 Export related expenses 3,162 3,240 Insurance 3,148 3,791 Advertising and marketing 2,642 1,744 Rent 2,299 2,039 Other 11,934 8,997

314,587 286,571

33 F-36 12. ADMINISTRATIVE EXPENSES

Year ended Year ended 31 December 31 December 2012 2011

Payroll and related taxes and share options 41,390 33,971 Professional fees (legal, audit, consulting, etc.) 21,459 13,261 Rent 14,892 14,358 Bank charges 3,146 3,608 Advertising and marketing 3,057 2,771 Taxes other than income tax 2,773 2,269 Other 9,023 7,219

95,740 77,457

Deloitte was an auditor of the Group’s consolidated IFRS financial statements for the years ended 31 December 2012 and 2011. The Group had the following audit related expenses:

Year ended Year ended 31 December 31 December 2012 2011

Deloitte - audit 1,904 1,782 Deloitte - consulting 922 835 CJSC Audit Consult - audit 602 648 Other - audit and consulting 942 806

4,370 4,071

13. OTHER OPERATING EXPENSES, NET

Year ended Year ended 31 December 31 December 2012 2011

Charity donations 9,986 12,736 Loss on disposal of assets 5,948 3,196 Other 3,551 2,288

19,485 18,220

Charity donations primarily represent contributions to the Fund named after Z. Bazhaev.

14. FINANCE COSTS

Year ended Year ended 31 December 31 December 2012 2011

Interest expense on bonds 117,883 105,809 Interest expense on loans and borrowings 39,824 22,582 Total interest expense for financial liabilities not classified as at fair value through profit or loss 157,707 128,391

Amortisation of debt issue costs and bank commissions 24,524 18,937 Unwinding of discount on provision for decommissioning and site restoration costs (Note 31) 2,829 3,214

Less: amounts included in the cost of qualifying assets (90,026) (91,408)

95,034 59,134

Capitalised borrowing costs relate to loans obtained for the purposes of modernising the Khabarovsk Oil Refinery and developing oil and gas fields.

34 F-37 15. DERIVATIVES CLASSIFIED AS HELD FOR TRADING

In June and August 2011, the Group entered into two cross-currency interest rate swaps in order to balance cash inflows from export sales denominated in USD with cash outflows on interest payments denominated in RUB, and obtain a lower interest rate. Due to the absence of a designated hedge relationship between a hedging instrument and a hedged item, hedge accounting has not been applied. Swap 1 was settled in July 2012. Swap 2 matures in July 2013.

Swap 1 Swap 2 Total

At 1 January 2011 - - - Loss on derivatives classified as held for trading (5,518) (10,114) (15,632) Interest on swap received during the year 188 - 188 Translation difference 423 1,175 1,598 At 31 December 2011 (4,907) (8,939) (13,846) Gain on derivatives classified as held for trading 480 7,198 7,678 Interest on swap received during the year (1,011) (2,403) (3,414) Effect on settlement of swap contract 5,544 - 5,544 Translation difference (106) (500) (606)

At 31 December 2012 - (4,644) (4,644)

In 2012, the Group received interest on swaps in the amount of TUSD 3,414 and settled a cross currency swap with notional amount of TRUB 1,000,000 through cash payment in the amount of TUSD 5,544 resulting in net cash outflow in the amount of TUSD 2,130 presented in the consolidated statement of cash flows within "Payments on settlement of swap contract, net of interest received".

16. INCOME TAX

The Parent company, Alliance Oil Company Ltd, which is registered in Bermuda, is exempt from income tax.

The statutory income tax rate in the Russian Federation, the location of the majority of the Group’s entities, is 20%. OJSC Khabarovsk Oil Refinery applies a 15.5% income tax rate due to the decreased regional budget component of the income tax.

The profit of LLC Potential Oil, a Kazakhstan subsidiary, is subject to a 30% income tax rate.

The profit of Cypriot subsidiaries, Vostok Oil (Cyprus) Ltd and O&G Credit Agency Ltd, is subject to income tax at the rate of 10%. On taxable profits above 1 million euro (EUR) an additional tax of 5% is imposed.

Income tax recognised in the consolidated statement of profit or loss:

Year ended Year ended 31 December 31 December 2012 2011

Current tax 95,676 83,246 Deferred tax 27,970 21,225

Total income tax expense 123,646 104,471

35 F-38 The income tax expense recorded in the consolidated statement of profit or loss differs from the theoretical amount that would have arisen applying the tax rate to the profit before income tax by jurisdiction and is reconciled as follows:

Year ended Year ended 31 December 31 December 2012 2011

Profit before tax 544,416 432,761

Theoretical tax at rate 20% for Russian Federation 79,844 60,390 Theoretical tax at rate 15.5% for Russian Federation 18,489 17,243 Theoretical tax at rate 30% for Kazakhstan 15,521 11,964 Theoretical tax at other rates 3,464 2,499 Non-deductible charity expenses 2,716 2,825 Effect of intragroup dividends received - 2,850 Other 3,612 6,700 Total income tax expense 123,646 104,471 Effective tax rate for the Group 23% 24%

The movement in the Group's net deferred tax liabilities was as follows:

Year ended Year ended 31 December 31 December 2012 2011

Net deferred tax liabilities at beginning of the year 161,559 152,712 Recognised in the consolidated statement of profit or loss 27,970 21,225 Effect of currency exchange differences on intercompany loans 3,435 (2,256) Acquired on acquisition of subsidiaries (Note 36) 31,817 589 Translation difference 11,690 (10,711)

Net deferred tax liabilities at end of the year 236,471 161,559

Certain deferred tax assets and liabilities have been offset in accordance with the Group’s accounting policy. The analysis of the deferred tax balances (after offset) as they are recorded in the consolidated statement of financial position is presented below:

31 December 31 December 2012 2011

Deferred tax liabilities 265,002 187,998 Deferred tax assets (28,531) (26,439)

Net deferred tax liabilities 236,471 161,559

The tax effects on the major temporary differences that gave rise to the deferred taxation as at 31 December 2012 and 2011 are presented below:

31 December 31 December 2012 2011

Property, plant and equipment 282,086 194,363 Inventories (5,017) (4,682) Trade, other receivables and prepaid expenses (534) (1,224) Effect of currency exchange differences on intercompany loans (3,274) (4,719) Valuation of loans and borrowings 5,863 6,779 Trade, other payables and accrued expenses (6,124) (5,888) Derivatives classified as held for trading (929) (2,769) Tax loss carry-forward (35,540) (24,599) Other (60) 4,298

Net deferred tax liabilities 236,471 161,559

36 F-39 Deferred tax liabilities have not been recognised for the following temporary differences associated with investments in subsidiaries:

Applicable for dividends tax 31 December 31 December Investor country of incorporation rate 2012 2011

Russian Federation 0% 845,824 688,164 Russian Federation 9% 385,091 30,294 Cyprus 5% 196,214 166,753 Luxembourg 0% 89,176 -

17. EARNINGS PER SHARE

Basic earnings per share

Year ended Year ended 31 December 31 December 2012 2011

Profit attributable to owners of the Company 402,833 318,873 Preference dividends for cumulative preference shares required for the year (Note 28) (5,768) - 397,065 318,873

Weighted average number of ordinary shares in issue 171,528,414 171,528,414

Basic earnings per share 2.31 1.86

Diluted earnings per share

Diluted earnings per share are calculated by adjusting the weighted average number of ordinary shares outstanding to assume conversion of dilutive potential ordinary shares. The Company has the following categories of dilutive potential ordinary shares: convertible bonds and share options.

For the year ended 31 December 2012, convertible bonds with a conversion price of SEK 121.13 (USD 15.94 at fixed exchange rate) were the only instruments which influenced the calculation of diluted earnings per share. Share options had no potentially dilutive effect.

For the year ended 31 December 2011, the following instruments influenced the calculation of diluted earnings per share:

 Convertible bonds with a conversion price of SEK 121.13 (USD 15.94 at fixed exchange rate) (Note 30);  437,700 share options with an exercise price of SEK 81.80 (USD 11.87 at the exchange rate on the reporting date); and  614,934 share options with an exercise price of SEK 85.00 (USD 12.33) per share (Note 28).

For the year ended 31 December 2011, the following instruments were antidilutive:

 578,850 share options with an exercise price of SEK 124.00 (USD 17.99 at the exchange rate on the reporting date);  50,000 share options with an exercise price of SEK 111.00 (USD 16.11 at the exchange rate on the reporting date); and  934,912 share options with an exercise price of SEK 115.00 (USD 16.69 at the exchange rate on the reporting date).

The convertible bonds are assumed to have been converted into ordinary shares, and the net profit is adjusted to eliminate the finance costs. Assumed conversion of convertible bonds results in the issuance of 16,624,791 ordinary shares.

37 F-40 For the share options, a calculation is performed to determine the number of shares that could have been acquired at fair value (determined as the average annual market share price of the Company’s shares). The number of shares calculated as above is compared with the number of shares that would have been issued assuming the conversion of bonds and exercise of the share options.

Year ended Year ended 31 December 31 December 2012 2011

Earnings used in the calculation of basic earnings per share 402,833 318,873 Preference dividends for cumulative preference shares required for the year (Note 28) (5,768) - Finance costs on convertible bonds recognised in the consolidated statement of profit or loss 12,251 9,709 Earnings used in the calculation of diluted earnings per share 409,316 328,582

Weighted average number of ordinary shares in issue 171,528,414 171,528,414 Adjustments for: – Assumed conversion of convertible bonds 16,624,791 16,624,791 – Share options - 169,883 Weighted average number of ordinary shares used in the calculation of diluted earnings per share 188,153,205 188,323,088

Diluted earnings per share 2.18 1.74

18. PROPERTY, PLANT AND EQUIPMENT

Oil and gas Refining Marketing and assets assets other assets Total Cost At 31 December 2011 2,432,883 1,181,055 282,339 3,896,277 Reclassifications (502) - 502 - Additions 359,234 417,753 47,494 824,481 Acquisitions through business combination (Note 36) 303,734 - 146 303,880 Additions to provision for decommissioning and site restoration costs (Note 31) 53,526 - - 53,526 Disposals (9,306) (3,154) (3,713) (16,173) Translation difference 156,820 82,969 16,767 256,556 At 31 December 2012 3,296,389 1,678,623 343,535 5,318,547

Accumulated depletion and depreciation At 31 December 2011 (393,400) (86,772) (87,076) (567,248) Charge for the year (154,218) (24,433) (19,998) (198,649) Disposals 1,137 1,298 1,471 3,906 Translation difference (25,549) (5,741) (5,217) (36,507) At 31 December 2012 (572,030) (115,648) (110,820) (798,498)

Accumulated impairment At 31 December 2011 (105,231) - - (105,231) Reversal of impairment 58,721 - - 58,721 Depletion of accumulated impairment 5,765 - - 5,765 Translation difference (4,705) - - (4,705) At 31 December 2012 (45,450) - - (45,450)

Net book value at 31 December 2012 2,678,909 1,562,975 232,715 4,474,599

38 F-41 Oil and gas Refining Marketing and assets assets other assets Total Cost At 31 December 2010 1,944,048 858,843 270,508 3,073,399 Reclassifications (535) - 535 - Additions 651,303 403,326 29,782 1,084,411 Acquisitions through business combination (Note 36) - - 8,403 8,403 Additions to provision for decommissioning and site restoration costs (Note 31) 569 - - 569 Disposals (3,300) (1,925) (3,791) (9,016) Derecognised on disposal of a subsidiary - - (6,334) (6,334) Translation difference (159,202) (79,189) (16,764) (255,155) At 31 December 2011 2,432,883 1,181,055 282,339 3,896,277

Accumulated depletion and depreciation At 31 December 2010 (279,057) (73,049) (76,235) (428,341) Charge for the year (141,095) (20,349) (17,150) (178,594) Disposals 1,460 1,030 1,745 4,235 Derecognised on disposal of a subsidiary - - 540 540 Translation difference 25,292 5,596 4,024 34,912 At 31 December 2011 (393,400) (86,772) (87,076) (567,248)

Accumulated impairment At 31 December 2010 (116,814) - - (116,814) Depletion of accumulated impairment 5,872 - - 5,872 Translation difference 5,711 - - 5,711 At 31 December 2011 (105,231) - - (105,231)

Net book value at 31 December 2011 1,934,252 1,094,283 195,263 3,223,798

As a result of the impairment test performed for upstream segment assets, the previously recognised impairment loss in the amount of TUSD 58,721 was reversed. The reversal related to the Tomsk cash generating unit and reflected the fact that conditions that gave rise to impairment loss in prior years, have improved. In performing impairment test, management took into consideration significant increase in oil price projections and the relative stability of reserves for the two consecutive years.

Exploration and evaluation assets

Exploration and evaluation assets included in property, plant and equipment mainly comprise capitalised exploration drilling costs and geological studies and seismic researches related to the exploration license oil fields and prospects located in the Volga-Urals, Timano-Pechora and Tomsk regions of the Russian Federation.

Year ended Year ended 31 December 31 December 2012 2011

Balance at beginning of the year 32,950 37,121 Transfers to oil and gas assets - (11,744) Additions 47,846 9,322 Acquisition of exploration license 9,650 - Translation difference 4,200 (1,749)

Balance at end of the year 94,646 32,950

Additions to exploration and evaluation assets for the year ended 31 December 2012 included acquisition of an exploration license for the West-Osoveiskoye block in the Timano-Pechora region in Northern Russia for the total consideration of TUSD 30,026 (Note 36).

Investing cash flows arising from the exploration for and evaluation of crude oil and gas, recorded in the consolidated statement of cash flows within “Investments in oil and gas assets”, for the year ended 31 December 2012 amounted to TUSD 47,150 (2011: TUSD 9,322).

39 F-42 19. GOODWILL

Year ended Year ended 31 December 31 December 2012 2011 Balance at beginning of the year 19,239 11,728 Additional amounts recognised from business combination (Note 36) - 8,947 Translation difference 1,155 (1,436) Balance at end of the year 20,394 19,239

At 31 December 2012, the Group performed an impairment test in respect of goodwill. For the purpose of such testing, goodwill was allocated to a cash-generating unit "Downstream segment" (Note 8). No impairment loss has been identified.

20. INVESTMENTS IN ASSOCIATES AND JOINT VENTURE

Details of the Group's joint venture and associates at 31 December 2012 and 2011 were as follows:

31 December 2012 31 December 2011 Proportion Proportion of of ownership ownership and voting and voting power power held by held by Country of Carrying the Group, Carrying the Group, Name of the entity Type Principal activity incorporation value % value % AR Oil & Gaz B.V. Joint venture Holding company Netherlands 162,537 51% - - Trading of crude oil and oil Lia Oil S.A. Associate products Switzerland 23,964 40% 21,505 40% Trading of oil Russian LLC Dalnefteresource Associate products Federation 690 49% 321 49% 187,191 21,826

Investment in joint venture

In 2011, the Group established a new entity AR Oil & Gaz B.V. (“AROG”) registered in the Netherlands, with a purpose of its further conversion into a joint venture with Repsol Exploracion, S.A. (“Repsol”). At the point of establishment AROG was wholly-owned by the Group, and had no assets, liabilities or operations.

On 16 August 2012, the Group contributed to AROG 100% of its shares in CJSC Saneco (“Saneco”). On the same date, the share capital of AROG was increased and 49% of the resulting share capital was transferred to Repsol in exchange for TUSD 35,660 in cash paid directly to the Group and a contribution of TUSD 37,302 in cash into AROG. As a result of these transactions, the Group’s ownership interest in AROG decreased to 51%.

On 20 December 2012, the Group contributed 99.54% of its shares in OJSC Tatnefteotdacha (“TNO”) into AROG, and AROG issued shares to the Group in exchange. The Group then sold these shares to Repsol for TUSD 224,591, of which TUSD 81,068 was paid in cash by Repsol directly to the Group, and the remaining TUSD 143,523 to be met by contributing their subsidiary OJSC Eurotek (“Eurotek”) to the joint venture arrangement, under the same terms that the Group contributed Saneco and TNO. The subsidiary contribution was recorded as a receivable within investment in joint venture as at 31 December 2012 as the contribution of Eurotek did not legally occur until January 2013. In January 2013, the formation of the joint venture was completed through Repsol contributing Eurotek to AROG.

As noted in Note 2, the Group continues to consolidate Saneco and TNO on the basis that the Group has a fair value option that is deemed in the money. Repsol has the same fair value option over Eurotek. As such, AROG does not control any of the contributed subsidiaries, but does have significant influence. To avoid double-counting, the Group does not equity account for the impact of Saneco and TNO on AROG’s results, and only equity accounts for the remaining portion of AROG. As such, the Group’s investment in AROG was accounted for under the equity method, as a 51% share in the joint venture’s net assets, excluding the investment in Saneco and TNO.

40 F-43 Following the contribution of Saneco and TNO to AROG and transfer of 49% interest to Repsol, the total balance of non-controlling interests in respect of these subsidiaries increased and was recognised in the consolidated financial statements in the amount of TUSD 183,572, with any difference between the cash received, increase in non-controlling interests, and the Group’s share in the net assets of AROG being recognised in equity.

The net cash inflow in respect of this joint venture investment was TUSD 116,728, being the TUSD 35,660 cash contribution for Saneco and TUSD 81,068 cash contribution for TNO.

Carrying value of investment in AROG, excluding Saneco and TNO, at 31 December 2012 was as follows:

31 December 2012 Net assets 37,284 Voting power held by the Group 51% Group's share of net assets 19,014 OJSC Eurotek contribution outstanding 143,523 Carrying value of investment 162,537

The Group’s share in the joint venture’s net loss from 16 August to 31 December 2012 of TUSD 89 was recognised in profit or loss.

Following the contribution of CJSC Saneco and OJSC Tatnefteotdacha, a non-controlling interest representing 49% of the CJSC Saneco net assets and 48.78% of the OJSC Tatnefteotdacha net assets was recognised in the consolidated financial statements in the amount of TUSD 183,572.

Investments in associates

In May 2011, the Group completed the acquisition of a 40% share in the capital of Lia Oil S.A. from a related party for a cash consideration of TUSD 20,000.

Summarised financial information in respect of Lia Oil S.A. is set out below:

31 December 31 December 2012 2011 Non-current assets 24,260 10,178 Current assets 187,619 247,399 Non-current liabilities (8,577) - Current liabilities (149,583) (210,005)

Year ended Year ended 31 December 31 December 2012 2011 Revenue 2,696,428 1,698,087 Profit for the period 5,037 4,742 Total comprehensive income 5,037 4,742

Group’s share of profit of Lia Oil S.A. for the year ended 31 December 2012 amounted to TUSD 2,015 (2011: TUSD 1,897).

A reconciliation of the above summarised financial information to the carrying value of investment in the associate recognised in the consolidated financial statements:

31 December 31 December 2012 2011 Net assets 53,719 47,572 Proportion of ownership and voting power held by the Group 40% 40% Group's share of net assets 21,488 19,029 Goodwill recognised in cost of investment 2,476 2,476 Carrying value of investment 23,964 21,505

The carrying amount of the Group’s interest in LLC Dalnefteresource at 31 December 2012 amounted to TUSD 690 (2011: TUSD 321). Group’s share of profit of LLC Dalnefteresource for the year ended 31 December 2012 amounted to TUSD 383 (2011: TUSD 256).

41 F-44 21. OTHER FINANCIAL ASSETS

31 December 31 December 2012 2011

Bank deposits placed with third party banks 34,464 25 Bank deposits placed with a related party bank - 26,090 Loans 14,020 64,973 Derivatives classified as held for trading (Note 15) 1,337 2,175

49,821 93,263

Bank deposits placed with third party banks are denominated in RUB and bear interest of 7.1% - 7.7% (2011: 10.25%) per annum with original maturity of more than three months.

At 31 December 2012, loans provided to third parties include:

 non-collateralised RUB-denominated short-term loan bearing interest of 10% per annum with maturity in July 2013; and  non-collateralised RUB-denominated non-interest bearing short-term loan with maturity in January 2013.

At 31 December 2011, loans provided to third parties include:

 non-collateralised RUB-denominated short-term loan bearing interest of 10% per annum; and  USD-denominated short-term loan bearing interest of 10.59% per annum, which is collateralised by 100% of the borrower’s own shares and 100% of the shares of the borrower’s subsidiary.

22. OTHER ASSETS

31 December 31 December 2012 2011

Long-term prepaid expenses 2,186 - Value added tax (VAT) recoverable after 12 months 656 29,878 Other 149 167

2,991 30,045

23. INVENTORIES

31 December 31 December 2012 2011

Oil products 114,661 67,816 Crude oil 81,649 55,207 Other inventories 32,809 23,029 Allowance for slow-moving and obsolete inventories (1,128) (1,023)

227,991 145,029

24. TRADE AND OTHER ACCOUNTS RECEIVABLE

31 December 31 December 2012 2011

Trade accounts receivable 99,482 87,183 Other accounts receivable 26,418 29,459 Less: allowance for doubtful debts (9,532) (3,037)

116,368 113,605

42 F-45 The majority of retail and wholesale customers operate on the advance payment terms. The credit period for other customers does not exceed 30 days. No interest is charged on the outstanding balances. The Group monitors trade accounts receivable through a special committee on a monthly basis. The concentration of credit risk is limited due to the customer base being large and unrelated.

At 31 December 2012 and 2011, balances of the Group’s largest customers each exceeded 10% of the outstanding balance of trade accounts receivable:

31 December 31 December 2012 2011

Company A 19,112 20,069 Company B 15,120 5,818 Company С 14,658 - Company D - 16,696

Based on the past history of transactions with these customers management believes that there is no specific credit risk attached to them.

Allowance for doubtful debts is recognised in respect of estimated irrecoverable amounts determined by reference to past default experience of the counterparty and analysis of the counterparty's current financial position.

The movements in the allowance for trade and other accounts receivable are presented below:

Year ended Year ended 31 December 31 December 2012 2011

Balance at beginning of the year 3,037 7,204 Additions to allowance 8,323 753 Release of allowance (48) (791) Amounts written-off (2,103) (4,113) Translation difference 323 (16)

Balance at end of the year 9,532 3,037

At 31 December 2012, included in the allowance for doubtful debts are individually impaired but not past due interest receivable amounting to TUSD 5,505 (2011: nil).

Ageing of fully and partially impaired trade and other receivables:

31 December 31 December 2012 2011

Less than 90 days 50 28 90-365 days 6,838 3,009

6,888 3,037

The Group has past due balances of trade and other receivables for which no allowance was created as the management considered such balances as recoverable. Ageing of past due but not impaired trade and other receivables is presented below:

31 December 31 December 2012 2011

Less than 90 days 3,363 4,072 90-365 days 1,817 3,745

5,180 7,817

43 F-46 25. VALUE ADDED TAX AND OTHER TAXES RECEIVABLE

31 December 31 December 2012 2011

VAT recoverable within 12 months 264,003 202,805 Export and other custom duties 28,904 20,870 Other taxes receivable 3,329 877

296,236 224,552

26. ADVANCES PAID AND PREPAID EXPENSES

31 December 31 December 2012 2011

Advances paid 154,205 118,744 Prepaid expenses 7,785 7,252 Less: impairment of advances paid (728) (89)

161,262 125,907

27. CASH, CASH EQUIVALENTS AND RESTRICTED CASH

31 December 31 December 2012 2011 Cash in banks: in USD 12,076 9,214 in RUB 56,049 14,280 in EUR 1,004 1,139 in other currencies 1,169 1,808 Cash in transit 7,817 3,952 Cash deposits: in USD 219,631 9,308 in RUB 80,972 116,633 in EUR 2,116 2,006 in other currencies 1,538 - Petty cash 2,441 1,974 Other 120 169 384,933 160,483 Restricted cash: in USD 1,069 1,115 in EUR 25,818 26,203 26,887 27,318

411,820 187,801

At 31 December 2012, cash deposits bear interest of 0.01%-7.6% (2011: 0.4%-7.1%) per annum with an original maturity within three months.

Restricted cash is represented by letters of credit on a special account with OJSC Bank VTB in relation to agreements for the reconstruction of OJSC Khabarovsk Oil Refinery.

44 F-47 28. SHARE CAPITAL AND RESERVES

Share capital

Share capital comprises:

31 December 31 December 2012 2011

171,528,414 fully paid ordinary shares 171,528 171,528 5,000,000 fully paid preference shares 5,000 -

176,528 171,528

At 31 December 2012, the authorised share capital of the Parent company amounted to 220,000,000 ordinary or preference shares (2011: 220,000,000 ordinary shares).

Each ordinary share had a par value of USD 1 and carried one vote.

In December 2012, 5,000,000 preference shares (Swedish Depository Receipts) were issued with a subscription price of SEK 270 and a par value of USD 1 per share raising TSEK 1,350,000 before issue costs (TUSD 202,329 as of settlement date). The financing raised after issue costs amounted to TSEK 1,309,589 (TUSD 196,272 as of settlement date and TUSD 200,891 as of the date of cash transfer). Following the transaction, total number of the Company’s shares increased to 176,528,414.

The following terms and conditions apply to the preference shares issued:

 Preference shares have 1/10 vote each;  Preference shares dividends were set at SEK 30 per share per year;  Dividend payments are subject to resolution by the annual general meeting;  If no dividend is paid on preference shares with respect to any quarter, holders of preference shares are entitled to receive in addition to dividends for the current period the full outstanding amount of dividends for the prior periods;  The outstanding amount shall be increased by an annual interest rate of 14% calculated from the quarterly date on which the dividend payment should have been made, where no or insufficient dividend was paid, to the date of actual payment;  No dividend or other distribution to holders of ordinary shares may be paid until preference shares have received full payment of any dividend due, plus any outstanding amount;  The preference shares can be redeemed by the Group at any time at a fixed redemption price of 130% of the subscription price plus any outstanding amount of dividends for the prior periods.

On 14 December 2012, at Special General meeting shareholders approved the proposal of the Board of direсtors to pay a dividend on preference shares of SEK 7.50 (in the total amount of TUSD 5,768) with a record date for the distribution being 28 February 2013.

Share option plan

The Group has a share option plan under which share options can be granted to eligible employees, including Group management and directors. Each option gives the right to subscribe for one share of common stock at the exercise price. All options are exercisable after 3 years subject to certain non- market vesting conditions, such as the Group’s and individual performance, and expire in 5 years from issuance. The fair value of the employee services received in exchange for the grant of the options is recognised as an expense. The total amount to be expensed over the vesting period of 3 years is determined by reference to the fair value of the options granted excluding the impact of any non-market vesting conditions. For the years ended 31 December 2012 and 2011, the share option charge amounted to TUSD 1,667 and TUSD 1,357, respectively, and was recorded within administrative expenses.

45 F-48 Movements in the number of share options outstanding and their related weighted average exercise prices are presented below:

Year ended 31 December 2012 Year ended 31 December 2011 Average Average exercise price in Number of exercise price in Number of SEK per share options SEK per share options

At beginning of the year 104.31 2,615,879 115.54 3,769,753 Granted during the year 55.00 749,522 85.00 614,934 Expired during the year 122.97 (628,850) 125.06 (1,588,700) Forfeited during the year - - 90.41 (180,108)

At end of the year 86.51 2,736,551 104.31 2,615,879

Share options outstanding at 31 December 2012 and 2011 had the following grant and expiry dates and exercise prices:

Fair value Exercise price Number of options outstanding in SEK in SEK 31 December 31 December Grant date Expiry date per share per share 2012 2011

28 February 2007 28 February 2012 38.40 124.00 - 578,850 22 May 2007 22 May 2012 34.40 111.00 - 50,000 2 May 2008 2 May 2013 27.80 81.80 437,700 437,700 20 August 2010 20 August 2015 22.28 115.00 934,395 934,395 23 September 2011 23 September 2016 20.90 85.00 614,934 614,934 11 December 2012 11 December 2017 12.77 55.00 749,522 -

2,736,551 2,615,879

The weighted average remaining contractual life for share options outstanding at 31 December 2012 was 3.15 years (2011: 2.68 years).

Options were priced using a Black-Scholes option pricing model. The significant inputs into the share options valuation model were reference share prices at the grant dates and the exercise prices as shown above, volatility varied in the range between 30% and 48%, no dividend yield, an expected option life of 5 years, and annual risk-free interest rate varied between 2% and 5%. The volatility measured at the standard deviation of continuously compounded share returns is based on statistical analysis of daily share prices over the last 3 years.

At 31 December 2012 and the date of authorisation of the consolidated financial statements 2,736,551 (2011: 2,615,879) options were outstanding and 437,700 (2011: 1,066,550) options were exercisable out of which none have been exercised.

46 F-49 29. NON-CONTROLLING INTERESTS

The table below show details of non-wholly-owned subsidiaries of the Group that had material non- controlling interests for the year ended 31 December 2012:

OJSC OJSC OJSC Tatnefte- LLP Potential Khabarovsk Khabarovsk- Other CJSC Saneco otdacha Oil Oil Refinery nefteproduct subsidiaries Total

Russian Russian Russian Russian Russian Country of incorporation Federation Federation Kazakhstan Federation Federation Federation Ownership held by non-controlling 0.34% - interests, % 49.00% 49.23% 20.36% 2.27% 11.11% 5.22% Voting rights held by non-controlling 0.34% - interests, % 49.00% 49.23% 20.00% 1.17% 7.15% 4.96%

Accumulated non- controlling interests at 31 December 2011 - 717 15,929 9,626 7,087 4,624 37,983 Profit attributable to non- controlling interests for the year ended 31 December 2012 8,681 269 7,067 2,606 (669) (17) 17,937 Disposal of non- controlling interests 86,187 97,385 - - - - 183,572 Changes in ownership of subsidiaries - - - (680) (389) - (1,069) Currency exchange differences on translating foreign operations 5,807 (249) 418 605 410 285 7,276 Accumulated non- controlling interests at 31 December 2012 100,675 98,122 23,414 12,157 6,439 4,892 245,699

Summarised financial information in respect of the Group’s subsidiaries that have the most material non-controlling interests is set out below. The summarised financial information below represents amounts before intragroup eliminations.

CJSC Saneco

31 December 2012

Non-current assets 199,104 Current assets 48,652 Non-current liabilities (11,872) Current liabilities (30,424)

Year ended From 16 August 31 December to 31 December 2012 2012

Revenue 211,211 91,462 Profit for the period 30,595 17,717 Total comprehensive income 41,032 28,993 Net increase in cash and cash equivalents 14,998 2,469

47 F-50 OJSC Tatnefteotdacha

31 December 2012

Non-current assets 154,253 Current assets 70,433 Non-current liabilities (12,920) Current liabilities (12,463)

Year ended 31 December 2012

Revenue 165,940 Profit for the year 59,114 Total comprehensive income 69,781 Net increase in cash and cash equivalents 16,051

30. LOANS AND BORROWINGS

31 December 2012 Currency Interest rate Principal Interest Total

Non-convertible interest bearing bonds RUB 8.85-9.75% 655,295 14,296 669,591 Non-convertible interest bearing Eurobonds USD 9.88% 346,959 10,561 357,520 Convertible interest bearing bonds USD 7.25% 254,417 4,003 258,420 Libor 3m + 3.85%-Libor Bank loans denominated in USD USD 6m+5.5% 329,550 3,924 333,474 Euribor Bank loans denominated in EUR EUR 6m+5.5% 175,088 4,548 179,636 Bank loans denominated in RUB RUB 10.9-12% 267,969 4,010 271,979 Total loans and borrowings 2,029,278 41,342 2,070,620 Current portion repayable within one year 401,606

Long-term loans and borrowings 1,669,014

31 December 2011 Currency Interest rate Principal Interest Total

Non-convertible interest bearing bonds RUB 8.85-9.75% 616,579 13,174 629,753 Non-convertible interest bearing Eurobonds USD 9.88% 345,772 10,561 356,333 Convertible interest bearing bonds USD 7.25% 248,302 4,003 252,305 Libor 1m + 3.6%-Libor Bank loans denominated in USD USD 6m+5.5% 233,601 3,060 236,661 Euribor Bank loans denominated in EUR EUR 6m+5.5% 142,077 3,963 146,040 Total loans and borrowings 1,586,331 34,761 1,621,092 Current portion repayable within one year 106,829

Long-term loans and borrowings 1,514,263

In the third quarter 2012, OJSC “Alliance” Oil Company and CJSC Alliance Oil, the wholly owned subsidiaries of the Group, obtained long-term loans from Gazprombank in a total amount of TRUB 5,000,000 (approximately TUSD 155,212 at the exchange rates on the dates of the transactions) with an interest rate of 10.90% per annum maturing in the third quarter 2017.

48 F-51 In February 2011, OJSC “Alliance” Oil Company issued TRUB 5,000,000 (approximately TUSD 170,248 at the exchange rate on the date of the transaction) of three-year bonds with a fixed coupon of 9.25% per annum maturing in February 2014.

In June 2011, OJSC “Alliance” Oil Company issued TRUB 10,000,000 (approximately TUSD 360,968 at the exchange rate on the date of the transaction) of ten-year bonds with a five-year put option and a fixed coupon for the five-year period of 8.85% per annum.

In 2011, bonds with a notional amount of TRUB 3,000,000 and a fixed coupon of 9.75% were swapped to USD through a cross currency interest swap contract bearing interest of 5.3%-5.8% in order to balance cash inflows from export sales denominated in USD with cash outflows on interest payments denominated in RUB and obtain a lower interest rate (Note 15). In July 2012, the Group settled a cross currency swap with notional amount of TRUB 1,000,000.

The weighted average effective interest rates were as follows:

31 December 31 December 2012 2011

Weighted average interest rate 8.23% 8.19%

At 31 December 2012 and 2011, 22% and 24%, respectively, of the Group’s borrowings were at floating interest rates.

At 31 December 2012 and 2011, loans and borrowings were collateralised by:

 97.73% (2011: 97.90%) of the Group's holding in OJSC Khabarovsk Oil Refinery;  100% of the Group's holding in LLC SN-Gasproduction (2011: nil);  Proceeds from sale of crude oil under the contract between OJSC Vostochnaya Transnationalnaya Kompaniya and one of its customers in the total amount of TUSD 330,000 (2011: TUSD 330,000);  Proceeds from sale of gas under the contract between LLC SN-Gasproduction and one of its customers in the total amount of TUSD 42,854 (2011: nil);  Property, plant and equipment with a carrying value of TUSD 137,540 (2011: TUSD 123,763).

The maturity profile of the Group’s loans and borrowings based on contractual undiscounted payments, including accrued interest for the two years ending 31 December 2014 and thereafter are as follows:

31 December 2012 Principal Interest Total

Within one year from 31 December 2012 361,050 171,845 532,895 Within second year from 31 December 2012 491,050 136,368 627,418 More than two years from 31 December 2012 1,232,924 251,450 1,484,374

2,085,024 559,663 2,644,687

The interest payments were based on the interest rate effective at 31 December 2012. The principal and interest payments denominated in RUB were converted into USD using the exchange rate at 31 December 2012.

The difference between principal as per maturity profile and principal as included in the consolidated statement of financial position relates to unamortised issue costs.

The Group is subject to external capital requirements imposed on Eurobonds and loans provided by CJSC UniCredit Bank and Gazprombank on the basis of debt to EBITDA ratio. At 31 December 2012, the Group complied with all capital requirements.

49 F-52 31. PROVISION FOR DECOMMISSIONING AND SITE RESTORATION COSTS

31 December 31 December 2012 2011

Balance at beginning of the year 15,440 15,960 New obligation raised 6,351 7,876 Used during the year (2,591) (2,407) Change in estimates 47,175 (7,307) Unwinding of discount on provision for decommissioning and site restoration costs (Note 14) 2,829 3,214 Additions through business combination (Note 36) 1,871 - Translation difference 2,120 (1,896)

Balance at end of the year 73,195 15,440

The provision was estimated by the Group based on the existing technology and current prices. The timing of decommissioning and site restoration obligations is determined as the expiry of the estimated period during which oil and gas fields will continue to bring economic benefits to the Group (between 2016 and 2107).

Key assumptions used for evaluation of provision for the year ended 31 December 2012 were discount rate of 11.36% (2011: 15.3%) and inflation rate of 5.5%-7% (2011: 5.5%-7%).

32. TRADE AND OTHER ACCOUNTS PAYABLE

31 December 31 December 2012 2011

Trade accounts payable 14,932 17,189 Other accounts payable 109,164 126,995 Dividends payable 5,768 -

129,864 144,184

The average credit period on purchases of goods and services in 2012 was 17 days (2011: 15 days). No interest is charged on the outstanding balance for trade and other accounts payable during the allowed credit period. The Group has financial risk management policies in place, which include budgeting and analysis of cash flows and payments schedules to ensure that all trade and other accounts payable are paid within the credit limit timeframe.

The table below summarises the maturity profile of the Group's trade and other accounts payable at 31 December 2012 and 2011 based on contractual undiscounted payments.

31 December 31 December 2012 2011

Due in less than 90 days 87,384 114,448 Due in 90-180 days 5,420 28,570 Due in 180-365 days 37,060 1,166

129,864 144,184

33. ADVANCES RECEIVED AND ACCRUED EXPENSES

31 December 31 December 2012 2011

Advances received 259,682 140,610 Wages and salaries payable 26,079 21,106 Accrued vacations 8,667 7,334 Accrued professional services fees 1,637 1,060 Other accrued expenses - 356

296,065 170,466

50 F-53 In September 2012, the Group received an advance from one of its customers for crude oil shipments during 18 months from the date of payment. At 31 December 2012, advances received were classified as non-current (TUSD 26,309) and current (TUSD 130,779) according to the agreed delivery schedule.

34. OTHER TAXES PAYABLE

31 December 31 December 2012 2011

VAT payable 28,523 31,985 Production tax 17,157 15,478 Excise tax 13,825 10,695 Other taxes 13,408 10,250

72,913 68,408

35. PERSONNEL COSTS

The Group's personnel costs for the years ended 31 December 2012 and 2011 are presented below:

Year ended Year ended 31 December 31 December 2012 2011

Remuneration to the members of the board of directors and the managing director (including related taxes, annual bonuses and share options) 5,552 5,811 Remuneration to other employees (including related taxes and pension costs, annual bonuses and share options) 176,355 162,258

181,907 168,069

The Group's personnel costs for the years ended 31 December 2012 and 2011 are recorded in the consolidated statement of profit or loss within “Production costs of crude oil”, “Production costs of oil products”, “Selling expenses” and “Administrative expenses”.

Annual bonuses accrued for the years ended 31 December 2012 and 2011 were based on financial performance against the budget and amounted to 10%-50% of the base salary of other employees depending on the position and individual performance. Total bonus for the year ended 31 December 2012 amounted to TUSD 18,410 to be paid in 2013 (2011: TUSD 14,567 paid in 2012), subject to Remuneration committee approval after the authorisation of annual financial statements of the Group.

The Group has the share option plan under which share options can be granted to eligible employees, including Group management and directors, for details refer to Note 28.

The average number of employees during the years ended 31 December 2012 and 2011 for the Group was 7,512 (unaudited) and 7,185 (unaudited), respectively.

Remuneration of the key management personnel

The Group has adopted the following principles for executive remuneration. The executive remuneration consists of a base salary, an annual bonus and participation in the Group’s long-term incentive plan. The annual bonus is capped at 50%–100% of the individual’s salary and is determined based on the Group’s and personal performance which are measured by several performance indicators, both operational and financial.

51 F-54 Remuneration paid to the key management personnel during the years ended 31 December 2012 and 2011:

2012 2011 Salary Bonus Total Salary Bonus Total Managing director – Mr. Arsen Idrisov 2,000 1,501 3,501 2,006 2,177 4,183 Other key management personnel 6,688 5,914 12,602 5,529 4,582 10,111 8,688 7,415 16,103 7,535 6,759 14,294

Total remuneration of the managing director and other key management personnel accrued for the year ended 31 December 2012 amounted to TUSD 16,787 (2011: TUSD 18,293).

The managing director is a member of the Group's board of directors. No board fees are paid to the managing director. The employment contract effective at 31 December 2012 may be terminated by the Group upon six months written notice to the managing director. Should the managing director decide to leave the Group he also has to give a six months notice. The managing director is entitled to a bonus with an amount not to exceed 50% of his annual salary and can be awarded a bonus up to 100% of his annual salary for specific projects as determined by the board of directors.

Other key management personnel includes the management of the Parent company and the corporate centre LLC “Alliance” Oil Company MC, which provides management services to the Group's subsidiaries.

Remuneration to the board members

Remuneration paid to the board of directors members during the years ended 31 December 2012 and 2011:

2012 2011 Board fee Other fee Total Board fee Other fee Total Chairman of the board 180 5 185 180 15 195 Other board members 600 50 650 595 50 645 780 55 835 775 65 840

Other fees represent remuneration paid to certain directors in connection with their work as part of the Remuneration and Audit committees.

Social security charges and defined benefit plans

Social security charges, recorded within payroll and related taxes, for the year ended 31 December 2012 included contributions to the Pension Fund of the Russian Federation of TUSD 23,101 (2011: TUSD 15,039).

The Group operates unfunded defined benefit plans for qualifying employees of its subsidiaries in the Russian Federation. Under the plans, the employees are entitled to flat retirement benefits payable on actual retirement, recurring social benefits to employees and retired employees, and flat payment on employee's death. No post-employment healthcare benefits are provided.

The present value of the defined benefit obligation and related past service cost were measured using the projected unit credit method by a professional independent actuary.

The principal assumptions used for the purposes of the actuarial valuations for the years ended 31 December 2012 and 2011 were as follows:

Discount rate 8.0% Expected rate of inflation 6.0% Expected rate of salary increase 7.5% Retirement age, years Male 59.0 Female 54.5

52 F-55 Movements in the present value of the defined benefit obligation were as follows:

Year ended Year ended 31 December 31 December 2012 2011 Balance at beginning of the year 2,669 - Current service cost 548 - Interest expense 623 - Past service cost 4,718 2,880 Translation difference 170 (211)

Balance at end of the year 8,728 2,669

The Group expects to make a contribution of TUSD 3,513 to the defined benefit plans during the next financial year.

36. BUSINESS COMBINATIONS, ACQUISITION AND DISPOSAL OF SUBSIDIARIES

Acquisition of controlling interests in subsidiaries in 2012

Acquisition of oil and gas assets

On 29 August 2012, the Group acquired 100% interest in CAP Agro S.A., the ultimate owner of LLC GeoInvestService, for cash consideration of TUSD 30,026. LLC GeoInvestService holds an exploration license for the West-Osoveiskoye block in the Timano-Pechora region in Northern Russia, on the East side of the Kolvinskoye oil field.

LLC GeoInvestService did not carry out any activity before the date of acquisition. Accordingly, the acquisition did not meet the definition of a business combination as stated in IFRS 3 “Business Combinations”, and was treated as acquisition of an asset. Identifiable assets acquired and liabilities assumed were accounted for on an individual basis in the consolidated statement of financial position. The remaining purchase price was allocated to cost of license for West-Osoveiskoye block within the Group’s exploration assets.

Acquisition of a gas company

On 15 October 2012, the Group acquired 100% of the shares in Polonio Holdings Limited, the ultimate owner of LLC SN-Gasproduction, an upstream segment company holding two gas licenses in the Tomsk region of the Russian Federation, for cash consideration of TUSD 127,768. Field development was at an advanced stage at the date of acquisition and gas production commenced in February 2013.

The Group engaged an independent appraisal in order to determine the fair value of assets acquired and liabilities assumed. The fair values of assets acquired and liabilities assumed at the date of acquisition were as follows:

Assets Property, plant and equipment 303,880 VAT and other taxes receivable 7,666 Cash and cash equivalents 2,036 Other assets 2,967 Liabilities Loans and borrowings (147,172) Deferred tax liabilities (31,817) Provision for decommissioning and site restoration costs (1,871) Payables and accrued expenses (7,921) Identifiable net assets at the date of acquisition 127,768

Net cash outflow on acquisition of Polonio Holdings Limited Group:

Consideration paid in cash 127,768 Less: cash and cash equivalents acquired (2,036)

125,732

53 F-56 Included in the Group’s consolidated results for the year is TUSD 328 of loss generated by Polonio Holdings Limited Group. Had the business combination occured at 1 January 2012, the profit for the year of the Group would have been TUSD 416,964.

Increase in ownership in subsidiaries in 2012

During the year ended 31 December 2012, the Group acquired interests in the following subsidiaries:

Preference Increase in shares interest voting power, % acquired, % Consideration

OJSC Khabarovsknefteproduct 0.29 1.93 295 OJSC Khabarovsk Oil Refinery 0.01 2.27 191

486

As a result of these transactions, the Group recognised a decrease in non-controlling interests of TUSD 1,069.

Acquisition of controlling interests in subsidiary in 2011

Acquisition of a sea terminal company

On 16 February 2011, the Group acquired 100% shares in CJSC Gavanbunker, a sea terminal in the Sovetskaya Gavan port located in the Khabarovsk region of the Russian Federation, for a total consideration transferred of TUSD 17,284, including advance payment of TUSD 1,500 made in 2010.

Fair values of assets acquired and liabilities assumed at the date of acquisition were as follows:

Assets Property, plant and equipment 8,403 Cash and cash equivalents 794 Other assets 2,090

Liabilities Deferred tax liabilities (589) Payables and accrued expenses (2,361)

Identifiable net assets at the date of acquisition 8,337

Goodwill on acquisition:

Consideration paid in cash 14,000 Fair value of loans repayable on acquisition, net of deferred tax 3,284 Total consideration transferred 17,284 Less: fair value of identifiable net assets acquired (8,337)

Goodwill on acquisition 8,947

Goodwill on acquisition of CJSC Gavanbunker primarily represented a control premium. In addition, the consideration effectively included effect of expected synergies and expansion of bunkering operations in the Russian Far East. These benefits were not recognised separately from goodwill because they do not meet the recognition criteria for identifiable intangible assets. Goodwill is not deductible for tax purposes.

Net cash outflow on acquisition of CJSC Gavanbunker:

Consideration paid in cash 14,000 Less: cash and cash equivalents acquired (794) 13,206 Loans repaid on acquisition 3,930

17,136

54 F-57 Total revenue contributed by CJSC Gavanbunker from the date of acquisition to 31 December 2011 amounted to TUSD 6,855; loss for the period - TUSD 1,026.

Had the business combination been effected as at 1 January 2011, the revenue of the Group would have been TUSD 3,085,244 and the profit for the year would have been TUSD 328,305.

Increase in ownership in subsidiaries in 2011

During the year ended 31 December 2011, the Group acquired interests in the following subsidiaries:

Preference Increase in shares interest voting power, % acquired, % Consideration

OJSC Khabarovsk Oil Refinery 0.03 4.86 535 OJSC Primornefteproduct 0.37 1.26 510 OJSC Khabarovsknefteproduct 0.20 1.63 309

1,354

As a result of these transactions, the Group recognised a decrease in non-controlling interests of TUSD 1,864.

Disposal of subsidiaries in 2011

In December 2011, the Group disposed of its entire share in CJSC "Ecobioprom" and subsidiaries, the group involved in operations with biofuels, for a cash consideration of TUSD 9. Loss on disposal in the amount of TUSD 2,904 was recognised in the consolidated statement of profit or loss.

Analysis of assets and liabilities over which control was lost:

Property, plant and equipment 5,620 Cash, cash equivalents and accounts receivable 202 Accounts payable, loans and borrowings (281)

Net assets disposed of 5,541

Loss on disposal of subsidiary:

Consideration received 9 Net assets disposed of (5,541) Non-controlling interests 2,799 Translation difference (171)

Loss on disposal (2,904)

55 F-58 37. RELATED PARTY TRANSACTIONS

Related parties include shareholders with significant influence, associates, joint venture and other related parties representing entities under common ownership and control with the Group and members of key management personnel.

Significant balances with related parties at 31 December 2012 and 2011:

31 December 31 December 2012 2011 Shareholders Trade and other accounts receivable 1,153 886 Associates Trade and other accounts receivable 19,112 20,076 Advances paid and prepaid expenses 2,002 - Advances received and accrued expenses 55,057 79,670 Other related parties Trade and other accounts receivable 9 1,400 Advances paid and prepaid expenses 1,999 1,403 Other financial assets - 26,090

No allowance for doubtful debts in respect of the amounts owed by related parties was recognised.

Significant transactions with related parties for the years ended 31 December 2012 and 2011:

Year ended Year ended 31 December 31 December 2012 2011 Associates Revenue 917,508 482,840 Purchase of oil products 28,052 7,482 Purchase of services 1,531 341 Loans provided 24,786 16,588 Loans repaid 24,786 16,588 Other related parties Revenue 253 385,327 Purchase of services 18,583 35,377 Charity donations 9,736 10,333 Interest income 3,370 3,111 Short-term deposits placed - 30,015 Proceeds from deposits withdrawn 27,030 30,076

Revenue from sales to related parties includes sales of crude oil and oil products in the domestic and export markets. Purchase of services from related parties mainly includes insurance services and rent.

Charity donations primarily represent contributions to the Fund named after Z. Bazhaev.

Transactions with shareholders with significant influence, associates and other related parties relate to transactions in the ordinary course of business with terms and conditions, that management believe similar to transactions with third parties. All related party balances are unsecured and will be settled in cash under normal commercial credit terms. No guarantees have been given or received in relation to any related party balance.

Disclosure of transactions in relation to members of key management personnel is presented in Note 35.

38. COMMITMENTS AND CONTINGENCIES

Capital commitments

The Group’s contractual capital commitments at 31 December 2012 and 2011 amounted to TUSD 855,011 and TUSD 750,651, respectively.

56 F-59 License commitments

The Group is subject to periodic reviews of its activities by local regulatory authorities regarding the requirements of its oil and gas licenses. Management of the Group entities agrees with local regulatory authorities remedial actions necessary to resolve any findings resulting from these reviews. Non-compliance with the terms of a particular license could result in penalties, fines or license limitations, suspension or revocation. The Group’s management believes that any non- compliance with license terms that the Group may have in the future will be resolved through negotiations or proposed amendments without material effect on the consolidated financial positions or the operating results of the Group.

Litigation

The Group has been and continues to be the subject of legal proceedings and adjudications from time to time, none of which has had or is expected to have, individually or in the aggregate, a material adverse impact on the Group.

The legal system in Russia is not fully developed and cannot be compared with the legal system in the West. It is also subject to constant changes, sometimes with retroactive effect. This fact could imply negative consequences to the companies of the Group.

Environmental matters

The Group is subject to extensive federal, state and local environmental controls and regulations in the Russian Federation and Kazakhstan. The Group’s operations involve air and water venting of detrimental impurities, that may have a potential impact on flora and fauna in the region of operations, and other environmental concerns.

Management believes that the Group’s operations are in compliance with all current existing environmental laws and regulations. However, environmental laws and regulations of the Russian Federation and Kazakhstan continue to evolve. The Group is unable to predict the timing or extent to which those environmental laws and regulations may change. Such change, if it occurs, may require that the Group modernise technology to meet more stringent standards.

In accordance with the terms of various laws and extracting licenses upon completion of the oil and gas field exploitation the Group is liable to perform decommissioning and site restoration of the oil fields. The estimated cost of known environmental obligations has been recorded in the consolidated financial statements (Note 31). Management of the Group regularly reassesses environmental obligations related to its operations. Estimates are based on management’s understanding of current legal requirements, the terms of license agreements and the size and nature of the oil and gas fields under the licenses. Should the requirements of applicable environmental legislation change or be clarified, the Group may incur additional environmental obligations.

Russian Federation economic environment

Emerging markets such as the Russian Federation are subject to different risks than more developed markets, including economic, political and social, and legal and legislative risks. As has happened in the past, actual or perceived financial problems or an increase in the perceived risks associated with investing in emerging economies could adversely affect the investment climate in the Russian Federation and the Russia’s economy in general.

The global financial system continues to exhibit signs of deep stress and many economies around the world are experiencing lesser or no growth than in prior years. Additionally there is increased uncertainty about the creditworthiness of some sovereign states in the Eurozone and financial institutions with exposure to the sovereign debt of such states. These conditions could slow or disrupt the Russian Federation‘s economy, adversely affect the Group’s access to capital and cost of capital for the Group and, more generally, its business, results of operations, financial condition and prospects.

Because the Russian Federation produces and exports large volumes of oil and gas, the Russian Federation’s economy is particularly sensitive to the price of oil and gas on the world market which has fluctuated significantly during 2012 and 2011.

57 F-60 Russian Federation tax and regulatory environment

Laws and regulations affecting businesses in the Russian Federation continue to change rapidly. Tax, currency and customs legislation within the Russian Federation are subject to varying interpretations, and other legal and fiscal impediments contribute to the challenges faced by entities currently operating in the Russian Federation. The future economic direction of the Russian Federation is heavily influenced by the economic, fiscal and monetary policies adopted by the government, together with developments in the legal, regulatory, and political environment.

While the Group believes it has provided adequately for all tax liabilities based on its understanding of the tax legislation, the above facts may create tax risks for the Group. The management believes that its interpretation of the relevant legislation is appropriate and the Group’s tax, currency and customs positions will be sustained.

39. RISK MANAGEMENT

Capital risk management

The Group’s objective for managing capital is to deliver competitive, secure and sustainable returns to maximise long-term shareholders value and reduce the cost of capital maintenance.

The Group monitors capital structure on the basis of the total debt to equity ratio. Total debt comprises non-current and current loans and borrowings, as shown in the consolidated statement of financial position. Equity of the Group comprises share capital, additional paid-in capital, translation reserve on intercompany loans, translation reserve on foreign operations, option premium on convertible bonds, retained earnings and non-controlling interests.

31 December 31 December 2012 2011

Loans and borrowings 2,070,620 1,621,092 Total equity 3,033,010 1,993,433

Debt to equity ratio 68% 81%

In addition, the management of the Group reviews the following ratios on a quarterly basis: net debt, total debt to adjusted EBITDA, net debt to adjusted EBITDA and EBIT to interest expense.

Major categories of financial instruments

Major categories of financial assets and financial liabilities are presented below:

31 December 31 December 2012 2011 Financial assets Loans and receivables (including cash and cash equivalents): Trade and other accounts receivable 116,368 113,605 Other financial assets 48,484 91,088 Cash, cash equivalents and restricted cash 411,820 187,801 Fair value through profit or loss Other financial assets 1,337 2,175 578,009 394,669 Financial liabilities Measured at amortised cost: Loans and borrowings 2,070,620 1,621,092 Trade and other accounts payable 129,864 144,184 Wages and salaries payable 26,079 21,106 Fair value through profit or loss Derivatives classified as held for trading 5,981 16,021 2,232,544 1,802,403

58 F-61 Management believes that the carrying values of financial assets (Notes 21, 24 and 27) and financial liabilities, excluding loans and borrowings, (Notes 32 and 33) recorded at amortised cost in the consolidated financial statements approximate their fair values. At 31 December 2012, convertible interest bearing corporate bonds had a market value of TUSD 271,376 (2011: TUSD 278,703), non- convertible interest bearing Eurobonds had a market value of TUSD 385,665 (2011: TUSD 353,948) and non-convertible interest bearing rouble bonds had a market value of TUSD 645,596 (2011: TUSD 600,228). The fair values of other fixed-rate debt and floating-rate debt (Note 30) approximate their carrying values.

The Group faces a number of financial risks arising from its operations and use of financial instruments, including, but not limited to: foreign currency risk, interest rate risk, credit risk and liquidity risk.

Foreign currency risk

Currency risk is the risk that the financial results of the Group will be adversely impacted by changes in exchange rates. The Group undertakes certain transactions denominated in foreign currencies. The significant part of the Group’s revenues are denominated in USD, whereas the majority of the Group’s operational costs are denominated in RUB. At the same time the major part of the Group’s borrowings are denominated in USD and EUR, while most of the Group’s assets are denominated in RUB.

The Group’s exposure to the risk of changes in exchange rates relates primarily to the Group’s long- term debt obligations denominated in USD and EUR. The Group manages its foreign currency risk by economically hedging transactions that are expected to occur within a maximum 24-month period. In June and August 2011, the Group entered cross-currency interest rate swaps in order to balance cash inflows from export sales denominated in USD with cash outflows on interest payments denominated in RUB and obtain a lower interest rate (Note 15).

The outstanding balances of the Group's foreign currency denominated monetary assets and monetary liabilities at the end of the reporting period were as follows:

Denominated in USD Denominated in EUR 31 December 31 December 31 December 31 December 2012 2011 2012 2011 Assets Trade and other accounts receivable 67,038 58,792 18,180 14,772 Cash, cash equivalents and restricted cash 232,776 19,637 28,938 29,348 299,814 78,429 47,118 44,120

Liabilities Loans and borrowings 361,452 289,991 198,155 166,777 Trade and other accounts payable 2,473 3,300 32,799 435 363,925 293,291 230,954 167,212

Total net position (64,111) (214,862) (183,836) (123,092)

The following table details the Group's sensitivity to a 10% increase and decrease in the RUB against the relevant foreign currencies. 10% is the sensitivity rate used when reporting foreign currency risk internally to key management personnel and represents management's assessment of the reasonably possible change in foreign exchange rates. The sensitivity analysis includes only outstanding foreign currency denominated monetary items and adjusts their translation at the period end for a 10% change in foreign currency rates. A positive number below indicates an increase in profit or equity where the RUB strengthens for 10% against the relevant currency. For a 10% weakening of the RUB against the relevant currency, there would be a comparable impact on the profit or equity, and the balances below would be negative.

Denominated in USD Denominated in EUR Year ended Year ended Year ended Year ended 31 December 31 December 31 December 31 December 2012 2011 2012 2011

Profit or loss/ equity 6,411 21,486 18,384 12,309

59 F-62 In addition, a change of exchange rate of the RUB against the USD by 10% would lead to recognition of TUSD 7,454 profit or loss in relation to valuation of fair value of cross-currency interest rate swaps.

Interest rate risk

The Group is exposed to interest rate risk as Group entities borrow a portion of funds at floating interest rates. At 31 December 2012 and 2011, 22% and 24%, respectively, of the Group’s borrowings were at floating interest rates. Management considers such portfolio of fixed and floating rate loans and borrowings to be appropriate, therefore the Group does not use any derivatives to manage interest rate risk exposure.

The table below details the Group’s sensitivity to increase or decrease of the floating rate by 1%, which is used when reporting interest rate risk internally to key management personnel and represents management’s assessment of the reasonably possible change in interest rates. The analysis was applied to loans and borrowings based on the assumptions that amount of liabilities outstanding at the reporting date were outstanding for the whole year.

Profit or loss/ equity Year ended Year ended 31 December 31 December 2012 2011 LIBOR 1,475 1,185

Credit risk

Credit risk is the risk that a customer may default or not meet its obligations to the Group on a timely basis, leading to financial losses. The Group has adopted a policy of only dealing with creditworthy counterparties. The Group takes into account all available quantitative and qualitative information and its own trading records to mitigate the risk of financial loss from defaults.

Credit risk of the Group arises from cash, cash equivalents and restricted cash, loans and receivables and other financial assets, and has a maximum exposure equal to the carrying value of these instruments.

Description of risk management policies relating to trade and other receivables are described in the Note 24.

The credit risk on cash, cash equivalents, restricted cash and investments in deposits is limited because the counterparties are highly rated banks or banks approved by the management of the Group, deposits in which are placed only within approved limits.

In addition the Group is exposed to credit risk in relation to investments in loans. The counterparty’s business activities, financial resources and business risk management processes are taken into account in the assessment of their creditworthiness. The Group issues loans only to counterparties approved by management within the established limits.

There were no guarantees given to secure financing of third parties at 31 December 2012 and 2011.

Liquidity risk

Liquidity risk is the risk that the Group will not be able to settle all liabilities as they fall due. The Group’s liquidity position is carefully monitored and managed.

The net cash flow position of the Group is monitored on a daily basis by the central treasury function with weekly cash movements and cash balances being reported to the Group's management. A significant portion of crude oil and oil products sales contracts is executed on an advanced basis and the Group has also a strict policy for collecting doubtful debts and monitoring trade debtors. The Group prepares detailed budgets and forecasts and reviews the global and domestic oil price environment on a monthly basis in order to optimise crude oil sales, supply routes, oil product mix and refinery volumes. Management is focusing on matching the maturity profiles of financial assets and liabilities and reducing short-term debt through repayment of existing short-term loans. Accordingly, management considers that it is taking all necessary actions to allow the Group to meet its current obligations as they fall due.

The Group's primary sources of cash are its operations, as well as bank loans and the proceeds from equity and debt capital markets offerings.

60 F-63 At 31 December 2012, the Group’s unused financing facilities amounted to TUSD 444,025 (2011: TUSD 635,646).

Fair value of financial instruments

The fair value of financial assets and liabilities is determined as follows:

 The fair value of financial assets and financial liabilities with standard terms and conditions and traded on active liquid markets are determined with reference to quoted market prices.  The fair values of derivative instruments are calculated using a discounted cash flow analysis based on the applicable yield curve for the duration of the instruments. Cross-currency interest rate swaps are measured at the present value of future cash flows estimated and discounted on rates of 6.9%-7.2% for cash flows denominated in RUB and 0.2%-0.8% for cash flows denominated in USD. Discount rates are based on Bloomberg yield curves.  The fair value of other financial assets and financial liabilities are determined in accordance with generally accepted pricing model based on discounted cash flow analysis using prices from observable current market transactions.

The Group uses the following hierarchy for determining and disclosing the fair value of financial instruments by valuation technique:

Level 1: fair value measurements are those derived from quoted (unadjusted) prices in active markets for identical assets or liabilities; Level 2: fair value measurements are those derived from direct or indirect observable inputs for the asset or liability, other than quoted prices included within Level 1; and Level 3: fair value measurements are those derived from valuation techniques that include inputs for the asset or liability that are not based on observable market data (unobservable inputs).

At 31 December 2012, cross-currency interest rate swaps held by the Group and carried at fair value were attributed to Level 2 of the hierarchy.

40. SIGNIFICANT EVENTS AFTER THE END OF THE PERIOD

Completion of formation of the joint venture with Repsol (Note 20)

In January 2013, Repsol contributed its subsidiary, OJSC Eurotek, to the joint venture. OJSC Eurotek owns two gas exploration and production licenses.

In March 2013, OJSC Eurotek commenced commercial gas production in Russia with initial daily gas production of approximately 855 thousand cubic metres (about 5,350 barrels of oil equivalent, both amounts unaudited).

Gas production in Tomsk region

Alliance Oil Company completed infrastructure development and launched gas production at the Ust- Silginskiy field in the Tomsk region. Gas production commenced in February 2013 with initial daily gas production of approximately 700 thousand cubic metres (about 4,500 barrels of oil equivalent, both amounts unaudited).

Dividends on preference shares

On 28 February 2013, dividends on preference shares of SEK 7.50 (in the total amount of TSEK 37,500 or TUSD 5,816 as of the date of cash transfer) were paid. In addition, the Board of directors proposes to pay quarterly dividends on preference shares of SEK 7.50, record dates for the distribution being 31 May 2013, 30 August 2013, 29 November 2013 and 28 February 2014.

61 F-64 41. SUMMARISED FINANCIAL INFORMATION ON SPECIFIC SUBSIDIARIES OF THE GROUP

If a debt security is issued, the Group has put in place a proposed guarantor structure that will be used to guarantee such debt. For information purposes, the Group has chosen to present a condensed consolidated statement of profit or loss and condensed consolidated statement of financial position for each of the last two years, separately reporting amounts for the Company (who is proposed to be the issuer of any debt security), the proposed guarantors (see below), the other subsidiaries within the Group, and adjustments required to reconcile the total amount to the consolidated statement of profit or loss for the Group.

1. The proposed guarantors (the “Guarantors”) include the following subsidiaries of the Group:

Ownership held Guarantor company by the Group%

CJSC Alliance Oil 100.00% OJSC “Alliance” Oil Company 100.00% LLC Alliance Bunker 100.00% CJSC Alliancetransoil 100.00% OJSC Amurnefteproduct 94.78% OJSC Khabarovsknefteproduct 88.89% CJSC Khvoinoye 100.00% LLC Kolvinskoye 100.00% OJSC Pechoraneft 99.66% LLP Potential Oil 79.64% OJSC Primornefteproduct 95.04% LLC SN-Gazodobycha 100.00% OJSC Vostochnaya Transnationalnaya Kompaniya 100.00%

2. The column relating to “Other subsidiaries” presented in the condensed consolidated statement of profit or loss and condensed consolidated statement of financial position include all the other subsidiaries excluding the Guarantors and the Company.

The financial information included in the condensed consolidated statement of profit or loss and condensed consolidated statement of financial position for each of the last two years has been prepared on an IFRS basis. The summarised financial information on the Guarantors and the Other subsidiaries was presented on a combined basis with all eliminations and other consolidation adjustments being presented within an “Adjustments” column.

62 F-65 The condensed consolidated statement of profit or loss for the year ended 31 December 2012 is presented below:

Alliance Oil Company Other Adjust- Ltd. Guarantors subsidiaries Aggregated ments Total Revenue Revenue from sales of crude oil - 2,393,665 376,196 2,769,861 (2,167,507) 602,354 Revenue from sales of oil products - 4,146,156 190,763 4,336,919 (1,549,158) 2,787,761 Revenue from other sales - 763,981 534,488 1,298,469 (1,243,345) 55,124 - 7,303,802 1,101,447 8,405,249 (4,960,010) 3,445,239 Cost of sales Production costs of crude oil - (252,181) (138,227) (390,408) 24,527 (365,881) Production costs of oil products - (6,014,128) (261,403) (6,275,531) 4,376,751 (1,898,780) Cost of other sales - (146,070) (213,209) (359,279) 334,964 (24,315) Depletion and depreciation of oil and gas and refining assets - (87,192) (91,926) (179,118) 5,228 (173,890) Reversal of impairment of oil and gas assets - 58,721 - 58,721 - 58,721 Gross profit - 862,952 396,682 1,259,634 (218,540) 1,041,094 Selling expenses - (439,292) (47,449) (486,741) 172,154 (314,587) Administrative expenses (35,258) (30,490) (88,914) (154,662) 58,922 (95,740) Depreciation and amortisation of marketing and other assets - (16,259) (2,225) (18,484) - (18,484) Other operating expenses, net (9,040) (7,704) 20,716 3,972 (23,457) (19,485) Share of profits of associates and joint venture - - - - 2,309 2,309 Operating income (44,298) 369,207 278,810 603,719 (8,612) 595,107 Interest income 54,186 62,434 83,849 200,469 (185,492) 14,977 Finance costs (64,979) (143,230) (85,403) (293,612) 198,578 (95,034) Gain on derivatives classified as held for trading, net - 7,678 - 7,678 - 7,678 Currency exchange gain/(loss), net 6,498 18,034 45,164 69,696 (48,008) 21,688 Profit before tax (48,593) 314,123 322,420 587,950 (43,534) 544,416 Income tax expense - (72,721) (53,766) (126,487) 2,841 (123,646) Profit for the year (48,593) 241,402 268,654 461,463 (40,693) 420,770

The condensed consolidated statement of profit or loss for the year ended 31 December 2011 is presented below:

Alliance Oil Company Other Ltd. Guarantors subsidiaries Aggregated Adjustments Total Revenue Revenue from sales of crude oil - 2,059,877 357,345 2,417,222 (1,885,566) 531,656 Revenue from sales of oil products - 3,781,190 83,443 3,864,633 (1,368,415) 2,496,218 Revenue from other sales - 726,797 679,312 1,406,109 (1,351,323) 54,786 - 6,567,864 1,120,100 7,687,964 (4,605,304) 3,082,660 Cost of sales Production costs of crude oil - (246,507) (139,775) (386,282) 33,235 (353,047) Production costs of oil products - (5,382,339) (150,818) (5,533,157) 3,897,895 (1,635,262) Cost of other sales - (143,303) (352,720) (496,023) 472,112 (23,911) Depletion and depreciation of oil and refining assets - (78,811) (75,325) (154,136) (2,034) (156,170) Gross profit - 716,904 401,462 1,118,366 (204,096) 914,270 Selling expenses - (406,332) (43,339) (449,671) 163,100 (286,571) Administrative expenses (31,007) (25,252) (86,116) (142,375) 64,918 (77,457) Depreciation and amortisation of marketing and other assets - (15,357) (2,528) (17,885) (140) (18,025) Other operating expenses, net (16,821) 103,907 62,734 149,820 (168,040) (18,220) Share of profits of associates - - - - 2,153 2,153 Gain/(loss) on disposal of shares in subsidiaries 491,757 210 (16,154) 475,813 (478,707) (2,894) Operating income 443,929 374,080 316,059 1,134,068 (620,812) 513,256 Interest income 71,526 29,750 102,358 203,634 (191,375) 12,259 Finance costs (64,816) (107,251) (107,610) (279,677) 220,543 (59,134) Loss on derivatives classified as held for trading, net - (15,444) - (15,444) - (15,444) Currency exchange (loss)/gain, net (2,389) (8,845) (56,281) (67,515) 49,339 (18,176) Profit before tax 448,250 272,290 254,526 975,066 (542,305) 432,761 Income tax expense - (71,230) (44,447) (115,677) 11,206 (104,471) Profit for the year 448,250 201,060 210,079 859,389 (531,099) 328,290

63 F-66 The condensed consolidated statement of financial position as at 31 December 2012 is presented below:

Alliance Oil Company Other Ltd. Guarantors subsidiaries Aggregated Adjustments Total ASSETS Non-current assets Property, plant and equipment - 2,469,217 1,929,440 4,398,657 75,942 4,474,599 Intangible assets - 267 604 871 - 871 Goodwill - - - - 20,394 20,394 Investments in associates and joint venture - - 327,577 327,577 (140,386) 187,191 Deferred tax assets - 354 5,962 6,316 22,215 28,531 Other assets 3,319,372 918,402 2,179,474 6,417,248 (6,414,257) 2,991 3,319,372 3,388,240 4,443,057 11,150,669 (6,436,092) 4,714,577 Current assets Inventories - 231,574 33,926 265,500 (37,509) 227,991 Trade and other accounts receivable 12 462,888 229,496 692,396 (576,028) 116,368 Value added tax and other taxes receivable - 177,565 118,608 296,173 63 296,236 Income tax receivable - 12,847 964 13,811 - 13,811 Advances paid and prepaid expenses 98 145,061 100,907 246,066 (84,804) 161,262 Other financial assets - 506,847 92,482 599,329 (549,508) 49,821 Restricted cash - 254 26,633 26,887 - 26,887 Cash and cash equivalents 208,391 124,871 51,671 384,933 - 384,933 208,501 1,661,907 654,687 2,525,095 (1,247,786) 1,277,309

TOTAL ASSETS 3,527,873 5,050,147 5,097,744 13,675,764 (7,683,878) 5,991,886

EQUITY AND LIABILITIES

3 TOTAL EQUITY 2,821,120 1,953,444 2,672,856 7,447,420 (4,414,410) 3,033,010

Non-current liabilities Loans and borrowings 673,251 1,464,445 1,952,416 4,090,112 (2,421,098) 1,669,014 Deferred tax liabilities - 161,463 60,469 221,932 43,070 265,002 Provision for decommissioning and site restoration costs - 62,326 10,869 73,195 - 73,195 Advances received - 26,309 - 26,309 - 26,309 Retirement benefit obligation - 2,936 5,792 8,728 - 8,728 673,251 1,717,479 2,029,546 4,420,276 (2,378,028) 2,042,248 Current liabilities Loans and borrowings 14,563 631,315 178,015 823,893 (422,287) 401,606 Trade and other accounts payable 14,328 421,560 105,259 541,147 (411,283) 129,864 Advances received and accrued expenses 4,611 283,541 60,994 349,146 (53,081) 296,065 Income tax payable - 1,737 8,462 10,199 - 10,199 Other taxes payable - 35,090 42,612 77,702 (4,789) 72,913 Derivatives classified as held for trading - 5,981 - 5,981 - 5,981 33,502 1,379,224 395,342 1,808,068 (891,440) 916,628

TOTAL LIABILITIES 706,753 3,096,703 2,424,888 6,228,344 (3,269,468) 2,958,876

TOTAL EQUITY AND LIABILITIES 3,527,873 5,050,147 5,097,744 13,675,764 (7,683,878) 5,991,886

3 Includes 34,745 TUSD attributable to non-controlling interests

64 F-67 The condensed consolidated statement of financial position as at 31 December 2011 is presented below:

Alliance Oil Company Other Ltd. Guarantors subsidiaries Aggregated Adjustments Total ASSETS Non-current assets Property, plant and equipment - 1,722,273 1,423,432 3,145,705 78,093 3,223,798 Intangible assets - 949 968 1,917 - 1,917 Goodwill - - - - 19,239 19,239 Investments in associates and joint venture - - 20,022 20,022 1,804 21,826 Deferred tax assets - 2,335 7,914 10,249 16,190 26,439 Other assets 3,386,500 601,591 1,985,103 5,973,194 (5,943,149) 30,045 3,386,500 2,327,148 3,437,439 9,151,087 (5,827,823) 3,323,264 Current assets Inventories - 156,275 13,610 169,885 (24,856) 145,029 Trade and other accounts receivable 12 413,929 103,944 517,885 (404,280) 113,605 Value added tax and other taxes receivable - 173,069 51,307 224,376 176 224,552 Income tax receivable - 6,071 5,743 11,814 - 11,814 Advances paid and prepaid expenses 95 180,788 112,734 293,617 (167,710) 125,907 Other financial assets - 451,557 104,964 556,521 (463,258) 93,263 Restricted cash - 234 27,084 27,318 - 27,318 Cash and cash equivalents 7,248 138,439 14,796 160,483 - 160,483 7,355 1,520,362 434,182 1,961,899 (1,059,928) 901,971

TOTAL ASSETS 3,393,855 3,847,510 3,871,621 11,112,986 (6,887,751) 4,225,235

EQUITY AND LIABILITIES

4 TOTAL EQUITY 2,671,775 1,240,362 1,772,438 5,684,575 (3,691,142) 1,993,433

Non-current liabilities Loans and borrowings 691,097 1,569,707 1,740,991 4,001,795 (2,487,532) 1,514,263 Deferred tax liabilities - 144,221 52,911 197,132 (9,134) 187,998 Provision for decommissioning and site restoration costs - 10,720 4,720 15,440 - 15,440 Retirement benefit obligation - 558 2,111 2,669 - 2,669 Derivatives classified as held for trading - 11,114 - 11,114 - 11,114 691,097 1,736,320 1,800,733 4,228,150 (2,496,666) 1,731,484 Current liabilities Loans and borrowings 14,563 253,389 57,784 325,736 (218,907) 106,829 Trade and other accounts payable 12,324 416,981 78,135 507,440 (363,256) 144,184 Advances received and accrued expenses 4,096 161,816 109,258 275,170 (104,704) 170,466 Income tax payable - 1,446 4,078 5,524 - 5,524 Other taxes payable - 32,289 49,195 81,484 (13,076) 68,408 Derivatives classified as held for trading - 4,907 - 4,907 - 4,907 30,983 870,828 298,450 1,200,261 (699,943) 500,318

TOTAL LIABILITIES 722,080 2,607,148 2,099,183 5,428,411 (3,196,609) 2,231,802

TOTAL EQUITY AND LIABILITIES 3,393,855 3,847,510 3,871,621 11,112,986 (6,887,751) 4,225,235

42. PARENT COMPANY (UNAUDITED)

Presented below are the key financial indicators of the Parent company:

Year ended Year ended 31 December 31 December 2012 2011

Operating (loss)/income (44,298) 443,929 (Loss)/profit before tax (48,593) 448,250 (Loss)/profit for the year (48,593) 448,250 Total assets 3,527,873 3,393,855 Total liabilities 706,752 722,080 Equity 2,821,121 2,671,775

4 Includes 25,889 TUSD attributable to non-controlling interests

65 F-68

Alliance Oil Company Ltd and subsidiaries

Consolidated Financial Statements for the Year Ended 31 December 2011

F-69 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

CONTENTS

Page

STATEMENT OF DIRECTORS’ RESPONSIBILITIES FOR THE PREPARATION AND APPROVAL OF THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2011 1

INDEPENDENT AUDITOR’S REPORT 2-3

CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2011:

Consolidated Income Statement 4

Consolidated Statement of Comprehensive Income 5

Consolidated Statement of Financial Position 6

Consolidated Statement of Changes in Equity 7

Consolidated Statement of Cash Flows 8-9

Notes to the Consolidated Financial Statements 10-53

F-70 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

STATEMENT OF DIRECTORS’ RESPONSIBILITIES FOR THE PREPARATION AND APPROVAL OF THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2011

The Board of Directors is responsible for the preparation of the consolidated financial statements that present fairly the financial position of Alliance Oil Company Ltd and its subsidiaries (the “Group”) as of 31 December 2011, and the results of its operations, cash flows and changes in shareholders’ equity for the year then ended, in compliance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).

In preparing the consolidated financial statements, the Board of Directors is responsible for:

 Properly selecting and applying accounting policies;  Presenting information, including accounting policies, in a manner that provides relevant, reliable, comparable and understandable information;  Providing additional disclosures when compliance with the specific requirements in IFRSs are insufficient to enable users to understand the impact of particular transactions, other events and conditions on the Group's consolidated financial position and financial performance; and  Making an assessment of the Group's ability to continue as a going concern.

The Board of Directors is also responsible for:

 Designing, implementing and maintaining an effective and sound system of internal controls, throughout the Group;  Maintaining adequate accounting records that are sufficient to show and explain the Group's transactions and disclose with reasonable accuracy the consolidated financial position of the Group, and which enable them to ensure that the consolidated financial statements of the Group comply with IFRS;  Maintaining statutory accounting records in compliance with local legislation and accounting standards in the respective jurisdictions in which the Group operates;  Taking such steps as are reasonably available to them to safeguard the assets of the Group; and  Preventing and detecting fraud and other irregularities.

The consolidated financial statements of the Group for the year ended 31 December 2011 were approved by the Board of directors on 16 April 2012.

On behalf of the Board of Directors:

______Arsen E. Idrisov, Chief Executive Officer

16 April 2012

1 F-71 ZAO “Deloitte & Touche CIS” 5 Lesnaya Street Moscow, 125047 Russia

Tel: +7 (495) 787 06 00 Fax: +7 (495) 787 06 01 www.deloitte.ru

INDEPENDENT AUDITOR’S REPORT

To the Shareholders and Board of Directors of Alliance Oil Company Ltd

We have audited the accompanying consolidated financial statements of Alliance Oil Company Ltd and its subsidiaries, which comprise the consolidated statement of financial position as at 31 December 2011, the consolidated income statement, and statements of comprehensive income, changes in equity and cash flows for the year then ended, and a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit in accordance with International Standards on Auditing. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated 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 consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Deloitte refers to one or more of Deloitte Touche Tohmatsu Limited, a UK private company limited by guarantee, and its network of member firms, each of which is a legally separate and independent entity. Please see www.deloitte.com/about for a detailed description of the legal structure of Deloitte Touche Tohmatsu Limited and its member firms. Please see www.deloitte.com/ru/about for a detailed description of the legal structure of Deloitte CIS.

© 2012 ZAO “Deloitte & Touche CIS”. All rights reserved. 2 Member of Deloitte Touche Tohmatsu Limited F-72 Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Alliance Oil Company Ltd and its subsidiaries as at 31 December 2011, and its financial performance and cash flows for the year then ended in accordance with International Financial Reporting Standards.

Deloitte AB ZAO Deloitte & Touche CIS

______Svante Forsberg Natalia Golovkina Authorized public accountant Certified auditor

16 April 2012

3 F-73 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

CONSOLIDATED INCOME STATEMENT (Expressed in USD thousands)

Year ended Year ended 31 December 31 December Note 2011 2010

Revenue Revenue from sales of crude oil 531,656 397,943 Revenue from sales of oil products 2,496,218 1,756,295 Other income 54,786 41,518 3,082,660 2,195,756 Cost of sales Production costs of crude oil 9 (353,047) (269,162) Production costs of oil products 7,10 (1,631,909) (1,168,068) Cost of other sales (23,911) (21,824) Depletion and depreciation of oil and gas and refining assets (156,170) (117,625) ReversaI of impairment of oil and gas assets, net 18 - 1,051 Gross profit 917,623 620,128

Selling expenses 7,11 (289,924) (223,730) Administrative expenses 12 (77,457) (67,890) Depreciation and amortisation of marketing and other non-production assets (18,025) (14,610) Other operating expenses, net 13 (18,220) (6,691) Share of profits of associates 20 2,153 104 (Loss)/gain on disposal of shares in subsidiaries 35 (2,894) 9 Operating income 513,256 307,320

Interest income 12,259 7,901 Finance costs 14 (59,134) (29,473) Loss on derivatives classified as held for trading, net 15 (15,444) - Currency exchange (loss)/gain, net (18,176) 3,923 Profit before tax 432,761 289,671

Income tax expense 16 (104,471) (63,339) Profit for the year 328,290 226,332

Attributable to: Owners of the Company 318,873 222,221 Non-controlling interests 9,417 4,111

Earnings per share Basic (USD per share) 17 1.86 1.30 Diluted (USD per share) 17 1.74 1.21

4 F-74 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (Expressed in USD thousands)

Year ended Year ended 31 December 31 December 2011 2010

Profit for the year 328,290 226,332

Other comprehensive loss Currency exchange loss on intercompany loans classified as net investments in subsidiaries (49,216) (15,035) Exchange loss on translating foreign operations (95,224) (10,451) Income tax relating to currency exchange differences on intercompany loans 7,574 1,299

Other comprehensive loss for the year, net of tax (136,866) (24,187) Total comprehensive income for the year 191,424 202,145

Attributable to: Owners of the Company 179,594 198,034 Non-controlling interests 11,830 4,111

5 F-75 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF FINANCIAL POSITION (Expressed in USD thousands)

31 December 31 December Note 2011 2010

ASSETS Non-current assets Property, plant and equipment 18 3,223,798 2,528,244 Intangible assets 1,917 3,840 Goodwill 19 19,239 11,728 Investments in associates 20 21,826 150 Deferred tax assets 16 26,439 25,319 Other financial assets 21 167 10,188 Other assets 22 29,878 38,115 3,323,264 2,617,584 Current assets Inventories 23 145,029 141,316 Trade and other accounts receivable 24 113,605 117,135 Value added tax and other taxes receivable 25 224,552 135,766 Income tax receivable 11,814 9,876 Advances paid and prepaid expenses 26 125,907 98,003 Other financial assets 21 93,263 49,629 Restricted cash 27 27,318 79,322 Cash and cash equivalents 27 160,483 98,777 901,971 729,824

TOTAL ASSETS 4,225,235 3,347,408

EQUITY AND LIABILITIES Capital and reserves Share capital 28 171,528 171,528 Additional paid-in capital 1,104,355 1,103,845 Other reserves (480,379) (341,100) Retained earnings 1,159,946 839,716 Equity attributable to owners of the Company 1,955,450 1,773,989 Non-controlling interests 37,983 31,307 TOTAL EQUITY 1,993,433 1,805,296

Non-current liabilities Loans and borrowings 29 1,514,263 912,471 Deferred tax liabilities 16 187,998 178,031 Provision for decommissioning and site restoration costs 30 15,440 15,960 Retirement benefit obligation 34 2,669 - Derivatives classified as held for trading 15 11,114 - 1,731,484 1,106,462 Current liabilities Loans and borrowings 29 106,829 127,134 Trade and other accounts payable 31 144,184 95,797 Advances received and accrued expenses 32 170,466 152,484 Income tax payable 5,524 1,607 Other taxes payable 33 68,408 58,628 Derivatives classified as held for trading 15 4,907 - 500,318 435,650

TOTAL LIABILITIES 2,231,802 1,542,112

TOTAL EQUITY AND LIABILITIES 4,225,235 3,347,408

6 F-76 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (Expressed in USD thousands)

Attributable to owners of the Company Translation Translation Option Additional reserve on reserve on premium on Non- paid-in intercompany foreign convertible Retained controlling Share capital capital loans operations bonds earnings Total interests Total equity

Balance at 1 January 2010 171,528 1,105,848 (114,970) (224,214) 22,271 616,644 1,577,107 29,651 1,606,758 Profit for the year - - - - - 222,221 222,221 4,111 226,332 Other comprehensive loss - - (13,736) (10,451) - - (24,187) - (24,187) Total comprehensive (loss)/income for the year - - (13,736) (10,451) - 222,221 198,034 4,111 202,145

Changes in ownership of subsidiaries (Note 35) - (2,003) - - - - (2,003) (2,404) (4,407) Disposal of subsidiaries ------(51) (51) Share option plan (Note 28) - - - - - 851 851 - 851 Balance at 31 December 2010 171,528 1,103,845 (128,706) (234,665) 22,271 839,716 1,773,989 31,307 1,805,296

F-77 Profit for the year - - - - - 318,873 318,873 9,417 328,290 Other comprehensive (loss)/income - - (41,642) (97,637) - - (139,279) 2,413 (136,866) Total comprehensive (loss)/income for the year - - (41,642) (97,637) - 318,873 179,594 11,830 191,424

Changes in ownership of subsidiaries (Note 35) - 510 - - - - 510 (1,864) (1,354) Disposal of subsidiaries (Note 35) ------(2,799) (2,799) Dividends to shareholders of non- controlling interests ------(491) (491) Share option plan (Note 28) - - - - - 1,357 1,357 - 1,357

Balance at 31 December 2011 171,528 1,104,355 (170,348) (332,302) 22,271 1,159,946 1,955,450 37,983 1,993,433

7 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS (Expressed in USD thousands)

Year ended Year ended 31 December 31 December 2011 2010

Operating activities Profit before tax 432,761 289,671

Adjustments for:

Depreciation, depletion and amortisation 174,195 132,235 Interest income (12,259) (7,901) Finance costs 59,134 29,473 Loss on derivatives classified as held for trading, net 15,444 - Currency exchange loss/(gain), net 18,176 (3,923) Loss/(gain) on disposal of shares in subsidiaries 2,894 (9) Share of profits of associates (2,153) (104) Loss on disposal of assets 3,196 204 Reversal of impairment of oil and gas assets, net - (1,051) Other non-cash items 3,271 4,733 Operating cash flows before changes in working capital 694,659 443,328

Changes in working capital Increase in inventories (13,832) (26,052) Increase in accounts receivable (144,624) (170,934) Increase in accounts payable 40,078 21,357 Cash generated from operations 576,281 267,699

Interest paid (42,106) (18,934) Income tax paid (71,675) (45,010) Total cash generated from operating activities 462,500 203,755

Investing activities Investments in oil and gas assets (603,744) (351,905) Investments in refining assets (314,912) (223,505) Investments in marketing and other non-production assets (28,194) (29,234) Interest capitalised and paid (78,268) (45,991) Investments in shares in subsidiaries (15,636) - Proceeds from disposal of assets 1,683 1,704 Interest received 5,770 6,711 Loans provided (56,588) (29,372) Loans repaid 19,169 16,912 Short-term deposits placed (30,015) (29,859) Proceeds from deposits withdrawn 30,076 - Advances for acquisition of shares - (20,000) Total cash used in investing activities (1,070,659) (704,539)

8 F-78 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS (CONTINUED) (Expressed in USD thousands)

Year ended Year ended 31 December 31 December 2011 2010

Financing activities Proceeds from financing raised, net of issue costs 1,111,272 825,837 Repayment of loans and borrowings (478,913) (519,668) Acquisition of non-controlling interest in subsidiaries (1,267) (4,716) Dividends paid by subsidiaries (397) (8) Other financing activities - 89 Total cash generated from financing activities 630,695 301,534

Effect of exchange rate changes on cash balances held in foreign currencies 4,148 (4,970) Translation difference (16,982) (9,751) Change in cash, cash equivalents and restricted cash 9,702 (213,971)

Cash, cash equivalents and restricted cash at beginning of the year 178,099 392,070

Cash, cash equivalents and restricted cash at end of the year 187,801 178,099

9 F-79 ALLIANCE OIL COMPANY LTD AND SUBSIDIARIES

NOTES TO THE FINANCIAL STATEMENTS Expressed in USD thousand (TUSD) unless indicated otherwise

1. ORGANISATION

Alliance Oil Company Limited (the “Parent company” or “Company”) was incorporated in Bermuda on 1 September 1998, as a tax exempted limited liability private company. The Company's registered office is located at: Clarendon House, 2 Church Street, Hamilton HM11, Bermuda.

The Company and its subsidiaries (the “Group”) emerged in its current form as a result of the merger between OJSC “Alliance” Oil Company (“Alliance”) and the Company in April 2008.

The Group is an independent vertically integrated oil and gas company with upstream operations in the Russian Federation and Kazakhstan and downstream operations in the Russian Federation. The Group's upstream operations include crude oil exploration, extraction and production in the Timano-Pechora, Volga Urals and Tomsk regions of the Russian Federation and the Atyrau region of Kazakhstan. The downstream operations include oil refining, transportation, marketing and sales of oil products in the Russian Far East and Eastern Siberia.

The principal activities of the significant entities and voting power held by the Group at 31 December 2011 and 2010 were as follows:

Voting power held by the Group, % 31 December 31 December Activity/ Operating entity Country 2011 2010

Holding companies Alliance Oil Company Ltd Bermuda - - OJSC “Alliance” Oil Company Russian Federation 100.00 100.00 Financing of subsidiaries O&G Credit Agency Ltd Cyprus 100.00 100.00 Management services LLC “Alliance” Oil Company MC Russian Federation (former LLC Alliance Management) 100.00 100.00 Oil exploration and production OJSC Vostochnaya Russian Federation Transnationalnaya Kompaniya 100.00 100.00 LLC Khvoinoye Russian Federation 100.00 100.00 OJSC Pechoraneft Russian Federation 99.66 99.66 CJSC Saneco Russian Federation 100.00 100.00 LLC Kolvinskoye Russian Federation 100.00 100.00 OJSC Tatnefteotdacha Russian Federation 99.54 99.54 LLP Potential Oil Kazakhstan 80.00 80.00 Oil refining OJSC Khabarovsk Oil Refinery Russian Federation 98.82 98.79 Marketing and sales of oil products CJSC Alliance Oil Russian Federation 100.00 100.00 OJSC Khabarovsknefteproduct Russian Federation 92.56 92.36 OJSC Amurnefteproduct Russian Federation 96.36 96.36 OJSC Primornefteproduct Russian Federation 95.04 94.67 LLC Alliance – Baikalneftesbyt Russian Federation 100.00 100.00 LLC Alliance Bunker Russian Federation 100.00 100.00 CJSC Gavanbunker Russian Federation 100.00 - Inventory and equipment supply LLC Naftatekhresource Russian Federation 100.00 100.00 Transportation services CJSC Alliancetransoil Russian Federation 100.00 100.00

2. STATEMENT OF COMPLIANCE

The accompanying consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”). IFRS include standards and interpretations approved by the International Accounting Standards Board, including International Accounting Standards (“IAS”) and interpretations issued by International Financial Reporting Interpretations Committee (“IFRIC”).

10 F-80 3. APPLICATION OF NEW AND REVISED INTERNATIONAL FINANCIAL REPORTING STANDARDS

Revised IFRSs applied with no or not material effect on amounts reported, presentation and disclosure

The following new and revised IFRSs have been adopted in these consolidated financial statements:

● Amendments to IAS 1 “Presentation of Financial Statements” ● Revised IAS 24 “Related Party Disclosures” ● Amendments to IAS 27 “Consolidated and Separate Financial Statements” ● Amendments to IAS 32 “Financial Instruments: Presentation” ● Revised IFRS 1 “First-time Adoption of International Financial Reporting Standards” ● Amendments to IFRS 3 “Business Combinations” ● Amendments to IFRS 7 “Financial Instruments: Disclosures” ● Amendments to IFRIC 13 “Customer Loyalty Programmes” ● IFRIC 14 “IAS 19 – The Limit on a Defined Benefit Asset, Minimum Funding Requirements and their Interaction” ● IFRIC 19 “Extinguishing Financial Liabilities with Equity Instruments”

The application of these new and revised IFRSs has not had any material impact on the amounts reported for the current and prior years but may affect the accounting for future transactions or arrangements.

Standards, amendments and interpretations to existing standards that are not yet effective and have not been early adopted by the Group

At the date of approval of the Group’s consolidated financial statements, the following new, revised and amended Standards and Interpretations have been issued, but are not effective for the year ended 31 December 2011:

Effective for the accounting periods beginning on or after

Amendments to IFRS 1 “First-time Adoption of International Financial Reporting Standards” – Additional exemption for entities ceasing to suffer from severe hyperinflation 1 July 2011 Amendments to IFRS 7 “Financial Instruments: Disclosures” - Amendments enhancing disclosures about transfers of financial assets 1 July 2011 Amendments enhancing disclosures about offsetting of financial assets and financial liabilities 1 January 2013 Amendments requiring disclosures about the initial application of IFRS 9 1 January 2015 IFRS 9 “Financial Instruments” 1 January 2015 IFRS 10 “Consolidated Financial Statements” 1 January 2013 IFRS 11 “Joint Arrangements” 1 January 2013 IFRS 12 “Disclosure of Interests in Other Entities” 1 January 2013 IFRS 13 “Fair Value Measurement” 1 January 2013 Amendments to IAS 1 “Presentation of Financial Statements” – Amendments to revise the way other comprehensive income is presented 1 July 2012 Limited scope amendment to IAS 12 “Income Taxes”: Deferred tax – Recovery of underlying assets 1 January 2012 Amendments to IAS 19 “Employee Benefits” – Amended Standard resulting from the Post- Employment Benefits and Termination Benefits projects 1 January 2013 Reissue of IAS 27 as “Separate Financial Statements” 1 January 2013 Reissue of IAS 28 as “Investments in Associates and Joint Ventures” 1 January 2013 Amendments to IAS 32 “Financial Instruments: Presentation” 1 January 2014 IFRIC 20 “Stripping Costs in the Production Phase of a Surface Mine” 1 January 2013

Management is currently considering the potential impact of the adoption of these Standards, amendments and interpretations. However, it is not practicable to provide a reasonable estimate of their effect until a detailed review has been completed.

11 F-81 4. BASIS OF PREPARATION

Entities of the Group maintain their accounting records in accordance with the laws and accounting and reporting regulations of the countries of incorporation. Statutory accounting principles and procedures may differ substantially from those generally accepted under IFRS. Accordingly, the accompanying consolidated financial statements, which have been prepared from the Group entities statutory accounting records, reflect adjustments necessary for such financial statements to be presented in accordance with IFRS.

The consolidated financial statements have been prepared on the historical cost basis, except for certain financial instruments that are measured at fair values, as explained in the accounting policies below. Historical cost is generally based on the fair value of the consideration given in exchange for assets.

5. SIGNIFICANT ACCOUNTING POLICIES

Basis of consolidation

The consolidated financial statements incorporate the financial statements of the Company and entities controlled by the Company (its subsidiaries). Control is achieved where the Company has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities.

Income and expenses of subsidiaries acquired or disposed of during the year are included in the consolidated income statement from the effective date of acquisition and up to the effective date of disposal, as appropriate. Total comprehensive income of subsidiaries is attributed to the owners of the Company and to the non-controlling interests even if this results in the non-controlling interests having a deficit balance.

Where necessary, adjustments are made to the financial statements of subsidiaries to bring their accounting policies into line with those used by other members of the Group.

All intragroup transactions, balances, income and expenses are eliminated in full on consolidation.

Changes in the Group's ownership interests in subsidiaries that do not result in the Group losing control over the subsidiaries are accounted for as equity transactions. The carrying amounts of the Group's interests and the non-controlling interests are adjusted to reflect the changes in their relative interests in the subsidiaries. Any difference between the amount by which the non-controlling interests are adjusted and the fair value of the consideration paid or received is recognised directly in equity and attributed to owners of the Company.

When the Group loses control of a subsidiary, the profit or loss on disposal is calculated as the difference between (i) the aggregate of the fair value of the consideration received and the fair value of any retained interest and (ii) the previous carrying amount of the assets (including goodwill), and liabilities of the subsidiary and any non-controlling interests. Amounts previously recognised in other comprehensive income in relation to the subsidiary’s assets or liabilities are accounted for (i.e. reclassified to the income statement or transferred directly to retained earnings) in the same manner as would be required if the relevant assets or liabilities were disposed of. The fair value of any investment retained in the former subsidiary at the date when control is lost is regarded as the fair value on initial recognition for subsequent accounting under IAS 39 “Financial Instruments: Recognition and Measurement” or, when applicable, the cost on initial recognition of an investment in an associate.

Business combinations

Acquisitions of businesses are accounted for using the acquisition method. The consideration transferred in a business combination is measured at fair value, which is calculated as the sum of the acquisition-date fair values of the assets transferred by the Group, liabilities incurred by the Group to the former owners of the acquiree and the equity interests issued by the Group in exchange for control of the acquiree. Acquisition-related costs are recognised in profit or loss as incurred.

12 F-82 At the acquisition date, the identifiable assets acquired and the liabilities assumed are recognised at their fair value at the acquisition date, except that:

 Deferred tax assets or liabilities, and assets or liabilities related to employee benefit arrangements are recognised and measured in accordance with IAS 12 “Income Taxes” and IAS 19 “Employee Benefits”, respectively;  Liabilities or equity instruments related to the replacement by the Group of an acquiree’s share- based payment awards are measured in accordance with IFRS 2 “Share-based Payment”; and  Assets (or disposal groups) that are classified as held for sale in accordance with IFRS 5 “Non- current Assets Held for Sale and Discontinued Operations” are measured in accordance with that Standard.

Goodwill is measured as the excess of the sum of the consideration transferred, the amount of any non-controlling interests in the acquiree, and the fair value of the acquirer's previously held equity interest in the acquiree (if any) over the net of the acquisition-date amounts of the identifiable assets acquired and the liabilities assumed. If, after reassessment, the net of the acquisition-date amounts of the identifiable assets acquired and liabilities assumed exceeds the sum of the consideration transferred, the amount of any non-controlling interests in the acquiree and the fair value of the acquirer's previously held interest in the acquiree (if any), the excess is recognised immediately in profit or loss as a bargain purchase gain.

Non-controlling interests that are present ownership interests and entitle their holders to a proportionate share of the entity's net assets in the event of liquidation may be initially measured either at fair value or at the non-controlling interests' proportionate share of the recognised amounts of the acquiree's identifiable net assets. The choice of measurement basis is made on a transaction- by-transaction basis.

When the consideration transferred by the Group in a business combination includes assets or liabilities resulting from a contingent consideration arrangement, the contingent consideration is measured at its acquisition-date fair value and included as part of the consideration transferred in a business combination. Changes in the fair value of the contingent consideration that qualify as measurement period adjustments are adjusted retrospectively, with corresponding adjustments against goodwill. Measurement period adjustments are adjustments that arise from additional information obtained during the ‘measurement period’ (which cannot exceed one year from the acquisition date) about facts and circumstances that existed at the acquisition date.

The subsequent accounting for changes in the fair value of the contingent consideration that do not qualify as measurement period adjustments depends on how the contingent consideration is classified. Contingent consideration that is classified as equity is not remeasured at subsequent reporting dates and its subsequent settlement is accounted for within equity. Contingent consideration that is classified as an asset or a liability is remeasured at subsequent reporting dates in accordance with IAS 39, or IAS 37 “Provisions, Contingent Liabilities and Contingent Assets”, as appropriate, with the corresponding gain or loss being recognised in profit or loss.

When a business combination is achieved in stages, the Group's previously held equity interest in the acquiree is remeasured to fair value at the acquisition date (i.e. the date when the Group obtains control) and the resulting gain or loss, if any, is recognised in profit or loss. Amounts arising from interests in the acquiree prior to the acquisition date that have previously been recognised in other comprehensive income are reclassified to profit or loss where such treatment would be appropriate if that interest were disposed of.

If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the Group reports provisional amounts for the items for which the accounting is incomplete. Those provisional amounts are adjusted during the measurement period (see above), or additional assets or liabilities are recognised, to reflect new information obtained about facts and circumstances that existed at the acquisition date that, if known, would have affected the amounts recognised at that date.

Goodwill

Goodwill arising on an acquisition of a business is carried at cost as established at the date of acquisition of the business (see above) less accumulated impairment losses, if any.

13 F-83 For the purpose of impairment testing, goodwill is allocated to each of the Group’s cash generating units (“CGU”s) that is expected to benefit from the synergies of the combination.

A cash generating unit to which goodwill has been allocated is tested for impairment annually, or more frequently when there is an indication that the unit may be impaired. If the recoverable amount of the CGU is less than its carrying amount, the impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the unit and then to the other assets of the unit pro rata on the basis of the carrying amount of each asset in the unit. Any impairment loss for goodwill is recognised directly in profit or loss in the consolidated income statement. An impairment loss recognised for goodwill is not reversed in subsequent periods.

On disposal of the relevant CGU, the attributable amount of goodwill is included in the determination of the profit or loss on disposal.

The Group's policy for goodwill arising on the acquisition of an associate is described below.

Investments in associates

An associate is an entity over which the Group has significant influence and that is neither a subsidiary nor an interest in a joint venture. Significant influence is the power to participate in the financial and operating policy decisions of the investee where the Group does not have control or joint control over those policies.

The results and the assets and liabilities of associates are incorporated in these consolidated financial statements using the equity method of accounting. Under the equity method, an investment in an associate is initially recognised in the consolidated statement of financial position at cost and adjusted thereafter to recognise the Group's share of the profit or loss and other comprehensive income of the associate. When the Group's share of losses of an associate exceeds the Group's interest in that associate (which includes any long-term interests that, in substance, form part of the Group's net investment in the associate), the Group discontinues recognising its share of further losses.

Any excess of the cost of acquisition over the Group’s share of the net fair value of the identifiable assets, liabilities and contingent liabilities of the associate recognised at the date of acquisition is recognised as goodwill, which is included within the carrying amount of the investment. Any excess of the Group’s share of the net fair value of the identifiable assets, liabilities and contingent liabilities over the cost of acquisition, after reassessment, is recognised immediately in profit or loss.

The requirements of IAS 39 are applied to determine whether it is necessary to recognise any impairment loss with respect to the Group’s investment in an associate. When necessary, the entire carrying amount of the investment (including goodwill) is tested for impairment in accordance with IAS 36 “Impairment of Assets” as a single asset by comparing its recoverable amount (higher of value in use and fair value less costs to sell) with its carrying amount. Any impairment loss recognised forms part of the carrying amount of the investment. Any reversal of that impairment loss is recognised in accordance with IAS 36 to the extent that the recoverable amount of the investment subsequently increases.

When a Group’s entity transacts with its associate, profits and losses resulting from the transactions with the associate are recognised in the Group's consolidated financial statements only to the extent of interests in the associate that are not related to the Group.

Functional and presentation currency

Amounts presented in the financial statements of each of the Group’s entities are measured using the currency of the primary economic environment in which the entity operates (“functional currency”). The individual financial statements of each Group’s entity are presented in its functional currency:

 For entities operating in the Russian Federation – Russian Rouble (“RUB”);  For entities operating in Kazakhstan – Kazakhstan Tenge (“KZT”);  For entities operating in Cyprus and Bermuda – US Dollar (“USD”).

14 F-84 The Group has chosen to present its consolidated financial statements in the USD, as management believes it is a more convenient presentation currency for international users of the consolidated financial statements of the Group as it is a common presentation currency in the oil and gas industry. The translation of balances and transactions of the Group’s entities from their functional currencies to the presentation currency is performed as follows:

 All assets and liabilities, both monetary and non-monetary, are translated at closing exchange rates at each reporting period end date;  All income and expenses are translated at the quarterly average exchange rates for the period, except for significant transactions that are translated at rates on the date of such transactions;  Resulting exchange differences are recognised in other comprehensive income as “Exchange differences on translating foreign operations” and accumulated in equity (attributed to non- controlling interests as appropriate);  All cash flows are translated at the quarterly average exchange rates for the period, except for significant transactions that are translated at rates on the date of such transactions. Resulting exchange differences are presented as “Translation difference”.

On the disposal of a foreign operation (i.e. a disposal of the Group’s entire interest in a foreign operation, or a disposal involving loss of control over a subsidiary that includes a foreign operation), all of the accumulated exchange differences in respect of that operation attributable to the owners of the Group are reclassified to the consolidated income statement as part of the gain or loss on disposal. Any exchange differences that have previously been attributed to non-controlling interests are derecognised, but they are not reclassified to income statement.

Foreign currencies

In preparing the financial statements of the individual entities, transactions in currencies other than the entity’s functional currency (foreign currencies) are recognised at the rates of exchange prevailing at the dates of the transactions. At the end of each reporting period, monetary items denominated in foreign currencies are retranslated at the rates prevailing at that date. Non-monetary items carried at fair value that are denominated in foreign currencies are retranslated at the rates prevailing at the date when the fair value was determined. Non-monetary items that are measured in terms of historical cost in a foreign currency are not retranslated.

Exchange differences are recognised in profit or loss in the period in which they arise except for:

 Exchange differences on foreign currency borrowings relating to assets under construction for future productive use, which are included in the cost of those assets when they are regarded as an adjustment to interest costs on those foreign currency borrowings;  Exchange differences on monetary items receivable from or payable to a foreign operation for which settlement is neither planned nor likely to occur (therefore forming part of the net investment in the foreign operation), which are recognised initially in other comprehensive income and reclassified from equity to profit or loss on disposal or partial disposal of the net investment.

Property, plant and equipment

The Group’s property, plant and equipment consist of oil and gas assets involved in crude oil exploration and production (“oil and gas assets”), refining assets involved in oil refining (“refining assets”) and marketing and other non-production assets involved in oil and oil products transportation and marketing of oil products (“marketing and other non-production assets”).

Oil and gas assets

Exploration and evaluation assets

The Group follows the “successful efforts” method of accounting for its oil and gas assets, under which all costs for acquiring licenses and for the exploration and evaluation, survey, drilling and development of oil fields are initially capitalised in field area cost centres pending determination of oil reserves. Costs incurred prior to having obtained the legal rights to explore an area are expensed directly to the income statement as they are incurred. Capitalised expenditure incurred during the various exploration and appraisal phases is then written off unless commercial reserves have been established or the determination process has not been completed.

15 F-85 Exploration and evaluation assets are accounted for at historic cost less impairment losses if applicable. These assets related to each exploration license are not depleted, but are carried forward until the existence (or otherwise) of commercial reserves has been determined. Upon the completion of the development and the start of production the field will be accounted for as a production asset.

Impairment of exploration and evaluation assets

Exploration and evaluation assets are assessed for impairment when facts and circumstances suggest that the carrying amount of an exploration and evaluation asset may exceed its recoverable amount. The following facts and circumstances, among other, indicate that exploration and evaluation assets must be tested for impairment:

 The term of exploration license in the specific area has expired during the reporting period or will expire in the near future, and is not expected to be renewed;  Substantive expenditure on further exploration for and evaluation of oil resources in the specific area is neither budgeted nor planned;  Exploration for and evaluation of oil resources in the specific area have not led to the discovery of commercially viable quantities of oil resources and the decision was made to discontinue such activities in the specific area; and  Sufficient data exist to indicate that, although the development in the specific area is likely to occur, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale.

For the purpose of assessing exploration and evaluation assets for impairment, such assets are allocated to cash-generating units, being exploration license areas.

Any impairment loss is recognised as an expense in accordance with the policy on impairment of tangible assets set out below.

Oil and gas production assets

Oil and gas production assets are stated at cost less accumulated depletion and impairment losses, if applicable. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning obligation and for qualifying assets, borrowing costs capitalized in accordance with the Group’s accounting policy. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.

Oil and gas production assets are depleted in accordance with the unit-of-production method over proved and probable reserves; the base for depletion includes management's best estimates of future development costs related to probable reserves. The Group has engaged an independent reserve engineer, DeGolyer and MacNaughton, to estimate its reserves under Petroleum Resources Management System. Depletion of a field area is charged to profit or loss after production commences.

Proved and probable reserves include oil quantities which the Group expects to produce after the expiry dates of its current licenses. The Group’s current licenses for exploration, production and development of oil fields expire between 2013 and 2033. Where the license term is shorter than the production phase of the oil field, the oil and gas properties are depreciated over the production phase of the oil and gas fields, as management believes that such licenses will be renewed. The production phase of oil and gas fields is determined based on the estimate of commercially viable reserves.

Proved reserves are those volumes of oil which, by analysis of geological and engineering data, are estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods and governmental regulations. Proved reserves can be categorised as developed or undeveloped.

Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable, under current economic conditions, operating methods and government regulations. In this context, when probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves.

16 F-86 Refining, marketing and other non-production assets

Refining, marketing and other non-production assets are measured at cost less accumulated depreciation and impairment losses, if applicable. Such cost includes borrowing costs capitalised in accordance with the Group's accounting policy. Depreciation of these assets commences when the assets are ready for their intended use and is calculated on a straight-line basis over the estimated useful economic lives of assets, which are:

Buildings and Infrastructure 20-50 years Machinery and Equipment 8-20 years Vehicles 3-10 years Fixtures and Fittings 2-8 years

The estimated useful lives, residual values and depreciation method are reviewed at each year end, with the effect of any changes in estimate accounted for on a prospective basis.

An item of property, plant and equipment is derecognised upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on the disposal or retirement of an item of property, plant and equipment is determined as the difference between the sales proceeds and the carrying amount of the asset and is recognised in profit or loss.

Provision for decommissioning and site restoration costs

Decommissioning and site restoration provision relates primarily to the conservation and abandonment of wells, removal of pipelines and other oil and gas facilities together with site restoration related to the Group's license areas. Management estimates the obligation related to these costs based on internally generated engineering estimates, current statutory requirements and industry practices. Future decommissioning and site restoration costs, discounted to net present value, are capitalised within property, plant and equipment and a corresponding obligation recorded when a constructive obligation to incur such costs exists and the amount can be reliably estimated.

The decommissioning asset is depleted using the unit-of-production method based on proved and probable reserves. The unwinding of discount is recognised as finance costs.

The adequacy of the decommissioning and site restoration provision is periodically reviewed in the light of current laws and regulations, and adjustments made as necessary. Changes in the estimated expenditure are reflected as an adjustment to the provision and a corresponding adjustment to property, plant and equipment.

Impairment of tangible and intangible assets (excluding goodwill and exploration and evaluation assets)

At the end of each reporting period, the Group reviews the carrying amounts of its tangible and intangible assets to determine whether there is any indication that those assets have suffered an impairment loss. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment loss (if any). Where it is not possible to estimate the recoverable amount of an individual asset, the Group estimates the recoverable amount of the Cash Generating Unit (CGU) to which the asset belongs.

Recoverable amount is the higher of fair value less costs to sell or value in use. In assessing value in use, the estimated future cash flows are discounted to their present value, using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset for which the estimates of future cash flows have not been adjusted.

If the recoverable amount of an asset (or CGU) is estimated to be less than its carrying amount, the carrying amount of the asset (or CGU) is reduced to its recoverable amount. An impairment loss is recognised immediately in profit or loss. After the recognition of an impairment loss depletion charge for impaired oil and gas assets is adjusted in the reporting periods following the date of impairment recognition.

Where an impairment loss subsequently reverses, the carrying amount of the asset (or CGU) is increased to the revised estimate of its recoverable amount but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset (or CGU) in prior years. A reversal of an impairment loss is recognised immediately in profit or loss.

17 F-87 Inventories

Inventories are stated at the lower of cost and net realisable value. Costs, including an appropriate portion of fixed and variable overhead expenses, are assigned to inventories held by the method most appropriate to the particular class of inventory, with the majority being valued on a first-in-first- out basis and crude oil stock being valued on a weighted average basis. Net realisable value represents the estimated selling price for inventories in the ordinary course of business less all estimated costs of completion and costs necessary to make the sale.

Provisions

Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that the Group will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation.

The amount recognised as a provision is the best estimate of the consideration required to settle the present obligation at the balance sheet date, taking into account the risks and uncertainties surrounding the obligation. Where a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows.

When some or all of the economic benefits required to settle a provision are expected to be recovered from a third party, a receivable is recognised as an asset if it is virtually certain that reimbursement will be received and the amount of the receivable can be measured reliably.

Financial instruments

Financial assets and financial liabilities are recognised when a Group’s entity becomes a party to the contractual provisions of the instrument.

Financial assets and financial liabilities are initially measured at fair value. Transaction costs that are directly attributable to the acquisition or issue of financial assets and financial liabilities (other than financial assets and financial liabilities at fair value through profit or loss) are added to or deducted from the fair value of the financial assets or financial liabilities, as appropriate, on initial recognition. Transaction costs directly attributable to the acquisition of financial assets or financial liabilities at fair value through profit or loss are recognised immediately in profit or loss.

Financial assets

Financial assets are classified into the following specified categories: financial assets ‘at fair value through profit or loss' (“FVTPL”), ‘held to maturity’ investments and ‘loans and receivables’. The classification depends on the nature and purpose of the financial assets and is determined at the time of initial recognition.

Financial assets at FVTPL

Financial assets are classified as at FVTPL when the financial asset is held for trading.

A financial asset is classified as held for trading if:

 it has been acquired principally for the purpose of selling it in the near term; or  on initial recognition it is part of a portfolio of identified financial instruments that the Group manages together and has a recent actual pattern of short-term profit-taking; or  it is a derivative that is not designated and effective as a hedging instrument.

Held-to-maturity investments

Held-to-maturity investments are non-derivative financial assets with fixed or determinable payments and fixed maturity dates that the Group has the positive intent and ability to hold to maturity. Subsequent to initial recognition, held-to-maturity investments are measured at amortised cost using the effective interest method less any impairment.

18 F-88 Loans and receivables

Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. Loans and receivables (including trade and other receivables, bank balances and cash) are measured at amortised cost using the effective interest method, less any impairment.

Interest income is recognised by applying the effective interest rate, except for short-term receivables when the recognition of interest would be immaterial.

Effective interest method

The effective interest method is a method of calculating the amortised cost of a financial asset or liability and of allocating interest income or expense, respectively, over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash receipts or payments, as applicable (including all fees on points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the financial asset or liability, or, where appropriate, a shorter period, to the net carrying amount on initial recognition.

Income or expense is recognised on an effective interest basis for debt instruments other than those financial assets classified as at FVTPL.

Impairment of financial assets

Financial assets, other than those at FVTPL, are assessed for indicators of impairment at the end of each reporting period. Financial assets are considered to be impaired where there is objective evidence that, as a result of one or more events that occurred after the initial recognition of the financial asset, the estimated future cash flows of the investment have been affected.

Loans and receivables are reviewed and subsequently assessed for impairment on an individual basis. Objective evidence of impairment for an individual account receivable could include: significant financial difficulty of the issuer or counterparty; or breach of contract, such as default or delinquency in payments; or it becoming probable that the counterparty will enter bankruptcy or financial re-organisation.

For financial assets carried at amortised cost, the amount of the impairment is the difference between the asset’s carrying amount and the present value of estimated future cash flows, discounted at the financial asset’s original effective interest rate.

The carrying amount of the financial asset is reduced by the impairment loss directly for all financial assets with the exception of accounts receivable, where the carrying amount is reduced through the use of an allowance account. When an account receivable is considered uncollectible, it is written off against the allowance account. Subsequent recoveries of amounts previously written off are credited against the allowance account. Changes in the carrying amount of the allowance account are recognised in profit or loss.

For financial assets measured at amortised cost, if, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognised, the previously recognised impairment loss is reversed through profit or loss to the extent that the carrying amount of the investment at the date the impairment is reversed does not exceed what the amortised cost would have been had the impairment not been recognised.

Derecognition of financial assets

The Group derecognises a financial asset only when the contractual rights to the cash flows from the asset expire, or when it transfers the financial asset and substantially all the risks and rewards of ownership of the asset to another entity. If the Group neither transfers nor retains substantially all the risks and rewards of ownership and continues to control the transferred asset, the Group recognises its retained interest in the asset and an associated liability for amounts it may have to pay. If the Group retains substantially all the risks and rewards of ownership of a transferred financial asset, the Group continues to recognise the financial asset and also recognises a collateralised borrowing for the proceeds received.

19 F-89 Cash, cash equivalents and restricted cash

Cash and cash equivalents comprise cash balances, cash deposits and highly liquid investments with maturities of three months or less at the date of investment, which are readily convertible to known amounts of cash and are subject to an insignificant risk of changes in value.

Restricted cash comprises cash deposited in special bank accounts that can be used only for the purpose intended.

Financial liabilities and equity instruments

Classification as debt or equity

Debt and equity instruments are classified as either financial liabilities or as equity in accordance with the substance of the contractual arrangement and the definitions of a financial liability and an equity instrument.

Equity instruments

An equity instrument is any contract that evidences a residual interest in the assets of an entity after deducting all of its liabilities. Equity instruments issued by the Group are recorded at the proceeds received, net of direct issue costs.

Convertible bonds

The component parts of compound instruments issued by the Group are classified separately as financial liabilities and equity in accordance with the substance of the contractual arrangement the definitions of a financial liability and an equity instrument. Conversion option that will be settled by the exchange of a fixed amount of cash or another financial asset for a fixed number of the Company's own equity instruments is an equity instrument.

At the date of issue, the fair value of the liability component is estimated using the prevailing market interest rate for a similar non-convertible instrument. This amount is recorded as a liability on an amortised cost basis using the effective interest method until extinguished upon conversion or at the instrument’s maturity date.

The conversion option classified as equity is determined by deducting the amount of the liability component from the fair value of the compound instrument as a whole. This is recognised and included in equity, net of income tax effects, and is not subsequently remeasured. In addition, the conversion option classified as equity will remain in equity until the conversion option is exercised, in which case, the balance recognised in equity will be transferred to additional paid-in-capital. Where the conversion option remains unexercised at the maturity date of the convertible note, the balance recognised in equity will be transferred to retained earnings. No gain or loss is recognised in profit or loss upon conversion or expiration of the conversion option.

Financial liabilities

Financial liabilities are classified as either financial liabilities ‘at FVTPL' or ‘other financial liabilities'.

Financial liabilities at FVTPL

Financial liabilities are classified as at FVTPL when the financial liability is held for trading.

A financial liability is classified as held for trading if:

 It has been acquired principally for the purpose of repurchasing it in the near term; or  On initial recognition it is part of a portfolio of identified financial instruments that the Group manages together and has a recent actual pattern of short-term profit-taking; or  It is a derivative that is not designated and effective as a hedging instrument.

20 F-90 Other financial liabilities

Other financial liabilities (including borrowings and trade and other payables) are subsequently measured at amortised cost using the effective interest method.

The effective interest method is a method of calculating the amortised cost of a financial liability and of allocating interest expense over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash payments (including all fees and points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the financial liability, or (where appropriate) a shorter period, to the net carrying amount on initial recognition.

Derecognition of financial liabilities

The Group derecognises financial liabilities when, and only when, the Group's obligations are discharged, cancelled or they expire. The difference between the carrying amount of the financial liability derecognised and the consideration paid and payable is recognised in profit or loss.

Derivative financial instruments

In order to manage its exposure to foreign exchange rate risks the Group enters into a derivative financial instrument such as cross currency interest swap. Further details of derivative financial instruments are disclosed in note 15.

Derivatives are initially recognised at fair value at the date the derivative contracts are entered into and are subsequently remeasured to their fair value at the end of each reporting period. The resulting gain or loss is recognised in profit or loss immediately. Fair value is determined in the manner described in note 38.

Borrowing costs

Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale.

Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalisation.

All other borrowing costs are recognised in profit or loss in the period in which they are incurred.

Employee benefits

Remuneration to employees, in respect of services rendered during the period is recognised as an expense in profit or loss in that reporting period.

Defined contribution plan

The Group’s entities are legally obliged to make defined contributions to the State Pension Funds of the Russian Federation and Kazakhstan where Group operates (a defined contribution plan financed on a pay-as-you-go basis). In the Russian Federation all obligatory social contributions, including contributions to the Russian Federation State Pension Fund, are collected through social security charges at the rate of 26% for annual gross remuneration of each employee not exceeding certain amount, for remuneration exceeding the set amount the rate drops to 0%. The Group’s contributions to the State Pension Funds of the Russian Federation and Kazakhstan where the Group operates relating to defined contribution plans are charged to profit or loss in the period to which they relate.

Defined benefit plans

The Group has defined benefits plans, which are unfunded. The cost of providing benefits under these defined benefit plans is determined separately for each plan using the projected unit credit method. The past service costs are recognised as an expense on straight-line basis over the average period until the benefits become vested. The past service costs at the introduction of the plans are being deferred and amortised on a straight-line basis over the expected average remaining working lives of the employees participating in the plans.

21 F-91 Share based payments

The Group operates the global share option plan. The fair value of the employee services received in exchange for the grant of the options is recognised as an expense. The total amount to be expensed over the vesting period is determined by reference to the fair value of the options granted, excluding the impact of non-market vesting conditions. Non-market vesting conditions are included in assumptions about the number of options that are expected to vest. At the end of reporting period, the Group revises its estimates of the number of options that are expected to vest. The Group recognises the impact of the revision of the original estimates in profit or loss with a corresponding entry to equity. The proceeds received net of any directly attributable transaction costs are credited to share capital (nominal value) and share premium when the options are exercised.

Revenue recognition

Revenue is measured at the fair value of the consideration received or receivable, net of discounts, value added tax and customs duties.

Revenue from the sale of crude oil, oil products and other goods is recognised when the following conditions are satisfied:

 Group has transferred to the buyer the significant risks and rewards of ownership;  Group retains neither continuing managerial involvement to the degree usually associated with ownership nor effective control over the goods sold;  Amount of revenue can be measured reliably;  It is probable that the economic benefits associated with the transaction will flow to the Group; and  Costs incurred or to be incurred in respect of the transaction can be measured reliably.

Incidental revenues from production of crude oil at the well’s development stage or revenues associated with initial test production are offset against capitalised costs of the related field area cost centre until quantities of proven and probable reserves are determined and commercial production has commenced.

Revenue from rendering of services is recognised at the time the services are provided to the customer.

Interest income from a financial asset is recognised when it is probable that the economic benefits will flow to the Group and the amount of income can be measured reliably. Interest income is accrued on a time basis, by reference to the principal outstanding and at the effective interest rate applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset's net carrying amount on initial recognition.

Leasing

Leases are classified as finance leases whenever the terms of the lease transfer substantially all the risks and rewards of ownership to the lessee. All other leases are classified as operating leases.

The Group as lessor

Rental income from operating leases is recognised on a straight-line basis over the term of the relevant lease. Initial direct costs incurred in negotiating and arranging an operating lease are added to the carrying amount of the leased asset and recognised on a straight-line basis over the lease term.

The Group as lessee

Operating lease payments are recognised as an expense on a straight-line basis over the lease term, except where another systematic basis is more representative of the time pattern in which economic benefits from the leased asset are consumed. Contingent rentals arising under operating leases are recognised as an expense in the period in which they are incurred.

In the event that lease incentives are received to enter into operating leases, such incentives are recognised as a liability. The aggregate benefit of incentives is recognised as a reduction of rental expense on a straight-line basis, except where another systematic basis is more representative of the time pattern in which economic benefits from the leased asset are consumed.

22 F-92 Income tax

Income tax expense represents the sum of the tax currently payable and deferred tax. Income taxes are computed in accordance with the laws of countries where the Group's entities operate.

Current tax

The tax currently payable is based on taxable profit for the period. Taxable profit differs from profit as reported in the consolidated income statement because of items of income or expense that are taxable or deductible in other years and items that are never taxable or deductible. The Group’s liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the end of reporting period.

Deferred tax

Deferred tax is recognised on temporary differences between the carrying amounts of assets and liabilities in the consolidated financial statements and the corresponding tax bases used in the computation of taxable profit. Deferred tax liabilities are generally recognised for all taxable temporary differences. Deferred tax assets are generally recognised for all deductible temporary differences to the extent that it is probable that taxable profits will be available against which those deductible temporary differences can be utilised. Such deferred tax assets and liabilities are not recognised if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the taxable profit nor the accounting profit.

The carrying amount of deferred tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.

Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period in which the liability is settled or the asset realised, 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 liabilities and assets reflects the tax consequences that would follow from the manner in which the Group 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 same taxation authority and the Group intends to settle its current tax assets and liabilities on a net basis.

Current and deferred tax for the period

Current and deferred tax are recognised in profit or loss, except when they relate to items that are recognised in other comprehensive income or directly in equity, in which case, the current and deferred tax are also recognised in other comprehensive income or directly in equity respectively. Where current tax or deferred tax arises from the initial accounting for a business combination, the tax effect is included in the accounting for the business combination.

Segment information

Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision makers, who are responsible for allocating resources and assessing performance of the operating segments. Chief operating decision makers have been identified as the management team of Managing Director, Chief Financial Officer, Chief Operating Officer, Chief Executive Officer Downstream, Chief Executive Officer Upstream.

23 F-93 6. CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS

In the application of the Group’s accounting policies management is required to make judgements, estimates and assumptions about the carrying amounts of assets and liabilities and amount of revenues and expenses, recognised during the reporting period, that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant. They are reviewed on an ongoing basis. Actual results could differ from those estimates.

The most significant areas of accounting requiring the use of the Group’s management estimates and assumptions relate to useful economic lives and residual values of property, plant and equipment; impairment of goodwill and tangible assets; decommissioning and site restoration costs; taxation; valuation of financial instruments and fair value of net assets acquired and liabilities assumed in business combinations.

Useful economic lives of property, plant and equipment

Oil and gas assets

The Group’s oil and gas assets are depleted over the respective life of the oil and gas fields using the unit-of-production method based on proved and probable oil and gas reserves and incorporating the anticipated future capital cost for the development of those reserves.

When determining the life of the oil and gas field, assumptions that were valid at the time of estimation, may change when new information becomes available. The factors that could affect the estimation of the life of an oil and gas field include the following:

 Changes in the estimation of proved and probable oil and gas reserves;  Variances between actual and forecasted commodity prices used in the estimation of oil and gas reserves;  Unforeseen operational issues; and  Changes in capital, operating, processing and reclamation costs, discount rates and foreign exchange rates possibly adversely affecting the economic viability of oil and gas reserves.

Any of these changes could affect prospective depletion of oil and gas assets and their carrying value.

Anticipated future development costs are estimated using assumptions as to the number of wells required to produce the commercial reserves, the cost of such wells and associated production facilities, and other capital costs.

Refining, marketing and other non-production assets

Property, plant and equipment other than oil and gas assets are depreciated on a straight-line basis over their useful economic lives. Management at the end of each reporting period reviews the appropriateness of the assets useful economic lives and residual values. The review is based on the current condition of the assets, the estimated period during which they will continue to bring economic benefits to the Group and the estimated residual value.

Impairment of goodwill and tangible assets

Impairment of goodwill

Goodwill acquired through business combinations has been allocated to a cash-generating unit “Downstream segment” which is also a reportable operating segment.

The recoverable amount of downstream segment assets was determined based on a value in use calculations using cash flow projections that were based on the following assumptions:

 Cash flows were calculated for an eleven-year period;  Prices of oil products were forecast on the basis of oil price and refining margins;  Costs included crude oil purchases, operating and administrative expenses;  Financial pre-tax discount rate of 11.68% per annum.

No impairment related to goodwill has been recognised in the consolidated income statement for the year ended 31 December 2011.

24 F-94 Impairment of tangible assets

The Group calculates recoverable amounts of its upstream CGUs, which are defined on a field area cost centre basis: group of three Kharyaga fields and the Kolvinskoye field located in the Timano- Pechora region, group of three fields and the Khvoinoye field located in the Tomsk region, Kochevnenskaya group of six fields and three separate fields located in the Volga-Urals region, and one field located in Kazakhstan.

The recoverable amounts of the cash-generating units were determined based on a value in use calculations. The key assumptions used in the value in use calculations were as follows:

 Crude oil price Brent based on Intercontinental Exchange crude oil price futures data;  Production volumes based on the approved field's development program;  Operating costs included production and other taxes, other controllable production and administrative expenses;  The capital expenditures included drilling costs and other capital expenditures expected to be incurred for field development;  Financial pre-tax discount rate of 11.68% per annum.

For each oil field or group of fields tests were performed for the period of expected profitable operations but no longer than the field development period determined in the reserve report prepared by DeGolyer & McNaughton.

Management believes that any reasonable possible change in the key assumptions on which recoverable amounts are based would not cause the aggregate carrying amounts to exceed the aggregate recoverable amounts of the cash-generating units determined for assessment of impairment of tangible assets and goodwill.

No impairment loss, or reversal of previously recognised impairment loss, has been recognised in the consolidated income statement for the year ended 31 December 2011.

Decommissioning and site restoration costs

In respect of fields where the Group is required to perform decommissioning and site restoration, a provision is recorded to recognise existing commitments (Note 30). The Group performs analysis and estimates in order to determine the probability, timing and amount involved with probable required outflow of resources. Estimating the amounts and timing of those decommissioning and site restoration obligations that should be recorded requires significant judgment. The judgment is based on cost and engineering studies using currently available technology and is based on current environmental regulations. Liabilities for decommissioning and site restoration costs are subject to change because of change in laws and regulations, and their interpretation.

When the final amount of decommissioning and site restoration obligations differ from the recognised provisions, the difference is recognised in profit or loss.

Taxation

The Group is subject to income tax and other taxes. Significant judgement is required in determining the provision for income tax and other taxes due to the complexity of the tax legislation of countries where the Group operates. There are many transactions and calculations for which the ultimate tax determination is uncertain. The Group recognises liabilities for anticipated tax audit issues based on estimates of whether additional taxes will be due. Where the final tax outcome of these matters is different from the amounts that were initially recorded, such differences will impact the amount of tax and tax provisions in the period in which such determination is made. Deferred tax assets are recognised for all unused tax losses to the extent that it is probable that taxable profit will be available against which the losses can be utilised. Significant management judgment is required to determine the amount of deferred tax assets that can be recognised, based upon the likely timing and the level of future taxable profits together with future tax planning strategies (Note 16).

25 F-95 Valuation of financial instruments

As described in note 38, the Group uses valuation techniques that include inputs that are not based on observable market data to estimate the fair value of certain types of financial instruments. Note 38 provides detailed information about the key assumptions used in the determination of the fair value of financial instruments.

The directors believe that the chosen valuation techniques and assumptions used are appropriate in determining the fair value of financial instruments.

Fair value of net assets acquired and liabilities assumed in business combinations

In accordance with the Group’s policy, the Group allocated the cost of the acquired entity to the assets acquired and liabilities assumed based on their fair value estimated on the date of acquisition. The excess of the sum of the consideration transferred, the amount of any non-controlling interests in the acquiree, and the fair value of the acquirer's previously held equity interest in the acquiree (if any) over the net of the acquisition-date amounts of the identifiable assets acquired and the liabilities assumed is recorded as goodwill. The Group exercises significant judgment in the process of identifying tangible and intangible assets and liabilities, valuing these assets and liabilities, and estimating their remaining useful life. The valuation of these assets and liabilities is based on assumptions and criteria that, in some cases, include estimates of discounted future cash flows. The use of valuation assumptions includes cash flow estimates from sales and marketing activities and discount rates and may result in values that are different from the assets acquired and liabilities assumed.

If actual results are not consistent with estimates and assumptions considered, the Group may be exposed to losses that could be material.

7. RECLASSIFICATIONS

Certain comparative information presented in the consolidated financial statements for the year ended 31 December 2010 has been reclassified. Reclassifications were based upon management’s decision to enhance disclosure of the Group’s results of operation through presentation of transportation costs in accordance with their substance.

Before After reclassification reclassification Effect

Production costs of oil products (1,159,842) (1,168,068) (8,226) Selling expenses (231,956) (223,730) 8,226

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8. SEGMENT INFORMATION

Management determines its reporting segments based on the nature of operations of the Group’s entities. As a result, two business segments are presented: the upstream segment which includes crude oil exploration, extraction and production, and the downstream segment which includes oil refining, transportation and sales of oil products. Management reviews and evaluates the performance of these segments on a regular basis. Operations of the Parent company and subsidiaries involved in non-core activities are combined into one segment “Other companies”.

Management assesses the performance of the operating segments based on EBITDA (Earnings Before Interest, Tax, Depreciation and Amortisation) which is calculated as follows: operating result plus depletion and depreciation and impairment of oil and gas assets and goodwill, if any, less gain on disposal of shares in subsidiaries, if any, and other significant one-off items in the income statement. EBITDA is a supplemental financial measure used by management to evaluate operations. Management believes that EBITDA represents useful means of assessing the performance of the Group's ongoing operating activities, as it reflects the earnings trend. Calculation of segment EBITDA is performed based on management accounts.

26 F-96 Financial information by reportable segments is presented below:

Year ended 31 December 2011 Inter- segment Recon- Down- Other elimi- ciling Upstream stream companies nations items Total Revenue Export 345,192 883,703 - - - 1,228,895 Export CIS 19,320 - - - - 19,320 Domestic 518,562 1,959,422 40,432 (683,489) (482) 1,834,445 Total segment revenue 883,074 2,843,125 40,432 (683,489) (482) 3,082,660 Less inter-segment revenue (342,944) (300,113) (40,432) 683,489 - - Revenue from external customers 540,130 2,543,012 - - (482) 3,082,660

Segment operating income 279,157 274,874 (23,565 ) (229 ) (16,981 ) 513,256 Interest income 5,560 6,927 106,256 (106,389) (95) 12,259 Finance costs (51,088) (28,041) (92,131) 93,044 19,082 (59,134) Loss on derivatives classified as held for trading, net - (15,444) - - - (15,444) Currency exchange gain/(loss), net 7,111 (42,816) (5,700) 73 23,156 (18,176) Profit before tax 240,740 195,500 (15,140) (13,501) 25,162 432,761 Income tax expense (59,076) (39,110) (4,721) - (1,564) (104,471) Profit for the year 181,664 156,390 (19,861) (13,501) 23,598 328,290

Segment EBITDA 413,857 315,955 (23,116 ) (230 ) (16,121 ) 690,345

Additions to property, plant and equipment 653,528 431,106 346 - - 1,084,980 Depreciation, depletion and amortisation (134,699) (38,198) (449) - (849) (174,195) Share of profits of associates - 256 1,897 - - 2,153

Year ended 31 December 2010

Inter- segment Recon- Down- Other elimi- ciling Upstream stream companies nations items Total Revenue Export 211,786 508,658 - - - 720,444 Export CIS 48,140 1,640 - - - 49,780 Domestic 323,126 1,403,720 32,988 (335,003) 701 1,425,532 Total segment revenue 583,052 1,914,018 32,988 (335,003) 701 2,195,756 Less inter-segment revenue (181,806) (120,601) (32,596) 335,003 - - Revenue from external customers 401,246 1,793,417 392 - 701 2,195,756

Segment operating income 129,316 211,449 (29,530 ) - (3,915 ) 307,320 Interest income 4,075 5,996 84,896 (87,223) 157 7,901 Finance costs (36,770) (30,331) (46,315) 76,353 7,590 (29,473) Currency exchange gain/(loss), net 1,480 (1,489) 53 - 3,879 3,923 Profit before tax 98,101 185,625 9,104 (10,870) 7,711 289,671 Income tax expense (26,222) (34,959) (1,553) - (605) (63,339) Profit for the year 71,879 150,666 7,551 (10,870) 7,106 226,332

Segment EBITDA 233,165 240,992 (28,892 ) - (6,874 ) 438,391

Additions to property, plant and equipment 409,361 320,564 472 - - 730,397 Depreciation, depletion and amortisation (101,685) (29,543) (642) - (365) (132,235) ReversaI of impairment of oil and gas assets, net (2,285) - - - 3,336 1,051 Share of profits of associates - 104 - - - 104

Upstream and downstream segment revenue includes revenue from sales of crude oil and oil products, respectively, and income from other non-core activities.

27 F-97 Domestic revenue from external customers of upstream and downstream includes TUSD 42,515 of other income for the year ended 31 December 2011 (2010: TUSD 30,251), mainly represented by sales of services and goods at fuel stations of TUSD 16,145 (2010: TUSD 14,208) and transportation services of TUSD 15,335 (2010: TUSD 13,379).

The Group has one customer that comprises more than 10% of the Group’s revenue:

Year ended 31 December 2011 Year ended 31 December 2010 % of segment % of segment Revenue revenue Revenue revenue

Upstream 66,108 7% 40,707 7% Downstream 775,602 27% 466,928 24%

The reconciliation of segment results to the consolidated financial statements primarily includes:  elimination of unrealised gains/losses on intra-segment operations;  currency exchange gains/losses related to intercompany loans treated as extended investments and classified within the statement of comprehensive income;  capitalised interest on loans and borrowings;  tax effect on the above mentioned adjustments;  reversal of impairment provision in the amount of TUSD 3,336 in 2010 that was recognised on the Group level and not allocated to the upstream operating segment result.

Prices used in transactions between reportable segments are determined on an arm’s length basis in a manner equal to transactions with third parties, except for interest-free loans provided and obtained.

Reconciliation of the segments’ EBITDA to profit before tax is presented below:

Year ended Year ended 31 December 31 December 2011 2010

EBITDA of reportable segments 729,812 474,157 EBITDA of other companies (23,116) (28,892) Inter-segment eliminations (230) - Effect of reconciling items (16,121) (6,874) Total EBITDA 690,345 438,391

Depreciation, depletion and amortisation (174,195) (132,235) Interest income 12,259 7,901 Finance costs (59,134) (29,473) Loss on derivatives classified as held for trading, net (15,444) - Currency exchange (loss)/gain, net (18,176) 3,923 (Loss)/gain on disposal of shares in subsidiaries (2,894) 9 ReversaI of impairment of oil and gas assets, net - 1,051 Other - 104

Profit before tax 432,761 289,671

Activities by geographical areas

The Group operates in two geographical areas, Russia and Kazakhstan. For management accounting purposes activities in Kazakhstan are considered to be not significant.

28 F-98 9. PRODUCTION COSTS OF CRUDE OIL

Year ended Year ended 31 December 31 December 2011 2010

Production tax 201,847 159,246 Payroll and related taxes 47,397 35,141 Taxes other than income and production tax 29,425 21,726 Transportation 17,917 8,229 Materials and fuel 17,183 8,724 Repairs and maintenance 12,921 13,440 Energy 5,604 4,398 Insurance 4,684 4,382 Rent 4,339 2,053 Oil preparation 3,752 4,490 Exploration and evaluation costs 2,734 3,577 Other 5,244 3,756

353,047 269,162

Production costs of crude oil represent cost of crude oil sold both intragroup and to the external customers.

10. PRODUCTION COSTS OF OIL PRODUCTS

Year ended Year ended 31 December 31 December 2011 2010

Crude oil purchased for refining 799,661 548,199 Transportation 513,426 397,394 Oil products purchased for re-sale 129,524 108,028 Taxes other than income tax 121,054 67,494 Payroll and related taxes 30,881 20,952 Other 37,363 26,001

1,631,909 1,168,068

Transportation costs include cost of delivery of crude oil to the Khabarovsk Oil Refinery and related insurance expenses.

11. SELLING EXPENSES

Year ended Year ended 31 December 31 December 2011 2010

Transportation 185,602 135,164 Payroll and related taxes 55,820 46,503 Repairs and maintenance 13,960 12,731 Taxes other than income tax 7,726 6,799 Energy and utilities 7,005 5,558 Insurance 3,791 3,254 Export related expenses 3,240 3,437 Rent 2,039 1,927 Advertising and marketing 1,744 1,616 Other 8,997 6,741

289,924 223,730

29 F-99 12. ADMINISTRATIVE EXPENSES

Year ended Year ended 31 December 31 December 2011 2010

Payroll and related taxes and share options 33,971 28,827 Rent 14,358 13,363 Professional fees (legal, audit, consulting, etc.) 13,261 11,322 Advertising and marketing 2,771 3,758 Bank charges 3,608 3,495 Taxes other than income tax 2,269 2,210 Other 7,219 4,915

77,457 67,890

Deloitte was the Group’s auditor for the years ended 31 December 2011 and 2010. The Group had the following audit related expenses:

Year ended Year ended 31 December 31 December 2011 2010

Deloitte – audit 1,782 1,544 Deloitte – consulting 835 255 Audit Consult – audit 648 754 Other – audit and consulting 806 124

4,071 2,677

13. OTHER OPERATING EXPENSES, NET

Year ended Year ended 31 December 31 December 2011 2010

Charity 12,736 6,539 Loss on disposal of assets 3,196 204 Other 2,288 (52)

18,220 6,691

14. FINANCE COSTS

Year ended Year ended 31 December 31 December 2011 2010

Interest expense on bonds 105,809 58,740 Interest expense on loans and borrowings 22,582 27,618 Total interest expense for financial liabilities not classified as at fair value through profit or loss 128,391 86,358

Bank commissions and other issue costs 18,937 10,786 Unwinding of discount on provision for decommissioning and site restoration costs (Note 30) 3,214 1,808

Less: amounts included in the cost of qualifying assets (91,408) (69,479)

59,134 29,473

Capitalised borrowing costs related to loans obtained for the purposes of modernisation of the Khabarovsk Oil Refinery and development of oil and gas fields.

Capitalisation rates used to determine the amount of borrowing costs eligible for capitalisation for the year ended 31 December 2011 were between 4.10% and 10.18% (2010: 4.50%-18.00%).

30 F-100 15. DERIVATIVES CLASSIFIED AS HELD FOR TRADING

In June and August 2011, the Group has entered cross-currency interest rate swaps in order to balance cash inflows from export sales denominated in USD with cash outflows on interest payments denominated in RUB and obtain a lower interest rate. Due to the absence of designated relationship between a hedging instrument and a hedged item, hedge accounting has not been applied.

Swap 1 Swap 2 Total

At 1 January 2011 - - - Loss on derivatives classified as held for trading (5,518) (10,114) (15,632) Interest on swap received during the year 188 - 188 Translation difference 423 1,175 1,598

At 31 December 2011 (4,907) (8,939) (13,846)

The analysis of the swaps as they are recorded in the consolidated statement of financial position at 31 December 2011 is presented below:

Swap 1 Swap 2 Total

Current assets - 2,175 2,175 Non-current liabilities - (11,114) (11,114) Current liabilities (4,907) - (4,907)

(4,907) (8,939) (13,846)

Swap 1 matures in July 2012 and Swap 2 matures in July 2013.

16. INCOME TAX

The Parent company, Alliance Oil Company Ltd, which is registered in Bermuda, is exempt from income tax. The statutory income tax rate in the Russian Federation, the location of the majority of the Group’s entities, is 20%. OJSC Khabarovsk Oil Refinery applies a 15.5% income tax rate due to the decreased regional budget component of the income tax. The profit of LLC Potential Oil, a Kazakhstan subsidiary, is subject to a 30% income tax rate. The profit of Cypriot subsidiaries, Vostok Oil (Cyprus) Ltd and O&G Credit Agency Ltd, is subject to income tax at the rate of 10%. On taxable profits above MEUR 1 an additional tax of 5% is imposed.

Income tax recognised in the consolidated income statement:

Year ended Year ended 31 December 31 December 2011 2010

Current tax 83,246 46,276 Deferred tax 21,225 17,063

Total income tax expense 104,471 63,339

The income tax expense recorded in the consolidated income statement differs from the theoretical amount that would have arisen applying the tax rate to the profit before income tax and is reconciled as follows:

Year ended Year ended 31 December 31 December 2011 2010

Profit before tax 432,761 289,671

Theoretical tax at rate 20% for Russian Federation 60,390 37,664 Theoretical tax at rate 15.5% for Russian Federation 17,243 12,650 Theoretical tax at rate 30% for Kazakhstan 11,964 6,243 Theoretical tax at other rates 2,499 942 Effect of intragroup dividends received 2,850 - Non-deductible charity expenses 2,825 2,237 Other 6,700 3,603

Total income tax expense 104,471 63,339 Effective tax rate for the Group 24% 22%

31 F-101 The movement in the Group's net deferred tax liabilities was as follows:

Year ended Year ended 31 December 31 December 2011 2010

Net deferred tax liabilities at beginning of the year 152,712 137,442 Recognised in the consolidated income statement 21,225 17,063 Effect of currency exchange differences on intercompany loans classified as net investments recognised in other comprehensive income (2,256) (1,299) Acquired on acquisition of subsidiaries (Note 35) 589 - Translation difference (10,711) (494)

Net deferred tax liabilities at end of the year 161,559 152,712

Certain deferred tax assets and liabilities have been offset in accordance with the Group’s accounting policy. The analysis of the deferred tax balances (after offset) as they are recorded in the consolidated statement of financial position is presented below:

31 December 31 December 2011 2010

Deferred tax liabilities 187,998 178,031 Deferred tax assets (26,439) (25,319)

Net deferred tax liabilities 161,559 152,712

The tax effects on the major temporary differences that gave rise to the deferred taxation as at 31 December 2011 and 2010 are presented below:

31 December 31 December 2011 2010

Property, plant and equipment 194,363 191,033 Inventories (4,682) (3,965) Trade, other receivables and prepaid expenses (1,224) (2,135) Effect of currency exchange differences on intercompany loans classified as net investments (4,719) (5,836) Valuation of loans and borrowings 6,779 6,227 Trade, other payables and accrued expenses (5,888) (5,797) Derivatives classified as held for trading (2,769) - Tax loss carry-forward (24,599) (27,919) Other 4,298 1,104

Net deferred tax liabilities 161,559 152,712

Deferred tax liabilities have not been recognised for the following temporary differences associated with investments in subsidiaries:

Applicable for dividends tax 31 December 31 December Investor country of incorporation rate 2011 2010

Russian Federation 0% 688,164 741,084 Cyprus 5% 166,753 34,620 Russian Federation 9% 30,294 13,961

32 F-102 17. EARNINGS PER SHARE

Basic earnings per share

Basic earnings per share are calculated by dividing the profit attributable to owners of the Company by the weighted average number of ordinary shares in issue during the year.

Year ended Year ended 31 December 31 December 2011 2010

Profit attributable to owners of the Company 318,873 222,221 Weighted average number of ordinary shares in issue 171,528,414 171,528,414

Basic earnings per share 1.86 1.30

Diluted earnings per share

Diluted earnings per share are calculated by adjusting the weighted average number of ordinary shares outstanding to assume conversion of dilutive potential ordinary shares. The Company has the following categories of dilutive potential ordinary shares: convertible bonds, share options and warrants (expired in October 2011).

For the year ended 31 December 2011, the following instruments were included in the calculation of diluted earnings per share:

 Convertible bonds with a conversion price of SEK 121.13 (USD 15.94 at fixed exchange rate) (Note 29);  437,700 share options with an exercise price of SEK 81.80 (USD 11.87 at the exchange rate on the reporting date); and  614,934 share options with an exercise price of SEK 85.00 (USD 12.33) per share (Note 28).

For the year ended 31 December 2010, the following instruments were included in the calculation of diluted earnings per share:

 Convertible bonds with a conversion price of SEK 121.13 (USD 15.94); and  571,100 share options with an exercise price of SEK 81.80 (USD 12.06).

The convertible bonds are assumed to have been converted into ordinary shares, and the net profit is adjusted to eliminate the finance costs. Assumed conversion of convertible bonds results in the issuance of 16,624,791 ordinary shares.

For the share options, a calculation is performed to determine the number of shares that could have been acquired at fair value (determined as the average annual market share price of the Company’s shares) based on the monetary value of the subscription rights attached to outstanding share options. The number of shares calculated as above is compared with the number of shares that would have been issued assuming the conversion of bonds and exercise of the share options.

Year ended Year ended 31 December 31 December 2011 2010

Profit attributable to owners of the Company 318,873 222,221 Interest expense on convertible bonds recognised in statement of comprehensive income 9,709 6,278 328,582 228,499

Weighted average number of ordinary shares in issue 171,528,414 171,528,414 Adjustments for: - Assumed conversion of convertible bonds 16,624,791 16,624,791 - Share options 169,883 117,840 Weighted average number of ordinary shares used in the calculation of diluted earnings per share 188,323,088 188,271,045

Diluted earnings per share 1.74 1.21

33 F-103 18. PROPERTY, PLANT AND EQUIPMENT

Marketing and other Oil and gas non-production assets Refining assets assets Total

Cost

At 31 December 2010 1,944,048 858,843 270,508 3,073,399 Reclassifications (535) - 535 - Additions 651,872 403,326 29,782 1,084,980 Acquisitions through business combination - - 8,403 8,403 Disposals (3,300) (1,925) (3,791) (9,016) Derecognised on disposal of a subsidiary - - (6,334) (6,334) Translation difference (159,202) (79,189) (16,764) (255,155) At 31 December 2011 2,432,883 1,181,055 282,339 3,896,277

Accumulated depletion and depreciation At 31 December 2010 (279,057 ) (73,049 ) (76,235 ) (428,341 ) Charge for the year (141,095) (20,349) (17,150) (178,594) Disposals 1,460 1,030 1,745 4,235 Derecognised on disposal of a subsidiary - - 540 540 Translation difference 25,292 5,596 4,024 34,912 At 31 December 2011 (393,400) (86,772) (87,076) (567,248)

Accumulated impairment At 31 December 2010 (116,814 ) - - (116,814 ) Depletion of accumulated impairment 5,872 - - 5,872 Translation difference 5,711 - - 5,711 At 31 December 2011 (105,231) - - (105,231)

Net book value at 31 December 2011 1,934,252 1,094,283 195,263 3,223,798

Marketing and other Oil and gas non-production assets Refining assets assets Total

Cost

At 31 December 2009 1,553,753 580,416 245,813 2,379,982 Reclassifications 370 - (370) - Additions 413,221 285,455 31,721 730,397 Disposals (10,377) (2,075) (4,821) (17,273) Translation difference (12,919) (4,953) (1,835) (19,707) At 31 December 2010 1,944,048 858,843 270,508 3,073,399

Accumulated depletion and depreciation At 31 December 2009 (174,578 ) (59,874 ) (63,866 ) (298,318 ) Charge for the year (106,869) (14,631) (15,143) (136,643) Disposals 836 975 2,239 4,050 Translation difference 1,554 481 535 2,570 At 31 December 2010 (279,057) (73,049) (76,235) (428,341)

Accumulated impairment At 31 December 2009 (124,340 ) - - (124,340 ) Impairment charge reversal 3,336 - - 3,336 Write-off of exploration assets (2,285) - - (2,285) Depletion of accumulated impairment 5,536 - - 5,536 Translation difference 939 - - 939 At 31 December 2010 (116,814) - - (116,814)

Net book value at 31 December 2010 1,548,177 785,794 194,273 2,528,244

In 2010, the Group reversed an impairment loss of TUSD 3,336 related to the Kolvinskoye CGU in the Timano-Pechora region, which was initially recorded in 2008. Management’s judgment was primarily based on the significant increase in proved and probable reserves at the Kolvinskoye oil field, reported by the independent reserve engineers.

34 F-104 Exploration and evaluation assets

Exploration and evaluation assets included in the property, plant and equipment mainly comprised capitalised exploration drilling costs and geological studies and seismic researches related to the exploration license oil fields and prospects located in the Volga-Urals region of the Russian Federation:

Year ended Year ended 31 December 31 December 2011 2010

Balance at beginning of the year 37,121 18,792 Transfers to oil and gas assets (11,744) (9,146) Additions 9,322 30,432 Write-off - (2,285) Translation difference (1,749) (672)

Balance at end of the year 32,950 37,121

Investments in exploration and evaluation assets for the year ended 31 December 2011 amounted to TUSD 9,322 (2010: TUSD 27,321).

In 2010, based on the unsatisfactory results of the exploration works performed for Ivanikhinskoye license area located in the Volga-Urals region of the Russian Federation, the Group made a decision to write-off the value of the capitalised exploration costs in the amount of TUSD 2,285.

19. GOODWILL

Year ended Year ended 31 December 31 December 2011 2010

Balance at beginning of the year 11,728 11,818 Additional amounts recognised from business combination occurring during the year (Note 35) 8,947 - Translation difference (1,436) (90)

Balance at end of the year 19,239 11,728

At 31 December 2011, the Group tested the amount of goodwill for impairment. For the purpose of such testing, goodwill was allocated to a cash-generating unit "Downstream segment" (Note 8). No impairment loss has been identified.

20. INVESTMENTS IN ASSOCIATES

Details of the Group's associates as at 31 December 2011 and 2010 were as follows:

Voting power held by the Group, % 31 December 31 December Operating entity Activity Country 2011 2010

LLC Dalnefteresource Trading of oil products Russian Federation 49% 49% Trading of crude oil and Lia Oil S.A. oil products Switzerland 40% -

In May 2011, the Group completed the acquisition of 40% share in the capital of Lia Oil S.A. from a related party for a cash consideration of TUSD 20,000. The acquisition was financed in 2010. From the acquisition, Lia Oil S.A. is treated as an associate of the Group and accounted for using the equity method.

35 F-105 Summarised financial information in respect of the Group's associates is set out below:

31 December 31 December 2011 2010

Total assets 258,645 18,938 Total liabilities (209,642) (18,631) Net assets 49,003 307 Group's share of net assets 19,663 150 Goodwill recognised in cost of investment 2,476 - Consolidation adjustments recognised in cost of investment (313) -

Total carrying value of investment 21,826 150

Year ended Year ended 31 December 31 December 2011 2010

Total revenue 2,156,317 226,211 Total profit for the year 5,263 213

Group's share of profits of associates 2,153 104

21. OTHER FINANCIAL ASSETS

31 December 31 December 2011 2010 Non -current Loans - 10,090 Other 167 98 167 10,188 Current Bank deposits 26,115 30,000 Loans and promissory notes 64,973 19,629 Derivatives classified as held for trading (Note 15) 2,175 - 93,263 49,629

93,430 59,817

Bank deposits placed with the related party bank are denominated in RUB and bear interest of 10.25% per annum with original maturity after three months (2010: denominated in USD and bear interest of 6.5% per annum).

At 31 December 2011, loans provided to third parties include:

 Not collateralised RUB-denominated short-term loan bearing interest of 10% per annum; and  USD-denominated short-term loan bearing interest of 10.59% per annum, which is collateralised by 100% of the Borrower’s own shares and 100% of the shares of the Borrower’s subsidiary.

At 31 December 2010, loans provided to third parties include:

 Not collateralised RUB-denominated short-term loans bearing interest of 10-15% per annum; and  Not collateralised USD-denominated long-term loan bearing interest of Libor 6m+10% with maturity in 2012.

22. OTHER ASSETS

31 December 31 December 2011 2010

Value added tax (VAT) recoverable after 12 months 29,878 18,115 Advance for acquisition of associate (Note 20) - 20,000

29,878 38,115

36 F-106 23. INVENTORIES

31 December 31 December 2011 2010

Oil products 67,816 69,042 Crude oil 55,207 53,513 Other inventories 23,029 19,734 Allowance for slow-moving and obsolete inventories (1,023) (973)

145,029 141,316

24. TRADE AND OTHER ACCOUNTS RECEIVABLE

31 December 31 December 2011 2010

Trade accounts receivable 87,183 67,686 Other accounts receivable 29,459 56,653 Less: allowance for doubtful debts (3,037) (7,204)

113,605 117,135

The majority of retail and wholesale customers operate on the advance payment terms. The credit period for other customers does not exceed 30 days. No interest is charged on the outstanding balances. The Group monitors the trade debtors through a special committee on a monthly basis. The concentration of credit risk is limited due to the customer base being large and unrelated and all goods produced by the Group can be easily sold on the active market.

At 31 December 2011, balances of the Group’s two largest customers each exceeded 10% of the outstanding balance of trade accounts receivable. Based on the past history of transactions with these customers management believes that there is no credit risk attached to them.

Allowance for doubtful debts is recognised in respect of estimated irrecoverable amounts determined by reference to past default experience of the counterparty and analysis of the counterparty's current financial position.

The movements in the allowance for trade and other accounts receivable are presented below:

Year ended Year ended 31 December 31 December 2011 2010

Balance at beginning of the year 7,204 9,748 Additions to allowance 753 348 Release of allowance (791) (329) Amounts written-off (4,113) (2,502) Translation difference (16) (61)

Balance at end of the year 3,037 7,204

Ageing of fully and partially impaired trade and other receivables:

31 December 31 December 2011 2010

Less than 90 days 28 45 90-365 days 3,009 7,319

3,037 7,364

37 F-107 The Group has past due balances of trade and other receivables for which no allowance was created as the management considered such balances as recoverable. Ageing of past due but not impaired trade and other receivables is presented below:

31 December 31 December 2011 2010

Less than 90 days 4,072 2,139 90-365 days 3,745 6,810

7,817 8,949

25. VALUE ADDED TAX AND OTHER TAXES RECEIVABLE

31 December 31 December 2011 2010

VAT 202,805 126,498 Export and other custom duties 20,870 8,855 Other taxes receivable 877 413

224,552 135,766

26. ADVANCES PAID AND PREPAID EXPENSES

31 December 31 December 2011 2010

Advances paid 118,744 89,546 Prepaid expenses 7,252 8,889 Less: impairment of advances paid (89) (432)

125,907 98,003

27. CASH, CASH EQUIVALENTS AND RESTRICTED CASH

31 December 31 December 2011 2010 Cash in banks: in USD 9,214 14,221 in RUB 14,280 26,725 in EUR 1,139 821 in other currencies 1,808 283 Cash in transit 3,952 1,170

Cash deposits: in USD 9,308 2,344 in RUB 116,633 52,146 in EUR 2,006 - Petty cash 1,974 1,060 Other 169 7 160,483 98,777

Restricted cash: in USD 1,115 29,342 in RUB - 49 in EUR 26,203 49,931 27,318 79,322

187,801 178,099

At 31 December 2011, cash deposits bear interest of 0.4%-7.1% per annum with original maturity within three months (2010: 0.1%-3%).

Restricted cash is mostly represented by letters of credit on a special account with OJSC Bank VTB in relation to agreements for the reconstruction of OJSC Khabarovsk Oil Refinery.

38 F-108 28. SHARE CAPITAL AND RESERVES

At 31 December 2011 and 2010, the authorised share capital of the Parent company consisted of 220,000,000 ordinary shares, of which 171,528,414 were issued and fully paid. Each ordinary share has a par value of USD 1 and carries one vote.

No dividends were approved or paid in 2011 in respect of 2010.

Share option plan

The Group has Global Share Option Plan under which share options can be granted to eligible employees, including Group management and directors. Each option gives the right to subscribe for one share of common stock at the exercise price. All options are exercisable after 3 years subject to certain non-market conditions, such as the Group’s and individual performance, and expire in 5 years from issuance. The fair value of the employee services received in exchange for the grant of the options is recognised as an expense. Total amount to be expensed over the vesting period of 3 years is determined by reference to the fair value of the options granted excluding the impact of any non- market vesting conditions. For the years ended 31 December 2011 and 2010, the share option charge amounted to TUSD 1,357 and TUSD 851, respectively, and was recorded within administrative expenses.

Movements in the number of share options outstanding and their related weighted average exercise prices are presented below:

Year ended 31 December 2011 Year ended 31 December 2010 Average Average exercise price in Number of exercise price in Number of SEK per share options SEK per share options

At beginning of the year 115.54 3,769,753 114.34 2,999,050 Granted during the year 85.00 614,934 115.00 995,204 Expired during the year 125.06 (1,588,700) - - Forfeited during the year 90.41 (180,108) 93.02 (224,501)

At end of the year 104.31 2,615,879 115.54 3,769,753

In September 2011, the Board of directors approved the issue of 614,934 share options to employees with a grant date of 23 September 2011 and an exercise price of SEK 85 (USD 12.33 at the exchange rate on the reporting date). All options are exercisable after 3 years subject to certain conditions and expire after 5 years from issuance.

In August 2010, the Board of directors approved the issue of 995,204 share options to employees with a grant date of 20 August 2010 and an exercise price of SEK 115 (USD 16.95). All options are exercisable after 3 years subject to certain conditions and expire after 5 years from issuance.

Share options outstanding at 31 December 2011 and 2010 had the following grant and expiry dates and exercise prices:

Exercise Number of options outstanding Fair value in price in SEK 31 December 31 December Grant date Expiry date SEK per share per share 2011 2010

31 January 2006 31 January 2011 50.00 122.60 - 1,363,700 10 April 2006 10 April 2011 60.20 140.00 - 225,000 28 February 2007 28 February 2012 38.40 124.00 578,850 578,850 22 May 2007 22 May 2012 34.40 111.00 50,000 50,000 2 May 2008 2 May 2013 27.80 81.80 437,700 571,100 20 August 2010 20 August 2015 22.28 115.00 934,395 981,103 23 September 2011 23 September 2016 20.90 85.00 614,934 -

2,615,879 3,769,753

The weighted average remaining contractual life for share options outstanding at 31 December 2011 was 2.68 years (2010: 1.96 years).

39 F-109 Options were priced using a Black-Scholes option pricing model. The significant inputs into the share options valuation model were reference share prices at the grant dates and the exercise prices as shown above, volatility varied in the range between 30% and 48%, no dividend yield, an expected option life of 5 years, and annual risk-free interest rate varied between 2% and 5%. The volatility measured at the standard deviation of continuously compounded share returns is based on statistical analysis of daily share prices over the last 3 years.

At 31 December 2011 and the date of authorisation of the consolidated financial statements 2,615,879 options were outstanding and 1,066,550 options were exercisable out of which none have been exercised.

29. LOANS AND BORROWINGS

31 December 2011 Currency Interest rate Principal Interest Total

Non-convertible interest bearing bonds RUB 8.85-9.75% 616,579 13,174 629,753 Non-convertible interest bearing Eurobonds USD 9.88% 345,772 10,561 356,333 Convertible interest bearing bonds USD 7.25% 248,302 4,003 252,305 Libor 1m + 3.6%- Libor Bank loans nominated in USD USD 6m+5.5% 233,601 3,060 236,661 Euribor Bank loans nominated in EUR EUR 6m+5.5% 142,077 3,963 146,040 Total loans and borrowings 1,586,331 34,761 1,621,092 Current portion repayable within one year 106,829

Long-term loans and borrowings 1,514,263

31 December 2010 Currency Interest rate Principal Interest Total

Non-convertible interest bearing Eurobonds USD 9.88% 344,697 10,561 355,258 Convertible interest bearing bonds USD 7.25% 237,064 9,691 246,755 Libor 3m + 2.3%- Bank loans nominated in USD USD 14% 228,852 1,604 230,456 Non-convertible interest bearing bonds RUB 9.75-14% 171,317 6,942 178,259 Euribor Bank loans nominated in EUR EUR 6m+5.5% 27,750 1,127 28,877 Total loans and borrowings 1,009,680 29,925 1,039,605 Current portion repayable within one year 127,134

Long-term loans and borrowings 912,471

In February 2011, OJSC “Alliance” Oil Company, a wholly owned subsidiary of the Group, issued TRUB 5,000,000 (approximately TUSD 170,248 at the exchange rate on the date of the transaction) of three-year bonds with a fixed coupon of 9.25% per annum maturing in February 2014.

In June 2011, OJSC “Alliance” Oil Company issued TRUB 10,000,000 (approximately TUSD 360,968 at the exchange rate on the date of the transaction) of ten-year bonds with a five-year put option and a fixed coupon for the five-year period of 8.85% per annum.

Bonds with a notional amount of TRUB 3,000,000 and a fixed coupon of 9.75% have been swapped to USD through a cross currency interest swap contract bearing interest of 5.3%-5.8% in order to balance cash inflows from export sales denominated in USD with cash outflows on interest payments denominated in RUB and obtain a lower interest rate (Note 15).

40 F-110 The weighted average effective interest rates were as follows:

31 December 31 December 2011 2010

Weighted average interest rate 8.19% 7.95%

At 31 December 2011 and 2010, 24% and 30%, respectively, of the Group’s borrowings were at floating interest rates.

At 31 December 2011, loans and borrowings were collateralised by:

 97.90% of the Group's holding in OJSC Khabarovsk Oil Refinery;  Proceeds from sale of crude oil under the contract between OJSC “Vostochnaya Transnationalnaya Kompaniya” and one of its customers in the total amount of TUSD 330,000;  Property, plant and equipment with a carrying value of TUSD 123,763.

At 31 December 2010, loans and borrowings were collateralised by:

 98.18% of the Group's holding in OJSC Khabarovsk Oil Refinery, 99.98% in OJSC Tatnefteotdacha and 50.03% in CJSC Saneco;  Property, plant and equipment with a carrying value of TUSD 105,711.

The maturity profile of the Group’s loans and borrowings based on contractual undiscounted payments, including accrued interest, is presented as follows:

31 December 2011 Principal Interest Total

Within one year from 31 December 2011 72,961 133,492 206,453 Within second year from 31 December 2011 210,211 131,997 342,208 More than two years from 31 December 2011 1,372,654 225,278 1,597,932

Total amount estimated to be repaid 1,655,826 490,767 2,146,593

The interest payments were based on the interest rate effective at 31 December 2011. The principal and interest payments denominated in RUB were converted into USD using the exchange rate at 31 December 2011.

The Group is subject to external capital requirements imposed on Eurobonds and loans provided by CJSC UniCredit Bank on the basis of debt to EBITDA ratio. At 31 December 2011, the Group complied with all capital requirements.

30. PROVISION FOR DECOMMISSIONING AND SITE RESTORATION COSTS

31 December 31 December 2011 2010

Balance at beginning of the year 15,960 11,872 New obligation raised 7,876 4,070 Used during the year (2,407) (2,418) Change in estimates (7,307) 830 Unwinding of discount on provision for decommissioning and site restoration costs (Note 14) 3,214 1,808 Translation difference (1,896) (202)

Balance at end of the year 15,440 15,960

The provision was estimated by the Group based on the existing technology and current prices. Timing of decommissioning and site restoration obligations is determined as expiry of the estimated period during which oil and gas fields will continue to bring economic benefits to the Group (between 2018 and 2083).

Key assumptions used for evaluation of provision for the year ended 31 December 2011 were discount rate of 15.3% and inflation rate of 5.5%-7% (2010: 14% and 6%-9.5%, respectively).

41 F-111 31. TRADE AND OTHER ACCOUNTS PAYABLE

31 December 31 December 2011 2010

Trade accounts payable 17,189 13,232 Other accounts payable 126,995 82,565

144,184 95,797

The average credit period established for the Group by its suppliers in 2011 was 37 days (2010: 39 days). There is no interest charged on the outstanding balance for trade and other accounts payable during the allowed credit period. The Group has financial risk management policies in place, which include budgeting and analysis of cash flows and payments schedules to ensure that all trade and other accounts payable are paid within the credit limit timeframe.

The table below summarises the maturity profile of the Group's trade and other accounts payable at 31 December 2011 and 2010 based on contractual undiscounted payments.

31 December 31 December 2011 2010

Due in less than 90 days 114,448 85,021 Due in 90-180 days 28,570 9,989 Due in 180-365 days 1,166 787

144,184 95,797

32. ADVANCES RECEIVED AND ACCRUED EXPENSES

31 December 31 December 2011 2010

Advances received 140,610 126,169 Wages and salaries payable 28,440 24,970 Accrued professional services fees 1,060 1,221 Other accrued expenses 356 124

170,466 152,484

33. OTHER TAXES PAYABLE

31 December 31 December 2011 2010

VAT 31,985 28,498 Production tax 15,478 15,380 Excise tax 10,695 5,954 Other taxes 10,250 8,796

68,408 58,628

34. PERSONNEL COSTS

The Group's personnel costs for the years ended 31 December 2011 and 2010 are presented below.

Year ended Year ended 31 December 31 December 2011 2010

Remuneration to the members of the board of directors and the managing director (including related taxes, annual bonuses and share options) 5,811 3,692 Remuneration to other employees (including related taxes and pension costs, annual bonuses and share options) 162,258 127,731

168,069 131,423

42 F-112 The Group's personnel costs for the years ended 31 December 2011 and 2010 are recorded in the consolidated income statement lines “Production costs of crude oil”, “Production costs of oil products”, “Selling expenses” and “Administrative expenses”.

Annual bonus accrued for the year ended 31 December 2011 was based on financial performance against the budget and amounted to 10-50% of the base salary of other employees depending on the position and individual performance. Total bonus for the year ended 31 December 2011 amounted to TUSD 14,567 to be paid in 2012 (2010: TUSD 12,269 paid in 2011), subject to remuneration committee approval after the authorisation of annual financial statements of the Group.

Annual option grants are based on the employee’s total compensation and the value of granted options can amount to 100%-200% of annual compensation, but lower amounts can be granted. Notice periods are not to exceed twelve months, during which the employee is entitled to full compensation.

The average number of employees during the years ended 31 December 2011 and 2010 for the Alliance Oil Company Limited Group was 7,185 and 6,945, respectively.

Remuneration to the management

Remuneration paid to the management during the years ended 31 December 2011 and 2010:

2011 2010 Salary Bonus Total Salary Bonus Total

Managing director – Mr. Arsen Idrisov 2,006 2,177 4,183 2,012 1,000 3,012 Other management 5,529 4,582 10,111 2,590 2,847 5,437

7,535 6,759 14,294 4,602 3,847 8,449

Total management’s remuneration accrued for the year ended 31 December 2011 amounted to TUSD 18,293 (2010: TUSD 8,660).

The Group has adopted the following principles for executive remuneration. The executive remuneration consists of a base salary, an annual bonus and participation in the Group’s long-term incentive plan. The annual bonus is individually capped at 50%-100% of the salary and is determined based on the Group’s performance which is measured by several performance indicators, both operational and financial.

The managing director is a member of the Group's board of directors. No board fees are paid to the managing director. The employment contract effective at 31 December 2011 may be terminated by the Group upon six months written notice to the managing director. Should the managing director decide to leave the Group he also has to give a six months notice. The managing director is entitled to a bonus with an amount not to be exceeding 50% of the annual salary and can be awarded a bonus up to 100% of the annual salary, including performance bonus for specific projects as determined by the board of directors.

Other management includes management of the Parent company and the corporate centre LLC “Alliance” Oil Company MC, which provides management services to the Group's upstream and downstream subsidiaries.

Remuneration to the board members

Remuneration paid to the board of directors members during the years ended 31 December 2011 and 2010:

2011 2010 Board fee Other fee Total Board fee Other fee Total

Chairman of the board 180 15 195 155 5 160 Other board members 595 50 645 455 65 520

775 65 840 610 70 680

Other fees represent remuneration paid to certain directors in connection with their work in Remuneration and Audit committees.

43 F-113 Social security charges and defined benefit plans

Social security charges, recorded within payroll and related taxes, for the year ended 31 December 2011 included contributions to the Pension Fund of the Russian Federation of TUSD 15,039 (2010: TUSD 13,602).

The Group operates unfunded defined benefit plans for qualifying employees of its subsidiaries in the Russian Federation. Under the plans, the employees are entitled to flat retirement benefits payable on actual retirement, recurring social benefits to employees and retired employees and flat payment on employee's death. No post-employment healthcare benefits are provided.

At 31 December 2011, the Group employed a professional independent actuary to assess the present value of the defined benefit obligation. The present value of the defined benefit obligation and related past service cost were measured using the projected unit credit method.

The principal assumptions used for the purposes of the actuarial valuations were as follows:

Discount rate 8.0% Expected rate of inflation 6.0% Expected rate of salary increase 7.5% Retirement age, years Male 59.0 Female 54.5

Past service cost in the amount of TUSD 2,880 was recognised in profit or loss in respect of these defined benefit plans. The expense for the year is included in the consolidated income statement. Of the expense for the year TUSD 160 has been included in the consolidated income statement as “Production costs of crude oil”, TUSD 2,130 as “Production costs of oil products” and TUSD 590 as “Selling expenses”.

The Group expects to make a contribution of TUSD 2,853 to the defined benefit plans during the next financial year.

35. BUSINESS COMBINATIONS

Acquisition of controlling interest in subsidiary in 2011

On 16 February 2011, the Group acquired 100% shares in CJSC Gavanbunker, a sea terminal in the Sovetskaya Gavan port located in the Khabarovsk region of the Russian Federation, for a total consideration transferred of TUSD 17,284, including advance payment of TUSD 1,500 made in 2010.

Fair value of assets acquired and liabilities assumed at the date of acquisition were as follows:

Assets Property, plant and equipment 8,403 Cash and cash equivalents 794 Other assets 2,090 Liabilities Deferred tax liabilities (589) Payables and accrued expenses (2,361)

Identifiable net assets at the date of acquisition 8,337

Goodwill on acquisition:

Consideration paid in cash 14,000 Fair value of loans repayable on acquisition, net of deferred tax 3,284 Total consideration transferred 17,284

Less: fair value of identifiable net assets acquired (8,337)

Goodwill on acquisition 8,947

44 F-114 Goodwill on acquisition of CJSC Gavanbunker primarily represented a control premium. In addition, the consideration effectively included effect of expected synergies and expansion of bunkering operations in the Russian Far East. These benefits were not recognised separately from goodwill because they do not meet the recognition criteria for identifiable intangible assets. Goodwill is not deductible for tax purposes.

Net cash outflow on acquisition of CJSC Gavanbunker:

Consideration paid in cash 14,000 Less: cash and cash equivalents acquired (794) 13,206

Loans repaid on acquisition 3,930

17,136

Total revenue contributed by CJSC Gavanbunker from the date of acquisition to 31 December 2011 amounted to TUSD 6,855; loss for the period – TUSD 1,026.

Had the business combination been effected as at 1 January 2011, the revenue of the Group would have been TUSD 3,085,244 and the profit for the year would have been TUSD 328,305. In determining the "pro-forma" revenue and profit of the Group had the subsidiary been acquired at the beginning of the current year depreciation of the subsidiary's assets was calculated on the basis of the fair values arising in the initial accounting rather than the carrying amounts recognised in the pre- acquisition financial statements.

Increase in ownership in subsidiaries in 2011

During the year ended 31 December 2011, the Group acquired interests in the following subsidiaries:

Preference Increase in shares interest Consideration voting power, % acquired, % paid

OJSC Khabarovsk Oil Refinery 0.03 4.86 535 OJSC Primornefteproduct 0.37 1.26 510 OJSC Khabarovsknefteproduct 0.20 1.63 309

1,354

As a result of these transactions, the Group recognised a decrease in non-controlling interest of TUSD 1,864.

Increase in ownership in subsidiaries in 2010

During the year ended 31 December 2010, the Group acquired interests in the following subsidiaries:

Preference Increase in shares interest Consideration voting power, % acquired, % paid

OJSC Khabarovsk Oil Refinery 3.00 24.88 3,083 OJSC Khabarovsknefteproduct 3.12 3.73 786 OJSC Amurnefteproduct 14.33 22.37 442 OJSC Primornefteproduct 0.11 0.31 96

4,407

As a result of these transactions, the Group recognised a decrease in non-controlling interest of TUSD 2,404.

45 F-115 Disposal of subsidiaries

In December 2011, the Group disposed of its entire share in CJSC "Ecobioprom" and subsidiaries, the group involved in operations with biofuels, for a cash consideration of TUSD 9. Loss on disposal in the amount of TUSD 2,904 was recognised in the consolidated income statement.

Analysis of assets and liabilities over which control was lost:

Property, plant and equipment 5,620 Cash, cash equivalents and accounts receivable 202 Accounts payable, loans and borrowings (281)

Net assets disposed of 5,541

Loss on disposal of subsidiary:

Consideration received 9 Net assets disposed of (5,541) Non-controlling interest 2,799 Translation difference (171)

Loss on disposal (2,904)

36. RELATED PARTY TRANSACTIONS

Related parties include shareholders, associates, other related parties representing entities under common ownership and control with the Group and members of key management personnel.

Significant balances with related parties at 31 December 2011 and 2010:

31 December 31 December 2011 2010 Associates Trade and other accounts receivable 20,076 - Advances received and accrued expenses 79,670 -

Other related parties Other assets - 20,000 Trade and other accounts receivable 1,400 869 Advances paid and prepaid expenses 1,403 1,729 Other financial assets 26,159 30,264 Trade and other accounts payable 11 699 Advances received and accrued expenses 20 74,230

Other financial assets were mostly presented by a bank deposit (Note 21).

Other assets at 31 December 2010 were presented by advance paid for acquisition of 40% share in the capital of Lia Oil S.A., a related party of the Group. The acquisition was completed in 2011 (Note 20).

No allowance for doubtful debts in respect of the amounts owed by related parties was recognised.

Significant transactions with related parties for the years ended 31 December 2011 and 2010:

Year ended Year ended 31 December 31 December 2011 2010 Associates Revenue 482,840 - Purchase of oil products 7,482 19,450 Loans provided 16,588 5,897 Loans repaid 16,588 5,897

Other related parties Revenue 385,327 575,883 Purchase of services 35,377 35,755 Charity contributions to the Fund named by Z. Bazhaev (for participation in the Russian federal national projects) 10,333 5,252 Interest income 3,111 2,379 Short-term deposits placed 30,015 - Proceeds from deposits withdrawn 30,076 -

46 F-116 Revenue from sales to related parties includes sales of crude oil and oil products in the domestic and export markets. Purchase of services from related parties mainly includes insurance services and rent.

The charity contributions to the Fund named by Z. Bazhaev were made with the purpose of their further transfer to the Federal Treasury of the Russian Federation and other governmental organisations.

Transactions with shareholders, associates and other related parties relate to transactions in the ordinary course of business with terms and conditions, similar to transactions with third parties. All related party balances are unsecured and will be settled in cash under normal commercial credit terms. No guarantees have been given or received in relation to any related party balance.

Disclosure of transactions in relation to members of key management personnel is presented in note 34.

37. COMMITMENTS AND CONTINGENCIES

Capital commitments

The Group’s contractual capital commitments at 31 December 2011 and 2010 amounted to TUSD 750,651 and TUSD 610,901, respectively.

License commitments

The Group is subject to periodic reviews of its activities by local regulatory authorities regarding the requirements of its oilfield licenses. Management of the Group entities agrees with local regulatory authorities remedial actions necessary to resolve any findings resulting from these reviews. Non- compliance with the terms of a particular license could result in penalties, fines or license limitations, suspension or revocation. The Group’s management believes that any non-compliance with license terms that the Group may have in the future will be resolved through negotiations or proposed amendments without material effect on the consolidated financial positions or the operating results of the Group.

Litigation

The Group has been and continues to be the subject of legal proceedings and adjudications from time to time, none of which has had or will have, individually or in the aggregate, a material adverse impact on the Group.

The legal system in Russia is not fully developed and cannot be compared with the legal system in the West. It is also subject to constant changes, sometimes with retroactive effect. This fact could imply negative consequences to the companies of the Group.

Environmental matters

The Group is subject to extensive federal, state and local environmental controls and regulations in the Russian Federation and Kazakhstan. The Group’s operations involve air and water venting of detrimental impurities, potential impact to flora and fauna in the region of operations, and other environmental concerns.

The management believes that the Group’s operations are in compliance with all current existing environmental laws and regulations. However, environmental laws and regulations of the Russian Federation and Kazakhstan continue to evolve. The Group is unable to predict the timing or extent to which those environmental laws and regulations may change. Such change, if it occurs, may require that the Group modernise technology to meet more stringent standards.

In accordance with the terms of various laws and extracting licenses upon completion of the oil and gas field exploitation the Group is liable to perform decommissioning and site restoration of the oil fields. The estimated cost of known environmental obligations has been recorded in the consolidated financial statements (Note 30). Management of the Group regularly reassesses environmental obligations related to its operations. Estimates are based on management’s understanding of current legal requirements, the terms of license agreements and the size and nature of the oil fields under the licenses. Should the requirements of applicable environmental legislation change or be clarified, the Group may incur additional environmental obligations.

47 F-117 Russian Federation economic environment

Emerging markets such as the Russian Federation are subject to different risks than more developed markets, including economic, political and social, and legal and legislative risks. As has happened in the past, actual or perceived financial problems or an increase in the perceived risks associated with investing in emerging economies could adversely affect the investment climate in the Russian Federation and the Russia’s economy in general.

The global financial system continues to exhibit signs of deep stress and many economies around the world are experiencing lesser or no growth than in prior years. Additionally there is increased uncertainty about the creditworthiness of some sovereign states in the Eurozone and financial institutions with exposure to the sovereign debt of such states. These conditions could slow or disrupt the Russian Federation‘s economy, adversely affect the Group’s access to capital and cost of capital for the Group and, more generally, its business, results of operations, financial condition and prospects.

Because the Russian Federation produces and exports large volumes of oil and gas, the Russian Federation’s economy is particularly sensitive to the price of oil and gas on the world market which has fluctuated significantly during 2011 and 2010.

Russian Federation tax and regulatory environment

Laws and regulations affecting businesses in the Russian Federation continue to change rapidly. Tax, currency and customs legislation within the Russian Federation are subject to varying interpretations, and other legal and fiscal impediments contribute to the challenges faced by entities currently operating in the Russian Federation. The future economic direction of the Russian Federation is heavily influenced by the economic, fiscal and monetary policies adopted by the government, together with developments in the legal, regulatory, and political environment.

While the Group believes it has provided adequately for all tax liabilities based on its understanding of the tax legislation, the above facts may create tax risks for the Group. The management believes that its interpretation of the relevant legislation is appropriate and the Group’s tax, currency and customs positions will be sustained.

38. RISK MANAGEMENT

Capital risk management

The Group’s objective for managing capital is to deliver competitive, secure and sustainable returns to maximise long-term shareholders value and reduce the cost of capital maintenance.

The Group monitors capital on the basis of the total debt to equity ratio. Total debt comprises long- term and short-term loans and borrowings, as shown in the consolidated statement of financial position. Equity of the Group comprises share capital, additional paid-in capital, other reserves, retained earnings and non-controlling interests.

31 December 31 December 2011 2010

Loans and borrowings 1,621,092 1,039,605 Total equity 1,993,433 1,805,296

Debt to equity ratio 81% 58%

Management considers debt to equity ratio at 31 December 2011 to be appropriate.

In addition, the management of the Group reviews the following ratios on a quarterly basis: net debt, total debt to EBITDA, net debt to EBITDA and EBIT to interest expense.

48 F-118 Major categories of financial instruments

Major categories of financial assets and financial liabilities are presented below:

31 December 31 December 2011 2010 Financial assets Loans and receivables (including cash and cash equivalents): Trade and other accounts receivable 113,605 117,135 Other financial assets 91,141 58,786 Cash, cash equivalents and restricted cash 187,801 178,099 Available for sale financials assets, carried at fair value: Other financial assets 114 47 Held to maturity financial assets, carried at amortised cost: Other financial assets - 984 Fair value through profit or loss Other financial assets 2,175 - 394,836 355,052

Financial liabilities Measured at amortised cost: Loans and borrowings 1,621,092 1,039,605 Trade and other accounts payable 144,184 95,797 Fair value through profit or loss Derivatives classified as held for trading 16,021 - 1,781,297 1,135,402

The Group faces a number of financial risks arising from its operations and use of financial instruments, including, but not limited to: commodity price risk, foreign currency risk, interest rate risk, credit risk and liquidity risk.

Commodity price risk

Commodity price risk is the risk that the Group’s current or future earnings will be adversely impacted by changes in world crude oil prices. A decline in crude oil and oil products prices results in a decrease in profit for the year and negatively affects cash flows. The Group does not use hedging to reduce the exposure to this risk. The table below details the sensitivity of the Group’s profit before tax to changes in the crude oil and oil products prices by 10%.

Crude oil Oil products Year ended Year ended Year ended Year ended 31 December 31 December 31 December 31 December 2011 2010 2011 2010

Profit or loss 53,166 39,794 249,622 175,630

The sensitivity of oil and oil products prices are hypothetical and should not be considered to be predictive of future performance of the Group. For the purpose of the analysis in the table above the effect of price variation is calculated independently of any change in other assumptions. In reality, changes in prices may contribute to changes in other factors, which may magnify or counteract the sensitivity.

Foreign currency risk

Currency risk is the risk that the financial results of the Group will be adversely impacted by changes in exchange rates. The Group undertakes certain transactions denominated in foreign currencies. The significant part of the Group’s revenues are denominated in USD, whereas the majority of the Group’s operational costs are denominated in RUB. At the same time the major part of the Group’s borrowings are denominated in USD and EUR, while most of the Group’s assets are denominated in RUB.

The Group’s exposure to the risk of changes in exchange rates relates primarily to the Group’s long- term debt obligations denominated in USD and EUR. The Group manages its foreign currency risk by economically hedging transactions that are expected to occur within a maximum 24-month period. In June and August 2011, the Group entered cross-currency interest rate swaps in order to balance cash inflows from export sales denominated in USD with cash outflows on interest payments denominated in RUB and obtain a lower interest rate (Note 15).

49 F-119 The outstanding balances of the Group's foreign currency denominated monetary assets and monetary liabilities at the end of the reporting period were as follows:

Nominated in USD Nominated in EUR 31 December 31 December 31 December 31 December 2011 2010 2011 2010 Assets Trade and other accounts receivable 58,792 61,031 14,772 29,130 Other financial assets - 30,000 - - Cash, cash equivalents and restricted cash 19,637 34,256 29,348 50,752 78,429 125,287 44,120 79,882

Liabilities Loans and borrowings 289,991 302,031 166,777 53,260 Trade and other accounts payable 3,300 19,165 435 802 293,291 321,196 167,212 54,062

Total net position (214,862) (195,909) (123,092) 25,820

The following table details the Group's sensitivity to a 10% increase and decrease in the RUB against the relevant foreign currencies. 10% is the sensitivity rate used when reporting foreign currency risk internally to key management personnel and represents management's assessment of the reasonably possible change in foreign exchange rates. The sensitivity analysis includes only outstanding foreign currency denominated monetary items and adjusts their translation at the period end for a 10% change in foreign currency rates. A positive number below indicates an increase in profit or equity where the RUB strengthens for 10% against the relevant currency. For a 10% weakening of the RUB against the relevant currency, there would be a comparable impact on the profit or equity, and the balances below would be negative.

Nominated in USD Nominated in EUR Year ended Year ended Year ended Year ended 31 December 31 December 31 December 31 December 2011 2010 2011 2010

Profit or loss 21,486 19,591 12,309 2,582

In addition, change of exchange rate of the RUB against the USD by 10% would lead to recognition of TUSD 11,493 profit or loss in relation to valuation of fair value of cross-currency interest rate swaps.

Certain currency exchange gains/losses related to intercompany loans treated as extended investments are recorded in the statement of comprehensive income. The sensitivity analysis includes loans to foreign operations within the Group where the denomination of the loan is in a currency other than the functional currency of the lender or the borrower. The table below details the sensitivity of the Group's foreign currency exchange gains/losses recorded in the consolidated statement of comprehensive income to changes of exchange rate of the functional currency of the lender or the borrower against the currency of intercompany loans by 10%.

Nominated in USD Nominated in RUB Year ended Year ended Year ended Year ended 31 December 31 December 31 December 31 December 2011 2010 2011 2010

Equity 66,959 67,055 17,822 21,215

50 F-120 Interest rate risk

The Group is exposed to interest rate risk as Group entities borrow a portion of funds at floating interest rates. At 31 December 2011 and 2010, 24% and 30%, respectively, of the Group’s borrowings were at floating interest rates. Management considers such portfolio of fixed and floating rate loans and borrowings to be appropriate, therefore the Group does not use any derivatives to manage interest rate risk exposure.

The table below details the Group’s sensitivity to increase or decrease of the floating rate by 1%, which is used when reporting interest rate risk internally to key management personnel and represents management’s assessment of the reasonably possible change in interest rates. The analysis was applied to loans and borrowings based on the assumptions that amount of liabilities outstanding at the reporting date were outstanding for the whole year.

Profit or loss Year ended Year ended 31 December 31 December 2011 2010

LIBOR 1,185 1,159

Credit risk

Credit risk is the risk that a customer may default or not meet its obligations to the Group on a timely basis, leading to financial losses. The Group has adopted a policy of only dealing with creditworthy counterparties. The Group takes into account all available quantitative and qualitative information and its own trading records to mitigate the risk of financial loss from defaults.

Credit risk of the Group arises from cash, cash equivalents and restricted cash, loans and receivables and other financial assets, and has maximum exposure equal to the carrying value of these instruments.

Description of risk management policies relating to trade and other receivables are described in the Note 24.

The credit risk on cash, cash equivalents, restricted cash and investments in deposits is limited because the counterparties are highly rated banks or banks approved by the management of the Group, deposits in which are placed only within approved limits.

In addition the Group is exposed to credit risk in relation to investments in loans. The counterparty’s business activities, financial resources and business risk management processes are taken into account in the assessment of their creditworthiness. The Group issues loans only to counterparties approved by management within the established limits.

There were no guarantees given to secure financing of third parties at 31 December 2011 and 2010.

Liquidity risk

Liquidity risk is the risk that the Group will not be able to settle all liabilities as they fall due. The Group’s liquidity position is carefully monitored and managed.

The net cash flow position of the Group is monitored on a daily basis by the central treasury function with weekly cash movements and cash balances being reported to the Group's management. Significant part of crude oil and oil products sales contracts is executed on advance basis and Group has also a strict policy for collecting doubtful debts and monitoring trade debtors. The Group prepares detailed budgets and forecasts and reviews the global and domestic oil price environment on a monthly basis in order to optimise crude oil sales, supply routes, oil product mix and refinery volumes. Management is focusing on matching the maturity profiles of financial assets and liabilities and reducing short-term debt through repayment of existing short-term loans. Accordingly, management considers that it is taking all necessary actions to allow the Group to meet its current obligations as they fall due.

The Group's primary sources of cash are its operations, as well as bank loans and the proceeds from equity and debt capital markets offerings.

At 31 December 2011, the Group’s unused financing facilities amounted to TUSD 635,646 (2010: TUSD 749,094).

51 F-121 Fair value of financial instruments

The fair value of financial assets and liabilities is determined as follows:

 The fair value of financial assets and financial liabilities with standard terms and conditions and traded on active liquid markets are determined with reference to quoted market prices.  The fair values of derivative instruments are calculated using a discounted cash flow analysis based on the applicable yield curve for the duration of the instruments. Cross-currency interest rate swaps are measured at the present value of future cash flows estimated and discounted on rates of 5.6%-6% for cash flows denominated in RUB and 0.3%-1.1% for cash flows denominated in USD. Discount rates are based on Bloomberg yield curves.  The fair value of other financial assets and financial liabilities are determined in accordance with generally accepted pricing model based on discounted cash flow analysis using prices from observable current market transactions.

The Group uses the following hierarchy for determining and disclosing the fair value of financial instruments by valuation technique:

Level 1: quoted (unadjusted) prices in active markets for identical assets or liabilities; Level 2: other techniques for which all inputs that have a significant effect on the recorded fair value are observable, either directly or indirectly; Level 3: techniques that use inputs that have a significant effect on the recorded fair value that are not based on observable market data.

At 31 December 2011 cross-currency interest rate swaps held by the Group and carried at fair value were attributed to Level 2 of the hierarchy.

39. PARENT COMPANY

Presented below are the key financial indicators of the Parent company:

Year ended Year ended 31 December 31 December 2011 2010

Operating income/(loss) 443,929 (23,184) Profit/(loss) before tax 448,250 (13,867) Profit/(loss) for the year 448,250 (13,867) Total assets 3,393,855 2,932,203 Total liabilities 722,080 710,035 Equity 2,671,775 2,222,168

52 F-122 40. ADOPTION OF THE ANNUAL REPORT

The annual report has been submitted by the board of directors on 16 April 2012. The consolidated financial statements are to be approved by the Company’s shareholders at the Annual general meeting on 22 May 2012.

Supplementary oil and gas reserves disclosure (unaudited)

Timano- Proved and probable oil Pechora Volga-Urals Tomsk reserves, thousand barrels region region region Kazakhstan Total

At 1 January 2010 304,917 146,990 60,606 13,414 525,927 Revisions 94,804 31,881 (1,478) 3,090 128,297 Production (4,964) (7,391) (3,023) (582) (15,960)

At 31 December 2010 394,757 171,480 56,105 15,922 638,264

Revisions 21,407 6,365 4,196 (4,504) 27,464 Production (7,178) (7,114) (2,940) (642) (17,874)

At 31 December 2011 408,986 170,731 57,361 10,776 647,854

The balances of proved and probable oil reserves are based on the reserve evaluation report prepared by DeGolyer & MacNaughton, an international petroleum consulting firm, under PRMS classification.

The “Revisions” lines in the above table included the effect of the oil reserves estimates revision made for the oil fields by DeGolyer & MacNaughton during the years ended 31 December 2011 and 2010.

53 F-123 ISSUER Alliance Oil Company Ltd. Clarendon House 2 Church Street Hamilton HM 11 Bermuda

GUARANTORS

CJSC Alliance Oil OJSC Oil Company Alliance LLC ‘‘Alliance-Bunker’’ Building 2, 101, Prospect Mira 39, Sivtsev Vrazhek Lane Office 301, 55, Fontannaya str. Moscow 129085 Moscow 119002 Vladivostok 690091 Russian Federation Russian Federation Russian Federation

CJSC Alliancetransoil OJSC ‘‘Amurnefteproduct’’ OJSC ‘‘Khabarovsknefteproduct’’ 10, Bld. 1 Kaloshin Lane Liter A, 1, Pervomayskaya str. 22, Mukhina str. Moscow 119002 Blagoveshchensk 675002 Khabarovsk 680030 Russian Federation Russian Federation Russian Federation

CJSC Khvoinoye Kolvinskoe LLC OJSC ‘‘Pechoraneft’’ 70/1, Komsomolsky prospect Office 17, 23A, Lenina str. 17 D, Montazhnikov str. Tomsk 634041 Naryan-Mar 166000 Iskateley village, Naryan-Mar 166700 Russian Federation Russian Federation Russian Federation

Potential Oil LLP PJSC ‘‘Primornefteprodukt’’ OJSC ‘‘Eastern Transnational 102, Vladimirskogo str. 55, Fontannaya str. Company’’ Atyrau 060009 Vladivostok 690091 70/1, Komsomolsky prospect Kazakhstan Russian Federation Tomsk 634041 Russian Federation

LLC SN-Gasproduction 70/1, Komsomolsky prospect Tomsk 634041 Russian Federation

MANAGERS Deutsche Bank AG, London Branch Goldman Sachs International Winchester House Peterborough Court 1 Great Winchester Street 133 Fleet Street London London EC4A 2BB EC2N 2DB United Kingdom United Kingdom

GPB-Financial Services Limited Raiffeisen Bank International AG Interlink Hermes Plaza, Am Stadtpark 9 1st Floor 46 Ayios Athanasios Av. 1030 Vienna 4102 Limassol, Cyprus Austria

INDEPENDENT AUDITORS TO THE ISSUER ZAO Deloitte & Touche CIS Deloitte AB 5 Lesnaya St., Rehnsgatan 11 Moscow, 125047, SE-113 79 Stockholm Russian Federation Sweden LEGAL ADVISERS TO THE ISSUER AND THE GUARANTORS as to English and U.S. law as to Russian law Cleary Gottlieb Steen & Hamilton LLP Cleary Gottlieb Steen & Hamilton LLC City Place House Paveletskaya Square 2/3 55 Basinghall Street 115054 Moscow London EC2V 5EH Russian Federation United Kingdom

To the Issuer and the Guarantors To the Issuer and the Guarantors as to Bermuda law as to Kazakhstan law Conyers Dill & Pearman Grata Law Firm 10 Dominion Street 104, M. Ospanov Street London EC2M 2EE Almaty, 050020 United Kingdom Republic of Kazakhstan

LEGAL ADVISERS TO THE MANAGERS as to English and U.S. law as to Russian law Linklaters LLP Linklaters CIS One Silk Street Paveletskaya Square 2/2 London EC2Y 8HQ 115054 Moscow United Kingdom Russian Federation

LEGAL ADVISERS TO THE TRUSTEE as to English law Linklaters LLP One Silk Street London EC2Y 8HQ United Kingdom

LISTING AGENT TRUSTEE Arthur Cox Listing Services Limited BNY Mellon Corporate Trustee Services Limited Earlsfort Centre One Canada Square Earlsfort Terrace London Dublin 2 E14 5AL Ireland United Kingdom PRINCIPAL PAYING AGENT AND TRANSFER AGENT REGISTRAR The Bank of New York Mellon, London Branch The bank of New York (Luxembourg) S.A. One Canada Square Vertigo Building – Polaris London 2-4 rue Euge`ne Ruppert E14 5AL L-2953 United Kingdom Luxembourg

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