Regulatory Filings • Sep 9, 2020
Regulatory Filings
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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 from us 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 U.S. SECURITIES ACT OF 1933 (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 OR TO, OR FOR THE ACCOUNT OR BENEFIT OF, U.S. PERSONS (AS DEFINED IN REGULATION S UNDER THE SECURITIES ACT ("REGULATION S")), 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 PROSPECTUS MAY NOT BE FORWARDED OR DISTRIBUTED OTHER THAN AS APPROVED BELOW AND MAY NOT BE REPRODUCED IN ANY MANNER WHATSOEVER. ANY FORWARDING, DISTRIBUTION OR REPRODUCTION OF THIS 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 this prospectus or make an investment decision with respect to the securities, you must be either (i) a person other than a U.S. person (within the meaning of Regulation S under the Securities Act) or (ii) a qualified institutional buyer ("QIB") within the meaning of Rule 144A under the Securities Act ("Rule 144A") who is a Qualified Purchaser as defined in Section 2(A)(51) of the U.S. Investment Company Act of 1940 (a "Qualified Purchaser"). By accepting the e-mail and accessing this prospectus, you shall be deemed to have represented to us that you are not a U.S. person or that you are a QIB that is a Qualified Purchaser and that you consent to delivery of such prospectus by electronic transmission.
This prospectus may only be communicated to persons in the United Kingdom in circumstances where section 21(1) of the Financial Services and Markets Act 2000 does not apply to the Issuer.
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, any 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 licensed broker or dealer and the underwriter or any affiliate of the underwriters is a licensed 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.
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 neither Credit Suisse Securities (Europe) Limited, Deutsche Bank AG, London Branch or any person who controls either of them, nor any director, officer, employee or agent of either of them nor any 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 Credit Suisse Securities (Europe) Limited or Deutsche Bank AG, London Branch.
• We are one of the largest publicly traded oil companies in the world in terms of proved crude oil and gas reserves and we are the second largest producer of crude oil in Russia. We divide our business into three main segments: exploration and production; refining, marketing and distribution; and petrochemicals.
• Our indirect wholly owned subsidiary, LUKOIL International Finance B.V., a company organised under the laws of The Netherlands, will issue the US\$500,000,000 6.356% notes due 2017 (the 2017 notes) and the US\$500,000,000 6.656% Notes due 2022 (the 2022 notes). References to the notes in this prospectus are references to the 2017 notes and the 2022 notes.
• If LUKOIL International Finance B.V. fails to make payments on the notes when they are due, OAO LUKOIL will be required to make them under the guarantees. LUKOIL is the only guarantor of the notes.
• The 2017 notes will mature on 7 June 2017. The 2022 notes will mature on 7 June 2022.
unsubordinated obligations, effectively junior to all our existing and future secured obligations and structurally junior to all existing and future obligations of our subsidiaries.
• The notes are expected to be delivered on or about 7 June 2007.
• We have applied to the Financial Services Authority in its capacity as competent authority under the Financial Services and Markets Act 2000 (the UK Listing Authority) for the notes to be admitted to the official list of the UK Listing Authority (the Official List) and to the London Stock Exchange plc for the notes to be admitted to trading on the London Stock Exchange's Gilt Edged and Fixed Interest Market (the Market). References in this prospectus to the notes being "listed" (and all related references) shall mean that the notes have been admitted to the Official List and have been admitted to trading on the Market. The Market is a regulated market for the purposes of the Markets in Financial Instruments Directive 2004/39/EC. The Rule 144A notes are expected to be designated for trading in the PORTAL Market ® of the Nasdaq Stock Market, Inc.® (PORTAL). There can be no assurance that a trading market for the notes will develop.
ISSUE PRICE: 100%
Joint Lead Managers
This prospectus comprises a prospectus for the purposes of Directive 2003/71/EC (the Prospectus Directive) and for the purpose of giving information with regard to LUKOIL International Finance B.V. (the Issuer), LUKOIL and its subsidiaries and affiliates taken as a whole (the Group) and the notes, which, according to the particular nature of the Issuer, LUKOIL and the notes, 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 and LUKOIL, and the rights attaching to the notes and the guarantees. The Issuer and LUKOIL accept responsibility for the information contained in this prospectus. To the best of the knowledge of the Issuer and LUKOIL (each of 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.
Certain information in this prospectus contained under the headings "Risk Factors", "Management's Discussion and Analysis of Financial Condition and Results of Operations", "Business" and "Regulation" has been based on information obtained from third party sources that we believe to be reliable. These sources include government agencies such as the Central Bank of Russia, the Russian Ministry of Energy and the Federal Statistics Service of Russia, market research and other research reports, press releases, securities filings and industry publications (including by publishers such as Platts, annual reports published by our competitors and other publicly available information). We accept responsibility for accurately reproducing this information and, as far as we are aware and are able to ascertain from information published by such sources, no facts have been omitted which would render this reproduced information inaccurate or misleading. See "Risk Factors – Other Risks – We have not independently verified information we have sourced from third parties".
No person is authorised to give any information or to make any representation in connection with the offer or sale of the notes other than as contained in this prospectus and any information or representation not so contained must not be relied upon as having been authorised by the Issuer, LUKOIL or any Manager (as defined in "Subscription and Sale"). 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 LUKOIL since the date hereof or the date upon which this prospectus has been most recently amended or supplemented or that there has been no adverse change in the financial position of the Issuer or LUKOIL since the date hereof or the date upon which this prospectus has been most recently amended or supplemented or that the information contained in it or any other information supplied in connection with the notes 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. No representation or warranty, express or implied, is made by any Manager as to the accuracy or completeness of such information.
This prospectus does not constitute an offer to sell, or a solicitation to subscribe for or purchase, by or on behalf of the Issuer, LUKOIL or any other person, any of the notes in any jurisdiction where it is unlawful for such person to make such offer or solicitation. The distribution of this prospectus and the offer and sale of the notes in certain jurisdictions is restricted by law. Persons into whose possession this prospectus may come are required by the Issuer, LUKOIL and the Managers to inform themselves about and to observe such restrictions. 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. Further information with regard to restrictions on offers and sales of the notes and the distribution of this prospectus is set out under "Subscription and Sale".
Except as otherwise stated in "Subscription and Sale", 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.
Applications have been made to the UK Listing Authority for the notes to be admitted to the Official List and to the London Stock Exchange for such notes to be admitted to trading on the Market. Admission to the Official List of the UK Listing Authority together with admission to trading on the Market constitute official listing on a stock exchange. Application will be made for the Rule 144A notes to be eligible for trading by qualified institutional buyers in PORTAL.
THE UNITED STATES OR ANY OTHER REGULATORY AUTHORITY IN THE UNITED STATES NOR HAVE ANY OF THE FOREGOING AUTHORITIES PASSED UPON OR ENDORSED THE MERITS OF THE NOTES OR THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE IN THE UNITED STATES.
THE NOTES AND THE GUARANTEES HAVE NOT BEEN AND WILL NOT BE REGISTERED UNDER THE UNITED STATES SECURITIES ACT OF 1933 (THE SECURITIES ACT) AND SUBJECT TO CERTAIN EXCEPTIONS, 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 UNDER THE SECURITIES ACT (REGULATION S)). THE NOTES ARE BEING OFFERED AND SOLD OUTSIDE THE UNITED STATES TO NON-U.S. PERSONS IN RELIANCE ON REGULATION S AND BY THE MANAGERS THROUGH THEIR RESPECTIVE REGISTERED BROKER-DEALER AFFILIATES INSIDE THE UNITED STATES TO "QUALIFIED INSTITUTIONAL BUYERS" (AS DEFINED IN RULE 144A(a)(1) UNDER THE SECURITIES ACT) (QIBs) THAT ARE ALSO "QUALIFIED PURCHASERS" (QPs) AS DEFINED IN SECTION 2(A)(51) OF THE UNITED STATES INVESTMENT COMPANY ACT OF 1940 (THE INVESTMENT COMPANY ACT) IN RELIANCE ON THE EXEMPTION FROM REGISTRATION PROVIDED BY RULE 144A UNDER THE SECURITIES ACT (RULE 144A) (SEE "SUBSCRIPTION AND SALE"). PROSPECTIVE PURCHASERS ARE HEREBY NOTIFIED THAT SELLERS OF ANY NOTE MAY BE RELYING UPON THE EXEMPTION FROM THE PROVISIONS OF SECTION 5 OF THE SECURITIES ACT PROVIDED BY RULE 144A.
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 (RSA 421-B) 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, 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 HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GIVEN APPROVAL TO, ANY PERSON, 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.
The 2017 notes offered and sold outside the United States to non-U.S. persons in reliance on Regulation S (the 2017 Regulation S Notes) and the notes offered and resold within the United States only to QIBs that are also QPs in reliance on Rule 144A (the 2017 Rule 144A Notes) will be represented initially by two global certificates in registered form (respectively, the 2017 Regulation S Global Note and the 2017 Rule 144A Global Note and, together, the 2017 Global Notes). The 2022 notes offered and sold outside the United States to non-U.S. persons in reliance on Regulation S (the 2022 Regulation S Notes) and the 2022 notes offered and resold within the United States only to QIBs that are also QPs in reliance on Rule 144A (the 2022 Rule 144A Notes) will be represented initially by two global certificates in registered form (respectively, the 2022 Regulation S Global Note and the 2022 Rule 144A Global Note and, together, the 2022 Global Notes). References to the Regulation S Notes are references to the 2017 Regulation S Notes and the 2022 Regulation S Notes and references to the Regulation S Global Notes are references to the 2017 Regulation S Global Note and the 2022 Regulation S Global Note. References to the Rule 144A Notes are references to the 2017 Rule 144A Notes and the 2022 Rule 144A Notes and references to the Rule 144A Global Notes are references to the 2017 Rule 144A Global Note and the 2022 Rule 144A Global Note. References to the Global Notes are references to the 2017 Global Notes and the 2022 Global Notes. The Regulation S Global Notes will be registered in the name of Citivic Nominees Ltd. as nominee for Euroclear Bank S.A./N.V. (Euroclear) and Clearstream Banking, société anonyme (Clearstream, Luxembourg), and the Rule 144A Global Notes will be registered in the name of Cede & Co. as nominee for The Depository Trust Company (DTC). The Regulation S Global Notes will be held by Citibank, N.A., London. Branch as common depository for Euroclear and Clearstream, Luxembourg and the Rule 144A Global Notes will be held by Citibank, N.A., London Branch as custodian for DTC. Interests of participants in Euroclear, Clearstream, Luxembourg and DTC in the notes will be represented by book entries on the records of Euroclear, Clearstream, Luxembourg or DTC, as the case may be. It is expected that delivery of the Global Notes will be made on or about 7 June 2007 (the Closing Date).
Unless the context otherwise requires, "RUR" or "rubles" shall mean Russian rubles, "U.S. dollars", "US\$" or "\$" shall mean United States dollars. Except as otherwise provided, translation of rubles into U.S. dollars herein has been carried out at the rate of RUR 26.33 = \$1 for 31 December 2006, RUR 28.78 = \$1 for 31 December 2005 and RUR 27.75 = \$1 for 31 December 2004. The official exchange rate of the Central Bank of Russia on 31 March 2007 was RUR 26.01 = \$1. These translation rates should not be construed as representations that the ruble amounts have been, could have been or could be converted into U.S. dollars at that or any other rate.
In connection with the issue of the notes, Deutsche Bank AG, London Branch (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, there is no assurance that the Stabilising Manager (or any persons 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 the 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 shall be conducted in accordance with all applicable laws and rules. Any stabilisation action, if commenced, shall be effected outside the Russian Federation.
This prospectus describes matters related generally to LUKOIL and its consolidated subsidiaries and affiliated companies and also describes a series of specific transactions related to the notes. This series of transactions involves certain specific entities, including LUKOIL and LUKOIL International Finance B.V. Unless otherwise stated, all references to the "2017 notes" are to the US\$500,000,000 6.356% Notes due 2017 and the "2022 notes" are to the US\$500,000,000 6.656% Notes due 2022, in each case issued by LUKOIL International Finance B.V., and references to the "notes" are to the 2017 notes and the 2022 notes. References to the "guarantees" are to LUKOIL's guarantees of the 2017 notes and the 2022 notes. References to "our charter" relate only to LUKOIL's charter. In this prospectus, unless otherwise stated or otherwise required by the context, the following terms apply with respect to these entities:
This prospectus contains information concerning our estimated crude oil and gas reserves which has been derived or extracted from the reports of Miller and Lents, Ltd., our independent reservoir engineers, dated as at 1 January in each of 2003, 2004, 2005, 2006 and 2007, and which are estimated in accordance with standards of the Society of Petroleum Engineers, Inc. and World Petroleum Congresses (SPE standards). 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 our 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. You should not place undue reliance on the ability of the reserves reports prepared by Miller and Lents to predict actual reserves or on comparisons of similar reports concerning companies established in places with more mature economic systems.
The reserves amounts included in this prospectus, prepared in accordance with SPE standards, do not comply with certain standards of reserves measurement applied by the U.S. Securities and Exchange Commission. For example, under SPE standards, proved reserves are projected to the economic production life of the evaluated fields, whereas, under SEC standards, oil and gas deposits may not be classified as proved reserves if they will be recovered after the expiration of a current license period unless the license holder has the right to renew the license and there is a demonstrated history of license renewal. In addition, the SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. This prospectus contains data, such as reserves and resources presented in accordance with SPE standards, that the SEC's guidelines would prohibit us from including in filings with the SEC.
Because our estimated reserves totals included in this prospectus are taken directly from reserves reports prepared by Miller and Lents, they are presented in barrels (for crude oil) and cubic feet (for natural gas). However, like many other Russian and European oil companies, we use the metric tonne and the cubic metre as the standard unit of measurement for quantities of crude oil and natural gas, respectively, which we produce and sell. For convenience, amounts of crude oil have been translated from tonnes into barrels (or from barrels into tonnes in respect of reserve amounts) and amounts of natural gas have been translated from cubic metres into cubic feet (or from cubic feet into cubic metres in respect of reserve amounts). Translations of barrels to tonnes were made at the rate of 7.33 barrels per tonne (other than in respect of crude oil production amounts, where such translations were made using conversion rates characterising the density of oil from each of the relevant oil fields). Translations of cubic feet to cubic metres were made at the rate of 35.31 bcf per bcm. Translations of barrels of crude oil into boe were made at the rate of 1 barrel per boe and of mcf into boe at the rate of 6 bcf per 1 mmboe.
| NOTICE TO INVESTORS 1 | |
|---|---|
| AVAILABLE INFORMATION 1 | |
| ENFORCEABILITY OF JUDGMENTS 1 | |
| USE OF PROCEEDS 2 | |
| FORWARD-LOOKING STATEMENTS 3 | |
| OVERVIEW 5 | |
| OVERVIEW OF THE OFFERING 10 | |
| SUMMARY CONSOLIDATED FINANCIAL AND OTHER INFORMATION 13 | |
| RISK FACTORS 15 | |
| CAPITALISATION40 | |
| SELECTED CONSOLIDATED FINANCIAL AND OTHER INFORMATION41 | |
| MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 44 |
|
| BUSINESS 77 | |
| MANAGEMENT 107 | |
| THE ISSUER 114 | |
| ADDITIONAL INFORMATION REGARDING THE COMPANY 115 | |
| TERMS AND CONDITIONS OF THE NOTES 118 | |
| TRANSFER RESTRICTIONS 133 | |
| SUMMARY OF PROVISIONS RELATING TO THE NOTES IN GLOBAL FORM 137 | |
| SUBSCRIPTION AND SALE 143 | |
| TAXATION 145 | |
| GENERAL INFORMATION 151 | |
| REGULATION 153 | |
| GLOSSARY OF TERMS 159 | |
| INDEX TO CONSOLIDATED FINANCIAL STATEMENTS OF OAO LUKOIL AND ITS SUBSIDIARIES F-1 |
Due to the restrictions on transfer of the notes, purchasers of the notes are advised to consult legal counsel prior to making any purchases of the notes or reoffering, reselling, pledging or otherwise transferring any of the notes.
LUKOIL has received an exemption under Rule 12g3-2(b) under the U.S. Securities Exchange Act of 1934 (the Exchange Act) and, pursuant to such Rule, furnishes to the U.S. Securities and Exchange Commission the information that it makes public or is required to make public or distributes or is required to distribute to security holders in Russia.
Each of the Issuer and LUKOIL have agreed that, for so long as any notes are "restricted securities" within the meaning of Rule 144(a)(3) under the Securities Act, it will, during any period in which it is neither subject to Section 13 or 15(d) of the Exchange Act nor exempt from reporting pursuant to Rule 12g3-2(b) thereunder, provide to any holder or beneficial owner of such restricted securities or prospective purchaser designated by such holder or beneficial owner or to the Trustee for delivery to such holder, beneficial owner or prospective purchaser, in each case upon the request of such holder, beneficial owner, prospective purchaser or the Trustee (as defined in "Terms and Conditions of the Notes"), the information required to be provided by Rule 144A(d)(4) under the Securities Act. This covenant is intended to be for the benefit of the holders and the prospective purchasers designated by such holders, from time to time of such restricted securities.
LUKOIL is an open joint stock company organised under the laws of the Russian Federation, and most of its directors and executive officers reside in Russia. Most of the assets of LUKOIL and of such persons are located outside of the United States and the United Kingdom. Each of the Issuer and LUKOIL has appointed an agent for service of process in England; however, it may not be possible for investors to effect service of process within the United States or the United Kingdom on the directors and executive officers of the Issuer or LUKOIL or enforce judgments against such persons or the Issuer or LUKOIL. Judgments rendered by a court in any jurisdiction outside the Russian Federation will be recognised by courts in Russia only if an international treaty providing for the recognition and enforcement of judgments in civil cases exists between the Russian Federation and the country where the judgment is rendered. No such treaty exists between the United States or the United Kingdom and the Russian Federation for reciprocal enforcement of foreign court judgments. However, we are aware of at least one instance in which Russian courts have recognised and enforced an English court judgment. The basis for this was a combination of the principle of reciprocity and the existence of a number of bilateral and multilateral treaties to which both the United Kingdom and the Russian Federation are parties. The courts decided that such treaties constituted grounds for the recognition and enforcement of the relevant English court judgment in Russia. In the absence of established court practice, however, it is difficult to predict whether a Russian court will be inclined in any particular instance to recognise and enforce an English court judgment on these grounds. Consequently, judgments of U.S. courts or English courts, including judgments against LUKOIL and its officers or directors predicated upon the civil liability provisions of U.S. federal securities laws or any state or territory within the United States or English law, may not be enforced against LUKOIL and such persons in the courts of the Russian Federation without re-examination of the issues in the Russian Federation whether they are brought in original actions or in actions to enforce judgments of U.S. courts or English courts. Moreover, a court of the Russian Federation may refuse or limit enforcement of a foreign judgment, inter alia, on public policy grounds (see "Risk Factors – Risks Relating to the Offering and the Notes").
The notes and the guarantees will be governed by English law and will provide the option for disputes, controversies and causes of action brought by parties thereto against us to be settled by arbitration in accordance with the UNCITRAL Arbitration Rules. The Russian Federation is a party to the United Nations (New York) Convention on the Recognition and Enforcement of Foreign Arbitral Awards. However, it may be difficult to enforce arbitral awards in the Russian Federation due to:
Under current Russian law, state duty may be payable upon the initiation of any action or proceeding (including any proceeding for enforcement) arising out of the notes or the guarantees in any court of the Russian Federation.
After deduction of commissions and expenses (including total expenses related to admission to trading), which we expect to be \$4,450,000, we expect the net proceeds from the issue of the notes to be approximately \$995,550,000, which will be used for general corporate purposes, including the repayment of existing indebtedness and financing of capital expenditures.
Certain statements in this prospectus are not historical facts and are forward-looking statements. 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". We may from time to time make written or oral forward-looking statements in reports to shareholders and in other communications. Examples of such forward-looking statements include, but are not limited to:
Forward-looking statements that we may make from time to time (but that are not included in this prospectus) 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. You should be aware that 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:
This list of important factors is not exhaustive. When relying on forward-looking statements, you should carefully consider the foregoing factors and other uncertainties and events, especially in light of the political, economic, social and legal environment in which we operate. Such forward-looking statements speak only as at the date on which they were made and we do not undertake any obligation to update or revise any of them, whether as a result of new information, future events or otherwise. We do not make any representation, warranty or prediction that the results anticipated by such forward-looking statements will be achieved, and such forward-looking statements represent, in each case, only one of many possible scenarios and should not be viewed as the most likely or standard scenario.
The following overview should be read in conjunction with, and is qualified in its entirety by reference to, the more detailed information and our consolidated financial statements and notes and unaudited supplementary oil and gas information thereto included elsewhere in this prospectus. Investing in the notes involves risk. The information set out under "Risk Factors" should be carefully considered. Certain statements in this prospectus include forward-looking statements which also involve risks and uncertainties as described under "Forward-Looking Statements".
We are one of the largest publicly traded oil companies in the world in terms of proved crude oil and gas reserves and we are the second largest producer of crude oil in Russia. According to Miller and Lents, our independent reservoir engineers, as at 1 January 2007, our estimated proved crude oil reserves were 15,926.8 mmbls (2,172.8 million tonnes) and our estimated proved gas reserves were 26,597.3 bcf (753.3 bcm), an aggregate of 20,359.7 mmboe. As at the same date, our estimated probable crude oil reserves were 8,767.4 mmbls (1,196.1 million tonnes) and our estimated probable gas reserves were 21,435.7 bcf (607.1 bcm), an aggregate of 12,340.1 mmboe. These reserves amounts, and the reserves amounts included elsewhere in this prospectus, were estimated in accordance with SPE standards.
In 2006, we produced 703.1 mmbls (95.2 million tonnes) of crude oil, including 660.2 mmbls (89.6 million tonnes) in Russia and 42.9 mmbls (5.6 million tonnes) from our international projects. Our 2006 domestic crude oil production accounted for approximately 18.6% of all Russian crude oil production based on the aggregate Russian crude oil production for 2006 published by the Russian Ministry of Energy. In 2006, we produced 480.2 bcf (13.6 bcm) of gas available for sale, including 437.8 bcf (12.4 bcm) in Russia and 42.4 bcf (1.2 bcm) from our international projects. In 2006, we refined 358.4 mmbls (48.9 million tonnes) of crude oil at our own refineries, including 289.5 mmbls (39.5 million tonnes) at our Russian refineries and 68.9 mmbls (9.4 million tonnes) at our international refineries. We also refined 24.2 mmbls (3.3 million tonnes) of crude oil under contract with domestic third-party refineries, primarily at refineries in Ufa, and 12.5 mmbls (1.7 million tonnes) of crude oil under contract with international third-party refineries. In 2006, we sold 300.7 mmbls (41.0 million tonnes) of crude oil and 64.7 million tonnes of refined products to customers outside of Russia, including sales to CIS countries and exports to international markets. Our total revenues were \$68,109 million in 2006, compared to \$56,215 million in 2005. Our net income in 2006 was \$7,484 million, compared to \$6,443 million in 2005.
As at 1 January 2007, approximately 96% of our estimated proved crude oil reserves were in Russia. Our proved crude oil reserves in Western Siberia were 8,771.4 mmbls (1,196.6 million tonnes) as at 1 January 2007, constituting approximately 55% of our total estimated proved crude oil reserves. We are developing new reserves in Russia, most notably in the Timan-Pechora region and the northern Caspian region. We believe that these new areas will provide us with a reserves portfolio which is more balanced geographically. As at 1 January 2007, approximately 83% of our estimated proved natural gas reserves were in Russia. Our core gas producing area is the Bolshekhetskaya depression in the Yamal-Nenets Autonomous District in Western Siberia. In April 2005, we started producing natural gas from the Nakhodkinskoye field in the Bolshekhetskaya depression in this region. In 2006, our production of gas available for sale was 293.1 bcf (8.3 bcm) from this field.
Our primary international areas of focus are currently Kazakhstan and Uzbekistan. We also have interests in international projects in Africa, the Middle East, South America and elsewhere in the CIS. As at 1 January 2007, our international assets accounted for approximately 4% of our estimated proved crude oil reserves and 17% of our estimated proved gas reserves.
We own four oil refineries in Russia, located in Perm, Volgograd, Ukhta and Nizhny Novgorod. These refineries, along with our mini-refineries in Urai and Kogalym, have a combined refining capacity of 44.1 million tonnes per year and in 2006 refined a total of 39.5 million tonnes of crude oil. Outside of Russia, we own refineries in Bulgaria and Romania, which have a combined refining capacity of 11.2 million tonnes per year and in 2006 refined a total of 9.4 million tonnes of crude oil. We also own a refinery in Ukraine, which has been closed since August 2005 for a large-scale reconstruction programme. We expect the reconstruction to be completed in the fourth quarter of 2007 (at which time the refinery will be reopened). The reconstruction programme we have commenced at our Ukrainian refinery is part of a larger effort to upgrade and modernise all of our refineries to improve utilisation rates and depth of refining and to increase production of refined products which comply with the more stringent current environmental requirements applicable in some of our export markets, including the European Union. We have invested, and expect to continue to invest, substantial amounts on our modernisation efforts at our refineries.
Our downstream gas assets include four gas processing facilities: the Lokosovsky gas processing plant in the Khanty-Mansiysk Autonomous District, the Korobkovsky gas processing plant in the Volgograd region, the Permneftegazpererabotka plant in the Perm region and the Usinsk gas processing plant in the Komi Republic. In 2006, our gas processing plants processed 91.8 bcf (2.6 bcm) of gas. The Lokosovsky gas processing plant is currently our main gas processing facility in Russia, which has a gas processing capacity of 67.1 bcf (1.9 bcm) per year.
We sell the crude oil which we do not refine in the domestic market, which includes certain sales directed by the Russian government, and in the international market, which includes exports from Russia and sales outside of Russia of crude oil production from our international projects. In 2006, we sold 13.3 mmbls (1.8 million tonnes) of crude oil within Russia and 300.7 mmbls (41.0 million tonnes) of crude oil outside of Russia.
We sold a total of 83.9 million tonnes of refined products through wholesale and retail channels in 2006. We sell a wide range of refined products, including gasoline, diesel fuel, fuel oil and lubricants. In 2006, we sold 19.2 million tonnes of our refined products in the domestic market and 64.7 million tonnes internationally.
As at 31 December 2006, we owned or leased 5,169 retail filling stations, including 1,538 in Russia, 1,843 in the United States and 1,788 in the CIS (excluding Russia) and Europe. In 2006, we sold 4.0 million tonnes of refined products through filling stations in Russia and 7.2 million tonnes through filling stations outside Russia. In addition, in December 2006, we signed an agreement with ConocoPhillips to purchase 376 of ConocoPhillips' retail filling stations in Europe, including 156 in Belgium and Luxembourg, 49 in Finland, 44 in the Czech Republic, 30 in Hungary, 83 in Poland and 14 in Slovakia. On 30 April 2007, we completed the acquisition of the filling stations located in Finland. We intend to re-brand these stations as Teboil stations within one year. We completed the acquisition of the remaining stations on 1 June 2007, which we intend to rebrand as LUKOIL stations.
We continue to expand our petrochemicals business through our petrochemicals operations in Russia, Ukraine and Bulgaria. Currently, we have two petrochemicals plants in southern Russia and one in Ukraine. We also manufacture petrochemicals at our Burgas refinery in Bulgaria. Together, those plants manufactured 2.0 million tonnes of petrochemicals in 2006. We intend to utilise our expanding natural gas production and processing operations as a source of feedstock for our petrochemicals operations.
We use the Transneft pipeline system, our own pipeline network, rail cars and tankers to transport the crude oil which we produce within Russia, for export outside of Russia and to our refineries. In addition, LUKARCO, our joint venture with BP plc in which we have a 54% interest, has a 12.5% interest in the CPC, a pipeline project in the Caspian region which we use to transport crude oil produced in Kazakhstan to a marine terminal near the Russian city of Novorossiysk on the Black Sea for transport on to international markets. We also own export terminals at Ilyinka in the Astrakhan Region (with a total annual capacity of 2.0 million tonnes), at the port of Svetly in the Kaliningrad Region (with a total annual capacity of 6.0 million tonnes), at Varandey on the Barents Sea (with a total annual capacity of 1.5 million tonnes) and at Vysotsk, Vyborg's outer harbour on the Baltic Sea (with a total annual capacity of 11.6 million tonnes). We transport most of our gas through the United Gas Supply System (UGSS), which is responsible for gathering, transporting, dispatching and delivering substantially all natural gas supplies in Russia and is owned and operated by Gazprom. We transport our refined products primarily through a combination of Russia's state-owned refined products pipeline, Transnefteproduct, and by rail car, riverclass tanker and truck.
Our strategic objectives are to increase our profitability by increasing our sustainable production of crude oil, natural gas and refined products, replacing our reserves at low cost and maintaining returns on capital at levels comparable to our international peers. We aim to create shareholder value through rigorous management of capital and costs. We believe that one of the competitive advantages which allows us to achieve this strategic objective is our ability to identify and develop low-cost upstream and downstream opportunities in our core Russian and international markets.
We are in the process of implementing a comprehensive corporate development programme for 2007 to 2016, which we believe will better enable us to achieve our strategic goals of sustainable growth and value creation. Our major priorities include steps designed to deliver near- and medium-term benefits to our profitability and returns on investment and a long-term programme designed to sustain our growth and profitability.
Our development programme for the next two years is designed to take advantage of opportunities to increase profitability. We believe that the following initiatives will, upon successful implementation, have a positive impact on our profitability:
• Streamline our administration. We are currently reducing the number of our subsidiaries and affiliated companies to make our corporate structure more manageable and efficient and to increase transparency for investors. We believe that more efficient management of our business and a leaner, more focused corporate structure will enable us to reduce costs.
Long-Term Development Programme
Our longer-term initiatives include the following:
We consider retail operations to be one of the key elements in our integrated production and marketing strategy. We intend to expand our network of filling stations in Russia (primarily in the European Russia region) and internationally (primarily in Europe and elsewhere in the CIS) to increase our share of the retail market in those regions. We also intend to continue to improve the distribution of our products in the United States over the next several years.
Investing in the notes is speculative and involves a high degree of risk. You should carefully consider the risks and other information contained in this prospectus, although you should note that the risks described in this prospectus are not the only risks we face, and there may be additional risks that we currently consider not to be material or of which we are not presently aware.
We are currently rated by three rating agencies: Moody's Investors Service Inc., Fitch Ratings Ltd and Standard & Poor's Ratings Services. Our current ratings are as follows:
| Moody's 111111111111112 |
Fitch 111111111111113 |
S&P 111111111111112 |
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|---|---|---|---|---|---|
| Long term implied | Baa1 | Long term | BBB- | Long term | BBB |
| Senior unsecured | Baa2 | Short term | F3 | Senior unsecured | BBB |
| Outlook | Stable | Outlook | Stable | Outlook | Stable |
The notes are expected to be assigned a rating of Baa2 by Moody's, BBB- by Fitch and BBB- by S&P.
A credit 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. Similar ratings on different types of notes do not necessarily mean the same thing. The ratings do not address the likelihood that the principal on the notes will be prepaid, paid on an expected final payment date or paid on any particular date before the legal final maturity date of the notes. The ratings do not address the marketability of the notes or any market price. Any change in the credit ratings of the notes or our company could adversely affect the price that a subsequent purchaser will be willing to pay for the notes. We recommend that you analyse the significance of each rating independently from any other rating.
In January 2007, we acquired the remaining 34% of Geoilbent, which has exploration and production operations in Western Siberia, for \$300 million, increasing our ownership of Geoilbent to 100%.
In February 2007, we signed a memorandum of understanding with Qatar Petroleum, pursuant to which we will work together to explore opportunities for cooperation in new and existing oil and gas projects in Qatar.
On 20 April 2007, we sold 50% of Caspian Investments Resources, which has exploration and production operations in western Kazakhstan, to Mittal Investments S.a.r.L. for \$980 million. In addition, Mittal Investments committed to repay 50% of Caspian Investments Resources' outstanding debt, which consisted of inter-company debt to other members of our Group and, as at the date of the sale, was approximately \$175 million.
In April 2007, we signed a supplemental agreement to our agreement with Russian Railways on developing railway transportation infrastructure to increase the supply capacity of refined products to our Vysotsk terminal.
On 30 April 2007, we completed the acquisition of 49 filling stations located in Finland from ConocoPhillips pursuant to a December 2006 agreement with ConocoPhillips. We completed the acquisition of the remaining 327 filling stations located in Belgium, Luxembourg, the Czech Republic, Hungary, Poland and Slovakia on 1 June 2007.
On 21 May 2007, we signed an unsecured \$300 million loan agreement with the European Bank for Reconstruction and Development (the EBRD) to finance our environmental safety programme. The loan consists of two tranches of \$150 million each. The first tranche is provided by the EBRD at LIBOR plus 0.65% per annum for ten years, and the second tranche is provided by a syndicate of commercial banks at LIBOR plus 0.45% per annum for seven years.
On 15 May 2007, we announced certain preliminary operating estimates for the first quarter of 2007. In the first quarter of 2007, we currently estimate that our total crude oil production was 180.5 mmbls (24.4 million tonnes), our gas production available for sale was 127.1 bcf (3.6 bcm) and our refinery throughput was 12.1 million tonnes at our refineries and 1.0 million tonnes at third-party refineries. This information is based on preliminary operating data and is subject to adjustment in connection with the preparation of our consolidated financial statements for the first quarter of 2007.
On 25 April 2007, our Board of Directors resolved to add as an agenda item to our annual shareholders meeting, scheduled for 28 June 2007, the amendment of our charter to increase our authorised shares by 85 million shares, which is approximately 10% of our currently authorised and issued shares.
The following overview contains basic information about the notes and the guarantees and is not intended to be complete. For a more complete understanding of the notes and the guarantees, please refer to the section of this prospectus entitled "Terms and Conditions of the Notes".
| Issuer | LUKOIL International Finance B.V. |
|---|---|
| Guarantor | LUKOIL |
| Notes | US\$500,000,000 aggregate principal amount of 6.356% notes due 7 June 2017 |
| US\$500,000,000 aggregate principal amount of 6.656% notes due 7 June 2022 |
|
| Issue Price | l00% |
| Closing Date | 7 June 2007 |
| Maturity Date | Unless previously redeemed, or purchased and cancelled, the 2017 notes will be redeemed at their principal amount on 7 June 2017. Unless previously redeemed, or purchased and cancelled, the 2022 notes will be redeemed at their principal amount on 7 June 2022. |
| Interest | The 2017 notes bear interest at the rate of 6.356% per annum payable in equal instalments semi-annually in arrear on 7 June and 7 December in each year, commencing on 7 December 2007. |
| The 2022 notes bear interest at the rate of 6.656% per annum payable in equal instalments semi-annually in arrear on 7 June and 7 December in each year, commencing on 7 December 2007. |
|
| Form | The notes will be in registered form, without interest coupons attached, in denominations of US\$100,000 or multiples of US\$1,000 in excess thereof. |
| The 2017 notes will be issued in the form of a 2017 Regulation S Global Note and a 2017 Rule 144A Global Note and the 2022 notes will be issued in the form of a 2022 Regulation S Global Note and a 2022 Rule 144A Global Note, each in registered form without interest coupons. The Regulation S Global Notes 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 Notes will be deposited with a custodian for, and registered in the name of, Cede & Co., as nominee of DTC. Ownership interests in the Regulation S Global Notes and the Rule 144A Global Notes 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. |
|
| Status of the Notes | The notes constitute unsubordinated and (subject to Condition 4 of the Terms and Conditions of the Notes) unsecured obligations of the Issuer which rank pari passu and without any preference among themselves. Subject to Condition 4 of the Terms and Conditions of the Notes, each of the Issuer and the Guarantor 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 unsecured and unsubordinated creditors, save those whose claims are preferred by any mandatory operation of law. |
| Guarantees | The payment, when due, of all sums expressed to be payable by the Issuer under the notes and the trust deeds (one constituting the 2017 notes and a second constituting the 2022 notes) has the benefit of unconditional and irrevocable guarantees of the Guarantor, as further described in Condition 2(a) of the Terms and Conditions of the Notes. |
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|---|---|---|---|---|---|
| Cross Default | There will be a cross default in respect of certain Indebtedness (as defined in the Terms and Conditions of the Notes) of the Issuer, the Guarantor or any Principal Subsidiary (as defined in the Terms and Conditions) equal to or greater than either (i) an individual amount of US\$50,000,000 or (ii) an aggregate amount of US\$150,000,000 (or their equivalents in another currency), as described in Condition 10(c) of the Terms and Conditions of the Notes. |
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| Negative Pledge | There will be a negative pledge in respect of certain Relevant Indebtedness (as defined in the Terms and Conditions of the Notes) of the Issuer, the Guarantor and its Subsidiaries, as described in Condition 4 of the Terms and Conditions of the Notes. |
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| The protection that the negative pledge affords to noteholders is limited in the following key ways: |
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| (1) | As the definition of Relevant Indebtedness is limited to present or future Indebtedness in the form of, or represented by, notes, debentures, bonds or other securities (but, for the avoidance of doubt, excluding term loans, credit facilities, credit agreements and other similar facilities and evidence of indebtedness under such loans, facilities or agreements) that are or ordinarily are quoted, listed or ordinarily dealt in or traded on any stock exchange, over-the-counter or other securities market, the Issuer and LUKOIL and their Subsidiaries will be permitted to secure a range of other forms of Indebtedness without any obligation to provide equal and ratable security in respect of the notes or the guarantees, as the case may be. |
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| (2) | The Issuer, LUKOIL and their Subsidiaries will be further permitted to secure an aggregate amount of Relevant Indebtedness not exceeding 20% of the value of Consolidated Assets (as defined in the Terms and Conditions of the Notes), without any obligation to afford any equal and ratable security to noteholders. As a result, the Issuer, LUKOIL and their Subsidiaries may create security in respect of a significant amount of their Relevant Indebtedness without, at the same time, being obliged to grant equal and ratable security in respect of the notes or the guarantees, as the case may be. |
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| pledge. | We urge you to read the Terms and Conditions of the Notes in their entirety and, in particular, Condition 4, which relates to the negative |
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| Covenants | The Terms and Conditions of the Notes contain covenants in respect of mergers and the payment of taxes. For more information, see "Terms and Conditions of the Notes". |
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| Tax Redemption | The Issuer may redeem the notes, in whole but not in part, at their principal amount, plus accrued interest, in the event of certain changes in taxation in The Netherlands or Russia. |
| "Make-Whole" Premium | The Issuer may also choose to redeem the notes prior to the Maturity Date, in whole or in part, on not less than 30 nor more than 60 days' irrevocable notice, by paying a redemption price equal to the sum of: |
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|---|---|---|---|---|---|
| (a) 100% of the principal amount of the notes to be redeemed, plus |
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| (b) the Applicable Premium (as defined in the Terms and Conditions of the Notes), |
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| plus accrued and unpaid interest thereon, if any, to the redemption date. |
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| Listing of Notes | Application has been made to list the notes on the Official List of the UK Listing Authority and for the notes to be admitted to trading on the Market of the London Stock Exchange plc. We expect the notes to be designated for trading on PORTAL. |
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| Ownership Restrictions | Neither Euroclear, Clearstream, Luxembourg nor DTC will monitor compliance with any transfer or ownership restrictions. |
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| Transfer Restrictions | The notes and the guarantees have not been and will not be registered under the Securities Act. You may offer to sell the notes only in transactions exempt from, or not subject to, the registration requirements of the Securities Act and in compliance with all applicable laws of any relevant jurisdiction. See "Transfer Restrictions". |
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| Trustee | Citicorp Trustee Company Limited. | ||||
| Principal Paying Agent and Registrar | Citibank, N.A., London Branch. | ||||
| Governing Law and Arbitration | The notes and the trust deeds (including the guarantees) will be governed by and construed in accordance with English law and contain provisions for arbitration in London, England. |
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| Use of Proceeds | After deduction of commissions and expenses (including total expenses related to admission to trading), which we expect to be \$4,450,000, we expect the net proceeds of the issue of the notes to be approximately \$995,550,000, which will be used for general corporate purposes of the Group including the repayment of existing indebtedness and financing of capital expenditures. |
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| Security Identification | ISIN Common CUSIP Code |
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| 2017 Rule 144A Notes US549876AB61 – 549876AB6 |
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| 2022 Rule 144A Notes US549876AA88 – 549876AA8 |
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| 2017 Regulation S Notes XS0304273948 030427394 – |
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| 2022 Regulation S Notes XS0304274599 030427459 – |
The following table sets forth a summary of our audited consolidated financial information. You should read the following summary information together with "– Current Trading and Prospects", "Selected Consolidated Financial and other Information", "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and notes and unaudited supplementary oil and gas information thereto included elsewhere in this prospectus. The financial information contained herein has been extracted without material adjustment from our consolidated financial statements included in this prospectus, which have been prepared in accordance with generally accepted accounting principles in the United States (U.S. GAAP) and audited by KPMG. Investors should read this prospectus as a whole and not rely solely on selected or summarised information.
| 11311111111111111 | Year ended 31 December | ||
|---|---|---|---|
| 2006 11111 |
2005 11111 |
2004 11111 |
|
| (in millions of U.S. dollars, except per share amounts) |
|||
| Consolidated Statement of Income Data: | |||
| Revenues | |||
| Sales (including excise and export tariffs) | 67,684 | 55,774 | 33,845 |
| Equity share in income of affiliates | 425 11111 |
441 11111 |
213 11111 |
| Total revenues | 68,109 | 56,215 | 34,058 |
| Costs and other deductions | |||
| Operating expenses | (4,657) | (3,487) | (2,880) |
| Cost of purchased crude oil, petroleum and chemical products | (22,374) | (19,398) | (10,124) |
| Transportation expenses | (3,863) | (3,519) | (2,784) |
| Selling, general and administrative expenses | (2,885) | (2,578) | (2,024) |
| Depreciation, depletion and amortisation | (1,851) | (1,315) | (1,075) |
| Taxes other than income taxes | (8,075) | (6,334) | (3,505) |
| Excise and export tariffs | (13,570) | (9,931) | (5,248) |
| Exploration expense | (209) | (317) | (171) |
| (Loss) gain on disposals and impairments of assets | (148) 11111 |
52 11111 |
(213) 11111 |
| Income from operating activities | 10,477 | 9,388 | 6,034 |
| Interest expense | (302) | (275) | (300) |
| Interest and dividend income | 111 | 96 | 180 |
| Currency translation gain (loss) | 169 | (134) | 135 |
| Other non-operating (expense) income | (118) | (44) | 21 |
| Minority interest | (80) 11111 |
(121) 11111 |
(62) 11111 |
| Income before income taxes | 10,257 | 8,910 | 6,008 |
| Current income taxes | (2,906) | (2,301) | (1,614) |
| Deferred income taxes | 133 11111 |
(166) 11111 |
(146) 11111 |
| Total income tax expense | (2,773) 11111 |
(2,467) 11111 |
(1,760) 11111 |
| Net income | 7,484 11111 aaaaa |
6,443 11111 aaaaa |
4,248 11111 aaaaa |
| Basic earnings per share of common stock | 9.06 | 7.91 | 5.20 |
| Diluted earnings per share of common stock | 9.04 | 7.79 | 5.13 |
| As at 31 December 111111111124 |
|||
| 2006 11111 |
2005 11111 |
||
| (in millions of U.S. dollars) | |||
| Balance Sheet Data: | |||
| Cash and cash equivalents | 752 | 1,650 | |
| Working capital | 6,641 | 6,661 | |
| Property, plant and equipment | 31,316 | 25,464 | |
| Total assets | 48,237 | 40,345 | |
| Long-term debt (including current portion) | 5,183 | 4,674 | |
| Shareholders' equity | 32,900 | 26,804 |
The reserves and production information in this prospectus includes reserves and production that we do not beneficially own which are attributable to minority interests in our consolidated subsidiaries and our equity share of reserves and production of our affiliated companies. Unless otherwise specified, the reserves and production information in this prospectus does not include information relating to:
We have extracted the reserves information set out below without material adjustment from the reserves reports prepared by Miller and Lents. We have extracted the production information set out below without material adjustment from our management accounts and operating records. We use this reserves and production information in managing our business and we expect to continue to report on such reserves and production information in our annual reports.
| As at 1 January 11311111111111111 |
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|---|---|---|---|---|
| 2007 11111 |
2006 11111 |
2005 11111 |
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| (in millions of U.S. dollars, except per share amounts) |
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| Reserves | ||||
| Crude oil (mmbls) | ||||
| Proved | 15,927 | 16,114 | 15,972 | |
| Probable | 8,767 | 8,869 | 7,424 | |
| Gas (bcf) | ||||
| Proved | 26,597 | 25,298 | 24,598 | |
| Probable | 21,436 | 20,587 | 15,537 | |
| Crude oil and gas (mmboe) | ||||
| Proved | 20,360 | 20,330 | 20,072 | |
| Probable | 12,340 | 12,300 | 10,014 | |
| 11311111111111111 | Year ended 31 December | |||
| 2006 11111 |
2005 11111 |
2004 11111 |
||
| Production | ||||
| Crude oil (mmbls/year) | 703 | 664 | 635 | |
| Russia | 660 | 634 | 608 |
Our businesses are performing, and trading since 31 December 2006 has been, in line with our directors' expectations. Our directors view our future prospects with confidence and believe that our position as one of the largest publicly traded oil companies in the world in terms of proved crude oil and gas reserves, and the execution of our corporate development and restructuring programme, will enable us to remain competitive in Russia, provide a platform for competing internationally with other major oil companies and deliver value to our shareholders.
International 43 30 27 Gas available for sale (bcf/year) 481 200 174
On 15 May 2007, we announced certain preliminary operating estimates for the first quarter of 2007. In the first quarter of 2007, we currently estimate that our total crude oil production was 180.5 mmbls (24.4 million tonnes), our gas production available for sale was 127.1 bcf (3.6 bcm) and our refinery throughput was 12.1 million tonnes at our refineries and 1.0 million tonnes at third-party refineries. This information is based on preliminary operating data and is subject to adjustment in connection with the preparation of our consolidated financial statements for the first quarter of 2007.
Investing in the notes is speculative and involves a high degree of risk. You should carefully consider the risks and the other information contained in this prospectus before you decide to invest in the notes. The trading price of the notes could decline due to any of these risks and you could lose all or part of your investment. You should note that the risks described below are not the only risks we face. We have described only the risks that we consider to be material. However, there may be additional risks that we currently consider not to be material or of which we are not presently aware. If any of the following risks were to materialise, our business, financial condition and results of operations and the value of the notes could be materially adversely affected.
Our business, financial condition and results of operations depend substantially upon prevailing prices of oil and natural gas. Historically, prices for oil and natural gas have fluctuated widely in response to changes in many factors. We do not and will not have control over the factors affecting prices for oil and natural gas. These factors include:
Crude oil prices have risen dramatically in recent years. For example, according to the International Energy Agency, the price of Brent crude, an international benchmark oil blend, as at 31 December 2004, 2005 and 2006 was \$40.00, \$58.33 and \$58.92 per barrel, respectively. However, in the past, the price of Brent crude has been significantly lower. For example, the price of Brent crude as at 31 December 1997 and 1998 was approximately \$16.41 and \$10.48 per barrel, respectively. International gas and refined products prices, which typically follow changes in international oil prices, have also fluctuated considerably in recent years.
It is impossible to predict future oil and natural gas price movements with certainty. Moreover, we engage in limited hedging transactions and other derivatives trading only in respect of our marketing and trading activity outside of our physical crude oil and refined products businesses.
A decline in oil or natural gas prices could materially adversely affect our financial condition, results of operations and our ability to finance planned capital expenditures. Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically (thereby decreasing the size of our reserves) and reduce the economic viability of projects planned or in development.
As is the case with all Russian oil companies, we sell a portion of our crude oil and refined products in the Russian market, where prices have historically been lower than in the international market. In the past, domestic Russian crude oil prices were set by the Russian government at levels substantially below those of world market prices. The Russian government ceased to regulate domestic prices for crude oil in early 1995, but domestic prices have remained below world levels due in part to export duties and transportation costs. The growth of investment in export channels of the Transneft pipeline system and other export infrastructure has had the effect of exerting upward pressure on domestic prices. If export infrastructure does not keep pace with increasing crude oil production, we cannot assure you that the Russian market will sustain current domestic price levels, which could have a material adverse effect on our business, financial condition and results of operations.
While prices in Russia for refined products are generally determined by the market, occasionally they may still be subject to government control. While the Decree of the President of the Russian Federation "On Measures to Adjust State Price (Rates) Controls" of 28 February 1995 established the general rule that free market prices and rates are to be applied in the Russian domestic market, the Decree also grants the Russian government control over a list of goods, including certain types of refined products. The list currently includes products such as fuel oil, kerosene and natural and liquefied gas sold directly to Russian consumers. Furthermore, Russian oil companies may, from time to time, be subject to political pressure to reduce domestic refined product prices. Accordingly, we cannot assure you that governmental price controls will not be implemented or increased for political or other reasons. Any resulting increase in the disparity between Russian and international market prices for refined products could have a material adverse effect on our business, financial condition and results of operations.
Most of the crude oil that we produce is transported through the Transneft pipeline system. Transneft is a stateowned oil pipeline monopoly. The Transneft pipeline system is subject to breakdowns and leakage. By using multiple pipelines, however, Transneft has generally avoided serious disruptions in the transport of crude oil and, to date, we have not suffered significant losses arising from the failure of the pipeline system. Much of the Transneft-operated pipeline system is over ten years old, with certain parts having been constructed over 40 years ago, and much of the system is located in regions with harsh climates where construction, maintenance and refurbishment are difficult and costly. As a result, the Transneft-operated system may experience outages or capacity constraints during required maintenance periods and it is likely that maintenance work will increase in the future. During these maintenance periods, we may experience delays in or be prevented from transporting crude oil. These delays, outages or capacity constraints could materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
The Russian government regulates access to Transneft's pipeline network. 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 35% of its crude oil so produced and delivered. Limitations on access to the export pipelines, combined with limited port, shipping and railway facilities, constrains the ability of Russian producers to export crude oil.
We, 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 Tariff Service (the FTS) is responsible for setting Transneft's fees, which have risen in recent years and may continue to rise. Failure to pay these fees could result in the termination or temporary suspension of our access to the Transneft network. Continued increases in Transneft's fees or the termination or suspension of our access to the Transneft network would materially adversely affect our business, financial conditions and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
In 2001, a Russian court ordered Transneft to stop accepting shipments of our crude oil in response to a lawsuit filed by one of our minority shareholders. This order was overturned quickly without causing a material adverse effect on our business. In 2002, Russian courts on several occasions granted similar requests in lawsuits against other Russian companies, all of which were overturned quickly. However, we cannot be certain that similar lawsuits will not be filed against us in the future or that any such lawsuits will be resolved in our favour.
A major disruption in (or on our access to) the Transneft system and continuing increases in Transneft's fees could have a material adverse effect on our business, financial condition and results of operations.
The Transnefteproduct pipeline system transports an average of approximately 10% of refined products produced in Russia. Transnefteproduct is a state-owned refined product pipeline monopoly. Transnefteproduct has generally avoided serious disruptions in the transport of refined products, and to date, we have not suffered significant losses arising from breakdowns or leakages in the pipeline system. Any significant disruption in the pipeline system could, however, materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
We, along with other Russian refined product producers, must pay transportation fees to Transnefteproduct in order to transport our refined products through the Transnefteproduct network. The FTS is responsible for setting Transnefteproduct's fees. Failure to pay these fees could result in the termination or temporary suspension of our access to the Transnefteproduct network, which would adversely affect our operating results and financial condition. Transnefteproduct periodically increases the fees for the use of its network. Continued increases in Transneftproduct's fees would increase our costs and could materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
We transport most of our refined products through Russia's rail network. We also depend on railway transportation for the distribution of our crude oil. OJSC Russian Railways is a state-owned monopoly provider of railway transportation services. Use of the railways exposes us to risks such as potential delivery disruptions due to the deteriorating physical condition of Russia's railway infrastructure. The incompatibility of Russia's wider railway gauge with the railway gauge of most other countries imposes additional costs and logistical constraints on our ability to export its products using the railways. Furthermore, although Russian Railway fees are subject to antimonopoly control, historically they have tended to increase. Continued increases in Russian Railway's fees would increase our transportation costs and could materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
The crude oil that we transport through the Transneft pipeline network is blended with crude oil of other producers that may differ in quality. Our sales of crude oil that we transport through the Transneft system are of the crude oil blend that results from the combination of different types and qualities of crude oil in the system, which is usually referred to as "Urals blend" crude oil. Therefore, the price we get for our oil may be lower than the price that we could get for oil of the same quality if we could transport our oil independently of Transneft. Any decrease in the quality of the crude oil blend transported through Transneft could reduce the marketability of the oil we produce and, thereby, materially adversely affect our business, financial conditions and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
All material aspects of the Russian natural gas industry are subject to or materially affected by government regulation. Moreover, through its share ownership, representation on the board of directors and role as regulator, the government has strong influence over Gazprom, the dominant participant in Russia's natural gas industry. The significant participation in the Russian natural gas industry of independent gas producers is a relatively recent development. If the government were to determine, through legislation, administrative action or otherwise, that independent gas producers should have a less significant role in the Russian natural gas industry, it could take actions (including through Gazprom) that would have a material adverse effect on our ability to develop our natural gas assets, which could in turn have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
The UGSS is responsible for gathering, transporting, dispatching and delivering substantially all natural gas supplies in Russia and is owned and operated by Gazprom. Under existing legislation, Gazprom must provide access to the UGSS to all independent suppliers on a non-discriminatory basis subject to spare capacity and other factors. See "Business – Exploration and Production – Gas Transportation" for more information about our transportation of gas through the UGSS. In practice, however, Gazprom exercises considerable discretion over access to the UGSS because it is the sole owner of information relating to capacity. We cannot assure you that the legislation requiring Gazprom to provide access on a non-discriminatory basis will remain in place or that Gazprom will continue to provide us with access to the UGSS or that the terms of access offered will be commercially reasonable. A change in the existing legislation, a failure by Gazprom to comply with the legislation or other action by Gazprom to decrease our access to transportation capacity may limit the effective use and value of our gas producing assets and adversely affect our ability to implement our strategy to develop our natural gas resources, which could have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
The UGSS includes an extensive network of pipelines and compressor installations that have been developed over the past 40 years. Most of the pipelines in the UGSS are over ten years old with certain parts being over 30 years old. Large segments of the network are located in regions with harsh climates where construction, maintenance and refurbishment are difficult and costly. As a result, the UGSS may experience outages or capacity constraints during required maintenance periods and it is likely that maintenance work will increase in the future. During these maintenance periods, we may experience delays in or be prevented from supplying natural gas to our customers. A major disruption in the UGSS could impact our ability to implement our strategy to develop our gas producing assets, which could ultimately have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
In Russia, the FTS regulates natural gas transportation tariffs. Regulated natural gas transportation tariffs have risen in recent years and we expect them to continue to rise. If natural gas transportation tariffs continue to rise and we are unable to pass on these additional costs to our end customers, or the impact of increased transportation tariffs on our wholesale customers requires us to decrease the natural gas prices we charge on a non-delivered basis, our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees could be materially adversely affected.
Gazprom is a monopoly supplier of gas in Russia. The Russian government regulates the prices for the gas that Gazprom sells in Russia. Although the regulated price has been rising in Russia, and is expected to continue to rise to a level closer to parity with export netbacks, it is still significantly below levels that prevail in international markets. The regulated price has affected, and is likely to continue to affect, the pricing of the gas we sell to Gazprom or any other customer. The limitations on our pricing flexibility due to Gazprom's dominant position in Russia and the Russian government's price regulations could have a material adverse effect on our business, financial condition and results of operations, particularly if the regulated prices are decreased or if we experience a significant increase in our operating costs related to the development of our gas producing assets.
We conduct our operations under numerous exploration, development and production licences. The licensing regime in Russia for the exploration, development and production of crude oil and natural gas is governed primarily by Law of the Russian Federation No. 2395-1, "On Subsoil", dated 21 February 1992, as amended (the Subsoil Law) and related regulations. Most of our licences may be suspended, terminated or revoked if we fail to comply with licence requirements, do not make timely payments of levies and taxes for the use of the subsoil, systematically fail to provide information, go bankrupt or fail to fulfil any capital expenditure and/or production obligations.
We may not comply with certain licence requirements for some or all of our licence areas. If we fail to fulfil the specific terms of any of our licences or if we operate in our licence areas in a manner that violates Russian law, government regulators may impose fines on us or suspend or terminate our licences, any of which could have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
For example, in January 2005, the Commission for Subsoil Use of the Ministry of Natural Resources investigated certain breaches of the terms of licensing agreements involving LUKOIL-Western Siberia, our principal production subsidiary, relating to six oil fields in the Khanty-Mansiysky Autonomous Region. In addition, in October 2006, an official at the Russian Ministry of Natural Resources threatened to revoke 36 of our exploration licences in the Komi region of Timan-Pechora and in the Khanty-Mansiysky Autonomous Region, alleging that we failed to explore or drill according to the timelines set out in the licences. We believe that we have addressed all of these alleged violations or we have agreed with the commission to amend the licensing agreements to enable our compliance with the terms of the licences. In June 2006, we acquired 100% of Khanty-Mansiysk Oil Corporation (KMOC) from Marathon Oil Corporation, which at the time owned approximately 95% of the share capital of OAO Khantymansiyskneftegazgeologia and 100% of the share capital of OAO Paitykh Oil and OAO Nazymgeodobycha (the KMOC companies), which operate oil and gas fields in Western Siberia. In September 2006, the Federal Agency for Subsoil Use issued notices of revocation of the licences of the KMOC companies unless the alleged violations were remedied by 29 December 2006. The Russian Ministry of Natural Resources conducted additional reviews of our activities conducted under these licences after 29 December 2006. As of the date of this prospectus, we are not aware of any additional acts or documents issued by the Federal Agency for Subsoil Use or the Russian Ministry of Natural Resources that may lead to the revocation of these licences. We cannot assure you that similar regulatory claims will not arise in the future with respect to these or other fields or that we will be able to settle such claims without licence revocation by revising licence agreements or otherwise. Any such revocations could have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
In addition, because we did not own or control all of our subsidiaries when they obtained their initial subsoil licences, we cannot be certain that all of our subsidiaries' licences were issued, or the preceding and current licences were re-issued, in accordance with all applicable law and regulations at the time. If it is determined that any of these licences were issued and/or re-issued in violation of applicable laws, such licences would be subject to revocation. A loss of any such licence could materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
Finally, to operate our business as currently contemplated, we must obtain permits and authorisations to conduct operations, such as land allotments, approvals of design and feasibility studies, pilot projects and development plans and for the construction of any facilities on site. We may not be able to obtain all required permits and authorisations. If we fail to receive any required permits and authorisations, we may have to delay our investment or development programmes, or both, which could materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
Our development and exploration projects may be delayed or unsuccessful for many reasons, including cost overruns, lower oil and gas prices, equipment shortages and mechanical difficulties. These projects will 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. In addition, some of our development and exploration projects are or will be located in deep water or frozen or other hostile environments, or involve or will involve production from challenging reservoirs, which can exacerbate such problems. The climate and topography of some of the regions where our fields are located limit access to certain fields and facilities during certain times of the year. During the summer and early fall, some fields are partially flooded and operating capacity is limited. If warmer weather starts earlier or ends later in the year than usual, then our operating capacity is more limited than normal. In winter, extreme cold or snowstorms could limit access to certain wells, and extreme cold could cause the temporary suspension of operations of wells with a high watercut. Such weather conditions could also limit our exploration operations. Unusually warm or severe weather conditions could impede our development or exploration plans for our fields and facilities and otherwise materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
We are exploring in various geographic areas, including Western Siberia, European Russia, the Timan-Pechora region and areas in and around the Caspian Sea, where environmental conditions are challenging and costs can be high. The cost of drilling, completing and operating wells is often uncertain. As a result, we may incur cost overruns or may be required to curtail, delay or cancel drilling operations because of a variety of factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements, including those relating to environmental protection, and shortages or delays in the availability of drilling rigs and the delivery of equipment. In addition, our overall drilling activity or drilling activity within a particular project area may be unsuccessful in that we may not find commercially productive reservoirs.
If we fail to conduct successful exploration and development activities or acquire properties with proved reserves, or both, our proved reserves will decline as we extract oil and natural gas. In addition, the volume of production from crude oil and natural gas properties generally declines as reserves are depleted. Our future production is highly dependent upon our success in finding or acquiring and developing additional reserves. If we are unsuccessful, we may not meet our production targets and our total proved reserves and production will decline, which could materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
The oil industry is intensely competitive. We compete with other major Russian oil companies and major international oil companies. Many of our international competitors have substantially greater resources and have been operating in a market-based, competitive economic environment for much longer than we have. The key activities in which we face competition are:
Russia has signed the Energy Charter Treaty, an international treaty for establishing and improving the legal framework for corporate international co-operation in energy matters, but the State Duma has not yet ratified the Treaty. We believe that ratification of the Energy Charter Treaty in its current form or in a modified form could provide foreign investors and oil companies with greater access to the energy markets in Russia and provide third parties with greater access to oil and gas trunk pipelines, including for the transportation of oil and natural gas to international markets. Accordingly, although we believe that we could benefit from increased third-party access to the Transneft and UGSS pipeline networks, the ratification of the Energy Charter Treaty could also lead to substantially increased competition.
Additionally, we may encounter competition from suppliers of alternative forms of energy sources, including environmentally friendly renewable energy sources such as solar power or wind generated power, as a result of continuing high hydrocarbon prices or potential depletion of hydrocarbon reserves in the future.
Our failure to compete effectively could materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
ConocoPhillips recently reported that it beneficially owned 20% of our shares. We believe that the involvement of ConocoPhillips in our operations has been, and will continue to be, important in the pursuit and implementation of our strategy. While under the terms of our shareholder agreement with ConocoPhillips they may not dispose of our shares until 2008, if ConocoPhillips were to dispose of its stake in our company, we may be deprived of the benefits and resources that we derive from our co-operation with ConocoPhillips, which could materially adversely affect our business, financial condition and results of operations.
On the other hand, by virtue of their stake in our company, ConocoPhillips may have the power to cause our business to be conducted for their own benefit rather than for the benefit of all of our shareholders. Under our shareholder agreement with ConocoPhillips, they have the right to nominate two candidates for election to our Board of Directors. See "Business – History". Our Board of Directors is responsible for important decisions including the approval of the business priorities and strategic orientations of our company, acquisitions or sales of shareholdings in other enterprises, approval of the annual budget and business plan, approval of internal documents of our company (except those requiring shareholder approval) and appointment, dismissal and early termination of the authority of the president. Therefore, there is a risk that ConocoPhillips' nominees to our Board of Directors could use their positions to block certain Board decisions. ConocoPhillips may exert similar influence in decisions requiring shareholder votes, including proposed amendments to our charter, takeover proposals, proposed substantial sales of assets or other major corporate transactions in a manner that may not be in our best interests or the best interests of our shareholders or other security holders.
Several members of our Board of Directors and management committee, together with their affiliates, collectively beneficially own approximately 28% of our company and thereby can exercise significant influence over our management and affairs, including:
The influence that they have may not always be in our best interests or the best interests of our other shareholders or holders of our other securities.
Our business requires significant capital expenditures, including in exploration and development, production, transportation and refining, and to meet our obligations under environmental laws and regulations. We expect to finance a substantial part of these capital expenditures from cash flows from our operating activities. If oil prices fall, however, we will have to finance more of our planned capital expenditures from external sources, including bank borrowings and offerings of debt or equity securities in the international capital markets. If necessary, these financings may be secured by our exports of crude oil. If oil prices fall and we are unable to raise the necessary financing, we will have to reduce our planned capital expenditures. Any such reduction could materially adversely affect our ability to expand our business and, if the reductions are severe enough, could materially adversely affect our ability to maintain our operations at current levels.
We incur and expect to continue to incur substantial capital and operating costs to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety. These include costs to reduce certain types of air emissions and discharges to the sea and to remediate contamination at various owned and previously owned facilities and at third-party sites where our products or waste have been handled or disposed. Our shipping and other transportation operations are also subject to extensive environmental and other regulations.
Our Petrotel refinery in Romania and our Burgas refinery in Bulgaria require the remediation of a substantial amount of environmental pollution that pre-dated our acquisition of these facilities. At the time of our acquisition of the Petrotel refinery, there was an understanding that the Romanian government would retain liability for existing environmental pollution at the site. In connection with our acquisition of the Burgas refinery, we understand that the Bulgarian government retains liability for remediation of existing environmental pollution at the site, estimated at approximately \$80 to \$100 million. There can be no assurance that the Romanian and Bulgarian governments will remediate the environmental pollution at these facilities in the way we expect. Accordingly, we could be exposed to additional remediation costs at these sites in excess of our planned expenditures.
Managed nuclear explosions were carried out within the Osinskoye oil field in 1969. This field is currently operated by LUKOIL-Perm. Subsequent drilling allowed radioactively contaminated water to enter the oil reservoir, which eventually led to a ground-level radioactive contamination problem being identified in 1976. Between 1996 and 2001, we undertook a project at a cost of \$6 million to manage and contain associated radiological risks and we believe that no further material liability exists. Well management procedures are in place to maintain a buffer zone around the location of the nuclear explosions. However, we cannot assure you that further ground water contamination of the surface soil will not occur.
New laws and regulations, the imposition of tougher requirements in licences, increasingly strict enforcement or new interpretations of existing laws, regulations and licences or the discovery of previously unknown contamination may require us to modify our operations 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. In addition, we may be required to modify, curtail or cease certain activities which could materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
Increasingly strict environmental requirements, including those relating to gasoline sulphur levels, diesel quality and the aromatic content of gasoline (including certain requirements that became effective in 2005 in the European Union), affect product specifications and operational practices. Our refineries will not be able to produce significant quantities of refined products that meet certain strict refined product specifications in some of our export markets, particularly those currently in effect or expected to take effect in the future in the European Union or the United States, without significant modification and capital expenditures. In addition, with the admission of Bulgaria and Romania to the European Union as at 1 January 2007, our refineries in these countries have become subject to stricter regulations relating to the quality of refined product production environmental protection. As a result, we have had to make substantial investments to upgrade our refineries to comply with such regulations, including those that relate to asbestos, which was present at both such refineries. Although our plans call for significant expenditures to continue to upgrade our refineries, we cannot assure you that we will have adequate resources to fulfil these plans. Failure to meet certain international standards at our refineries could have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
In 1994, the 1992 United Nations' Framework Convention on Climate Change came into force in Russia and three years later led to the Kyoto Protocol, which requires nations to reduce their emissions of carbon dioxide and other greenhouse gases. In late 2004, Russia ratified the Kyoto Protocol, and the protocol entered into force in February 2005 for all countries that have ratified it. The Ministry of Economic Development and Trade has developed a plan of action for the Russian government to implement the provisions of the Kyoto Protocol. Any changes in environmental legislation under the Kyoto Protocol or otherwise may require, among other things, reductions in emissions to the air from our operations and could result in increased capital expenditures.
Although the costs of the measures taken to comply with environmental regulations have not had a material adverse effect on our business, financial condition or results of operations to date, in the future, the costs of such measures and liabilities related to environmental damage that we cause may increase. Any such increased costs, or any requirements to modify our operations, could materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
This information concerning our estimated crude oil and gas reserves included in this prospectus has been derived or extracted from the reports of Miller and Lents. See "Presentation of Reserves and Resources". The estimates were calculated using oil and gas prices in effect on the date of the reports. Any significant price changes will have a material effect on the actual reserves quantity and present values.
Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. 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 necessarily depend upon a number of variable factors and assumptions, including the following:
Because all reserves estimates are subjective, each of the following items may differ materially from those assumed in estimating reserves:
Many of the factors, assumptions and variables involved in estimating reserves are beyond our control and may prove to be incorrect over time. This is especially true in relation to countries with political and economic uncertainty and instability, such as Russia and the other regions where we operate, including the CIS, the Middle East and South America. Results of drilling, testing and production after the date of the estimates may require substantial upward or downward revisions in our reserves data. Furthermore, different reservoir engineers may make different estimates of reserves and cash flows based on the same available data. Actual production, revenues and expenditures with respect to reserves will vary from estimates and the variances may be material. Any downward adjustment could lead to lower future production and, thus, materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
The discounted and undiscounted pre-tax future net revenues included in this prospectus should not be considered as the market value of the reserves attributable to our properties. Our actual pre-tax future net revenues will be affected by factors such as:
The information relating to oil and gas reserves contained in this prospectus has been prepared in accordance with SPE standards. These standards do not comply with certain standards of reserves measurement applied by the SEC, including reserves that will be recovered after the expiration of a current licence period. See "Selected Financial and Other Information – Selected Reserves and Production Information – Reserves Measurements" for more information on the differences between SPE and SEC standards.
We and our principal shareholders have engaged in transactions with affiliated parties and may continue to do so. For example, we have engaged in transactions with certain of our directors and executive officers and companies that they control, including equity purchases and sales, supply contracts, insurance services and loan and financing arrangements. Conflicts of interest may arise between our affiliates and us resulting in the conclusion of transactions on terms not determined by market forces. See "Management – Additional Information About Our Directors – Interests in Transactions with LUKOIL" for more information about certain transactions between our directors and us.
We have expanded our operations significantly through acquisitions since being privatised in 1993, both in Russia and internationally, and we expect to continue to do so in the future. See "Management's Discussion and Analysis of Financial Condition and Results of Operations – Major Aquistions and Dispositions" for a discussion of our recent acquisitions. The integration of these recently acquired businesses, and of businesses we may acquire in the future, requires significant time and effort of our senior management, who are also responsible for managing our existing operations. Integration of new businesses can be difficult, as our culture may differ from the cultures of the businesses we acquire, unpopular cost cutting measures may be required and control over cash flows and expenditures may be difficult to establish. While we have generally been satisfied with the progress we have made in integrating the businesses we have acquired thus far, we cannot assure you that we will continue to be as successful in the future.
International and U.S. sanctions have been imposed on companies engaging in certain types of transactions with specified countries or companies in those countries. In February 2003, we signed an agreement with Exploration and Production International, a division of the Norwegian company Norsk Hydro ASA, for the exploration and production of the Anaran prospective onshore block located in western Iran. A major oil field discovery was made on the Anaran block in December 2005. In June 2006, the National Iran Oil Company signed a commercialisation report giving Norsk Hydro and us the exclusive right to negotiate to further develop the field. Negotiations and the drafting of the overall field development plan are expected to be completed in the second quarter of 2007. In February 2006, we signed a contract with the NIOC regarding joint geological and geophysical work at the Mogan and Lali oil and gas blocks in Iran. See "Business – Exploration and Production – International Exploration and Production" for more information about these activities. If we violate existing international or U.S. sanctions, penalties could include a prohibition or limitation on our ability to obtain goods and services on the international market or to access the U.S. or international capital markets, which, in turn, could have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
We have a 68.5% interest in a production sharing agreement, or PSA, relating to the development of the second stage of the West Qurnah oil field in Iraq. In connection with our strategic alliance with ConocoPhillips, and subject to confirmation and the consents of governmental authorities and the parties to the PSA, we expect to enter into further agreements regarding the assignment of a 17.5% interest in the PSA to ConocoPhillips, which would reduce our effective interest to 51%. The PSA calls for the parties to make a total investment of at least \$6 billion on a pro rata basis. As a result of the prior U.N. sanctions against Iraq, we delayed our performance of certain obligations under the agreement. In December 2002, the former government of Iraq purported to terminate the PSA. Following the military campaign in Iraq in 2003, the provisional Iraqi administration expressed a desire to honour its obligations under the PSA. However, the future of our rights under the agreement remains uncertain. We cannot assure you that we will retain our rights under the PSA or that we will be able to begin developing the field when we are granted such opportunity by the Iraqi authorities or at any time after that. Because of the uncertainties surrounding our development of this field, no operating information relating to it has been included in this prospectus.
Our growth and future success depend in significant part upon the continued contributions of a number of our key senior management and personnel, in particular our President and a member of our Board of Directors, Vagit Yusufovich Alekperov. We cannot assure you that his services or the services of other key persons will continue to be available to us, and the loss of any one of them could have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
Our ability to exploit economically any reserves discovered will be dependent upon, among other things, the availability of the necessary infrastructure to transport oil and gas to potential buyers at a competitive price. Oil is usually transported by pipelines, tankers and rail to refineries. Natural gas is usually transported by pipelines to processing plants and end users. We face a number of significant obstacles related to the transportation of crude oil and natural gas from our holdings in the northern Caspian region and the CIS which could prevent sales to international markets. Such obstacles include capacity constraints, general political and economic instability and the necessity of obtaining approvals for pipelines from several governments that may not share a common development strategy. Additionally, our activities in northern Russia are constrained by, among other things, competition for pipeline access, the lack of infrastructure and the harsh weather conditions in that region.
Our business has grown substantially through the acquisition or creation of companies and assets, many of which required the prior approval or subsequent notification of the Russian Federal Antimonopoly Service (the FAS) or its predecessor agencies. Russian anti-monopoly legislation restricts the acquisition or creation of companies by groups of companies or individuals acting in concert without this approval or notification. The legislation is sometimes vague and subject to varying interpretations. If the FAS were to conclude that our acquisition or creation of a new company, shares or assets contravened applicable legislation, it could impose administrative sanctions on us and it could require the divestiture, liquidation or reorganisation of any such company or seek to invalidate any transactions related to such shares or assets, materially adversely affecting our acquisition strategy and, more generally, our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
We depend upon our management information systems to conduct our operations. We are also in the process of introducing new solutions to support our exploration and development activities and standardising and rationalising the accounting systems used at our subsidiaries. We have spent in excess of \$100 million over the past few years on information systems. Implementation of major new systems and enhancements to existing systems could cause disruptions in our operations. If the implementation of our new management information systems is delayed or the systems fail to perform as anticipated, we could experience difficulties in conducting our operations or generating necessary financial and accounting information. Any of these or other systems-related problems could, in turn, adversely affect our financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
Investors in emerging markets such as Russia should be aware that these markets are subject to greater risk than more developed markets, including in some cases significant political, legal and economic risks. Emerging economies such as the Russian economy are subject to rapid change and 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 equity markets of all emerging market countries as investors move their money to more stable, developed markets. As has happened in the past, financial problems or an increase in the perceived risks associated with investing in emerging economies could dampen foreign investment in Russia and adversely affect the Russian economy. In addition, during such times, companies that operate in emerging markets can face severe liquidity constraints as foreign funding sources are withdrawn. Thus, even if the Russian economy remains relatively stable, financial turmoil in any emerging market country could materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
Investors should exercise particular care in evaluating the risks involved and must decide for themselves whether, in light of those risks, their investment is appropriate. Generally, investment in emerging markets is only suitable for sophisticated investors who fully appreciate the significance of the risks involved, and investors are urged to consult with their own legal, financial and tax advisors before making an investment in the notes.
Approximately 4% of our proved crude oil reserves are located outside Russia. Currently, our principal international upstream interests are in two countries bordering the Caspian Sea: Kazakhstan and Uzbekistan. We also have upstream interests in Azerbaijan, Colombia, Egypt, Iran, Iraq, Saudi Arabia and Venezuela. We also have refining operations in Ukraine, Bulgaria and Romania. We are exposed to significant political, economic and legal risks in these countries. There has been war and civil strife in and around the Middle East, the Caspian region and in Colombia for much of the 1990s. Moreover, since the dissolution of the Soviet Union, the international legal status of the Caspian Sea has remained uncertain and is currently the subject of international negotiations that could have a material adverse effect on our interests there.
We are a Russian company and substantially all of our fixed assets are located in, and a significant portion of our revenues are derived from, Russia. There are certain risks associated with an investment in Russia.
We are subject to a broad range of taxes imposed at the federal, regional and local levels, and we are one of the largest sources of tax revenue to the federal authorities and to the regional and local authorities in those regions and localities in which we operate. The taxation system in Russia is subject to frequent change and inconsistent enforcement at the federal, regional and local levels. Until the adoption of the Russian Federation Tax Code, or the Tax Code, the system of tax collection was relatively ineffective, resulting in the continual imposition of new taxes in an attempt to raise state revenues. The existing Russian tax legislation, including the Tax Code, has been in force for a short period of time relative to tax laws in more developed market economies. The government's implementation of existing tax laws is often unclear or inconsistent. Accordingly, few precedents with regard to the interpretation of these laws have been established. In practice, Russian tax authorities generally interpret the tax laws in ways that rarely favour taxpayers, who often have to resort to court proceedings to defend their position against the tax authorities. In addition, differing opinions regarding the legal interpretation of tax legislation may exist within government ministries and organisations, such as the Ministry of Finance and the Federal Tax Service and its various inspectorates, creating uncertainties and areas of conflict.
Generally, tax declarations remain open and subject to inspection by tax and/or customs authorities for three years following the end of the relevant tax year. The fact that a particular year has been reviewed by tax authorities does not preclude that year, or any tax declaration for that year, from further review or audit. As a result, the statute of limitations is not entirely effective. In addition, on 14 July 2005, the Russian Constitutional Court issued a decision that allows the statute of limitations for tax liabilities to be extended beyond the three-year period if a court determines that a taxpayer has obstructed or hindered a tax inspection. Moreover, recent amendments to the first part of the Tax Code, effective 1 January 2007, provide for the extension of the three-year statute of limitations if the actions of the taxpayer created insurmountable obstacles for the tax audit. Because the terms "obstructed", "hindered" or "created insurmountable obstacles" are not defined, tax authorities may have broad discretion to argue that a taxpayer has "obstructed", "hindered" or "created insurmountable obstacles" in respect of an inspection and ultimately to seek penalties beyond the three-year term. These facts create tax risks in Russia substantially more significant than typically found in countries with more developed tax systems.
The Federal Tax Service has made tax claims in respect of, and challenged the use by, many Russian companies of tax optimisation schemes. For example, in June 2003, representatives of the Russian government began conducting investigations into Yukos and its subsidiaries, formerly one of the largest oil companies in Russia. These investigations ultimately resulted in tax claims against the company and the arrest on criminal charges and subsequent trial and sentence of some of the company's key shareholders and managers (including Yukos' Chief Executive Officer, Mikhail Khodorkovsky). In December 2004, OAO Rosneft, a Russian state-owned oil company, bought 76.79% of shares in OAO Yuganskneftegaz, Yukos' core oil production unit, by way of an auction conducted by the Russian government, the proceeds of which were intended to be used to satisfy the government's outstanding tax claims. In August 2006, a Moscow bankruptcy court declared Yukos officially bankrupt and ordered the liquidation of its assets. This process began in early 2007 through a series of auctions and has already been substantially completed. In addition, the press has reported significant claims for back taxes against other oil companies (including TNK-BP), telecommunications companies (including VimpelCom) and other major companies.
In 2004, Russian tax authorities conducted an investigation of our operations and the tax-planning initiatives that we have used in the past. As a result of this investigation, we paid \$163 million to settle the results of these tax audits for periods prior to 2004. Russian tax authorities are currently conducting investigations in respect of our operations in 2004 and 2005. Although we do not believe that any claims from Russian tax or other government authorities resulting from such investigations will materially adversely affect our business, financial condition or results of operations, we cannot assure you that such authorities will not bring any substantial claims as a result of these investigations, or any future investigations of these or other years, which could have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
Russian transfer pricing rules in effect since 1999 give Russian tax authorities the right to make transfer pricing adjustments and impose additional tax liabilities in respect of controlled transactions where the transaction price differs from the market price by more that 20%. Controlled transactions include transactions with related parties, barter transactions, foreign trade transactions and transactions with unrelated parties with significant price fluctuations (i.e., if the price of such transactions differs from the prices of similar transactions by more than 20% within a short period of time). The Russian transfer pricing rules are vaguely drafted, giving Russian tax authorities and arbitration courts considerable discretion in interpreting them, including potentially in connection with politically motivated investigations and prosecutions. It is difficult to determine market prices for crude oil in Russia, mainly due to the significant intragroup turnover of the vertically integrated oil companies that dominate the market. Substantially all crude oil produced in Russia is produced by vertically integrated oil companies, such as ours. As a result, most transactions are between affiliated entities within vertically integrated groups. Thus, there is no concept of a benchmark domestic market price for crude oil in Russia. The price of crude oil that is produced, but not refined or exported by one of the vertically integrated oil companies, is generally determined on a transaction-by-transaction basis against the background of world market prices, but with no direct reference or correlation. At any time, there may be significant price differences between regions for similar quality crude oil as a result of the competitive and economic conditions in those regions. Due to the uncertainties in the interpretation of transfer pricing legislation, the tax authorities may challenge our prices and propose adjustments. If such price adjustments are implemented, our business, financial condition or results of operations could be materially adversely affected. In addition, we could face significant losses associated with the assessment of prior underpaid tax and related interest and penalties, which would have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
All of the factors described above create tax risks in Russia that are more significant than those typically found in jurisdictions with more developed tax systems, imposing additional burdens and costs on our operations, including management resources and complicating our tax planning and related business decisions, potentially exposing us to significant fines and penalties and enforcement measures despite our best efforts at compliance. Additional tax exposures could have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
Since the dissolution of the Soviet Union, the Russian economy has experienced at various times:
The Russian economy has been subject to abrupt downturns. In particular, in August 1998, in the face of a rapidly deteriorating economic situation, the Russian government defaulted on some of its ruble-denominated securities, the Central Bank of Russia stopped its support of the ruble and a temporary moratorium was imposed on certain hard currency payments. These actions resulted in an immediate and severe devaluation of the ruble, a sharp increase in the rate of inflation, a dramatic decline in the prices of Russian debt and equity securities and an inability of Russian issuers to raise funds in the international capital markets. The near collapse of the Russian banking sector, which resulted in the loss of bank deposits in some cases, impaired its ability to act as a consistent source of liquidity to Russian companies, aggravating these problems.
Since the 1998 crisis, the Russian economy has experienced positive trends, such as an increase in gross domestic product, a relatively stable ruble, a reduced rate of inflation and positive capital and current account balances resulting in part from rising prices in world markets for the crude oil, gas and metals that Russia exports. In addition, the Russian government has achieved budget surpluses in recent years and has accumulated a sizeable "stabilisation fund", created to insulate the Russian government's budget from a fall in oil prices, and the Central Bank of Russia has considerable hard currency reserves. However, we cannot assure you that these recent trends will continue or will not be abruptly reversed. The return of economic instability, whether as a result of declines in oil and gas prices or otherwise, could materially adversely affect our business, financial condition and results of operations and the value of investments in Russia, such as the notes.
Since 1991, Russia has sought to transform itself from a one-party state with a centrally planned economy to a pluralist democracy with a market-oriented economy. The Russian political system remains vulnerable to popular dissatisfaction, including dissatisfaction with the results of privatisations in the 1990s, and 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, six different prime ministers headed governments between March 1998 and May 2000.
President Putin became acting president of Russia on 31 December 1999 and was elected president in March 2000. Since that time, Russia has generally experienced a higher degree of governmental stability. In February 2004, just prior to his election to a second term as president, President Putin dismissed his cabinet, including the prime minister. He subsequently appointed Mikhail Fradkov as prime minister and issued a presidential decree that significantly reduced the number of federal ministries, redistributed certain functions amongst various agencies of the government and announced plans for a major overhaul of the federal administrative system. Elections for the State Duma are scheduled for late 2007, and the next presidential election is scheduled for 2008.
Future presidential elections, changes in government, major policy shifts or a lack of consensus between the president, the government, Russia's parliament and powerful economic groups could lead to political instability, which could have a material adverse effect on the value of investment in Russia generally and the notes in particular.
Russia is a federation comprising 86 sub-federal political units, some of which have the right to manage their internal affairs pursuant to agreements with the federal government and in accordance with applicable laws. In practice, the division of authority between federal and regional governmental authorities remains uncertain and contested. This uncertainty could hinder our long-term planning efforts and may create uncertainties in our operating environment, which may prevent us from effectively carrying out our business strategy.
In addition, ethnic, religious, historical and other divisions have, on occasion, given rise to tensions and, in certain cases, military conflict, such as the continuing conflict in Chechnya. The military conflict in Chechnya has brought normal economic activity within Chechnya to a halt and disrupted the economies of neighbouring regions. Various armed groups in Chechnya have engaged in guerrilla attacks in that area. Violence and attacks relating to this conflict have also spread to other parts of Russia, including terrorist attacks in Moscow. The further intensification of violence, including terrorist attacks and suicide bombings, or its continued spread to other parts of Russia, could have significant political consequences, including the imposition of a state of emergency in some or all of Russia. Moreover, any terrorist attacks and the resulting heightened security measures may cause disruptions to domestic commerce and exports from Russia, and could materially adversely affect our business, financial condition, results of operations and the value of investments in Russia, such as the notes.
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. The August 1998 financial crisis resulted in the bankruptcy and liquidation of many Russian banks and almost entirely eliminated the developing market for commercial bank loans. Although the Central Bank of Russia has the mandate and authority to suspend banking licences of insolvent banks, many insolvent banks still operate. Aided by inadequate supervision by the regulators, many banks do not follow existing Central Bank of Russia 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.
Recently, there has been a rapid increase in lending by Russian banks, which many believe has been accompanied by deterioration in the credit quality of the borrowers. In addition, a robust domestic corporate debt market is leading to Russian banks increasingly holding large amounts of Russian corporate ruble bonds in their portfolios, which is further deteriorating the risk profile of Russian bank assets. 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 market downturns or economic slowdowns, including due to Russian corporate defaults that may occur during any such market downturn or economic slowdown. If a banking crisis were to occur, Russian companies would be subject to severe liquidity constraints due to the limited supply of domestic savings and the withdrawal of foreign funding sources that would occur during such a crisis.
There are currently a limited number of creditworthy Russian banks, most of which are located in Moscow. Another banking crisis or the bankruptcy or insolvency of the banks in which we receive or hold our funds could materially adversely affect our ability to conduct banking transactions in Russia and could, therefore, have a material adverse effect on our business, financial condition and results of operations.
The Russian economy has been characterised by high rates of inflation, including a rate of 84.4% in 1998, although it subsided to 11.7% in 2004, 10.9% in 2005 and 9.1% in 2006. Certain of our costs, such as salaries, are sensitive to increases in the general price level in Russia. Most of our revenues are either denominated in U.S. dollars or are linked to the U.S. dollar and are affected primarily by the international price of oil. Accordingly, our operating margins could be materially adversely affected if the inflation of our ruble costs in Russia is not balanced by a corresponding devaluation of the ruble against the U.S. dollar or an increase in oil prices.
Over the past ten years, the ruble has fluctuated dramatically against the U.S. dollar. In earlier years, the ruble depreciated against the U.S. dollar, although in each of the past four years, it has, on average, appreciated modestly. While most of our revenues are either denominated in U.S. dollars or are correlated to U.S. dollar oil prices, most of our costs (other than debt service costs and costs that are linked to U.S. dollar oil prices such as mineral extraction taxes, export duties, pipeline tariffs on exports and crude oil and refined product purchases) are denominated in rubles. Our results of operations are, therefore, significantly affected by the relative movements of ruble inflation and exchange rates. In particular, our operating margins are generally adversely affected by the appreciation of the ruble against the U.S. dollar because this will generally cause our costs to increase in real terms relative to our revenues. Conversely, our operating margins are generally positively affected by a depreciation of the ruble against the U.S. dollar because this will generally cause our costs to decrease in real terms relative to our revenues.
Because of the limited development of the foreign currency market in Russia, we may experience difficulty converting rubles into other currencies. Furthermore, the Russian government and the Central Bank of Russia may impose burdensome requirements governing currency operations, as it has done in the past. Additionally, any delay or other difficulty in converting rubles into a foreign currency to make a payment or any practical difficulty in the transfer of foreign currency could limit our ability to meet our 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 ruble-denominated instruments in which we may invest our excess cash. Any balances maintained in rubles will give rise to losses if the ruble devalues against major foreign currencies. Moreover, these restrictions could prevent or delay any acquisition opportunities outside of Russia that we might wish to pursue.
Russia is still developing the legal framework required by a market economy. Several fundamental Russian laws have only recently become effective. The relatively recent nature of much of Russian legislation and the rapid evolution of the Russian legal system place the enforceability and underlying constitutionality of laws in doubt and result in ambiguities, inconsistencies and anomalies. In addition, Russian legislation often leaves substantial gaps in the regulatory infrastructure. Among the risks of the current Russian legal system are:
All of these weaknesses could affect our ability to enforce our rights under contracts, or to defend ourselves against claims by others. We cannot assure you that regulators, judicial authorities or third parties will not challenge our internal procedures and by-laws or our compliance with applicable laws, decrees and regulations.
In addition, amendments to several Russian laws (including those relating to the tax regime, corporations and licensing) have only recently become effective. The recent nature of much of Russian legislation, the lack of consensus about the scope, content and pace of economic and political reform and the rapid evolution of the Russian legal system in ways that may not coincide with market developments may result in ambiguities, inconsistencies and anomalies, the enactment of laws and regulations without a clear constitutional or legislative basis and ultimately in investment risks that do not exist in countries with more developed legal systems. For example, although Russian bankruptcy laws establish a procedure for declaring an entity bankrupt and liquidating its assets, relatively few entities have been declared bankrupt in Russia, and many of the bankruptcy proceedings that have occurred have not been conducted in the best interests of creditors. All of these weaknesses could affect our ability to enforce our rights, or to defend ourselves against claims by others in respect of our Russian subsidiaries, and could affect enforcement of any rights of holders of the notes against the Issuer or LUKOIL. Furthermore, we cannot assure you that the development or implementation or application of legislation (including government resolutions or presidential decrees) will not adversely affect foreign investors (or private investors generally).
Many Russian laws are structured in a way that provides for significant administrative discretion in application and enforcement. Reliable texts of laws and regulations at the regional and local levels may not be available, and usually are not updated or catalogued. As a result, applicable law is often difficult to ascertain and apply, even after reasonable effort. In addition, the laws are subject to different and changing interpretations and administrative applications. As a result of these factors, even the best efforts to comply with the laws may not always result in full compliance.
Russian laws often provide general statements of principles rather than a specific guide to implementation and government officials may be delegated or exercise broad authority in determining matters of significance. Such authority may be exercised in an unpredictable way, and effective appeal processes may not be available. In addition, breaches of Russian law may involve severe penalties and consequences that could be considered to be disproportionate to any violation committed.
The independence of the judicial system and its immunity from economic, political and nationalistic influences in Russia remain largely untested. The court system is understaffed and underfunded. Judges and courts are generally inexperienced in the area of business and corporate law. Judicial precedents generally have no binding effect on subsequent decisions. In addition, most court decisions are not readily available to the public. Enforcement of court judgments can in practice be very difficult in Russia. Additionally, court claims are often used in furtherance of political and commercial aims. We may be subject to such claims and may not be able to receive a fair hearing. Additionally, court judgments are not always enforced or followed by law enforcement agencies. All of these factors make judicial decisions in Russia difficult to predict and make effective redress uncertain.
These uncertainties also extend to property rights. During Russia's transformation from a centrally planned economy to a market economy, legislation was enacted to protect private property against expropriation and nationalisation. However, these protections may not be enforced in the event of an attempted expropriation or nationalisation. Expropriation or nationalisation of any of the members of the Group or their assets, potentially with little or no compensation, could have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
Russia is not a party to multilateral or bilateral 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 1958 New York Convention on the Recognition and Enforcement of Foreign Arbitral Awards (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). Although the Russian 2002 Arbitration Procedural Code 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, in the event that Russian procedural legislation is further changed, new grounds preventing foreign court judgments and arbitral awards from being recognised and enforced in Russia could be introduced. 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 delay and unpredictability into the process of enforcing any foreign judgment or any foreign arbitral award in Russia.
Governmental authorities in Russia have a high degree of discretion and at times exercise their discretion arbitrarily, without hearing or prior notice, and sometimes in a manner that is contrary to law or influenced by political or commercial considerations. Selective or arbitrary governmental actions have included unscheduled inspections by regulators, suspension or withdrawal of licences and permissions, 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, 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 for political purposes.
In October 2006, an official at the Russian Ministry of Natural Resources threatened to revoke 36 of our licences for exploration in the Komi region of Timan-Pechora and in the Khanty-Mansiysky Autonomous Region, alleging that we failed to explore or drill according to the timelines set out in the licences. The same ministry official was responsible, in September 2006, for cancelling the ministry's 2003 environmental approval of Sakhalin-II, an LNG project in Russia's Far East run by a consortium including Royal Dutch Shell, Mitsui & Co. and Mitsubishi Corporation, due to alleged environmental breaches. See "Business – Health, Safety and Environment" for more information on the Sakhalin-II environmental breaches. Press reports suggested that the Russian government had grown impatient with cost overruns in the Sakhalin-II project which would lead to delays in the government's receipt of payments under the production sharing agreement between the Russian government and the Sakhalin-II consortium. Some analysts also interpreted the environmental authorities' crackdown on the project as a form of pressure on the consortium to conclude a deal with Gazprom, the state-owned gas company. In December 2006, each of the consortium members signed an agreement diluting their stakes in Sakhalin-II by 50% in order to accommodate a sale of a 50% plus one share controlling stake in the project to Gazprom for a purchase price of \$7.45 billion. Selective or arbitrary government action directed at us or preferential treatment by the Russian government of any of our competitors could have a material adverse effect on our business, financial condition and results of operations.
Russia's physical infrastructure largely dates back to Soviet times and has not been adequately funded and maintained over the past decade. Particularly affected are the rail and road networks, power generation and transmission systems, communication systems and building stock. For example, in May 2005, a fire and explosion in one of the Moscow power substations built in 1963 caused a major outage in a large section of Moscow and some surrounding regions, which resulted in a suspension of half of the Moscow metro lines, leaving thousands of people blocked underground for a long time. The blackout also hit the ground electric transport, led to road traffic accidents and massive traffic congestion, disrupted electricity and water supply in office and residential buildings and affected mobile communications. The trading on exchanges and the operation of many banks, stores and markets were also halted.
In addition, road conditions throughout Russia are poor. 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 may interrupt business operations. The government is actively considering plans to reorganise the nation's rail, electricity and telephone systems. Any such reorganisation may result in increased charges and tariffs while failing to generate the anticipated capital investment needed to repair, maintain and improve these systems. These factors could have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
The political and economic changes in Russia since the early 1990s have resulted in reduced policing of society and increased lawlessness. Reportedly, organised criminal activity has increased significantly since the dissolution of the Soviet Union, particularly in large metropolitan centres. Property crime in large cities has also increased substantially. In addition, the Russian and international press have reported high levels of official corruption, including the bribing of officials for the purpose of initiating investigations by government agencies. Press reports have also described instances in which government officials have engaged in selective investigations and prosecutions to further interests of the government officials and certain individuals. In addition, published reports indicate that a significant number of Russian media, including business focused media, regularly publish biased articles in return for payment. The effects of organised or other crime, demands of corrupt officials or claims that we have been involved in corruption could result in negative publicity, could disrupt our ability to conduct our business effectively and could, thus, have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
The failure of the government and many private enterprises to pay full salaries on a regular basis and the failure of salaries and benefits generally to keep pace with the rapidly increasing cost of living have led in the past, and could lead in the future, to labour and social unrest. Labour and social unrest may have political, social and economic consequences, such as increased support for a renewal of centralised authority, increased nationalism (with restrictions on foreign involvement in the economy of Russia) and increased violence. Any of these could restrict our operations and lead to the loss of revenue, materially adversely affecting our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
Our business includes a number of privatised companies and our business strategy will likely involve the acquisition of additional privatised companies. Many privatisations are arguably deficient and, therefore, vulnerable to challenge because the relevant privatisation legislation is vague, inconsistent or in conflict with other legislation. In the event that the privatisation of any of our companies is successfully challenged, we could risk losing our ownership interest in that company or its assets, which could materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
In addition, under Russian law, transactions with shares may be invalidated on many grounds, including a sale of shares by a person without the right to dispose of such shares, breach of interested party or major transaction rules and failure to register the share transfer in the securities register. As a result, defects in earlier transactions with shares in our subsidiaries (where such shares were acquired from third parties) may raise questions as to the validity of our title to such shares.
The regulation and supervision of the securities market, financial intermediaries and issuers are considerably less developed in Russia than in the United States and Western Europe. Corporate and securities laws, including those relating to corporate governance, disclosure and reporting requirements, anti-fraud safeguards, insider trading restrictions and fiduciary duties are relatively new to Russia and are unfamiliar to most Russian companies and managers. In addition, the Russian securities market is regulated by several different authorities, which are often in competition with each other, including the Federal Service for the Financial Markets, the Ministry of Finance, the Federal Antimonopoly Service, the Central Bank of Russia and various professional self-regulatory organisations. The regulations of these various authorities are not always co-ordinated and may be contradictory.
In addition, Russian corporate and securities rules and regulations can change rapidly, which may adversely affect our ability to conduct securities-related transactions. While some important areas are subject to virtually no oversight, the regulatory requirements imposed on Russian issuers in other areas result in delays in conducting securities offerings and in accessing the capital markets. It is often unclear whether, or how, regulations, decisions and letters issued by various regulatory authorities apply to us. As a result, we may be subject to fines or other enforcement measures, including delisting of our shares in Russia, despite our best efforts at compliance, which could cause our financial results to suffer and which could materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
The Russian government has the authority to direct us to deliver crude oil or refined products to certain government-designated customers, which may take precedence over market sales. In addition, the Russian government has used, and may continue to use, various administrative and fiscal measures to ensure sufficient supplies of crude oil and refined products are made available to domestic customers. Government-directed deliveries may take several forms. We may be directed to make deliveries to government agencies, the military, railways, agricultural producers, remote regions, specific consumers or refineries or to domestic refineries in general. Requirements for the delivery of domestic crude oil and refined products, with or without a corresponding limitation or ban of export sales, could be used or extended if the domestic market starts experiencing a shortage of crude oil or refined products. In addition, some of our oil production licences require us to sell crude oil that we produce to local government agencies. Our deliveries of refined products under government-directed programmes in 2005 and 2006 were made at domestic market prices. See "Business – Refining, Marketing and Distribution – Refined product sales" for more information on these government-directed deliveries.
Depending on the level of such required supplies, any government-directed deliveries may force us to curtail our export of crude oil or refined products, which have been generally made at higher prices than domestic sales. In addition, any government-directed deliveries may disrupt our relations with our customers and lead to delays in payments for crude oil and refined products. In addition, any failure to make government-directed deliveries may affect our ability to export our crude oil. For example, the Russian government has previously threatened to limit the access of Russian oil companies to export pipelines for failing to provide domestic refineries with steady supplies of oil. An increase in the levels of government-directed deliveries, or a revocation of export rights, could materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
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 currently apply to the export of crude oil, natural gas or refined products, although for the first half of 2002, the Russian government implemented limits on allowable export volumes in response to increasing pressure from OPEC to reduce the world's crude oil supply and maintain high commodity prices. However, the legislation may change, and quantitative restrictions on the existing or extended legal grounds may be reintroduced, if the current liberalisation policy of the Russian Government is reversed. Any such reintroduction of export quotas or an export licensing regime could materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
The Civil Code of the Russian Federation and the Federal Law on Joint Stock Companies generally provide that shareholders in a Russian joint stock company are not liable for the obligations of the joint stock company and bear only the risk of loss of their investment. This may not be the case, however, when one person is capable of determining decisions made by another person or entity. The person or entity capable of determining such decisions is deemed an "effective parent". The person whose decisions are capable of being so determined is deemed an "effective subsidiary". Under the Federal Law on Joint Stock Companies, an effective parent bears joint and several responsibility for transactions concluded by the effective subsidiary in carrying out these decisions if this decision-making capability is provided for in the charter of the effective subsidiary or in a contract between the companies and the effective parent gives obligatory directions to the effective subsidiary.
In addition, an effective parent is secondarily liable for an effective subsidiary's debts if an effective subsidiary becomes insolvent or bankrupt resulting from the action or inaction of an effective parent. This is the case no matter how the effective parent's ability to determine decisions of the effective subsidiary arises. For example, this liability could arise through ownership of voting securities or by contract. In these instances, other shareholders of the effective subsidiary may claim compensation for the effective subsidiary's losses from the effective parent which caused the effective subsidiary to take action or fail to take action knowing that such action or failure to take action would result in losses. Accordingly, we could be liable in some cases for the debts of our consolidated subsidiaries. This liability could have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
Russian law provides that shareholders that vote against or abstain from voting on certain matters have the right to require us to repurchase their shares at market value, as determined in accordance with Russian law. Decisions that trigger this put right include:
Our obligation to purchase shares in these circumstances, which is limited to 10% of our net assets calculated in accordance with Russian accounting standards at the time the matter at issue is voted upon, could have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
We are required by Russian law and our charter to obtain the approval of disinterested directors or shareholders for certain transactions with "interested parties". Under Russian law, the definition of an "interested party" includes members of the board of directors and members of any management body of a company, the chief executive officer of the company, the managing company of the company (if any) and any shareholder that owns, together with that person's close relatives and affiliates, at least 20% of the company's voting shares or a person who has the right to give mandatory instructions to the company if any of the above listed persons, or a close relative or affiliate of such person, is:
Due to the technical requirements of Russian law, entities within our Group may be deemed to be "interested parties" with respect to certain transactions between them. The failure to obtain necessary approvals for transactions within our Group could prevent us from entering into such transactions, which could materially adversely affect our business, financial condition and results of operations.
In addition, the concept of "interested parties" is defined with reference to the concepts of "affiliated persons" and "group of persons" under Russian law, which are subject to many different interpretations. Moreover, the provisions of Russian law defining the transactions which must be approved as "interested party" transactions are subject to different interpretations. Although we have generally taken a reasonably conservative approach in applying these concepts, our application of these concepts may be subject to challenge. Any such challenge could result in the invalidation of transactions that are important to our business, which could materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
Russian bankruptcy law differs considerably from comparable law in the United States or the United Kingdom and is subject to varying interpretations. The new Bankruptcy Law came into effect in late 2002. There is little precedent to predict how claims of noteholders against a Russian guarantor would be resolved in a bankruptcy of the guarantor. Weaknesses relating to the Russian legal system and Russian legislation create an uncertain environment for investment and business activity and thus could have a material adverse effect on an investment in the notes.
In addition, under Russian bankruptcy law, in case of our bankruptcy, our obligations as guarantor of the notes could be subordinated to the following obligations:
In the event of our bankruptcy, this legislation may materially adversely affect our ability to make principal and interest payments on the notes or under the guarantees.
Certain provisions of Russian law may allow a court to order liquidation of a Russian legal entity on the basis of its formal non-compliance with certain requirements during formation, reorganisation or during its 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 decrease the charter capital or liquidate the company). 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 companies in our Group currently have negative net assets. We are taking action to rectify this situation. In addition, although some of our subsidiaries may have failed from time to time to fully comply with all the applicable legal requirements, we believe that neither we, nor any of our subsidiaries, should be subject to liquidation on such grounds, and none of the possible violations has caused any damage to anyone or has had any other negative consequences. 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 we may be forced to reorganise the operations we currently conduct through the affected subsidiaries. Any such liquidation could lead to additional costs, which could materially adversely affect our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
The notes have not been registered under the Securities Act or any U.S. state securities laws and, unless so registered, may not be offered or sold except in a transaction exempt from, or not subject to, the registration requirements of the Securities Act and applicable state securities laws. Although it is expected that the notes will be admitted to trading on the London Stock Exchange on or after the Closing Date, there may be little or no secondary market for the notes. Even if a secondary market for the notes develops, it may not provide significant liquidity and it is expected that transaction costs in any secondary market would be high. As a result, the difference between bid and ask prices for the notes in any secondary market could be substantial and the value of the notes could be affected.
Historically, the markets for emerging market debt have been subject to disruptions 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 may have an adverse effect on holders of the notes.
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 will be shown on, and the transfer of that ownership will be 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.
The notes are being offered and sold in the United States in reliance on Rule 144A (the Rule 144A Offering) to purchasers who are QIBs and QPs. The notes also may be offered and sold outside the United States (the Regulation S Offering) in reliance on Regulation S. Each purchaser of notes pursuant to the Rule 144A Offering will be deemed to have represented to the Issuer that it is a QIB and a QP. Each purchaser of the notes pursuant to the Regulation S Offering will be deemed to have represented to the Issuer that it is not a U.S. person within the meaning of Regulation S and is not acquiring notes for the account or benefit of any U.S. person. See "Transfer Restrictions".
The Issuer has the option to redeem the notes prior to their scheduled maturity dates in certain circumstances as described in "Terms and Conditions of the Notes – Redemption and Purchase". 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.
The Issuer is an indirect wholly owned subsidiary of LUKOIL and will use the net proceeds from the issue of the notes for general corporate purposes, including the repayment of our indebtedness and financing capital expenditures. The Issuer has insufficient net assets, other than amounts due to it from LUKOIL in respect of any inter-company 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 LUKOIL or another Group company putting it in funds to meet such obligations.
We will have substantial amounts of outstanding indebtedness upon the completion of the issuance, primarily the notes and our obligations under existing credit arrangements. As a result of the issuance, our principal and interest payment obligations will increase substantially. We may also obtain working capital lines of credit, additional long-term debt, vendor financing and capital lease arrangements. We may not be able to generate enough cash to pay the principal, interest and other amounts due under all of our indebtedness.
Our substantial leverage could have significant negative consequences, including:
There can be no assurance that we will be able to meet such obligations, including our obligations under the notes. If we are unable to generate sufficient cash flow or otherwise obtain funds necessary to make required payments, we would be in default under the terms of our indebtedness, which would permit the holders of such indebtedness to accelerate the maturity of such indebtedness and could cause defaults under our various indebtedness, including the notes. Such defaults could delay or preclude payments of interest or principal on our indebtedness, including the notes.
Payments of interest under the guarantees are likely to be characterised as Russian source income. Accordingly, such payments should be subject to withholding tax in Russia at a rate of 20% in the event that a payment under our guarantees of the notes is made to a non-resident holder that is a legal entity or organisation and at a rate of 30% in the event that a payment under the guarantees is made to a non-resident individual, unless reduction or elimination of this tax is available under any applicable tax treaty. We cannot offer any assurance that such withholding tax would not be imposed upon the full payment under the guarantees, including with respect to the principal amount of the notes. See "Taxation – The Russian Federation".
If any payment required under the guarantees is subject to withholding tax, we will be obliged to increase the amount payable under the guarantees by the amount of withholding tax (except in circumstances specified in "Terms and Conditions of the Notes – Redemption and Purchase – Redemption for tax reasons"). As a result, we could incur expenses well in excess of the amount due to the holders of the notes. We cannot be certain that we would have sufficient funds to make any payment required under the guarantees or to pay the additional amounts associated with the withholding. Further, we can give no assurance that our obligation to pay the additional amounts associated with the withholding tax is enforceable under Russian law.
If a non-resident noteholder that is a legal entity or organisation sells notes and receives proceeds from a source within Russia, there is a risk that the part of the payment, if any, representing accrued interest may be subject to a 20% Russian withholding tax. Where proceeds from a sale, redemption or disposal of the notes are received from a source within Russia by an individual non-resident noteholder, a withholding tax would be charged at a rate of 30% on the gross proceeds from such disposal of the notes less any available cost deduction. The imposition or possibility of imposition of this withholding tax could adversely affect the value of the notes. See "Taxation – The Russian Federation".
The terms of the notes do not contain provisions that would afford you protection in the event of a decline in our credit quality resulting from highly leveraged or other similar transactions in which we may engage. We are also not limited in the amount of other indebtedness or other liabilities that we may incur or securities that we may issue. You do not have the right to require us to repurchase or redeem the notes in the event of many types of highly leveraged transactions.
LUKOIL will guarantee the notes, but the notes will not be guaranteed by LUKOIL's subsidiaries. Our operations are, to a significant extent, conducted through our subsidiaries. Accordingly, LUKOIL is and will be dependent on its subsidiaries' operations to service its indebtedness, including its guarantees of the notes. The guarantees are effectively subordinated to the claims of all of the creditors, including trade creditors, of LUKOIL's subsidiaries. In the event of an insolvency, bankruptcy, liquidation, reorganisation, dissolution or winding up of the business of any subsidiary of LUKOIL, creditors of such subsidiary generally will have the right to be paid in full before any distribution will be made to LUKOIL or the holders of the notes.
We have agreed in Condition 4 of the Terms and Conditions of the Notes not to, and to procure that no Subsidiary (as defined in the Terms and Conditions of the Notes) will, create or permit to subsist any Security Interest (as defined in the Terms and Conditions of the Notes) other than a Permitted Security Interest (as defined in the Terms and Conditions of the Notes) upon the whole or any part of its undertaking, property, assets or revenues, present or future, to secure for the benefit of the holders of any Relevant Indebtedness (as defined in the Terms and Conditions of the Notes) any payment in respect of or relating to any Relevant Indebtedness without procuring that the notes are secured equally and rateably with such Relevant Indebtedness to the satisfaction of the Trustee. The application of this negative pledge and the protection that it affords to holders of the notes, however, is limited. For example, the definition of Relevant Indebtedness is limited to our present or future Indebtedness in the form of, or represented by, notes, debentures, notes or other securities but, for the avoidance of doubt, excluding term loans, credit facilities, credit agreements and other similar facilities and evidence of indebtedness under such loans, facilities or agreements) which are or ordinarily are quoted, listed or ordinarily dealt in or traded on any stock exchange, over-the-counter or other securities market. In addition, pursuant to an exemption from the negative pledge, we will be permitted to secure an aggregate amount of Relevant Indebtedness not exceeding 20% of Consolidated Assets (as defined in the Terms and Conditions of the Notes), without any obligation to afford any equal and ratable security to holders of the notes. As a result, we will be permitted to secure a range of other forms of Indebtedness (as defined in the Terms and Conditions of the Notes) and may also create security in respect of a significant amount of Relevant Indebtedness without, at the same time, being obliged to grant equal and ratable security in respect of the notes or the guarantees, as the case may be, which may adversely affect the value of your investment in the notes and/or cause you to rank in terms of priority behind such secured creditors.
LUKOIL and most of its subsidiaries are incorporated outside of the United States or 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, some of which could be based upon the structure utilised in this offering. See "Enforceability of Judgments".
We have sourced certain information contained in this prospectus from third parties, including private companies and Russian government agencies, and we have 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.
The following table sets forth our consolidated capitalisation and short-term debt as at 31 December 2006, extracted from our audited consolidated financial information as at 31 December 2006 and as adjusted to give effect to the application of the net proceeds of the offering as described under "Use of Proceeds". There have been no material changes in our capitalisation since 31 December 2006, except as described in "Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources" and "Business – Recent Developments". For further information regarding our financial condition, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and notes and unaudited supplementary oil and gas information thereto included elsewhere in this prospectus.
| As at 31 December 2006 111111123111 |
||
|---|---|---|
| Actual 11111 |
As adjusted 11111 |
|
| (in millions of U.S. dollars) | ||
| Short-term debt | ||
| Short-term borrowings | 1,001 | 1,001 |
| Current portion of long-term debt | 376 11111 |
376 11111 |
| Total short-term debt | 1,377 11111 |
1,377 11111 |
| Long-term debt | ||
| Long-term loans and borrowings | 4,320 | 5,320 |
| 3.5% Convertible U.S. dollar bonds, maturing 2007 | 4 | 4 |
| 7.25% Russian ruble bonds, maturing 2009 | 228 | 228 |
| 7.10% Russian ruble bonds, maturing 2011 | 304 | 304 |
| 7.40% Russian ruble bonds, maturing 2013 | 228 | 228 |
| Capital lease obligation | 99 | 99 |
| Current portion of long-tem debt | (376) 11111 |
(376) 11111 |
| Total long-term debt | 4,807 11111 |
5,807 11111 |
| Total debt | 6,184 11111 |
7,184 11111 |
| Shareholders' equity | ||
| Share Capital | 15 | 15 |
| Treasury stock | (1,098) | (1,098) |
| Additional paid-in capital | 3,943 | 3,943 |
| Retained earnings | 30,061 | 30,061 |
| Accumulated other comprehensive income | (21) 11111 |
(21) 11111 |
| Total shareholders' equity | 32,900 11111 |
32,900 11111 |
| Total capitalisation1 | 37,707 11111 |
38,707 11111 |
| Share capital of LUKOIL Ordinary shares, authorised, issued and fully paid, nominal value RUR0.025 per share2 |
850,563,255 | |
| Note: |
(1) Comprising total long-term debt and total shareholders' equity.
(2) On 25 April 2007, our Board of Directors resolved to add as an agenda item to our annual shareholders meeting, scheduled for 28 June 2007, the amendment of our charter to increase our authorised shares by 85 million shares, which is approximately 10% of our currently authorised and issued shares.
Save in respect of the guarantees in relation to the notes and our guarantee in respect of \$678 million outstanding as at 31 December 2006 under the LUKARCO loan facility described in "Management's Discussion and Analysis of Financial Condition and Results of Operations – Off Balance Sheet Arrangements", there are no material contingent liabilities in relation to the Group. Of the total debt of the Group of \$6,184 million, \$3,180 million was guaranteed by LUKOIL, \$420 million was secured, \$295 million was secured and guaranteed by LUKOIL and \$2,289 million was unsecured and unguaranteed.
The selected consolidated financial data set out below present a summary of our historical consolidated financial information at 31 December 2006, 2005, 2004, 2003 and 2002 and for the years then ended and are derived from our consolidated financial statements and notes and unaudited supplementary oil and gas information thereto, which have been prepared in accordance with U.S. GAAP and audited by KPMG. The selected financial data set forth below should be read in conjunction with our consolidated financial statements and notes and unaudited supplementary oil and gas information thereto included elsewhere in this prospectus and "Management's Discussion and Analysis of Financial Condition and Results of Operations".
| Year ended 31 December | 111111111111111124411111111111 | ||||
|---|---|---|---|---|---|
| 2006 11111 |
2005 11111 |
2004 11111 |
2003 11111 |
2002 11111 |
|
| (in millions of U.S. dollars, except per share amounts) | |||||
| Consolidated Statement of Income Data: | |||||
| Revenues | |||||
| Sales (including excise and export | |||||
| tariffs) | 67,684 | 55,774 | 33,845 | 22,118 | 15,334 |
| Equity share in income of affiliates | 425 11111 |
441 11111 |
213 11111 |
181 11111 |
115 11111 |
| Total revenues | 68,109 | 56,215 | 34,058 | 22,299 | 15,449 |
| Costs and other deductions | |||||
| Operating expenses | (4,657) | (3,487) | (2,880) | (2,546) | (2,403) |
| Cost of purchased crude oil, petroleum | |||||
| and chemical products | (22,374) | (19,398) | (10,124) | (5,909) | (2,693) |
| Transportation expenses | (3,863) | (3,519) | (2,784) | (2,052) | (1,414) |
| Selling, general and administrative | |||||
| expenses | (2,885) | (2,578) | (2,024) | (1,800) | (1,313) |
| Depreciation, depletion and | |||||
| amortisation | (1,851) | (1,315) | (1,075) | (920) | (824) |
| Taxes other than income taxes | (8,075) | (6,334) | (3,505) | (2,456) | (1,972) |
| Excise and export tariffs | (13,570) | (9,931) | (5,248) | (2,954) | (1,996) |
| Exploration expense | (209) | (317) | (171) | (136) | (89) |
| Gain from sale of interest in Azeri | |||||
| Chirag Guneshli | – | – | – | 1,130 | – |
| (Loss) gain on disposals and impairments of assets |
(148) | 52 | (213) | (69) | (83) |
| 11111 | 11111 | 11111 | 11111 | 11111 | |
| Income from operating activities | 10,477 | 9,388 | 6,034 | 4,587 | 2,662 |
| Interest expense | (302) | (275) | (300) | (273) | (222) |
| Interest and dividend income | 111 | 96 | 180 | 139 | 160 |
| Currency translation gain (loss) | 169 | (134) | 135 | 148 | 40 |
| Other non-operating (expense) income Minority interest |
(118) (80) |
(44) (121) |
21 (62) |
11 (36) |
11 (69) |
| 11111 | 11111 | 11111 | 11111 | 11111 | |
| Income before income taxes | 10,257 | 8,910 | 6,008 | 4,576 | 2,582 |
| Current income taxes | (2,906) | (2,301) | (1,614) | (939) | (834) |
| Deferred income taxes | 133 11111 |
(166) 11111 |
(146) 11111 |
(68) 11111 |
95 11111 |
| Total income tax expense Income before cumulative effect of |
(2,773) | (2,467) | (1,760) | (1,007) | (739) |
| change in accounting principle | 7,484 | 6,443 | 4,248 | 3,569 | 1,843 |
| Cumulative effect of change in | |||||
| accounting principle, net of tax | – 11111 |
– 11111 |
– 11111 |
132 11111 |
– 11111 |
| Net income | 7,484 11111 aaaaa |
6,443 11111 aaaaa |
4,248 11111 aaaaa |
3,701 11111 aaaaa |
1,843 11111 aaaaa |
| Basic earnings per share of common | |||||
| stock | 9.06 | 7.91 | 5.20 | 4.52 | 2.26 |
| Diluted earnings per share of common | |||||
| stock | 9.04 | 7.79 | 5.13 | 4.45 | 2.26 |
| As at 31 December 111111111111111124411111111111 |
|||||||
|---|---|---|---|---|---|---|---|
| 2006 11111 |
2005 11111 |
2004 11111 |
2003 11111 |
2002 11111 |
|||
| (in millions of U.S. dollars) | |||||||
| Balance Sheet Data: | |||||||
| Cash and cash equivalents | 752 | 1,650 | 1,257 | 1,435 | 1,252 | ||
| Working capital | 6,641 | 6,661 | 4,029 | 2,652 | 1,678 | ||
| Property, plant and equipment | 31,316 | 25,464 | 19,329 | 16,859 | 13,499 | ||
| Total assets | 48,237 | 40,345 | 29,761 | 26,574 | 22,001 | ||
| Long-term debt (including current portion) | 5,183 | 4,674 | 2,981 | 2,803 | 2,698 | ||
| Shareholders' equity | 32,900 | 26,804 | 20,811 | 17,472 | 14,000 |
The reserves and production information in this prospectus includes reserves and production that we do not beneficially own which are attributable to minority interests in our consolidated subsidiaries and our equity share of reserves and production of our affiliated companies. Unless otherwise specified, the reserves and production information in this prospectus does not include information relating to:
We have extracted the reserves information set out below without material adjustment from the reserves reports prepared by Miller and Lents. We have extracted the production information set out below without material adjustment from our management accounts and operating records. We use this operating reserves and production information in managing our business and we expect to continue to report on such reserves and production information in our annual reports.
| As at 1 January 111111111111111124411111111111 |
|||||
|---|---|---|---|---|---|
| 2007 | 2006 | 2005 | 2004 | 2003 11111 |
|
| 15,258 | |||||
| 6,194 | |||||
| 24,164 | |||||
| 8,960 | |||||
| 19,285 | |||||
| 12,340 | 12,300 | 10,014 | 9,674 | 7,687 | |
| 11111 15,927 8,767 26,597 21,436 20,360 |
11111 16,114 8,869 25,298 20,587 20,330 |
11111 15,972 7,424 24,598 15,537 20,072 |
11111 15,977 7,238 24,473 14,616 20,056 |
| Year ended 31 December 111111111111111124411111111111 |
|||||
|---|---|---|---|---|---|
| 2006 11111 |
2005 11111 |
2004 11111 |
2003 11111 |
2002 11111 |
|
| Production | |||||
| Crude oil (mmbls/year) | 703 | 664 | 635 | 592 | 564 |
| Russia | 660 | 634 | 608 | 570 | 543 |
| International | 43 | 30 | 27 | 22 | 21 |
| Gas available for sale (bcf/year) | 481 | 200 | 174 | 133 | 126 |
This prospectus contains information concerning our estimated crude oil and gas reserves which has been derived or extracted from the reports of Miller and Lents, Ltd., our independent reservoir engineers, dated as at 1 January in each of 2003, 2004, 2005, 2006 and 2007, and which are estimated in accordance with standards of the Society of Petroleum Engineers, Inc. and World Petroleum Congresses (SPE standards). 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 our 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. You should not place undue reliance on the ability of the reserves reports prepared by Miller and Lents to predict actual reserves or on comparisons of similar reports concerning companies established in places with more mature economic systems.
The reserves amounts included in this prospectus, prepared in accordance with SPE standards, do not comply with certain standards of reserves measurement applied by the U.S. Securities and Exchange Commission. For example, under SPE standards, proved reserves are projected to the economic production life of the evaluated fields, whereas, under SEC standards, oil and gas deposits may not be classified as proved reserves if they will be recovered after the expiration of a current license period unless the license holder has the right to renew the license and there is a demonstrated history of license renewal. In addition, the SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. This prospectus contains data, such as reserves and resources presented in accordance with SPE standards, that the SEC's guidelines would prohibit us from including in filings with the SEC.
Because our estimated reserves totals included in this prospectus are taken directly from reserves reports prepared by Miller and Lents, they are presented in barrels (for crude oil) and cubic feet (for natural gas). However, like many other Russian and European oil companies, we use the metric tonne and the cubic metre as the standard unit of measurement for quantities of crude oil and natural gas, respectively, which we produce and sell. For convenience, amounts of crude oil have been translated from tonnes into barrels (or from barrels into tonnes in respect of reserve amounts) and amounts of natural gas have been translated from cubic metres into cubic feet (or from cubic feet into cubic metres in respect of reserve amounts). Translations of barrels to tonnes were made at the rate of 7.33 barrels per tonne (other than in respect of crude oil production amounts, where such translations were made using conversion rates characterising the density of oil from each of the relevant oil fields). Translations of cubic feet to cubic metres were made at the rate of 35.31 bcf per bcm. Translations of barrels of crude oil into boe were made at the rate of 1 barrel per boe and of mcf into boe at the rate of 6 bcf per 1 mmboe.
Our businesses are performing, and trading since 31 December 2006 has been in line with our directors' expectations. Our directors view our future prospects with confidence and believe that our position as one of the largest publicly traded oil companies in the world in terms of proved crude oil and gas reserves, and the execution of our corporate development and restructuring programme, will enable us to remain competitive in Russia, provide a platform for competing internationally with other major oil companies and deliver value to our shareholders.
On 15 May 2007, we announced certain preliminary operating estimates for the first quarter of 2007. In the first quarter of 2007, we currently estimate that our total crude oil production was 180.5 mmbls (24.4 million tonnes), our gas production available for sale was 127.1 bcf (3.6 bcm) and our refinery throughput was 12.1 million tonnes at our refineries and 1.0 million tonnes at third-party refineries. This information is based on preliminary operating data and is subject to adjustment in connection with the preparation of our consolidated financial statements for the first quarter of 2007.
The following is a discussion and analysis of our financial condition and results of operations as at 31 December 2005 and 2006 and for each of the years ended 31 December 2004, 2005 and 2006. You should read this discussion and analysis in conjunction with our consolidated financial statements and notes and unaudited supplementary oil and gas information thereto included elsewhere in this prospectus. This discussion and analysis contains forward-looking statements about our future revenue, operating results and expectations that involve risks and uncertainties. Our 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" and elsewhere in this prospectus.
We are a vertically integrated oil company primarily engaged in the exploration, development and production of crude oil and natural gas, the refining of crude oil into refined products, the processing of natural gas and the marketing and distribution of crude oil, natural gas and refined products. We also process and sell petrochemical products. The following table sets out our sales (including excise and export tariffs), net income and total crude oil and natural gas production for each of the years ended 31 December 2004, 2005 and 2006.
| Year ended 31 December 1211111111111111111111111 |
|||||
|---|---|---|---|---|---|
| 2006 12111111 |
2005 12111111 |
2004 12111111 |
|||
| Sales | \$ 67,684 million | \$ 55,774 million | \$ 33,845 million | ||
| Net income | \$ 7,484 million | \$ 6,443 million | \$ 4,248 million | ||
| Total crude oil and natural gas production | 783,194 mboe | 697,429 mboe | 665,024 mboe |
Our operations are divided into three main business segments:
Our other businesses, which include banking, finance and other activities, compose a fourth segment. This fourth segment is not significant to our overall results of operations and, therefore, is not discussed in detail in this discussion. In addition, following the sale of 78% of our interest in Bank Petrocommerce in September 2004 and our remaining 21% interest in May 2006, we have disposed of our material banking and finance components. We also sold our drilling subsidiary, OOO LUKOIL-Burenie, in the fourth quarter of 2004. In 2006, we sold our Astra jack-up rig, which is designed for offshore field exploration in the Caspian Sea, and eight tankers used in our shipping operations. In addition, we intend to sell two more tankers in July 2007. These dispositions reflect our strategy to divest our non-core businesses.
Each of our three main business segments is dependent on the other, with a portion of the revenues of one segment being a part of the costs of the other. In particular, our refining, marketing and distribution segment purchases crude oil from our exploration and production segment. It is difficult to determine market prices for crude oil in Russia, mainly due to the significant intra-group turnover of the vertically integrated oil companies that dominate the market. The prices we set for inter-segment purchases of crude oil reflect a combination of market factors, including international crude oil market prices, transportation costs, regional market conditions, the cost of refining crude oil and other factors. For this reason, we do not generally analyse our main segments separately in the discussion that follows. We present the financial data for each of our business segments in note 23 to our annual consolidated financial statements, which are included elsewhere in this prospectus.
Our financial condition and results of operations have been affected by acquisitions and dispositions during the period from 1 January 2004 through the date of this prospectus. We accounted for each of these acquisitions using the purchase method of accounting and reflected the results of operations of the acquired entities in our consolidated financial statements from the date of acquisition. We continue to review various potential acquisitions involving both upstream and downstream operations and are prepared to take advantage of appropriate acquisition opportunities. We have provided below a summary of the acquisitions and dispositions that have had or may have a material effect on our financial condition and results of operations since 1 January 2004.
In December 2004, we acquired Eni S.p.A's 50% interest in LUKAgip N.V. for \$143 million, of which \$32 million was the purchase price and \$111 million was used to discharge LUKAgip's debt to Eni. LUKAgip owns a 24% interest in the Meleiha project in Egypt and a 10% interest in the Shakh-Deniz project in Azerbaijan. It also owns an 8% in the Azerbaijan Gas Supply Company, a midstream gas marketing company, and a 10% interest (indirectly through LUKAgip Midstream) in the South Caucasus Pipeline Company. In November 2006, we liquidated LUKAgip and transferred its assets to LUKOIL Overseas Shah Deniz Ltd.
In July 2005, we acquired 66% of OOO Geoilbent for \$180 million. Geoilbent is an exploration and production company operating in Western Siberia. All decisions over Geoilbent's financing and operating activities required minority shareholder approval. As a result we accounted for our investment in Geoilbent using the equity method of accounting.
In July 2005, we sold our 100% stake in ZAO Arktikneft, an oil production company, for approximately \$40 million, including approximately \$20 million for the settlement of Arktikneft's debt to us.
In November 2005, we acquired the remaining 50% of ZAO SeverTEK from Neste Oil for \$318 million, including a \$98 million repayment of SeverTEK's long-term debt. This acquisition increased our ownership stake in SeverTEK to 100%. SeverTEK is an exploration and production company operating in the Komi Republic.
From 14 October through 5 December 2005, we acquired 100% of Nelson Resources Limited for \$1,951 million. Nelson Resources, which we have since renamed Caspian Investments Resources Limited, is an exploration and production company operating in western Kazakhstan.
From November through December 2005, we acquired 51% of OAO Primorieneftegaz for \$261 million. Primorieneftegaz is a Russian oil and gas exploration company operating in European Russia.
In May 2006, we acquired the remaining 49% of Primorieneftegaz for 4.165 million shares of our common stock (at a market value of approximately \$314 million), increasing our ownership stake in Primorieneftegaz to 100%.
In June 2006, we acquired 100% of KMOC from Marathon Oil Corporation for \$847 million, including a \$249 million repayment of KMOC debt. The purchase price is subject to the finalisation of working capital and other adjustments in accordance with the purchase agreement. At the time of our acquisition, KMOC owned 95% of OAO Khantymansiysknetegazgeologia and 100% of OAO Paitykh Oil and OAO Nazymgeodobycha, which have exploration and production interests in the Khanty-Mansiysk Autonomous District of Western Siberia. The KMOC companies are currently undergoing an internal restructuring as a result of which their assets will be owned by a number of entities within our Group. We expect to complete the restructuring of the KMOC companies during the second half of 2007.
In September 2006, we acquired the remaining 40% of Chaparral Resources, Inc. (owner of a 60% interest in the KarakudukMunai joint venture) for \$89 million, increasing our ownership stake in Chaparral Resources and our effective interest in the KarakudukMunai joint venture to 100%. Prior to this acquisition, we owned 60% of Chaparral Resources through Caspian Investments Resources.
In January 2007, we acquired the remaining 34% of Geoilbent for \$300 million, thereby increasing our ownership stake in Geoilbent to 100%.
On 20 April 2007, we sold 50% of Caspian Investments Resources to Mittal Investments S.a.r.L. for \$980 million. In addition, Mittal Investments committed to repay 50% of Caspian Investments Resources' outstanding debt, which was approximately \$175 million as at the date of the sale and which consisted of inter-company debt to other members of our Group.
In May 2004, we acquired from ConocoPhillips 308 retail filling stations and contracted to supply refined products to an additional 471 retail filling stations in the northeastern United States for \$270 million.
In January 2005, we acquired an additional 22% of the Burgas refinery in Bulgaria for \$56 million, including 20.7% from a related party for \$52 million. The acquisition increased our ownership stake in the refinery to 93.2%. In August 2005, we acquired an additional 4% in the refinery for \$10 million, thereby increasing our ownership stake to 97.2%.
In March 2005, we acquired 100% of Oy Teboil Ab and Suomen Petrooli Oy for \$160 million. Teboil and Suomen Petrooli are Finnish companies primarily engaged in the wholesale and retail sale of refined products and the production and sale of lubricants in Finland.
In June 2006, we acquired 41.81% of OAO Udmurtnefteproduct for \$25 million. Udmurtnefteproduct is a Russian refined product distribution company which operates more than 100 filling stations in the Udmurt Republic of the Russian Federation.
In December 2006, we entered into an agreement with ConocoPhillips to purchase 376 filling stations in seven countries in Europe. On 30 April 2007, we completed the acquisition of the filling stations located in Finland. We completed the acquisition of the remaining filling stations on 1 June 2007.
2004
In August 2004, we entered into an agreement with Financial Group IFD Kapital, a related party whose management and directors include certain members of our management and Board of Directors, to sell our 99% interest in OAO Bank Petrocommerce. In September 2004, we sold 78% of Bank Petrocommerce to IFD Kapital for \$169 million.
In December 2004, we disposed of 100% of LUKOIL-Burenie, our drilling subsidiary, to Eurasia Drilling Company Limited for \$69 million. In connection with the disposition, we signed a five-year contract with Eurasia Drilling for drilling services.
In June 2005, we sold our 38% interest in our construction affiliate, ZAO Globalstroy-Engineering (formerly LUKOIL-Neftegazstroy) for \$69 million.
In May 2006, we sold eight tankers used in our shipping operations for \$190 million. We intend to sell two more tankers in July 2007.
In December 2006, we sold our Astra jack-up rig, which is designed for offshore field exploration in the Caspian Sea, to Eurasia Drilling for approximately \$40 million.
In May 2006, we sold our remaining 21% interest in Bank Petrocommerce to IFD Kapital for \$33 million.
Our results of operations and the period-to-period changes in our results of operations have been, and will continue to be, affected by various factors, the most important of which are discussed below.
The prices at which we sell crude oil and refined products, which are the primary drivers of our revenues, are subject to frequent and significant fluctuations. These prices are affected by numerous external factors beyond our control, including the following:
Crude oil prices have risen dramatically in recent years, primarily as a result of continuing increases in demand (particularly in the United States and Asia), instability in major oil-producing regions (particularly in the Middle East and western Africa) and distribution bottlenecks in certain major consuming centres. From January to August 2006, the price of Brent crude oil, an international benchmark oil blend, fluctuated between \$55 and \$79 per barrel. After reaching a peak on 8 August 2006 of \$78.69 per barrel, the price of Brent crude oil declined as a result of a combination of factors, including excess supply and warm weather in the northern hemisphere. The price of Brent crude oil as at 31 December 2006 was \$58.92 per barrel. In the first quarter of 2007, the price of Brent crude oil recovered from the declines in the second half of 2006 due to continuing increases in demand and continuing instability in the Middle East, particularly in Iraq and Iran. As at 31 March 2007, the price of Brent crude oil was \$68.71 per barrel.
Substantially all of the crude oil that we produce and sell in international markets is transported through the Transneft pipeline system, where it is blended with other crude oil of varying qualities to produce an export blend commonly referred to as Urals blend. See "Business – Exploration and Production – Crude Oil Transportation – Pipelines". The following table sets out the average export prices for Urals blend crude oil for each of the years ended 31 December 2004, 2005 and 2006:
| 11311111111111111 | Year ended 31 December | ||
|---|---|---|---|
| 2006 11111 |
2005 11111 |
2004 11111 |
|
| Crude oil (average \$/bbl Urals Blend, CIF Mediterranean) | 61.37 | 50.67 | 34.50 |
Source: Platts
We sell crude oil and refined products internationally both to countries in the CIS and countries outside of the CIS. The following table sets out the average realised prices for our international sales of crude oil (both in and outside of the CIS) and refined products for each of the years ended 31 December 2004, 2005 and 2006.
| Year ended 31 December 11311111111111111 |
||||
|---|---|---|---|---|
| 2006 11111 |
2005 11111 |
2004 11111 |
||
| Crude oil (excluding CIS) (\$/bbl) | 60.43 | 49.85 | 33.62 | |
| Crude oil (CIS) (\$/bbl) | 36.46 | 32.63 | 20.13 | |
| Refined products (\$/tonne) | ||||
| Wholesale | 526.46 | 462.61 | 317.24 | |
| Retail | 998.05 | 884.30 | 714.19 |
Historically, crude oil prices in Russia have been significantly below prices in the international market. Substantially all crude oil produced in Russia is produced by vertically integrated oil companies, such as ours. As a result, most transactions are between affiliated entities within vertically integrated groups. Thus, there is no concept of a benchmark domestic market price for crude oil in Russia. The price of crude oil that is produced, but not refined or exported by one of the vertically integrated oil companies is generally determined on a transactionby-transaction basis against the background of world market prices, but with no direct reference or correlation. Crude oil prices in international markets will be higher than those in Russia due to higher transportation costs, which vary widely depending on the destination of the crude oil, and export tariffs incurred in connection with the delivery of crude oil from the Russian border to international markets. At any time, there may be significant price differences between regions for similar quality crude oil as a result of the competitive and economic conditions in those regions.
Domestic prices for refined products are determined in part by world market prices, but they are also directly affected by local demand and competition. The higher international prices for refined products result primarily from higher excise and similar taxes in Europe.
The table below sets out the average realised sales prices for our domestic sales of crude oil and refined products for each of the years ended 31 December 2004, 2005 and 2006.
| Year ended 31 December 11311111111111111 |
||||
|---|---|---|---|---|
| 2006 11111 |
2005 11111 |
2004 11111 |
||
| Crude oil (\$/bbl) | 28.16 | 24.44 | 15.09 | |
| Refined products (\$/tonne) | ||||
| Wholesale | 358.38 | 289.41 | 201.94 | |
| Retail | 680.79 | 555.80 | 450.64 |
The main Russian crude oil producing regions are remote from the main crude oil and refined product markets. Therefore, a crude oil production company's access to markets is dependent on the extent of the diversification of transport infrastructure and its access to such infrastructure. As a result, transportation cost is an important macroeconomic factor affecting our results of operations.
We transport most of our crude oil through the Transneft pipeline system and then to customers or to our refineries either solely by means of this pipeline system or in combination with transportation by railway, river, sea or other pipelines. Transneft is a state-owned pipeline monopoly. The Russian government regulates access to Transneft's pipeline network. 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 and proposed export destinations. See "Business – Exploration and Production – Crude Oil Transportation". Although pipeline capacity in Russia has increased in recent years, the capacity of Transneft's pipeline system still acts as a constraint on exports and, indirectly, on oil production in Russia, especially on the most profitable export routes.
Refined products in Russia are transported primarily by the pipeline system of Transnefteproduct and through the railway infrastructure owned and operated by Russian Railways. Transnefteproduct and Russian Railways are state-owned companies. We transport most of our refined products through Russian Railways' rail network. The Transnefteproduct pipeline system is not as extensive as the Transneft pipeline system.
To bypass these state-owned export routes, we use a combination of rail cars, tankers and our own infrastructure (including our Vysotsk, Varandey and Svetly terminals) to transport crude oil and refined products that we sell in international markets. In 2006, we exported 3% of our crude oil production by means other than Transneft, compared to 8.7% in 2005. This decrease is due primarily because of an increase in our exports through Transneft's dedicated Baltic Pipeline System resulting from an increase in the pipeline's capacity. Because of this increased capacity, we ceased exporting crude oil through our Vysotsk terminal in the third quarter of 2005 and now export refined products through that terminal.
We incur transportation costs to deliver crude oil and refined products to our refineries and our customers. Transportation costs include pipeline, freight, railway and river tariffs, loading costs and port charges. As noted above, we transport most of the crude oil that we produce through Transneft's pipeline system, which collects, on prepayment terms, a ruble tariff on domestic crude oil shipments and a combined ruble and hard currency tariff on exports.
Because Transneft, Russian Railways and Transnefteproduct are natural monopolies, their tariff policies are determined by the FTS to balance the interests of the state and all participants in the transportation process. The FTS's tariffs are based on destination, delivery volume, distance of transportation and other factors. Changes in tariffs depend on inflation forecasts, the investment needs of the transportation infrastructure, reimbursement of expenses for transporting crude oil or refined products and other macroeconomic factors. The FTS reviews tariff rates at least annually.
According to the Federal Statistics Service of the Russian Federation, from 2005 to 2006, tariffs for the transportation of crude oil by pipeline increased by 8%, tariffs for the transportation of refined products by pipeline increased by 4.1% and tariffs for the transportation of refined products by railway increased by 8.9%. These amounts differ from the actual increase in our transportation expenses because of differences between our specific transportation requirements (including, for example, transportation routes and the geography of our supplies) from the average of all companies using these state-owned transportation networks. Increases in transportation costs have affected, and possible future increases could further affect, our results of operations.
A substantial part of our revenues is either denominated in U.S. dollars or is correlated to some extent with U.S. dollar crude oil prices, while most of our costs in Russia are settled in rubles. Therefore, the relative movements of ruble inflation and ruble-U.S. dollar exchange rates can materially affect our results of operations. In particular, our operating margins are generally adversely affected by a real appreciation in the value of the ruble against the U.S. dollar because this generally causes the U.S. dollar value of our costs to increase. In recent years, with the exception of 2005, a nominal increase in the value of the ruble against the dollar magnified the effects of inflation of the ruble. This trend has continued in 2007. The following table sets out data on inflation in Russia, the nominal change in the value of the ruble against the dollar, and the level of real appreciation in each of the years ended 31 December 2004, 2005 and 2006.
| Year ended 31 December 11311111111111111 |
||||
|---|---|---|---|---|
| 2006 11111 |
2005 11111 |
2004 11111 |
||
| Inflation (CPI) | 9.1% | 10.9% | 11.7% | |
| Nominal appreciation/(devaluation) (RUR v. \$) | 8.5% | (3.7)% | 5.8% | |
| Real appreciation (RUR v. \$)1 | 19.3% | 6.9% | 18.5% | |
| Exchange rate at the end of the period (rubles per \$1.00) | 26.33 | 28.78 | 27.75 |
Note:
(1) Devaluation of the purchasing power of the U.S. dollar in Russia calculated on the basis of ruble-dollar exchange rates and inflation rates in Russia.
We are subject to a broad range of taxes imposed at the federal, regional and local levels, and we are one of the largest sources of tax revenue to the federal authorities, as well as to the regional and local authorities in those regions and localities in which we operate. The taxes to which we are subject have had a significant effect on our results of operations. Given the relative size of our activities in Russia compared to our international operations, our tax profile is largely determined by the taxes payable in Russia, which are based on records maintained under Russian tax legislation. In each of the years ended 31 December 2004, 2005 and 2006, our Russian tax liability accounted for more than 80% of our total taxes recorded in our financial statements. In addition to income taxes, we are subject to a number of other taxes in Russia, many of which are based on revenue or volumetric measures. These taxes include the mineral extraction tax, excise and export tariffs, property tax, social tax, value-added tax and other local and regional taxes. Our effective tax rate (including income taxes, taxes other than on income and excise and export tariffs) was 77% in 2006, 74% in 2005 and 71% 2004. In 2006, tax expenses in Russia were about 55% of the domestic sales revenue of Russian companies of the Group and export sales.
The tax system in Russia is subject to frequent change and inconsistent enforcement at the federal, regional and local levels. The existing Russian tax legislation has been in force for a short period of time relative to tax laws in more developed market economies. The government's implementation of existing tax laws is often unclear or inconsistent. The Russian tax system has recently been revised. The new tax system is intended to reduce the number of taxes and to simplify the tax laws. However, the revised tax system still relies heavily on the judgments of local tax officials (who may exercise their discretion arbitrarily) and fails to address many of the existing problems, and local tax officials have recently made several material tax claims against major Russian companies. See "Risk Factors – The Russian tax system imposes substantial burdens on us and is subject to frequent change and significant uncertainty".
The following table sets out the average enacted rates for taxes specific to the oil industry in Russia for each of the years ended 31 December 2004, 2005 and 2006.
| 11111 | 20061 11111 |
% Change 11111 |
20051 11111 |
% Change 11111 |
20041 11111 |
|
|---|---|---|---|---|---|---|
| Export tariffs on crude oil | \$/tonne | 197.01 | 50.8% | 130.62 | 134.2% | 55.77 |
| Export tariffs on refined | ||||||
| products | ||||||
| Light distillates | ||||||
| (gasoline), middle | ||||||
| distillates (jet fuel), | ||||||
| diesel fuel and gasoils | \$/tonne | 143.40 | 55.4% | 92.26 | 143.2% | 37.93 |
| Liquid fuels (fuel oil) | \$/tonne | 77.27 | 46.5% | 52.73 | 43.9% | 36.64 |
| Excise on refined products | ||||||
| High-octane gasoline | RUR/tonne | 3,629.00 | – | 3,629.00 | 8.0% | 3,360.00 |
| Low-octane gasoline | RUR/tonne | 2,657.00 | – | 2,657.00 | 8.0% | 2,460.00 |
| Diesel fuel | RUR/tonne | 1,080.00 | – | 1,080.00 | 8.0% | 1,000.00 |
| Motor oils | RUR/tonne | 2,951.00 | – | 2,951.00 | 8.0% | 2,732.00 |
| Mineral extraction tax | ||||||
| Crude Oil | RUR/tonne | 2,265.69 | 20.8% | 1,876.26 | 78.2% | 1,052.76 |
| Natural Gas | RUR/1,000 m3 | 147.00 | 8.9% | 135.00 | 26.2% | 107.00 |
(1) Average values for 2006, 2005 and 2004
The following table sets out the average enacted rates for the ruble-denominated tariffs in the above table translated into U.S. dollars at the average exchange rates for each of the years ended 31 December 2004, 2005 and 2006.
| 11111 | 20061 11111 |
% Change 11111 |
20051 11111 |
% Change 11111 |
20041 11111 |
|
|---|---|---|---|---|---|---|
| Excise on refined products | ||||||
| High-octane gasoline | \$/tonne | 133.49 | 4.1% | 128.29 | 10.0% | 116.59 |
| Low-octane gasoline | \$/tonne | 97.74 | 4.1% | 93.93 | 10.0% | 85.36 |
| Diesel fuel | \$/tonne | 39.73 | 4.1% | 38.18 | 10.0% | 34.70 |
| Motor oils | \$/tonne | 108.55 | 4.1% | 104.33 | 10.0% | 94.80 |
| Mineral extraction tax | ||||||
| Crude Oil | \$/tonne | 83.34 | 25.7% | 66.32 | 81.5% | 36.53 |
| Natural Gas | \$/1,000 m3 | 5.41 | 13.4% | 4.77 | 28.6% | 3.71 |
Note:
(1) Average values for 2006, 2005 and 2004.
Tax rates specific to the oil industry in Russia increased significantly from 2005 to 2006, which was due primarily to the increase in the Urals blend crude oil price. See "Regulation – Current System of Oil-Related Taxes and Duties" for a further discussion of taxes related to our oil and gas operations.
The following is a discussion of our results of operations for the periods indicated. The table below sets out selected data from our consolidated statements of income for the years ended 31 December 2004, 2005 and 2006, and also as a percentage of total revenues.
| 111111111111111111111111111112111 2006 2005 2004 11111123111 11111123111 11111123111 \$ millions % \$ millions % \$ millions Revenues Sales (including excise and export tariffs) 67,684 99.4% 55,774 99.2% 33,845 Equity share in income of affiliates 425 0.6% 441 0.8% 213 1111 1111 1111 1111 1111 |
% 99.4% 0.6% |
|---|---|
| Total revenues 68,109 100.0% 56,215 100.0% 34,058 |
1111 100.0% |
| 1111 1111 1111 1111 1111 |
1111 |
| Costs and other deductions | |
| Operating expenses (4,657) (6.8)% (3,487) (6.2)% (2,880) Cost of purchased crude oil, petroleum and chemical |
(8.5)% |
| products (22,374) (32.9)% (19,398) (34.5)% (10,124) |
(29.7)% |
| Transportation expenses (3,863) (5.7)% (3,519) (6.3)% (2,784) |
(8.2)% |
| Selling, general and | |
| administrative expenses (2,885) (4.2)% (2,578) (4.6)% (2,024) |
(5.9)% |
| Depreciation, depletion and | |
| amortisation (1,851) (2.7)% (1,315) (2.3)% (1,075) |
(3.2)% |
| Taxes other than income taxes (8,075) (11.9)% (6,334) (11.3)% (3,505) |
(10.3)% |
| Excise and export tariffs (13,570) (19.9)% (9,931) (17.7)% (5,248) |
(15.4)% |
| Exploration expense (209) (0.3)% (317) (0.5)% (171) |
(0.5)% |
| (Loss) gain on disposals | |
| and impairments of assets (148) (0.2)% 52 0.1% (213) 1111 1111 1111 1111 1111 |
(0.6)% 1111 |
| Income from operating | |
| activities 10,477 15.4% 9,388 16.7% 6,034 1111 1111 1111 1111 1111 |
17.7% 1111 |
| Interest expense (302) (0.4)% (275) (0.5)% (300) |
(0.9)% |
| Interest and dividend income 111 0.2% 96 0.1% 180 |
0.5% |
| Currency translation gain (loss) 169 0.2% (134) (0.2)% 135 |
0.4% |
| Other non-operating (expense) | |
| income (118) (0.2)% (44) (0.1)% 21 |
0.1% |
| Minority interest (80) (0.1)% (121) (0.2)% (62) 1111 1111 1111 1111 1111 |
(0.2)% 1111 |
| Income before income taxes 10,257 15.1% 8,910 15.8% 6,008 1111 1111 1111 1111 1111 |
17.6% 1111 |
| Total income tax expense (2,773) (4.1)% (2,467) (4.4)% (1,760) 1111 1111 1111 1111 1111 |
(5.1)% 1111 |
| Net income 7,484 11.0% 6,443 11.4% 4,248 1111 1111 1111 1111 1111 1111 1111 1111 1111 1111 |
12.5% 1111 1111 |
The following table contains data from our consolidated statements of income for each of the years ended 31 December 2005 and 2006 and the percentage change between the periods. The material changes in our results of operations are discussed below.
| Year ended 31 December 11311111111111111 |
|||
|---|---|---|---|
| 2006 11111 |
2005 11111 |
% Change 11111 |
|
| (in millions of U.S. dollars) |
|||
| Revenues Sales (including excise and export tariffs) |
67,684 | 55,774 | 21.4% |
| Equity share in income of affiliates | 425 11111 |
441 11111 |
(3.6)% 11111 |
| Total revenues | 68,109 11111 |
56,215 11111 |
21.2% 11111 |
| Costs and other deductions | |||
| Operating expenses | (4,657) | (3,487) | 33.6% |
| Cost of purchased crude oil, petroleum and chemical products | (22,374) | (19,398) | 15.3% |
| Transportation expenses | (3,863) | (3,519) | 9.8% |
| Selling, general and administrative expenses | (2,885) | (2,578) | 11.9% |
| Depreciation, depletion and amortisation | (1,851) | (1,315) | 40.8% |
| Taxes other than income taxes | (8,075) | (6,334) | 27.5% |
| Excise and export tariffs | (13,570) | (9,931) | 36.6% |
| Exploration expense | (209) | (317) | (34.1)% |
| (Loss) gain on disposals and impairments of assets | (148) 11111 |
52 11111 |
– 11111 |
| Income from operating activities | 10,477 11111 |
9,388 11111 |
11.6% 11111 |
| Interest expense | (302) | (275) | 9.8% |
| Interest and dividend income | 111 | 96 | 15.6% |
| Currency translation gain (loss) | 169 | (134) | – |
| Other non-operating expense | (118) | (44) | 168.2% |
| Minority interest | (80) 11111 |
(121) 11111 |
(33.9)% 11111 |
| Income before income taxes | 10,257 11111 |
8,910 11111 |
15.1% 11111 |
| Current income taxes | (2,906) | (2,301) | 26.3% |
| Deferred income taxes | 133 11111 |
(166) 11111 |
– 11111 |
| Total income tax expense | (2,773) 11111 |
(2,467) 11111 |
12.4% 11111 |
| Net income | 7,484 11111 aaaaa |
6,443 11111 aaaaa |
16.2% 11111 aaaaa |
The following tables provide a breakdown of our sales by revenue and volume for each of the years ended 31 December 2005 and 2006.
| 2006 11111 |
2005 11111 |
% Change 11111 |
|
|---|---|---|---|
| (in millions of | |||
| U.S. dollars) | |||
| Crude Oil | |||
| International sales (excluding CIS) | 16,859 | 15,589 | 8.1% |
| International sales (CIS) | 790 | 778 | 1.5% |
| Domestic sales | 376 11111 |
120 11111 |
213.3% 11111 |
| Total crude oil sales | 18,025 11111 aaaaa |
16,487 11111 aaaaa |
9.3% 11111 aaaaa |
| Refined Products | |||
| International sales | |||
| Wholesale | 30,302 | 22,923 | 32.2% |
| Retail | 7,157 | 6,293 | 13.7% |
| Domestic sales | |||
| Wholesale | 5,431 | 4,753 | 14.3% |
| Retail | 2,720 11111 |
1,972 11111 |
37.9% 11111 |
| Total refined products sales | 45,610 11111 aaaaa |
35,941 11111 aaaaa |
26.9% 11111 aaaaa |
| Petrochemicals | |||
| International sales | 1,260 | 1,134 | 11.1% |
| Domestic sales | 569 11111 |
469 11111 |
21.3% 11111 |
| Total petrochemicals sales | 1,829 11111 |
1,603 11111 |
14.1% 11111 |
| Other sales | 2,220 11111 |
1,743 11111 |
27.4% 11111 |
| Total sales revenues | 67,684 11111 aaaaa |
55,774 11111 aaaaa |
21.4% 11111 aaaaa |
| Sales Volumes | 2006 | 2005 | % Change |
| 11111 | 11111 | 11111 | |
| Crude Oil (in thousands of barrels) International sales (excluding CIS) |
278,972 | 312,712 | (10.8)% |
| International sales (CIS) | 21,682 | 23,852 | (9.1)% |
| Domestic sales | 13,363 11111 |
4,926 11111 |
171.3% 11111 |
| Total crude oil sales | 314,017 11111 |
341,490 11111 |
(8.0)% 11111 |
| Crude Oil (in thousands of tonnes) | aaaaa | aaaaa | aaaaa |
| International sales (excluding CIS) | 38,059 | 42,662 | (10.8%) |
| International sales (CIS) | 2,958 | 3,254 | (9.1)% |
| Domestic sales | 1,823 11111 |
672 11111 |
171.3% 11111 |
| 42,840 11111 aaaaa |
46,588 11111 aaaaa |
(8.0)% 11111 aaaaa |
|
| Refined Products (in thousands of tonnes) | |||
| International sales | |||
| Wholesale | 57,558 | 49,549 | 16.2% |
| Retail | 7,171 | 7,117 | 0.8% |
| Domestic sales | |||
| Wholesale | 15,155 | 16,421 | (7.7)% |
| Retail | 3,995 11111 |
3,549 11111 |
12.6% 11111 |
| 83,879 11111 aaaaa |
76,636 11111 aaaaa |
9.5% 11111 aaaaa |
The 21.4% increase in our sales revenues from 2005 to 2006 was due primarily to increases in our crude oil and refined product production volumes, crude oil and refined product prices, an increase in refining margins and our marketing and trading activities. See "– Main Factors Affecting Our Results of Operations – International Crude Oil and Refined Products Prices" for further discussion of factors affecting crude oil and refined product prices. A more detailed discussion of our crude oil and refined products sales follows.
The 9.3% increase in our total crude oil sales from 2005 to 2006 was attributable primarily to increases in our international crude oil sales revenues. Our international crude oil sales revenue, which accounted for approximately 97.9% of our total crude oil sales revenue in 2006 and 99.3% in 2005, increased by 7.8% from 2005 to 2006, primarily due to an increase in international crude oil prices. From 2005 to 2006, our average realised prices for our international sales outside of the CIS increased by 21.2% and our average realised prices for our international sales in the CIS increased by 11.7%. The effect of the increase in prices was partially offset by decreases in the volume of our international sales outside the CIS of 10.8% and in the CIS of 9.1%. We decreased the volume of crude oil exported from Russia by 3.7% from 2005 to 2006 in order to take advantage of increased international and domestic refined products prices and due to increases in crude oil export tariffs, compared to refined products export tariffs.
Sales of refined products constituted 67.3% of our total revenues (and 66.3% in terms of sales volume) in 2006, compared to 64.4% (and 62.2% in terms of sales volume) in 2005. Our domestic refined product sales in 2006 constituted 15.2% of total sales volume (compared to 16.2% in 2005), but represented 12% of our total revenues in 2006 (which is the same percentage as in 2005). The decrease in our domestic refined products sales as a percentage of total refined products sales was due to the expansion of our trading activities outside Russia.
The 26.9% increase in our total refined products sales resulted primarily from increases in our refined product sales volumes and realised prices. Our international refined products sales accounted for 82.1% of our total refined products sales in 2006, compared to 81.3% in 2005. In terms of volume, our international refined products sales increased by 14.2% from 2005 compared to 2006. Our international refined products wholesales revenues, which accounted for approximately 80.9% of our total international refined products sales revenues, increased by 32.2% from 2005 to 2006 primarily as a result of increases in both sales volumes and prices. Our average realised prices for our international refined products wholesales increased by 13.8% from 2005 to 2006. Our international wholesales volumes increased by 16.2% from 2005 to 2006 primarily as a result of an increase in our refined products trading activities outside of and exports from Russia. The 13.7% increase in our international refined products retail sales revenues were attributable primarily to a 12.9% increase in our average realised prices for our international refined product retail sales. Our international retail sales include supplies of refined products to third party retail networks under long-term contracts, with pricing similar to retail pricing.
Domestically, our refined products wholesales revenues increased by 14.3% from 2005 to 2006. The increase was primarily due to a 23.8% increase in the average realised price for our domestic refined products wholesales, which was partially offset by a 7.7% decrease in our domestic refined products sales volume. The decrease in our domestic refined products wholesale volume is attributable to an increase in retail sales and exports of refined products from Russia. Our domestic refined product retail sales revenues increased by 37.9% from 2005 to 2006 due primarily to a 12.6% increase in our retail sales volumes for refined products from 2005 to 2006 and a 22.5% increase in average retail prices for refined products.
Other sales include revenues from sales of gas and sales of other goods and services unrelated to our core activities (such as electricity and heat) sold by our production and marketing companies. Other sales revenues increased by 27.4% from 2005 to 2006, generally as a result of an increase in our natural gas sales. Sales of natural gas amounted to \$230 million in 2006, compared to \$41 million in 2005. Gazprom is our major purchaser of natural gas produced in Russia. In 2006, we sold 7.5 bcm to Gazprom at an average realised price of \$23.6 per mcm. See "Business – Exploration and Production – Domestic Exploration and Production – Western Siberia Operations" for more details on our agreements with Gazprom.
The following table provides a breakdown of our operating expenses for each of the years ended 31 December 2005 and 2006.
| Year ended 31 December 11311111111111111 |
||||
|---|---|---|---|---|
| 2006 11111 |
2005 11111 |
% Change 11111 |
||
| (in millions of U.S. dollars) |
||||
| Hydrocarbon extraction expenses | 2,312 | 1,764 | 31.1% | |
| Refining expenses | 730 | 644 | 13.4% | |
| Petrochemical expenses | 247 | 214 | 15.4% | |
| Other operating expenses | 1,782 11111 |
1,275 11111 |
39.8% 11111 |
|
| 5,071 | 3,897 | 30.1% | ||
| Change in operating expenses in crude oil and refined products | ||||
| inventory originated within the Group | (414) 11111 |
(410) 11111 |
(1.0)% 11111 |
|
| Total operating expenses | 4,657 11111 aaaaa |
3,487 11111 aaaaa |
33.6% 11111 aaaaa |
Our hydrocarbon extraction expenses include expenditures related to repairs of extraction equipment, labour costs, expenses for the artificial stimulation of reservoirs, fuel and electricity costs, property insurance of extraction equipment and other similar costs. The expenses of our oil and gas production enterprises related to the sale of services and goods (such as electricity, heat, etc.) that do not relate to core activities have been excluded from our hydrocarbon extraction expenses and are included in other operating costs. The 31.1% increase in our hydrocarbon extraction expenses resulted from increases in hydrocarbon production and in our average extraction cost per barrel. Our hydrocarbon production increased by 13.3% from 2005 to 2006. Our average extraction cost per barrel increased from \$2.66 in 2005 to \$3.08 in 2006, resulting from a 19.3% real appreciation of the ruble against the U.S. dollar during 2006 and increased expenses related to the artificial stimulation of reservoirs and expenses for power supply and materials. In 2006, our extraction expenses included \$95 million of expenses related to crude oil producing companies acquired in late 2005 and in 2006.
The 13.4% increase in our refining expenses resulted from the real appreciation of the ruble against the U.S. dollar, increased production in our domestic refineries and the increase in our production of higher quality refined products (which resulted in increased costs) at our Burgas refinery in Bulgaria. These factors were partly offset by the reduction of refining expenses at our Odessa refinery in Ukraine, which was closed in July 2005 for a largescale reconstruction programme.
The 15.4% increase in our operating expenses from our petrochemical companies resulted from an increased in the cost of raw materials and power supply and maintenance activities performed at our Russian petrochemical plants in the second quarter of 2006.
Other operating expenses include operating expenses of our gas processing plants, the costs of other services provided and goods not related to our core activities (such as electricity, heat, etc.) sold by our production and marketing companies and operating expenses of other non-core businesses of the Group. Other operating expenses also include transportation costs associated with the delivery of crude oil from our exploration and production entities to our refineries and processing fees paid to third party refineries. The 39.8% increase in our other operating expenses from 2005 to 2006 was due to increased volumes of crude oil that we refined at third party refineries, increased purchases of gas and gas refined products from third parties and other services provided.
We purchase crude oil both in Russia and in international markets to be processed at some of our refineries and in connection with our trading activities. We purchase refined products for distribution through some of our international retail filling stations (including through our retail network in the United States), for resale through our wholesale channels (including in connection with our bunkering activities in Europe and Asia) and in connection with our trading activities. The following table provides a breakdown of the costs of our crude oil, refined products and chemicals purchases for each of the years ended 31 December 2005 and 2006.
| Year ended 31 December 11311111111111111 |
|||
|---|---|---|---|
| 2006 11111 |
2005 11111 |
||
| 11111 (in millions of U.S. dollars) |
|||
| Crude oil | 2,538 | 3,902 | (35.0)% |
| Petroleum and chemical products | 19,836 11111 |
15,496 11111 |
28.0% 11111 |
| Total cost of purchased crude oil, petroleum and chemical products | 22,374 11111 qqqqq |
19,398 11111 qqqqq |
15.3% 11111 qqqqq |
The 15.3% increase in our total purchases of crude oil, petroleum and chemical products from 2005 to 2006 was attributable to an increase in our refined products purchases (in terms of volume) and an increase in market prices for both crude oil and refined products. At the same time, our cost of purchased crude oil decreased by 35% primarily due to decreased volumes resulting from the shutdown of our Odessa refinery in July 2005 for a largescale reconstruction programme. Our cost of purchased crude oil and refined products also includes the result of our hedging of international crude oil and refined products sales. We recognised a \$183 million gain on hedging in 2006, compared to a loss of \$171 million in 2005.
The 9.8% increase in our transportation expenses from 2005 to 2006 resulted both from an increase in our sales and an increase in transportation tariffs. See "– Main Factors Affecting our Results of Operations – Transportation Costs" for more information about recent trends in our transportation expenses.
Our selling, general and administrative expenses include general business expenses, payroll costs (excluding payroll costs for our extraction and refining subsidiaries), insurance costs (except for property insurance related to oil and gas and refinery equipment), costs of maintaining social infrastructure, provisions for bad debts and other expenses. The 11.9% increase in our selling, general and administrative expenses from 2005 to 2006 resulted primarily from a 19.3% real appreciation of the ruble against the U.S. dollar in 2006 and the general expansion of our operations outside of Russia. In addition, we accrued expenses of \$280 million in 2006 for compensation of our management in connection with the adoption of a share option program, compared to \$263 million in 2005. Selling, general and administrative expenses for 2006 also included \$87 million of expenses related to subsidiaries which we acquired in late 2005 and in 2006.
Depreciation, depletion and amortisation expenses include depletion of assets fundamental to production, depreciation of other productive and non-productive assets and certain intangible assets. The 40.8% increase in our depreciation, depletion and amortisation expenses from 2005 to 2006 resulted primarily from our capital expenditures and the corresponding increase in depreciable assets. In addition, the increase in our depreciation, depletion and amortisation expenses included \$198 million of expenses related to our acquisitions in late 2005 and in 2006.
The 27.5% increase in our taxes other than income taxes from 2005 to 2006 resulted primarily from a \$1,691 million increase in mineral extraction taxes, which are linked to international crude oil prices. Other taxes for 2005 included a \$150 million provision accrued in relation to the results of tax audits of our Group companies for periods prior to the 2004 financial year.
The following table sets out a breakdown of our taxes other than income taxes.
| Year ended 31 December 1111111111111111111111123111 |
||||||
|---|---|---|---|---|---|---|
| 2006 11111111112311 |
2005 11111111112311 |
|||||
| In Russia 111121 |
International 111121 |
In Russia 111121 |
International 111121 |
|||
| (in millions of U.S. dollars) | ||||||
| Mineral extraction taxes | 7,281 | – | 5,590 | – | ||
| Social security taxes and contributions | 309 | 47 | 284 | 40 | ||
| Property tax | 219 | 28 | 210 | 23 | ||
| Other taxes | 160 111121 |
31 111121 |
162 111121 |
25 111121 |
||
| 7,969 111121 |
106 111121 |
6,246 111121 |
88 111121 |
|||
| Total | 8,075 111121 aaaaas |
6,334 111121 aaaaas |
The 36.6% increase in our excise and export tariffs from 2005 to 2006 resulted primarily from an increase in export tariff rates. The Russian government sets export tariff rates for two-month periods. The rates in a specific two-month period are based on Urals blend international market prices in the immediately preceding two months. Thus, the calculation method that the Russian government employees to determine export tariff rates results in a two-month gap between movements in crude oil prices and the revision of the export duty rate based on those crude oil prices. Because oil prices declined in the fourth quarter of 2006, we paid export tariff rates based on prices higher than existing market prices. This resulted in a reduction in our income before income tax of approximately \$0.4 billion.
| Year ended 31 December 1111111111111111111111123111 |
||||
|---|---|---|---|---|
| 2006 11111111112311 |
2005 11111111112311 |
|||
| In Russia 111121 |
International 111121 |
In Russia 111121 |
International 111121 |
|
| (in millions of U.S. dollars) | ||||
| Excise tax and sales taxes on refined products | 610 | 2,835 | 654 | 2,679 |
| Export tariffs | 10,114 111121 |
11 111121 |
6,590 111121 |
8 111121 |
| 10,724 111121 |
2,846 111121 |
7,244 111121 |
2,687 111121 |
|
| Total | 13,570 111121 aaaaas |
9,931 111121 aaaaas |
Our exploration expenses decreased by 34.1% from 2005 to 2006. In 2006, dry hole costs amounted to \$91 million, primarily related to our international exploration projects in Egypt (\$12 million) and exploration activities in the Komi Republic and Timan-Pechora (\$53 million). Geological and geophysical costs charged to exploration expense in 2006 were incurred primarily in Russia and Uzbekistan (\$78 million and \$12 million, respectively). In 2005, dry hole costs amounted to \$170 million, of which \$105 million was attributable to the first exploratory wells of the Yalama (D-222) and Tyub-Karagan exploration projects (located in Azerbaijan and Kazakhstan, respectively), which were dry.
Loss on disposals and impairments of assets in 2006 amounted to \$148 million compared to a \$52 million gain in 2005. The losses in 2006 resulted in part from disposals of non-core assets and individually insignificant impairments of non-performing business units. Our 2006 losses also included a \$68 million impairment of unproved property in Azerbaijan. In 2005, we recognised a gain of \$152 million on the sale of our 30% interest in NMNG to ConocoPhillips, a gain of \$4 million on the sale of our 38% interest in Globalstroy-Engineering and a gain of \$25 million on the sale of our interest in Arktikneft.
The 9.8% increase in interest expense from 2005 to 2006 was primarily due to debt service related to our \$1,934 million loan to finance the acquisition of Nelson Resources and a general increase in our indebtedness. Moreover, in the second quarter of 2006, we and ConocoPhillips reached an agreement to amend the contractual interest rates related to the financing of our joint venture, NMNG, from 0.1% to a range of 6.8% to 8.2% per annum.
The 12.4% increase in our total income tax expense resulted primarily from the increase in our taxable income. Our effective tax rate in 2006 was 27.0% compared to 27.7% in 2005, which is higher than the maximum statutory rate in Russia of 24% due to the fact that some of our costs are not deductible or are only deductible to a limited extent.
The following table contains data from our consolidated statements of income for each of the years ended 31 December 2004 and 2005, as well as the percentage change between the periods. The material changes in our results of operations are discussed below.
| Year ended 31 December 11311111111111111 |
|||
|---|---|---|---|
| 2005 11111 |
2004 11111 |
% Change 11111 |
|
| (in millions of U.S. dollars) |
|||
| Revenues Sales (including excise and export tariffs) Equity share in income of affiliates |
55,774 441 11111 |
33,845 213 11111 |
64.8% 107.0% 11111 |
| Total revenues | 56,215 11111 aaaaa |
34,058 11111 aaaaa |
65.1% 11111 aaaaa |
| Costs and other deductions | |||
| Operating expenses | (3,487) | (2,880) | 21.1% |
| Cost of purchased crude oil, petroleum and chemical products | (19,398) | (10,124) | 91.6% |
| Transportation expenses | (3,519) | (2,784) | 26.4% |
| Selling, general and administrative expenses | (2,578) | (2,024) | 27.4% |
| Depreciation, depletion and amortisation | (1,315) | (1,075) | 22.3% |
| Taxes other than income taxes | (6,334) | (3,505) | 80.7% |
| Excise and export tariffs | (9,931) | (5,248) | 89.2% |
| Exploration expense | (317) | (171) | 85.4% |
| Gain (loss) on disposals and impairments of assets | 52 11111 |
(213) 11111 |
– 11111 |
| Income from operating activities | 9,388 11111 aaaaa |
6,034 11111 aaaaa |
55.6% 11111 aaaaa |
| Interest expense | (275) | (300) | (8.3)% |
| Interest and dividend income | 96 | 180 | (46.7)% |
| Currency translation (loss) gain | (134) | 135 | – |
| Other non-operating (expense) income | (44) | 21 | – |
| Minority interest | (121) 11111 |
(62) 11111 |
95.2% 11111 |
| Income before income taxes | 8,910 11111 aaaaa |
6,008 11111 aaaaa |
48.3% 11111 aaaaa |
| Current income taxes | (2,301) | (1,614) | 42.6% |
| Deferred income taxes | (166) 11111 |
(146) 11111 |
13.7% 11111 |
| Total income tax expense | (2,467) 11111 aaaaa |
(1,760) 11111 aaaaa |
40.2% 11111 aaaaa |
| Net income | 6,443 11111 aaaaa |
4,248 11111 aaaaa |
51.7% 11111 aaaaa |
The following tables provide a breakdown of our sales by revenue and volume for each of the years ended 31 December 2005 and 2004.
| 2005 11111 |
2004 11111 |
% Change 11111 |
||
|---|---|---|---|---|
| (in millions of U.S. dollars) |
||||
| Crude Oil | ||||
| International sales (excluding CIS) | 15,589 | 10,338 | 50.8% | |
| International sales (CIS) | 778 | 602 | 29.2% | |
| Domestic sales | 120 11111 |
181 11111 |
(33.7)% 11111 |
|
| Total crude oil sales | 16,487 11111 aaaaa |
11,121 11111 aaaaa |
48.3% 11111 aaaaa |
|
| Refined Products | ||||
| International sales | ||||
| Wholesale | 22,923 | 11,403 | 101.0% | |
| Retail | 6,293 | 3,914 | 60.8% | |
| Domestic sales | ||||
| Wholesale | 4,753 | 3,429 | 38.6% | |
| Retail | 1,972 11111 |
1,236 11111 |
59.5% 11111 |
|
| Total refined products sales | 35,941 11111 aaaaa |
19,982 11111 aaaaa |
79.9% 11111 aaaaa |
|
| Petrochemicals | ||||
| International sales | 1,134 | 1,021 | 11.1% | |
| Domestic sales | 469 11111 |
332 11111 |
41.3% 11111 |
|
| Total petrochemicals sales | 1,603 11111 |
1,353 11111 |
18.5% 11111 |
|
| Other sales | 1,743 11111 |
1,389 11111 |
25.5% 11111 |
|
| Total sales revenues | 55,774 11111 aaaaa |
33,845 11111 aaaaa |
64.8% 11111 aaaaa |
|
| Sales Volumes | ||||
| 2005 11111 |
2004 11111 |
% Change 11111 |
||
| Crude Oil (in thousands of barrels) | ||||
| International sales (excluding CIS) | 312,712 | 307,523 | 1.7% | |
| International sales (CIS) | 23,852 | 29,877 | (20.2)% | |
| Domestic sales | 4,926 11111 |
11,999 11111 |
(58.9)% 11111 |
|
| Total crude oil sales | 341,490 11111 aaaaa |
349,399 11111 aaaaa |
(2.3)% 11111 aaaaa |
|
| Crude Oil (in thousands of tonnes) | ||||
| International sales (excluding CIS) | 42,662 | 41,954 | 1.7% | |
| International sales (CIS) | 3,254 | 4,076 | (20.2)% | |
| Domestic sales | 672 11111 |
1,637 11111 |
(58.9)% 11111 |
|
| 46,588 11111 aaaaa |
47,667 11111 aaaaa |
(2.3)% 11111 aaaaa |
||
| Refined Products (in thousands of tonnes) | ||||
| International sales | ||||
| Wholesale | 49,549 | 35,946 | 37.8% | |
| Retail | 7,117 | 5,480 | 29.9% | |
| Domestic sales | ||||
| Wholesale | 16,421 | 16,981 | (3.3)% | |
| Retail | 3,549 11111 |
2,743 11111 |
29.4% 11111 |
|
| 76,636 11111 |
61,150 11111 |
25.3% 11111 |
||
| Total crude oil and refined products sales (in thousands of tonnes) | 123,224 11111 aaaaa |
108,817 11111 aaaaa |
13.2% 11111 aaaaa |
The 64.8% increase in our sales revenues from 2004 to 2005 was due primarily to increases in our crude oil and refined product production volumes, prices and our marketing activities. See "– Main Factors Affecting Our Results of Operations – International Crude Oil and Refined Products Prices" for further discussion of factors affecting the price of crude oil price. A more detailed discussion of our crude oil and refined products sales follows.
The 48.3% increase in our total crude oil sales from 2004 to 2005 were attributable primarily to a 49.6% increase in our international crude oil sales revenues. Our international crude oil sales revenues, which accounted for approximately 99.3% of our total crude oil sales revenues in 2005 and 98.4% in 2004, increased primarily due to an increase in international crude oil prices. From 2004 to 2005, our average realised prices for our international sales outside of the CIS increased by 48.3% and our average realised prices for our international sales in the CIS increased by 62.1%. Our domestic crude oil sales revenues decreased by 33.7% from 2004 to 2005, which is attributable primarily to a 58.9% decrease in our domestic crude oil sales volumes, which was partially offset by a 62% increase in our average realised domestic crude oil sales prices.
Sales of refined products constituted 64.4% of our total revenues (and 62.2% in terms of sales volume) in 2005, compared to 59.1% (and 56.2% in terms of sales volume) in 2004. Our domestic refined product sales in 2005 constituted 16.2% of total sales volume (compared to 18.1% in 2004), but represented 12% of our total revenues in 2005 (compared to 13.8% in 2004). The decrease in our domestic refined products sales as a percentage of total refined products sales was due to a significant expansion in our trading activities outside Russia.
The 79.9% increase in our total refined products sales resulted from increases in our international refined product sales volumes and both international and domestic realised prices. In terms of volume, our international refined products sales increased by 36.8% from 2004 to 2005.
Our international refined products wholesales revenues, which accounted for approximately 78.5% of our total international refined products sales revenues, increased by 101% from 2004 to 2005 primarily as a result of increases in both sales volumes and prices. Our average realised prices for our international refined products wholesales increased by 45.8% from 2004 to 2005. Our international wholesales volumes increased by 37.8% from 2004 to 2005 primarily as a result of an increase in our marketing activities outside of Russia. The 60.8% increase in our international refined products retail sales revenues from 2004 to 2005 were attributable primarily to a 29.9% increase in our international refined product retail sales volume and a 23.8% increase in average realised prices. The increase in our international sales volumes was attributable to the continuing development of our retail filling station network outside of Russia. We acquired 308 retail filling stations from ConocoPhillips in May 2004 and agreed to supply an additional 471 retail filling stations in the northeastern United States. We also acquired Teboil and Suomen Petrooli in March 2005, which had 289 retail filling stations and 132 retail diesel fuel outlets at the time of our acquisition.
Domestically, our refined products wholesales revenues increased by 38.6% from 2004 to 2005. The increase was primarily due to a 43.3% increase in average realised domestic refined product wholesale prices, which was partially offset by a 3.3% decrease in our domestic refined products wholesale volume. The decrease in our domestic refined products wholesale volume is attributable to an increase in retail sales and exports of refined products from Russia. Our domestic refined product retail sales revenues increased by 59.5% from 2004 to 2005 due primarily to a 29.4% increase in our retail sales volumes for refined products and a 23.3% increase in average retail prices for refined products.
Other sales include revenues from sales of gas, gas refined products and sales of goods and services unrelated to our core activities (such as electricity and heat) sold by our production and marketing companies. Other sales increased by 25.5% from 2004 to 2005 primarily due to increased activity in providing other services to third parties.
The 107% increase in our share in the income of affiliates from 2004 to 2005 was due primarily to a general increase in the profitability of our crude oil production affiliates, including in particular an increase in the net income of ZAO Turgai-Petroleum, an affiliated company of which we own 50%, which is developing the Kumkol field in Kazakhstan. Our share in the net income of Turgai-Petroleum in 2005 was \$198 million, an increase of \$153 million from 2004.
The following table provides a breakdown of our operating expenses for each of the years ended 31 December 2005 and 2004.
| Year ended 31 December 11311111111111111 |
|||||
|---|---|---|---|---|---|
| 2005 11111 |
2004 11111 |
||||
| % Change 11111 (in millions of U.S. dollars) |
|||||
| Hydrocarbon extraction expenses | 1,764 | 1,556 | 13.4% | ||
| Refining expenses | 644 | 532 | 21.1% | ||
| Petrochemical expenses | 214 | 207 | 3.4% | ||
| Other operating expenses | 865 11111 |
585 11111 |
47.9% 11111 |
||
| Total operating expenses | 3,487 11111 aaaaa |
2,880 11111 aaaaa |
21.1% 11111 aaaaa |
The 13.4% increase in our hydrocarbon extraction expenses resulted from increases in our hydrocarbon production and in our average extraction cost per barrel. Our hydrocarbon production increased by 4.9% from 2004 to 2005. Our average extraction cost per barrel increased from \$2.46 during 2004 to \$2.66 during 2005, resulting from a 6.9% real appreciation of the ruble against the U.S. dollar during 2005 and increased expenses related to repairs, overhaul and the artificial stimulation of reservoirs. The impact of these factors was partially mitigated, however, by an increase in average well production from 10.7 tonnes per day in 2004 to 11.07 tonnes per day in 2005.
The 21.1% increase in our refining expenses resulted from the real appreciation of the ruble against the U.S. dollar, increased production in our domestic refineries, increased production of higher quality refined products (which resulted in increased costs) in our domestic refineries (including diesel fuel that complies with European Union requirements that took effect in 2005), restarting operations at our Petrotel refinery in Romania and increased heating and power costs at our Burgas refinery in Bulgaria.
The 47.9% increase in our other operating expenses was due primarily to increased volumes of crude oil that we refined at third party refineries, an increase in sales volume of other products (primarily gas refined products), and as a result of a change in our crude oil and refined product inventory originated within the Group in the fourth quarter of 2005.
We purchase crude oil both in Russia and in international markets to be processed at some of our refineries and in connection with our trading activities. We purchase refined products for distribution through some of our international retail filling stations (including through our retail network in the United States), for resale through our wholesale channels (including in connection with our bunkering activities in Europe and Asia) and in connection with our trading activities. The following table provides a breakdown of the costs of our crude oil, refined products and chemicals purchases for each of the years ended 31 December 2005 and 2004.
| Year ended 31 December 11311111111111111 |
||||||
|---|---|---|---|---|---|---|
| 2005 2004 11111 11111 |
% Change 11111 |
|||||
| (in millions of U.S. dollars) |
||||||
| Crude oil | 3,902 | 2,577 | 51.4% | |||
| Petroleum and chemical products | 15,496 11111 |
7,547 11111 |
105.3% 11111 |
|||
| Total cost of purchased crude oil, petroleum and chemical products | 19,398 11111 aaaaa |
10,124 11111 aaaaa |
91.6% 11111 aaaaa |
The 91.6% increase in our total purchases of crude oil, petroleum and chemical products from 2004 to 2005 was attributable to a significant increase in our crude oil and refined products purchases (in terms of volume) and an increase in market prices for both crude oil and refined products.
The 26.4% increase in our transportation expenses from 2004 to 2005 resulted both from an increase in our sales and an increase in transportation tariffs.
Our selling, general and administrative expenses include general business expenses, payroll costs (excluding payroll costs for our extraction and refining subsidiaries), insurance costs (except for property insurance related to oil and gas and refinery equipment), costs of maintaining social infrastructure, provisions for bad debts and other expenses. The 27.4% increase in our selling, general and administrative expenses from 2004 to 2005 resulted primarily from the general expansion of our operations outside of Russia and the 6.9% real appreciation of the ruble compared to the U.S. dollar. In addition, we accrued expenses of \$263 million in 2005 for compensation of our management in connection with the adoption of a share option program, compared to \$65 million in 2004. Selling, general and administrative expenses for 2005 also included \$66 million of expenses of Teboil and Suomen Petrooli, which we acquired in March 2005, and \$20 million of expenses of Nelson Resources acquired in the fourth quarter of 2005.
Depreciation, depletion and amortisation expenses include depletion of assets fundamental to production, depreciation of other productive and non-productive assets and certain intangible assets. The 22.3% increase in our depreciation, depletion and amortisation expenses was a result of our capital expenditures and the corresponding increase in depreciable assets and \$41 million of depreciation, depletion and amortisation expenses related to Nelson Resources, which we acquired in 2005.
The 80.7% increase in our taxes other than income taxes from 2004 to 2005 resulted primarily from a \$2,619 million increase in mineral extraction taxes, which are linked to international crude oil prices. Property tax in Russia also increased in 2005, primarily due to the recalculation of domestic property tax related to 2002 and 2003. Other taxes for 2005 included \$150 million of expenses related to the results of tax audits of our Group companies for periods prior to the 2004 financial year.
The following table sets out a breakdown of our taxes other than income taxes.
| Year ended 31 December 1111111111111111111111123111 |
|||||||
|---|---|---|---|---|---|---|---|
| 2005 11111111112311 |
2004 11111111112311 |
||||||
| In Russia 111121 |
International 111121 |
In Russia 111121 |
International 111121 |
||||
| (in millions of U.S. dollars) | |||||||
| Mineral extraction taxes | 5,590 | – | 2,971 | – | |||
| Social security taxes and contributions | 284 | 40 | 302 | 28 | |||
| Property tax | 210 | 23 | 91 | 20 | |||
| Other taxes | 162 111121 |
25 111121 |
60 111121 |
33 111121 |
|||
| 6,246 111121 |
88 111121 |
3,424 111121 |
81 111121 |
||||
| Total | 6,334 111121 aaaaas |
3,505 111121 aaaaas |
The 89.2% increase in our excise and export tariffs from 2004 to 2005 resulted primarily from an increase in export tariff rates and an increase in international excise taxes, which, in turn, resulted from an increase in the volumes of products sold across our international group, primarily in the United States, and due to the commencement of our operations in Finland.
The following table sets out a breakdown of our excise and export tariffs.
| 1111111111111111111111123111 | |||||
|---|---|---|---|---|---|
| 2005 | 2004 11111111112311 |
||||
| In Russia 111121 |
International 111121 |
In Russia 111121 |
International 111121 |
||
| 654 | 2,679 | 547 | 1,774 | ||
| 6,590 | 8 | 2,913 | 14 111121 |
||
| 7,244 | 2,687 | 3,460 | 1,788 111121 |
||
| 9,931 111121 |
5,248 111121 aaaaas |
||||
| 111121 111121 |
11111111112311 111121 111121 aaaaas |
Year ended 31 December (in millions of U.S. dollars) 111121 111121 |
Our exploration expenses increased by 85.4% from 2004 to 2005, which is attributable to the fact that, during 2005, we completed drilling the first two exploratory wells of the Yalama (D-222) and Tyub-Karagan exploration projects, both of which were dry. As a result, the \$105 million of costs related to the two wells was charged as exploration expense.
We recognised a gain on disposals of assets in 2005 of \$52 million, compared to a \$213 million loss in 2004. In 2005, we recognised a \$152 million gain on the sale of our 30% interest in NMNG to ConocoPhillips, a gain of \$4 million on the sale of our 38% interest in Globalstroy-Engineering and a gain of \$25 million on the sale of our interest in Arktikneft. In 2005, we also recognised an additional \$12 million impairment loss related to the sale of our ownership interests in Bank Petrocommerce. In 2004 we recognised an impairment loss in relation to the disposal of our ownership interests in Bank Petrocommerce in the amount of \$35 million and an impairment loss of \$70 million in relation to the disposal of our ownership interest in LUKOIL-Burenie. Other losses relate to disposals of a number of non-core assets and individually insignificant impairments on non-performing business units.
The 8.3% decrease in interest expense from 2004 to 2005 was primarily due to the sale of our ownership interest in Bank Petrocommerce in the third quarter of 2004, which was partially offset by in the fourth quarter of 2005 by accrued interest expense related to our \$1,934 million loan for the acquisition of Nelson Resources.
The 40.2% increase in our total income tax expense resulted primarily from the increase in our taxable income. Our effective tax rate in 2005 was 27.7% compared to 29.3% in 2004, which is higher than the maximum statutory rate in Russia of 24%, due to the fact that some of our costs are not deductible or are only deductible to a limited extent.
Our primary cash requirements include financing our planned capital expenditures, servicing our indebtedness, and general working capital needs. Our primary sources of liquidity are available cash reserves, cash from operations and debt financing. Historically, our cash and available credit lines have been sufficient to finance our cash requirements. As at 31 December 2006, we had cash and cash equivalents of \$752 million and working capital of \$6,641 million. We believe that, having regard to our liquidity reserves, including available credit facilities, our working capital will be sufficient for our present requirements. The table below summarises our statements of cash flows for each of the years ended 31 December 2004, 2005 and 2006.
| Year ended 31 December 11311111111111111 |
||||
|---|---|---|---|---|
| 2006 11111 |
2005 11111 |
2004 11111 |
||
| (in millions of U.S. dollars) | ||||
| Net cash provided by operating activities | 7,639 | 6,097 | 4,180 | |
| Net cash used in investing activities | (7,515) | (6,225) | (3,741) | |
| Net cash (used in) provided by financing activities | (1,059) | 539 | (650) |
Our primary source of cash flow is funds generated from our operations. Our net cash provided by operating activities increased by 25.3% from 2005 to 2006 as a result of a number of factors, including an increase in the volume of our crude oil and refined products sales and an increase in realised prices, which was partially offset by an increase in the amount of income and mineral extraction taxes paid, export duties and transportation tariffs paid resulting from an increase in our export sales, and a seasonal increase in accounts receivable. Our 2006 operating cash inflows were also significantly affected by a \$1,621 million increase in working capital caused by an increase in inventory (resulting from increased stock of crude oil and refined products and increased purchase prices), a net increase in VAT receivables, a net increase in income tax receivables and a net increase in accounts receivable related to taxes other than income taxes, excise taxes and export tariffs. At the same time, the increase in working capital was partly offset by a \$180 million net increase in trade accounts payable. From 2004 to 2005, our net cash provided by operating activities increased by 45.9%, primarily as a result of an increase in our revenues, which was partially offset by an increase in income and mineral extraction taxes paid and in custom fees, export duties and transportation tariffs resulting from an increase in our export sales.
Our net cash used in investing activities increased by 20.7% from 2005 to 2006 primarily as a result of a 61.4% increase in capital expenditures. In 2006 we spent \$1,374 million on acquisitions of interests in other companies, \$1,500 million less than in 2005. We paid \$847 million for the acquisition of KMOC and \$300 million as an advance for the acquisition of the remaining 34% of Geoilbent. In 2005, we spent \$2,874 million primarily for our acquisitions of Nelson Resources, Primorieneftegaz, Teboil and Suomen Petrooli, the remaining interest in SeverTEK, an equity interest in Geoilbent and to increase our share in the Burgas refinery. From 2004 to 2005, our net cash used in investing activities increased by 66.4%, primarily as a result of our significant acquisitions in 2005.
Our net cash used in financing activities was \$1,059 million in 2006 compared to net cash provided by financing activities of \$539 million in 2005. The change from 2005 to 2006 resulted primarily from the payment of \$782 million to buy back our stock under our capital management program and a \$261 million increase in dividends paid. The effects of these payments were partially offset by an increase in net borrowings of \$715 million, including the issue of Russian ruble-denominated bonds with an aggregate face value of RUR 14 billion, \$530 million worth of borrowings related to our KMOC acquisition and \$381 million of loans received from ConocoPhillips as part of its financing of our joint projects in the Timan-Pechora region. Our net cash used in financing activities was \$650 million in 2004. The change from 2004 to 2005 resulted primarily from a loan of \$1,934 million we received for financing the acquisition of Nelson Resources. In addition, our repayments of short-term borrowings were \$468 million more in 2005 than in 2004.
The following table provides a breakdown of our debt as at 31 December 2006, 2005 and 2004.
| Year ended 31 December 11311111111111111 |
||||
|---|---|---|---|---|
| 2006 | 2005 | 2004 | ||
| 11111 | 11111 | 11111 | ||
| (in millions of U.S. dollars) | ||||
| Long-term debt (excluding the current portion) | 4,807 | 4,137 | 2,609 | |
| Current portion of long-term debt | 376 | 537 | 372 | |
| 11111 | 11111 | 11111 | ||
| Total long-term debt | 5,183 | 4,674 | 2,981 | |
| 11111 | 11111 | 11111 | ||
| Short-term borrowings | 1,001 | 316 | 893 | |
| 11111 | 11111 | 11111 | ||
| Total indebtedness | 6,184 | 4,990 | 3,874 | |
| 11111 | 11111 | 11111 | ||
| aaaaa | aaaaa | aaaaa |
Our total long-term debt consists of long-term loans and borrowings from third parties and related parties and our 3.5% convertible U.S. dollar bonds due 2007, 7.25% Russian ruble bonds due 2009, 7.10% Russian ruble bonds due 2011 and 7.40% Russian ruble bonds due 2013. Our long-term loans and borrowings are primarily repayable in U.S. dollars and mature from 2007 to 2035. Approximately 14% of this debt is secured by export sales, property, plant and equipment. The weighted-average annual interest rate on our long-term loans and borrowings from third parties was 6.23% as at 31 December 2006.
Our long-term loans and borrowings from related parties are repayable in Russian rubles and consist of several loan agreements with ConocoPhillips with an aggregate outstanding amount of \$1,043 million as at 31 December 2006. Borrowings under these agreements bear interest at fixed annual rates ranging from 6.8% to 8.2% and have maturity dates up to 2035. These agreements are part of our strategic alliance with ConocoPhillips, and we are using this financing to develop oil production and distribution infrastructure in the Timan-Pechora region of Russia.
Our 3.5% convertible bonds due 2007 were issued in November 2002 and mature on 27 November 2007. These bonds are convertible into global depositary receipts, each representing four of our ordinary shares. Our 7.25% Russian ruble bonds due 2009 were issued in November 2004 and mature on 23 November 2009. For a period of seven days commencing on 13 November 2007, the holders of these bonds have the right to demand that we repurchase the bonds. Our 7.10% Russian ruble bonds due 2011 were issued in December 2006 and mature on 14 December 2011. Our 7.40% Russian ruble bonds due 2013 were issued in December 2006 and mature on 14 December 2013.
As at 31 December 2006, \$1,050 million of our long-term debt was owed by LUKOIL and \$4,133 million was owed by our subsidiaries.
Our short-term borrowings consist of loans from various third parties and are unsecured and primarily payable in U.S. dollars. The weighted-average annual interest rate on our short-term borrowings from third parties was 5.64% as at 31 December 2006. As at 31 December 2006, \$284 million of our short-term borrowings was owed by LUKOIL and \$717 million was owed by our subsidiaries. As at 31 December 2006, we had \$1,563 million available under our existing credit facilities. Interest rates on these facilities vary and are based on LIBOR.
The following is a description of certain of our material debt arrangements outstanding as at 31 December 2006 under which LUKOIL or one of our subsidiaries is a borrower:
As at 31 December 2006, LUKOIL had \$286 million outstanding under a secured syndicated loan agreement, arranged by ABN AMRO Bank and Citibank, which bore interest at LIBOR plus 1.35% per annum. LUKOIL has since refinanced this facility with an unsecured syndicated loan arranged by CALYON and ABN AMRO. LUKOIL has \$250 million outstanding under the new unsecured loan as at the date of this prospectus. The loan matures in 2012 and bears interest at LIBOR plus 0.4% per annum.
Getty Petroleum Marketing Inc. has an unsecured syndicated loan agreement with CALYON and ABN AMRO with an outstanding amount of \$236 million as at 31 December 2006. Borrowings under this agreement bear interest at LIBOR plus 0.95% per annum and have maturity dates up to 2010.
On 21 May 2007, we signed an unsecured \$300 million loan agreement with the EBRD to finance our environmental safety programme. The loan consists of two tranches of \$150 million each. The first tranche is provided by the EBRD at LIBOR plus 0.65% per annum for ten years, and the second tranche is provided by a syndicate of commercial banks at LIBOR plus 0.45% per annum for seven years.
Set forth below are our capital expenditures and investments for each of the years ended 31 December 2004, 2005 and 2006.
| 11311111111111111 | Year ended 31 December | ||
|---|---|---|---|
| 2006 11111 |
2005 11111 |
2004 11111 |
|
| (in millions of U.S. dollars) | |||
| Capital Expenditures1 | |||
| Exploration and production | |||
| Russia | 4,334 | 2,487 | 2,100 |
| International | 786 11111 |
431 11111 |
189 11111 |
| Total exploration and production | 5,120 | 2,918 | 2,289 |
| Refining, marketing and distribution | |||
| Russia | 916 | 654 | 677 |
| International | 559 11111 |
475 11111 |
393 11111 |
| Total refining, marketing and distribution | 1,475 | 1,129 | 1,070 |
| Chemicals | |||
| Russia International |
121 51 |
59 18 |
55 16 |
| 11111 | 11111 | 11111 | |
| Total chemicals | 172 | 77 | 71 |
| Other | 119 11111 |
53 11111 |
17 11111 |
| Total capital expenditures | 6,886 11111 aaaaa |
4,177 11111 aaaaa |
3,447 11111 aaaaa |
| Acquisitions of subsidiaries2 | |||
| Exploration and production | |||
| Russia International |
1,469 91 |
778 1,959 |
23 143 |
| 11111 | 11111 | 11111 | |
| Total exploration and production | 1,560 | 2,737 | 166 |
| Refining, marketing and distribution | |||
| Russia | 122 | 27 | 1 |
| International | – 11111 |
229 11111 |
305 11111 |
| Total refining, marketing and distribution | 122 | 256 | 306 |
| Other | 32 | – | 5 |
| Less cash acquired | (26) 11111 |
(119) 11111 |
– 11111 |
| Total acquisitions of subsidiaries | 1,688 11111 aaaaa |
2,874 11111 aaaaa |
477 11111 aaaaa |
Notes:
(1) Including non-cash transactions.
(2) Including prepayments related to acquisitions of subsidiaries and minority shareholding interest and non-cash transactions.
The increase in our capital expenditures from 2005 to 2006 was attributable primarily to an increase in expenditures in our exploration and production segment, which increased by \$2,202 million compared to 2005. The growth in exploration and production capital expenditures in new regions (as described in the table below) amounted to \$725 million. The capital expenditures in our traditional exploration regions of Western Siberia and European Russia increased by \$483 million and \$366 million, respectively. The increase in our capital expenditures in our overseas exploration projects (excluding the Caspian region) amounted to \$459 million in 2006. The table below shows our exploration and production capital expenditures in new promising oil regions.
| Year ended 31 December 11311111111111111 |
|||||
|---|---|---|---|---|---|
| 2006 11111 |
2005 11111 |
2004 11111 |
|||
| (in millions of U.S. dollars) | |||||
| Northern Timan-Pechora | 1,526 | 673 | 379 | ||
| Yamal | 135 | 216 | 325 | ||
| Caspian region1 | 212 11111 |
259 11111 |
77 11111 |
||
| Total | 1,873 11111 aaaaa |
1,148 11111 aaaaa |
781 11111 aaaaa |
Note:
(1) Russian and international projects
For a discussion of our major acquisitions during the period from 1 January 2004 through the date of this prospectus, see "– Major Acquisitions and Dispositions".
The following table summarises the contractual principal maturities of long-term debt, including its current portion, and our minimum payments required under our capital lease obligations, purchase obligations and other obligations, each as at 31 December 2006.
| Payments due by period 111111111111111111111111111111 |
||||||||
|---|---|---|---|---|---|---|---|---|
| Total 111 |
2007 111 |
2008 111 |
2009 111 |
2010 111 |
2011 111 |
After 111 |
||
| (in millions of U.S. dollars) | ||||||||
| Short-term debt | 1,001 | 1,001 | – | – | – | – | – | |
| Long-term bank loans and borrowings | 3,204 | 311 | 2,249 | 128 | 270 | 86 | 160 | |
| Long-term non-bank loans and | ||||||||
| borrowings | 73 | 29 | 22 | 6 | 7 | 7 | 2 | |
| Long-term loans and borrowings from | ||||||||
| related parties | 1,043 | – | – | – | – | – | 1,043 | |
| 3.5% Convertible U.S. dollar bonds, | ||||||||
| maturing 2007 | 4 | 4 | – | – | – | – | – | |
| 7.25% Russian ruble bonds, | ||||||||
| maturing 2009 | 228 | – | – | 228 | – | – | – | |
| 7.10% Russian ruble bonds, | ||||||||
| maturing 2011 | 304 | – | – | – | – | 304 | – | |
| 7.40% Russian ruble bonds, | ||||||||
| maturing 2013 | 228 | – | – | – | – | – | 228 | |
| Capital lease obligations | 99 | 32 | 29 | 18 | 11 | 7 | 2 | |
| Capital expenditure commitments1 | 7,915 111 |
3,200 111 |
1,731 111 |
1,425 111 |
402 111 |
349 111 |
808 111 |
|
| Total | 14,099 111 aaa |
4,577 111 aaa |
4,031 111 aaa |
1,805 111 aaa |
690 111 aaa |
753 111 aaa |
2,243 111 aaa |
Note:
(1) See the table below setting out our committed capital expenditures. Management believes that the commitments under our Russian oil and gas licence agreements for 2007, 2008 and 2009 may overlap with the commitments under our contracts with Eurasia Drilling and Globalstroy-Engineering. Specifically, our management expects to satisfy a significant portion of the capital commitments under our Russian oil and gas licence agreements by procuring services from Eurasia Drilling and Globalstroy-Engineering under the contracts described in the above table, where we also have committed obligations
Aside from LUKOIL's new unsecured syndicated loan arranged by CALYON and ABN AMRO and LUKOIL's new unsecured syndicated loan with the EBRD which are described above under "– Description of Our Indebtedness", there have been no material changes in our long-term financial obligations and other contractual commitments since 31 December 2006.
We estimate 2007 capital expenditures in our exploration and production segment will be approximately \$5.4 billion, with approximately \$700 million of that outside of Russia. Exploration and production expenditures will target the most promising exploratory prospects in the Caspian region, major development projects in Timan-Pechora region and the maintenance and increase of production on existing fields in Western Siberia and other regions. We estimate 2007 capital expenditures in our refining, marketing and distribution segment will be approximately \$1.4 billion, with approximately \$0.5 billion of that outside of Russia. Refining, marketing and distribution expenditures in Russia will be allocated to upgrading our refineries and selling facilities. International refining, marketing and distribution capital spending will target our distribution infrastructure in Bulgaria, Ukraine, Hungary, Romania, the United States and other countries, as well as our international refineries. The capital expenditures in our chemical segment are estimated to be \$0.2 billion. We may amend our capital expenditures program during the year depending on economic conditions and our financial performance.
We have committed to spend \$3,200 million under various arrangements in 2007. In addition, we have additional committed capital expenditures of \$4,715 million in 2008 and thereafter. The table below provides a breakdown of our committed capital expenditures after 31 December 2006.
| Committed capital expenditures by period 111111111111111111111111111111 |
|||||||||
|---|---|---|---|---|---|---|---|---|---|
| Total 111 |
2007 111 |
2008 111 |
2009 111 |
2010 111 |
2011 111 |
After 111 |
|||
| (in millions of U.S. dollars) | |||||||||
| Capital commitments under oil and | |||||||||
| gas licence agreements in Russia1 | 1,731 | 372 | 401 | 330 | 126 | 150 | 352 | ||
| Operating lease obligations | 1,451 | 341 | 267 | 215 | 124 | 122 | 382 | ||
| Capital commitment in the Burgas | |||||||||
| refinery | 750 | 136 | 250 | 141 | 149 | 74 | – | ||
| Capital commitment in the Petrotel | |||||||||
| refinery | 57 | 2 | – | 18 | 1 | 1 | 35 | ||
| Commitment for modernisation of the | |||||||||
| petrochemical refinery in Ukraine | 156 | 97 | 52 | 7 | – | – | – | ||
| Capital commitments in PSAs | 343 | 224 | 64 | 12 | 2 | 2 | 39 | ||
| Obligations under contract with Eurasia | |||||||||
| Drilling1 | 2,172 | 773 | 697 | 702 | – | – | – | ||
| Obligations under contract with | |||||||||
| Globalstroy-Engineering1 | 1,255 111 |
1,255 111 |
– 111 |
– 111 |
– 111 |
– 111 |
– 111 |
||
| Total1 | 7,915 111 aaa |
3,200 111 aaa |
1,731 111 aaa |
1,425 111 aaa |
402 111 aaa |
349 111 aaa |
808 111 aaa |
||
Note:
(1) Management believes that the commitments under our Russian oil and gas licence agreements for 2007, 2008 and 2009 may overlap with the commitments under our contracts with Eurasia Drilling and Globalstroy-Engineering. Specifically, our management expects to satisfy a significant portion of the capital commitments under our Russian oil and gas licence agreements by procuring services from Eurasia Drilling and Globalstroy-Engineering under the contracts described in the above table, where we also have committed obligations.
In order to meet our debt service and other obligations, we are in part dependent on contributions, dividends, permitted repayment of debt and other transfers of funds from our subsidiaries. A significant portion of LUKOIL's assets consist of the share capital in and loans to other members of our Group. The ability of our subsidiaries to pay group contributions, dividends and make other payments to LUKOIL may be restricted by, among other things, applicable corporate and other laws and regulations and the terms of agreements to which such subsidiaries may be or may become subject.
We record our 54% interest in LUKARCO, our joint venture with BP, under the equity method of accounting. LUKARCO has a loan facility under which \$678 million was outstanding as at 31 December 2006. The amounts outstanding under this loan bear interest at LIBOR plus 2.5% and mature on 1 May 2012. To enhance the credit standing of LUKARCO, we guaranteed 54% of the interest payments and principal under the loan. As at 31 December 2006, the total amount of our guarantee was \$410 million, which includes \$44 million related to accrued interest on the outstanding amount. Our guarantee is secured by our 54% interest in LUKARCO with a carrying value of \$358 million and \$259 million as at 31 December 2006 and 2005, respectively. The amount of the guarantee is not reflected on our balance sheet. The table below sets out the amount of the guarantee that expires in each year until maturity.
| Guarantee expiring by period 111111111111111111111111111111 |
||||||||
|---|---|---|---|---|---|---|---|---|
| Total 111 |
2007 111 |
2008 111 |
2009 111 |
2010 111 |
2011 111 |
After 111 |
||
| (in millions of U.S. dollars) | ||||||||
| Guarantees of equity affiliate's debt | 410 | 42 | 135 | 76 | 92 | 65 | – |
Other than our guarantee of LUKARCO's debt described above, we do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
The preparation of our consolidated financial statements in conformity with U.S. GAAP requires our management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See note 2 to our consolidated financial statements included elsewhere in this prospectus for descriptions of our major accounting policies. Some of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following critical accounting policies require significant judgments, assumptions and estimates and should be read in conjunction with our annual consolidated financial statements.
Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business. For most assets and liabilities, purchase price allocation is accomplished by recording the asset or liability at its estimated fair value. The most difficult estimations of individual fair values are those involving property, plant and equipment and identifiable intangible assets. We use all available information to make these fair value determinations and, for major business acquisitions, typically engage an outside appraisal firm to assist in the fair value determination of the acquired long-lived assets. We have, if necessary, up to one year after the acquisition closing date to complete these fair value determinations and finalise the purchase price allocation.
Our consolidated financial statements include the financial position and results of our company, controlled subsidiaries of which we directly or indirectly own more than 50% of the voting interest, unless minority shareholders have substantive participating rights, and variable interest, entities where we are the primary beneficiary. We account for other significant investments in companies in which we directly or indirectly own between 20% and 50% of the voting interest and over which we exercise significant influence but not control using the equity method of accounting. We also account for investments in companies in which we directly or indirectly own more than 50% of the voting interest but where minority interest shareholders have substantive participating rights using the equity method of accounting. Investments in other companies are recorded at cost. Equity investments and investments in other companies are included in "Investments" in our consolidated balance sheet.
Revenues from the production and sale of crude oil and refined products are recognised when title passes to customers. Revenues include excise on refined products sales and duties on export sales of crude oil and refined products. Revenues from non-cash sales are recognised at the fair market value of the crude oil and refined products sold.
Accounting for oil and gas activities is subject to special accounting rules that are unique to the oil and gas industry. Property acquisitions, successful exploratory wells, all development costs and support equipment and facilities are capitalised. Artificial stimulation and well work-over costs are included in operating expenses as incurred.
For individually significant undeveloped properties, management periodically performs impairment tests based on exploration and drilling efforts to date. For undeveloped properties that individually are relatively small, management exercises its judgment and determines a periodic property impairment charge as required, which is reported in loss on disposals and impairments of assets.
For exploratory wells, drilling costs are temporarily capitalised, or "suspended", on the balance sheet, pending a judgmental determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort. If a judgment is made that the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and are reported in exploration expense. Exploratory wells that are judged to have discovered potentially economic quantities of oil and gas and that are in areas where a major capital expenditure would be required before production could begin remain capitalised on the balance sheet as long as additional exploratory appraisal work is under way or firmly planned. There is no periodic impairment assessment of suspended exploratory well costs. Management continuously monitors the results of the additional appraisal drilling and seismic work and expenses the suspended well costs as dry holes when it determines that the potential field does not warrant further exploratory efforts in the near term. Other exploratory costs, including geological and geophysical costs are expensed as incurred.
Reserves are estimated using the definitions of reserves prescribed by the standards of the Society of Petroleum Engineers, Inc. and World Petroleum Congresses. Due to the inherent uncertainties and the necessarily limited nature of reservoir data, estimates of reserves are inherently imprecise, require the application of judgment and are subject to change as additional information becomes available. The estimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in our plans.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas liquids including condensate, and natural gas that geological and engineering data demonstrate with reasonable certainty can be recovered in future years from known reservoirs under existing economic and operating conditions. Reserves are considered proved if they can be produced economically as demonstrated by either actual production or conclusive formation tests. Proved reserves do not include additional quantities of oil and gas reserves that may result from extensions of currently proved areas or from applying secondary or tertiary recovery techniques not yet tested and determined to be economic. Proved reserves include volumes which are recoverable up to and after license expiry dates. Proved developed reserves are the quantities of proved reserves expected to be recovered through existing wells with existing equipment and operating methods.
We have included within proved reserves quantities which we expect to produce after the expiration dates of our current production licences in Russia. These licences expire between 2011 and 2026, with the most significant ones expiring between 2011 and 2014. We believe that we will be able to extend our current production licences to produce oil and/or natural gas subsequent to their current expiry dates. We are in the process of extending all of our production licences in Russia. We have already extended a portion of these licences and expect to extend the remaining licences for a time equal to the economic viability of the relevant fields. To date, there have been no unsuccessful licence renewal applications.
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. This document contains data, such as reserves and resources presented in accordance with SPE standards (and, in particular, proved and possible reserves), that the SEC's guidelines would prohibit us from including in filings with the SEC.
Long-lived assets, such as oil and gas properties, other property, plant and equipment, and purchased intangibles subject to amortisation are assessed for impairment when events or changes in circumstances indicate that the carrying amount of an asset group may not be recoverable. The recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset group to the estimated undiscounted future cash flows expected to be generated by that group. If the carrying amount of an asset group exceeds its estimated undiscounted future cash flows, an impairment charge is recognised by writing down the carrying amount to the estimated fair value of the asset group, generally determined as discounted future net cash flows. Assets to be disposed of are separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated. The assets and liabilities of a disposed group classified as held for sale are presented separately in the appropriate asset and liability sections of the balance sheet.
Deferred income tax assets and liabilities are recognised in respect of future tax consequences attributable to temporary differences between the carrying amounts of existing assets and liabilities for the purposes of the consolidated financial statements and their respective tax bases and in respect of operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse and the assets be recovered and liabilities settled. The effect on deferred income tax assets and liabilities of a change in tax rates is recognised in the consolidated statement of income in the reporting period which includes the enactment date.
The ultimate realisation of deferred income tax assets is dependent upon the generation of future taxable income in the reporting periods in which the originating expenditure becomes deductible. In assessing the realisability of deferred income tax assets, our management considers whether it is more likely than not that the deferred income tax assets will be realised. In making this assessment, our management considers the scheduled reversal of deferred income tax liabilities, projected future taxable income, and tax planning strategies.
Under various laws, contracts, permits and regulations, we have legal obligations to remove tangible equipment and restore the land or seabed at the end of operations at production sites. Our largest asset retirement obligations relate to wells and oil and gas production facilities and pipelines. In accordance with Statement of Financial Accounting Standards (SFAS), No. 143, "Accounting for Asset Retirement Obligations", we record the fair value of liabilities associated with such obligations when incurred. Estimating the future asset retirement obligation costs necessary for this accounting calculation involves significant estimates and judgments by our management. Liabilities under most of these obligations will not arise for many years into the future and the contracts and regulations often have vague descriptions of the removal practices and criteria that we will have to meet when the removal event actually occurs. Asset removal technologies and costs are constantly changing, as well as political, environmental, safety and public relations considerations.
Certain conditions may exist as of balance sheet dates that may result in losses, but the impact of which will only be resolved when one or more future events occur or fail to occur. We are required to determine both whether a loss is probable based on judgment and interpretation of laws and regulations and whether the loss can be reasonably estimated. If our assessment of a contingency indicates that it is probable that a material loss will arise, and the amount of the liability can be estimated, then the estimated liability is accrued and charged to the consolidated statement of income. If our assessment indicates that a potentially material loss is not probable, but is only reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability is disclosed in the notes to our consolidated financial statements. Loss contingencies considered remote generally are not disclosed unless they involve guarantees, in which case the nature of the guarantee is disclosed. Our management continually monitors known and potential contingent matters and makes appropriate charges to the consolidated statement of income when warranted by the circumstance.
Our derivative activity is limited to certain refined products marketing and trading outside of our physical crude oil and refined products businesses and hedging of commodity price risks. Currently, this activity involves the use of futures and swaps contracts together with purchase and sale contracts that qualify as derivative instruments. We account for these activities under the mark-to-market methodology in which the derivatives are revalued at each accounting period. The resulting realised and unrealised gains or losses are presented in the consolidated statement of income on a net basis. Unrealised gains and losses are carried as assets or liabilities on the consolidated balance sheet.
In February 2007, FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities". This Statement expands the possibility of using fair value measurements and permits enterprises to choose to measure certain financial assets and financial liabilities at fair value. Enterprises shall report unrealised gains and losses on items for which the fair value option has been elected in earnings at each subsequent period. The Statement is effective in the first quarter 2008. We are currently assessing the effect of adoption of SFAS No. 159.
In September 2006, the FASB issued SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106 and 132(R)". This Statement requires an employer that sponsors one or more single-employer defined benefit plans to: (a) recognise the funded status of a benefit plan in its statement of financial position; (b) recognise as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognised as components of net periodic benefit cost; (c) measure defined benefit plan assets and obligations as of the date of the employer's fiscal year-end statement of financial position (with limited exceptions); (d) disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition asset or obligation. The provisions of this Statement are effective 31 December 2006, except for the requirement to measure plan assets and benefit obligations as of the date of the employer's fiscal year-end, which is effective 31 December 2008. The adoption of the provisions of SFAS No. 158 did not have a material impact on our results of operations, financial position or cash flows. See note 14 to our consolidated financial statements included elsewhere in this prospectus.
In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" which establishes a single authoritative definition of fair value, sets out a framework for measuring fair value and requires additional disclosures about fair value measurements. This Statement does not require any new fair value measurements but is expected to increase the consistency of those measurements. We are required to adopt the provisions of SFAS No. 157 in the first quarter 2008, and we do not expect any material impact on our financial statements upon adoption.
In June 2006, the FASB issued FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109" (FIN 48). This Interpretation clarifies the accounting for uncertainty in income taxes recognised in an enterprise's financial statements in accordance with FASB Statement No. 109, "Accounting for Income Taxes". We are required to adopt the provisions of FIN 48 in the first quarter 2007 and are currently assessing the effect of adoption.
In June 2006, the FASB ratified the consensus reached by the EITF on Issue No. 06-3, "How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)". The consensus requires disclosure of either the gross or net presentation, and any such taxes reported on a gross basis should be disclosed in the interim and annual financial statements. We adopted the provisions of EITF Issue No. 06-3 in 2006. The adoption of the Issue did not have a material impact on our financial statements.
In December 2004, the FASB issued SFAS No. 123(R), "Share-Based Payment", which revises SFAS No. 123 and supersedes Accounting Principles Board (APB) Opinion No. 25 regarding stock-based employee compensation plans. SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be valued at fair value on the date of grant and on each reporting date, and to be expensed over the applicable vesting period. The adoption of the provisions of SFAS No. 123(R) during 2006 did not have a material impact on our results of operations, financial position or cash flows.
We are exposed to changes in interest rates, primarily associated with our variable rate short-term and long-term borrowings. We do not utilise any interest rate swaps or other derivatives to hedge against the risk of changes in interest rates on our variable rate debt. As at 31 December 2006, our long-term borrowings which are sensitive to changes in interest rates totaled \$3,029 million. See note 12 to our consolidated financial statements included elsewhere in this prospectus for details of our long-term debt. Utilising the actual interest rates in effect and the balance of our variable rate debt as at 31 December 2006 and assuming a 10% change in interest rates and no change in the balance of debt outstanding, the potential effect on annual interest expense would not be material to our results of operations.
| Fixed rate borrowings 1111111113111 |
Floating rate borrowings 1111111113111 |
|||
|---|---|---|---|---|
| 2006 111 |
(\$ millions) 11111 |
% 11111 |
(\$ millions) 11111 |
% 11111 |
| 2007 | 1,022 | 5.43 | 271 | 6.94 |
| 2008 | 47 | 3.54 | 2,224 | 6.15 |
| 2009 | 283 | 6.49 | 79 | 7.29 |
| 2010 | 35 | 2.94 | 242 | 6.61 |
| 2011 | 341 | 6.68 | 56 | 7.87 |
| After | 233 11111 |
4.70 11111 |
157 11111 |
9.40 11111 |
| Total1 | 1,961 11111 aaaaa |
5.62 11111 aaaaa |
3,029 11111 aaaaa |
6.49 11111 aaaaa |
| Fixed rate borrowings | Floating rate borrowings | |||
| 2005 | 1111111113111 (\$ millions) |
% | 1111111113111 (\$ millions) |
% |
| 111 | 11111 | 11111 | 11111 | 11111 |
| 2006 | 408 | 5.30 | 422 | 6.69 |
| 2007 | 161 | 3.89 | 422 | 6.55 |
| 2008 | 63 | 3.99 | 2,366 | 5.33 |
| 2009 2010 |
308 41 |
7.48 3.25 |
149 296 |
6.74 6.35 |
| After | 64 11111 |
3.67 11111 |
180 11111 |
9.16 11111 |
Note:
(1) Excluding capital lease obligations and loans and borrowings from related parties.
The countries in which our principal operations are located have been subject to hyperinflation and during the last 10 years the local currency has been subject to large devaluations. As a result, we are subject to the risk that the local currency may suffer future devaluation that may subject us to losses, depending on our net monetary asset position. We currently do not use any formal hedging arrangements to minimise the effect of these potential losses. Additionally, because we have operations in a number of other countries, we are required to conduct business in a variety of foreign currencies and, as a result, we are subject to foreign exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. The impacts of fluctuations in foreign currency exchange rates on our geographically diverse operations are varied. We recognised a net foreign currency translation gain of \$169 million in 2006, a loss of \$134 million in 2005 and a gain of \$135 million in 2004.
Appreciation of the ruble against the U.S. dollar in 2006 had a negative impact on our operating profit and cash flows since it lead to an increase in our ruble costs in U.S. dollar terms and a decrease in the amount of our export cash revenue in ruble terms. As mentioned above, a substantial part of our revenue is denominated in U.S. dollars or, to some extent, linked to oil prices quoted in U.S. dollars, while a significant part of our costs are ruble denominated. If the ruble appreciates an additional 10% against the U.S. dollar in 2007, our net cash provided by operating and investing activities would have decreased by approximately \$0.5 billion (assuming all other factors remained constant).
We participate in certain refined products marketing and trading activity outside of our physical crude oil and refined products businesses. Our derivative activity is limited to these marketing and trading activities and hedging of commodity price risks. Currently, this activity involves the use of futures and swap contracts together with purchase and sale contracts that qualify as derivative instruments. We maintain a system of controls over these marketing and trading activities that includes policies covering the authorisation, reporting and monitoring of derivative activity. We do not believe our derivative activities pose material credit or market risks to our operations, financial condition or liquidity. We recognised income of \$183 million in 2006, an expense of \$171 million in 2005 and an expense of \$55 million in 2004 from the use of derivative instruments. The fair value of derivative contracts outstanding and recorded on the consolidated balance sheet as at 31 December 2006 was a net asset of \$43 million, compared to a net liability of \$26 million in 2005 and a net asset of \$28 million in 2004.
We are one of the largest publicly traded oil companies in the world in terms of proved crude oil and gas reserves and we are the second largest producer of crude oil in Russia. According to Miller and Lents, our independent reservoir engineers, as at 1 January 2007, our estimated proved crude oil reserves were 15,926.8 mmbls (2,172.8 million tonnes) and our estimated proved gas reserves were 26,597.3 bcf (753.3 bcm), an aggregate of 20,359.7 mmboe. As at the same date, our estimated probable crude oil reserves were 8,767.4 mmbls (1,196.1 million tonnes) and our estimated probable gas reserves were 21,435.7 bcf (607.1 bcm), an aggregate of 12,340.1 mmboe. These reserves amounts, and the reserves amounts included elsewhere in this prospectus, were estimated in accordance with SPE standards.
In 2006, we produced 703.1 mmbls (95.2 million tonnes) of crude oil, including 660.2 mmbls (89.6 million tonnes) in Russia and 42.9 mmbls (5.6 million tonnes) from our international projects. Our 2006 domestic crude oil production accounted for approximately 18.6% of all Russian crude oil production based on the aggregate Russian crude oil production for 2006 published by the Russian Ministry of Energy. In 2006, we produced 480.2 bcf (13.6 bcm) of gas available for sale, including 437.8 bcf (12.4 bcm) in Russia and 42.4 bcf (1.2 bcm) from our international projects. In 2006, we refined 358.4 mmbls (48.9 million tonnes) of crude oil at our own refineries, including 289.5 mmbls (39.5 million tonnes) at our Russian refineries and 68.9 mmbls (9.4 million tonnes) at our international refineries. We also refined 24.2 mmbls (3.3 million tonnes) of crude oil under contract with domestic third-party refineries, primarily at refineries in Ufa, and 12.5 mmbls (1.7 million tonnes) of crude oil under contract with international third-party refineries. In 2006, we sold 300.7 mmbls (41.0 million tonnes) of crude oil and 64.7 million tonnes of refined products to customers outside of Russia, including sales to CIS countries and exports to international markets. Our total revenues were \$68,109 million in 2006, compared to \$56,215 million in 2005. Our net income in 2006 was \$7,484 million, compared to \$6,443 million in 2005.
As at 1 January 2007, approximately 96% of our estimated proved crude oil reserves were in Russia. Our proved crude oil reserves in Western Siberia were 8,771.4 mmbls (1,196.6 million tonnes) as at 1 January 2007, constituting approximately 55% of our total estimated proved crude oil reserves. We are developing new reserves in Russia, most notably in the Timan-Pechora region and the northern Caspian region. We believe that these new areas will provide us with a reserves portfolio which is more balanced geographically. As at 1 January 2007, approximately 83% of our estimated proved natural gas reserves were in Russia. Our core gas producing area is the Bolshekhetskaya depression in the Yamal-Nenets Autonomous District in Western Siberia. In April 2005, we started producing natural gas from the Nakhodkinskoye field in the Bolshekhetskaya depression in this region. In 2006, our production of gas available for sale was 293.1 bcf (8.3 bcm) from this field.
Our primary international areas of focus are currently Kazakhstan and Uzbekistan. We also have interests in international projects in Africa, the Middle East, South America and elsewhere in the CIS. As at 1 January 2007, our international assets accounted for approximately 4% of our estimated proved crude oil reserves and 17% of our estimated proved gas reserves.
We own four oil refineries in Russia, located in Perm, Volgograd, Ukhta and Nizhny Novgorod. These refineries, along with our mini-refineries in Urai and Kogalym, have a combined refining capacity of 44.1 million tonnes per year and in 2006 refined a total of 39.5 million tonnes of crude oil. Outside of Russia, we own refineries in Bulgaria and Romania, which have a combined refining capacity of 11.2 million tonnes per year and in 2006 refined a total of 9.4 million tonnes of crude oil. We also own a refinery in Ukraine, which has been closed since August 2005 for a large-scale reconstruction programme. We expect the reconstruction to be completed in the fourth quarter of 2007 (at which time the refinery will be reopened). The reconstruction programme we have commenced at our Ukrainian refinery is part of a larger effort to upgrade and modernise all of our refineries to improve utilisation rates and depth of refining and to increase production of refined products which comply with the more stringent current environmental requirements applicable in some of our export markets, including the European Union. We have invested, and expect to continue to invest, substantial amounts on our modernisation efforts at our refineries. In October 2004, we put our Romanian refinery back into operation after an upgrade and modernisation programme. Once we complete the upgrades of all of our refineries, we believe that a significant portion of the refined products produced at our refineries will be in compliance with existing and expected future European Union standards and provide attractive integration opportunities with southeastern European markets.
Our downstream gas assets include four gas processing facilities: the Lokosovsky gas processing plant in the Khanty-Mansiysk Autonomous District, the Korobkovsky gas processing plant in the Volgograd region, the Permneftegazpererabotka plant in the Perm region and the Usinsk gas processing plant in the Komi Republic. In 2006, our gas processing plants processed 91.8 bcf (2.6 bcm) of gas. The Lokosovsky gas processing plant is currently our main gas processing facility in Russia, which has a gas processing capacity of 67.1 bcf (1.9 bcm) per year.
We sell the crude oil which we do not refine in the domestic market, which includes certain sales directed by the Russian government, and in the international market, which includes exports from Russia and sales outside of Russia of crude oil production from our international projects. In 2006, we sold 13.3 mmbls (1.8 million tonnes) of crude oil within Russia and 300.7 mmbls (41.0 million tonnes) of crude oil outside of Russia.
We sold a total of 83.9 million tonnes of refined products through wholesale and retail channels in 2006. We sell a wide range of refined products, including gasoline, diesel fuel, fuel oil and lubricants. In 2006, we sold 19.2 million tonnes of our refined products in the domestic market and 64.7 million tonnes internationally.
As at 31 December 2006, we owned or leased 5,169 retail filling stations, including 1,538 in Russia, 1,843 in the United States and 1,788 in the CIS (excluding Russia) and Europe. In 2006, we sold 4.0 million tonnes of refined products through our filling stations in Russia and 7.2 million tonnes through our filling stations outside Russia. In addition, in December 2006, we signed an agreement with ConocoPhillips to purchase 376 of ConocoPhillips' retail filling stations in Europe, including 156 in Belgium and Luxembourg, 49 in Finland, 44 in the Czech Republic, 30 in Hungary, 83 in Poland and 14 in Slovakia. On 30 April 2007, we completed the acquisition of the filling stations located in Finland. We intend to re-brand these stations as Teboil stations within one year. We completed the acquisition of the remaining stations on 1 June 2007, which we intend to rebrand as LUKOIL stations.
We continue to expand our petrochemicals business through our petrochemicals operations in Russia, Ukraine and Bulgaria. Currently, we have two petrochemicals plants in southern Russia and one in Ukraine. We also manufacture petrochemicals at our Burgas refinery in Bulgaria. Together, those plants manufactured 2.0 million tonnes of petrochemicals in 2006. We intend to utilise our expanding natural gas production and processing operations as a source of feedstock for our petrochemicals operations.
We use the Transneft pipeline system, our own pipeline network, rail cars and tankers to transport the crude oil which we produce within Russia, for export outside of Russia and to our refineries. In addition, LUKARCO, our joint venture with BP plc in which we have a 54% interest, has a 12.5% interest in the CPC, a pipeline project in the Caspian region which we use to transport crude oil produced in Kazakhstan to a marine terminal near the Russian city of Novorossiysk on the Black Sea for transport on to international markets. We also own export terminals at Ilyinka in the Astrakhan Region (with a total annual capacity of 2.0 million tonnes), at the port of Svetly in the Kaliningrad Region (with a total annual capacity of 6.0 million tonnes), at Varandey on the Barents Sea (with a total annual capacity of approximately 1.5 million tonnes) and at Vysotsk, Vyborg's outer harbour on the Baltic Sea (with a total annual capacity of 11.6 million tonnes). We transport most of our gas through UGSS, which is responsible for gathering, transporting, dispatching and delivering substantially all natural gas supplies in Russia and is owned and operated by Gazprom. We transport our refined products primarily through a combination of Russia's state-owned refined products pipeline, Transnefteproduct and by rail car, river-class tanker and truck.
Our strategic objectives are to increase our profitability by increasing our sustainable production of crude oil, natural gas and refined products, replacing our reserves at low cost and maintaining returns on capital at levels comparable to our international peers.
We aim to create shareholder value through rigorous management of capital and costs. We believe that one of the competitive advantages which allows us to achieve this strategic objective is our ability to identify and develop low-cost upstream and downstream opportunities in our core Russian and international markets.
We are in the process of implementing a comprehensive corporate development programme for 2007 to 2016, which we believe will better enable us to achieve our strategic goals of sustainable growth and value creation. Our major priorities include steps designed to deliver near- and medium-term benefits to our profitability and returns on investment and a long-term programme designed to sustain our growth and profitability.
Our development programme for the next two years is designed to take advantage of opportunities to increase profitability. We believe that the following initiatives will, upon successful implementation, have a positive impact on our profitability:
directors and officers of the Company and its subsidiaries based on our performance. In February 2007, the compensation plan was settled through the issuance of approximately 7.3 million shares. In December 2006, we introduced a new compensation plan for certain members of our management and key employees for the period from 2007 to 2009, which is based on assigned phantom shares.
• Streamline our administration. We are currently reducing the number of our subsidiaries and affiliated companies to make our corporate structure more manageable and efficient and to increase transparency for investors. We believe that more efficient management of our business and a leaner, more focused corporate structure will enable us to reduce costs. Since our restructuring programme began in 2001, we have reduced the number of Group companies from approximately 700 to 311 as at 31 December 2006.
Our longer-term initiatives include the following:
we will jointly pursue oil and gas exploration and development projects in the Nenets and the Yamal-Nenets Autonomous Districts, the Russian sector of the Caspian Sea, the Republic of Uzbekistan and certain other regions. In addition, in April 2005, we started producing natural gas from the Nakhodkinskoye field in the Bolshekhetskaya depression in Western Siberia, which is one of our major gas assets. In 2006, our production of gas available for sale was 293.1 bcf (8.3 bcm) of natural gas from this field.
We consider retail operations to be one of the key elements in our integrated production and marketing strategy. We intend to expand our network of filling stations in Russia (primarily in the European Russia region) and internationally (primarily in Europe and elsewhere in the CIS) to increase our share of the retail market in those regions. We also intend to continue to improve the distribution of our products in the United States over the next several years. In March 2005, we acquired 100% of two Finnish downstream companies which together own 289 retail filling stations and 132 retail diesel fuel outlets in Finland, for \$160 million. In addition, in December 2006, we signed an agreement with ConocoPhillips to purchase 376 of ConocoPhillips' retail filling stations in Europe, including 156 in Belgium and Luxembourg, 49 in Finland, 44 in the Czech Republic, 30 in Hungary, 83 in Poland and 14 in Slovakia. On 30 April 2007, we completed the acquisition of the filling stations located in Finland. We intend to re-brand these stations as Teboil stations within one year. We completed the acquisition of the remaining stations on 1 June 2007, which we intend to rebrand as LUKOIL stations.
In January 2007, we acquired the remaining 34% of Geoilbent, which has exploration and production operations in Western Siberia, for \$300 million, increasing our ownership of Geoilbent to 100%.
In February 2007, we signed a memorandum of understanding with Qatar Petroleum, pursuant to which we will work together to explore opportunities for cooperation in new and existing oil and gas projects in Qatar.
On 20 April 2007, we sold 50% of Caspian Investments Resources, which has exploration and production operations in western Kazakhstan, to Mittal Investments S.a.r.L. for \$980 million. In addition, Mittal Investments committed to repay 50% of Caspian Investments Resources' outstanding debt, which consisted of inter-company debt to other members of our Group and, as at the date of the sale, was approximately \$175 million.
In April 2007, we signed a supplemental agreement to our agreement with Russian Railways on developing railway transportation infrastructure to increase the supply capacity of refined products to our Vystosk terminal.
On 30 April 2007, we completed the acquisition of 49 filling stations located in Finland from ConocoPhillips pursuant to a December 2006 agreement with ConocoPhillips. We completed the acquisition of the remaining 327 filling stations located in Belgium, Luxembourg, the Czech Republic, Hungary, Poland and Slovakia on 1 June 2007.
On 21 May 2007, we signed an unsecured \$300 million loan agreement with the EBRD to finance our environmental safety programme. The loan consists of two tranches of \$150 million each. The first tranche is provided by the EBRD at LIBOR plus 0.65% per annum for ten years, and the second tranche is provided by a syndicate of commercial banks at LIBOR plus 0.45% per annum for seven years.
On 15 May 2007, we announced certain preliminary operating estimates for the first quarter of 2007. In the first quarter of 2007, we currently estimate that our total crude oil production was 180.5 mmbls (24.4 million tonnes), our gas production available for sale was 127.1 bcf (3.6 bcm) and our refinery throughput was 12.1 million tonnes at our refineries and 1.0 million tonnes at third-party refineries. This information is based on preliminary operating data and is subject to adjustment in connection with the preparation of our consolidated financial statements for the first quarter of 2007.
On 25 April 2007, our Board of Directors resolved to add as an agenda item to our annual shareholders meeting, scheduled for 28 June 2007, the amendment of our charter to increase our authorised shares by 85 million shares, which is approximately 10% of our currently authorised and issued shares.
We were initially established in November 1991 as a state-owned oil concern, LangepasUraiKogalymneft (from which we derive the acronym LUK). In line with the Russian government's privatisation plans, we were converted into a joint stock company in 1993, and the Russian government transferred to us 51% of the voting shares of 15 enterprises. The Russian government transferred an additional nine enterprises to us in 1995. In 1994, the Russian government disposed of 51% of our share capital through an exchange of shares for vouchers tendered by private investors in Russia, sales to private investors in Russia for cash and the distribution of shares to employees. The Russian government subsequently has disposed of all our shares. Most recently, the Russian government sold its remaining 7.6% to ConocoPhillips in October 2004 for a price of \$1.988 billion, or \$30.76 per share, in a transaction which was completed in October 2004.
At the time of the Russian government's sale of our shares to ConocoPhillips, we entered into a series of agreements with ConocoPhillips to form a broad-based strategic alliance. Specifically, we entered into a shareholder agreement, pursuant to which ConocoPhillips had the right to nominate a representative to our Board of Directors. In January 2005, the ConocoPhillips nominee, Kevin Meyers, was elected to our Board. The shareholders agreement also provides that once ConocoPhillips' ownership interest in LUKOIL reaches 12.5%, it will have the right to nominate a second representative to our Board of Directors. In addition, this agreement provides that ConocoPhillips may increase its total ownership stake in LUKOIL up to an aggregate total ownership interest of 20% and limits ConocoPhillips' ability to sell our shares for a period of four years. Since its initial acquisition of our shares, ConocoPhillips has increased its stake in our company through open market purchases on the London Stock Exchange. In May 2007, ConocoPhillips reported that, as at 31 March 2007, it owned 20% of our authorised and issued shares, which is the maximum permissible under our shareholder agreement and which is equivalent to approximately 20.6% based on estimated shares outstanding.
Our domestic operations are conducted primarily through:
Our international operations are conducted through two principal subsidiaries: LUKOIL Overseas Holding Ltd. and LUKOIL INTERNATIONAL GmbH. LUKOIL Overseas is responsible for our international exploration and production activities. LUKOIL INTERNATIONAL is primarily responsible for our international refining, trading, distribution and retail marketing operations.
We divide our operations into three principal segments: an exploration and production segment; a refining, marketing and distribution segment; and a petrochemicals segment, each of which we discuss below. A fourth segment, which includes our other business such as banking, finance and other activities, is not currently material to our results of operations.
We are one of the largest publicly traded oil and gas companies in the world in terms of proved crude oil and gas reserves and we are the second largest producer of crude oil in Russia. Our three core producing areas in Russia are Western Siberia, European Russia and the Timan-Pechora region, where as at 1 January 2007 we had an aggregate of 17,598.6 mmboe of proved and 10,020.65 mmboe of probable hydrocarbon reserves. Our main production subsidiaries in Western Siberia are LUKOIL-Western Siberia, RITEK and LUKOIL-AIK. Our main production subsidiaries in European Russia are LUKOIL-Perm, LUKOIL-Nizhnevolzhskneft and LUKOIL-Kaliningradmorneft. In Timan-Pechora, our main production companies are LUKOIL-Komi, LUKOIL-Sever and NMNG. As part of our efforts to develop our reserves in Timan-Pechora, we entered into a joint venture agreement with ConocoPhillips in September 2004, pursuant to which we sold a 30% interest in NMNG to ConocoPhillips. In addition, we have 1,412.7 mmboe of proved and 2,025.9 mmboe of probable oil and gas reserves in the northern Caspian region.
We must obtain licences from governmental authorities to explore for and produce oil and natural gas from our fields. As at 31 March 2007, we held 408 licences, of which 367 are either production or combined exploration and production licences and 41 are exploration licences. Exploration licences give the licence holder the nonexclusive right to explore for oil and natural gas in fields in a defined area and are generally valid for a period of five years. These licences do not give us the right to extract any oil which we find. However, if our exploration efforts are successful and we find oil, natural gas or both, our exploration licences generally provide that we can obtain a production licence without auction or tender. Production licences generally have been valid for 20 years and give us the exclusive right to extract oil and natural gas from fields in a defined area. Combined exploration and production licences permit both exploration and production and are generally valid for 25 years. Many of our original licences, especially those relating to our Western Siberia operations, expire between 2013 and 2017. Recent legislation, passed after the issuance of many of our licences, provides that licences are now granted for a time equal to the economic viability of the relevant field. As long as we meet certain conditions, such as compliance with approved development programmes, we believe that each of our licences issued prior to this legislation can be extended, upon expiration, for the economic life of the relevant fields. Of our 408 licences, 83 of our licences have been issued or extended for the economic life of fields. See "Risk Factors – Risks Relating to Our Business – Our exploration, development and production licences may be suspended, terminated or revoked prior to their expiration and we may be unable to obtain or maintain various permits or authorisations" for more information on the risks relating to our licences.
Our licences generally impose obligations on the licence holder to pay certain local and federal taxes and meet certain environmental requirements. Licences generally require the licence holder to make various commitments, including extracting annually an agreed target amount of reserves, conducting agreed minimum drilling levels and other exploratory and development activities, protecting the environment in the licence area from damage, providing certain progress reports and geological data to the relevant authorities and paying royalties and other amounts when due. Licences may be suspended or revoked if the licence holder fails to comply with their terms or to heed warnings from regulatory authorities. See "Regulation – Subsoil Production Licences".
At our request, Miller and Lents, our independent reservoir engineers, have carried out an independent evaluation of our estimated reserves as at 1 January 2007. Reserves were estimated in accordance with standards of the Society of Petroleum Engineers, Inc. and the World Petroleum Congresses. Unless otherwise specified, any information in this prospectus about our estimated crude oil and gas reserves is extracted from the reserves reports prepared by Miller and Lents as at 1 January in each of 2005, 2006 and 2007. The estimates of reserves in the Miller and Lents reports are based upon existing economic and operating conditions using prices and costs as at the date the estimates are made as well as various assumptions as to capital expenditures and availability of funds.
The process of estimating oil reserves is complex and inherently uncertain. We must project production rates and timing of development and analyse available geological, geophysical, production, engineering and economic data 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 "Selected Consolidated Financial and Other Information – Selected Reserves and Production Information" and "Selected Consolidated Financial and Other Information – Reserves Measurements". See also "Risk Factors – Risks Relating to Our Business – The crude oil and natural gas reserves data in this prospectus are only estimates, and our actual production, revenues and expenditures with respect to our reserves may differ materially from these estimates".
The following table sets out our total crude oil and natural gas reserves as at 1 January 2007.
| Net reserves1 | ||||||
|---|---|---|---|---|---|---|
| Total (mmboe) 111111 |
||||||
| 20,359.7 | ||||||
| 8,767.4 | 21,435.8 | 12,340.1 111111 |
||||
| 24,694.2 111111 |
48,033.1 | 32,699.8 111111 aaaaaa |
||||
| Oil (mmbls) 111111 15,926.8 111111 aaaaaa |
As at 1 January 2007 111111111111111111113 111111111111111111113 Gas (bcf)2 111111 26,597.3 111111 111111 aaaaaa |
Notes:
The following tables set out our Russian crude oil and natural gas reserves by our main production areas as at 1 January in each of 2005, 2006 and 2007.
| Proved plus | ||||||||
|---|---|---|---|---|---|---|---|---|
| Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable 1111 |
| 13,734.7 | ||||||||
| 3,122.4 | ||||||||
| 5,511.4 | ||||||||
| 448.3 | 598.4 | 1,046.7 | 183.3 | 452.2 | 635.5 | 184.1 | 296.1 | 480.2 1111 |
| 15,318.8 1111 |
8,628.2 1111 |
23,947.0 1111 |
15,501.1 1111 |
8,728.5 1111 |
24,229.6 1111 |
15,484.7 1111 |
7,364.0 1111 |
22,848.7 1111 aaaa |
| 1111 8,771.4 2,603.2 3,495.9 1111 aaaa |
1111 5,630.9 1,087.7 1,311.2 1111 aaaa |
1 January 2007 1111111111111124 Proved plus 1111 14,402.3 3,690.9 4,807.1 1111 aaaa |
1111 8,775.0 2,709.9 3,832.9 1111 aaaa |
1111 5,664.4 1,116.1 1,495.8 1111 aaaa |
Net Oil Reserves (mmbls) 1 January 2006 1111111111111124 Proved plus 1111 14,439.4 3,826.0 5,328.7 1111 aaaa |
1111 8,730.6 2,677.6 3,892.4 1111 aaaa |
11111111111111111111111111111111111111111111112 1 January 2005 1111111111111124 1111 5,004.1 444.8 1,619.0 1111 aaaa |
(1) Net oil and gas reserves include reserves that we do not beneficially own which are attributable to minority interests in our consolidated subsidiaries and our equity share of reserves of our affiliated companies. For disclosure that excludes reserves attributable to minority interests in our consolidated subsidiaries, see Table IV of "Supplementary Information on Oil and Gas Exploration and Production Activities (Unaudited)", supplemented to our consolidated financial statements and notes thereto included elsewhere in this prospectus and presented in accordance with SFAS No. 69, "Disclosures About Oil and Gas Producing Activities". No deduction for royalties was made in estimating net reserves.
(2) Estimated gas reserves were calculated on the basis of sales volumes and, beginning from 1 January 2007, on the basis of gas production used for internal consumption, but not reservoir volumes. In doing so, Miller and Lents assumed a constant ratio of gas sales to total gas production throughout the life of the fields.
| 11111111111111111111111111111111111111111111112 | Net Gas Reserves (bcf) | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| 1 January 2007 1111111111111124 |
1 January 2006 1111111111111124 |
1 January 2005 1111111111111124 |
|||||||
| Proved plus | Proved plus | Proved plus | |||||||
| Region | Proved 1111 |
Probable 1111 |
Probable 1111 |
Proved 1111 |
Probable 1111 |
Probable 1111 |
Proved 1111 |
Probable 1111 |
Probable 1111 |
| Western Siberia | 14,787.6 | 7,913.4 | 22,701.0 | 14,882.4 | 6,179.0 | 21,061.4 | 14,333.4 | 4,207.3 | 18,540.7 |
| European Russia | 873.3 | 3,890.9 | 4,764.2 | 791.4 | 3,893.2 | 4,684.6 | 849.5 | 93.0 | 942.5 |
| Timan-Pechora | 707.6 | 140.4 | 848.0 | 176.4 | 28.9 | 205.3 | 462.8 | 182.6 | 645.4 |
| Northern Caspian | 5,786.4 1111 |
8,565.2 1111 |
14,351.6 1111 |
5,603.4 1111 |
8,852.8 1111 |
14,456.2 1111 |
5,735.8 1111 |
10,331.4 1111 |
16,067.2 1111 |
| Total for Russia | 22,154.9 1111 aaaa |
20,509.9 1111 aaaa |
42,664.8 1111 aaaa |
21,453.6 1111 aaaa |
18,953.9 1111 aaaa |
40,407.5 1111 aaaa |
21,381.5 1111 aaaa |
14,814.3 1111 aaaa |
36,195.8 1111 aaaa |
Our total Russian crude oil production was 660.2 mmbls (89.6 million tonnes) in 2006, representing approximately 18.6% of Russia's total crude oil production in 2006 based on the aggregate Russian crude oil production for 2006 published by the Russian Ministry of Energy. Our total Russian gas production available for sale was 437.8 bcf (12.4 bcm) in 2006, of which 127.1 bcf (3.6 bcm) was petroleum gas and 310.7 bcf (8.8 bcm) was natural gas. The majority of our current production comes from our three core producing areas of Western Siberia, European Russia and Timan-Pechora.
As part of our strategy of cutting costs and maximising profitability, we intend to utilise more advanced reserves management techniques to increase production at our wells while shutting in low producing wells. We believe that this will allow us to increase production efficiency in Western Siberia and European Russia. In addition, we believe that further production increases will come from Timan-Pechora and the northern Caspian region, where relatively young reserves should provide higher flow rates. See "– Strategy".
The following table sets out our daily crude oil production data in our main crude oil production areas in Russia for each of the years ended 31 December 2004, 2005 and 2006.
| Analysis of Daily Crude Oil Production 111111111111111111113 |
|||
|---|---|---|---|
| (mbls/day) 111111111111111111113 |
|||
| For the year ended 31 December 111111111111111111113 |
|||
| 2006 111111 |
2005 111111 |
2004 111111 |
|
| Western Siberia | 1,214 | 1,184 | 1,143 |
| European Russia | 325 | 308 | 293 |
| Timan-Pechora | 270 111111 |
246 111111 |
228 111111 |
| Total for Russia | 1,809 111111 aaaaaa |
1,738 111111 aaaaaa |
1,664 111111 aaaaaa |
Our exploration drilling in Russia in 2006 totalled 139,000 metres in 2006, which yielded eight new oil fields and one new gas condensate field. We also carried out 9,240 kilometres (5,741 miles) of 2D seismic exploration and 2,848 square kilometres (1,100 square miles) of 3D seismic exploration in 2006. Our exploration costs in Russia totalled \$286 million in 2006. Our development costs in Russia totalled \$3,935 million in 2006. We estimate 2007 capital expenditures in our exploration and production segment will be approximately \$5.4 billion, with approximately \$700 million of that outside of Russia. Exploration and production expenditures will target the most promising exploratory prospects in the Caspian region, major development projects in Timan-Pechora region and the maintenance and/or increase of production from existing fields in Western Siberia and other regions. We may revise these allocations to reflect the results of our exploration activities.
The Western Siberia basin is located approximately 1,900 kilometres (1,180 miles) east of Moscow and extends over an area of approximately 3.1 million square kilometres (1.2 million square miles). The basin is bordered on the west by the Ural Mountains, on the south by the Kazakhstan plate and on the east by the Siberian plate, is open to the north and extends under the Kara Sea. Our Western Siberia crude oil production operations accounted for approximately 67.1% of our domestic crude oil production in 2006. Our core gas producing area in Russia is the Bolshekhetskaya depression in the Yamal-Nenets Autonomous District in Western Siberia.
Our Western Siberia production operations are conducted principally through LUKOIL-Western Siberia, a wholly owned consolidated subsidiary which has several crude oil production units and one natural gas production unit. As at 1 January 2007, LUKOIL-Western Siberia had estimated proved crude oil reserves of 8,032.7 mmbls (1,095.9 million tonnes) and estimated probable crude oil reserves of 4,969.2 mmbls (677.9 million tonnes). As at the same date, LUKOIL-Western Siberia had estimated proved natural gas reserves of 14,676.9 bcf (415.7 bcm) and estimated probable natural gas reserves of 6,985.2 bcf (197.8 bcm). LUKOIL-Western Siberia produced 394.0 mmbls (53.3 million tonnes) of crude oil in 2006.
In April 2005, through LUKOIL-Western Siberia's natural gas production unit, we started producing natural gas from the Nakhodkinskoye field in the Bolshekhetskaya depression. In 2006, our production of gas available for sale from this field was 293.1 bcf (8.3 bcm). Beginning in May 2006, we have sold a portion of our production from the Nakhodkinskoye field in Western Siberia to Gazprom. In addition, we signed a gas supply agreement with Gazprom under which Gazprom committed to purchase at least 282.5 bcf (8.0 bcm) from the Nakhodkinskoye field in 2007. In March 2005, we signed a general agreement on strategic partnership with Gazprom for the period from 2005 to 2014. Under this agreement, among other things, we agreed to jointly pursue oil and gas exploration and development projects in the Yamal-Nenets Autonomous District and the Nenets Autonomous District in Western Siberia, as well as the Russian sector of the Caspian Sea, the Republic of Uzbekistan and certain other regions.
We own 100% of Geoilbent, which produces crude oil from the Prisklonovoye, North-Gubkinsoye and South-Tarasovskoye fields in Western Siberia. We acquired 66% of Geoilbent from NOVATEK for \$180 million in July 2005 and the remaining 34% in January 2007. In 2005 and 2006, we accounted for our investment in Geoilbent using the equity method of accounting. As at 1 January 2007, our share of Geoilbent's estimated proved crude oil reserves was 57.8 mmbls (7.9 million tonnes) and estimated probable crude oil reserves was 105.8 mmbls (14.4 million tonnes). As at the same date, our share of Geoilbent's estimated proved natural gas reserves was 2.9 bcf (0.1 bcm) and estimated probable natural gas reserves was 861.6 bcf (24.4 bcm). Our share of Geoilbent's crude oil production in 2006 was 6.1 mmbls (0.8 million tonnes).
We effectively own 73.05% of LUKOIL-AIK, which produces crude oil from three fields in Kogalym in Western Siberia. As at 1 January 2007, LUKOIL-AIK had estimated proved crude oil reserves of 227.2 mmbls (31.0 million tonnes) and estimated probable crude oil reserves of 143.1 mmbls (19.5 million tonnes). LUKOIL-AIK produced 19.7 mmbls (2.6 million tonnes) of crude oil in 2006.
We also own 63.78% of RITEK, which has operations in both Western Siberia and European Russia. RITEK's production in Western Siberia is included under "Western Siberia" in the table above setting out our daily crude oil production in Russia. As at 1 January 2007, RITEK had estimated proved crude oil reserves in Western Siberia of 227.1 mmbls (31.0 million tonnes) and estimated probable crude oil reserves in Western Siberia of 121.8 mmbls (16.6 million tonnes). RITEK produced 14.6 mmbls (1.9 million tonnes) of crude oil in Western Siberia in 2006.
In June 2006, we acquired KMOC from Marathon Oil Corporation for \$847 million, including a \$249 million repayment of KMOC debt. At the time of our acquisition, KMOC owned 95% of OAO Khantymansiysknetegazgeologia and 100% of OAO Paitykh Oil and OAO Nazymgeodobycha, which have exploration and production interests in the Khanty-Mansiysk Autonomous District of Western Siberia. The KMOC companies are currently undergoing an internal restructuring as a result of which their assets will be owned by a number of entities within our Group. We expect to complete the restructuring of the KMOC companies during the second half of 2007. As at 1 January 2007, the KMOC companies had estimated proved crude oil reserves of 219.0 mmbls (29.9 million tonnes) and estimated probable crude oil reserves of 288.4 mmbls (39.3 million tonnes). From the date of our acquisition of KMOC, the KMOC companies produced 6.8 mmbls (0.9 million tonnes) of crude oil in 2006.
Our production of crude oil in European Russia, based in the Volga-Ural basin, accounted for approximately 18% of our domestic production in 2006. The Volga-Ural basin is located approximately 800 kilometres (500 miles) southeast of Moscow and includes an area of approximately 700,000 square kilometres (270,000 square miles) which includes the Russian cities of Volgograd, Astrakhan, Perm and Samara. The basin is a regional uplift of the east-central part of Russia and is bounded on the east by the Ural Mountains, on the south by the Pre-Caspian basin, and on the west by the Baltic basin.
We have three principal wholly owned production subsidiaries in the European Russia region: LUKOIL-Perm, LUKOIL-Nizhnevolzhskneft (in the Volga-Ural basin) and LUKOIL-Kaliningradmorneft (in the Baltic basin). As at 1 January 2007, these three companies and their subsidiaries had estimated proved crude oil reserves of 2,452.4 mmbls (334.6 million tonnes) and estimated probable crude oil reserves of 422.3 mmbls (57.6 million tonnes). These three companies and their subsidiaries produced 114.4 mmbls (15.5 million tonnes) of crude oil in 2006.
RITEK's European Russia production is included under "European Russia" in the table above setting out our daily crude oil production in Russia. As at 1 January 2007, RITEK had estimated proved crude oil reserves in European Russia of 150.8 mmbls (20.6 million tonnes) and estimated probable crude oil reserves in European Russia of 41.1 mmbls (5.6 million tonnes). RITEK produced 4.4 mmbls (0.6 million tonnes) of crude oil in European Russia in 2006.
In 2005, we acquired 51% of Primorieneftegaz, which has subsoil licences in the Poimenny block, located between the Volga and Akhtuba rivers in European Russia. We acquired the remaining 49% of Primorieneftegaz in May 2006. The Tsentralno-Astrahanskoye field was discovered on this block in 2004. We conducted 2D and 3D seismic exploration work at this field in 2006. As at 1 January 2007, Primorieneftegaz had estimated probable natural gas reserves of 3,782.5 bcf (107.1 bcm) and estimated probable crude oil reserves of 624.4 mmbls (85.2 million tonnes). Primorieneftegaz has not yet started producing crude oil or natural gas.
Our production of crude oil in Timan-Pechora accounted for approximately 14.9% of our domestic production in 2006. Our Timan-Pechora oil production operations include properties located in northern Russia in the Timan-Pechora basin, which is Russia's third largest region in terms of crude oil reserves. The Timan-Pechora basin is located approximately 1,100 kilometres (684 miles) northeast of Moscow in northwestern Russia. The region covers approximately 777,000 square kilometres (300,000 square miles) and is a triangular-shaped basin bounded on the east by the Ural Mountains and on the southwest by the Timan ridge and extends beneath the Barents Sea to the north.
Currently, our key assets in Timan-Pechora are held through LUKOIL-Komi, LUKOIL-Sever and NMNG. LUKOIL-Komi holds most of our exploration and development licences in Komi, which relate to fields generally located in the southern portion of Timan-Pechora. As at 1 January 2007, LUKOIL-Komi and its subsidiaries had estimated proved crude oil reserves of 2,203.4 mmbls (300.6 million tonnes) and estimated probable crude oil reserves of 484.7 mmbls (66.1 million tonnes). LUKOIL-Komi and its subsidiaries produced 85.3 mmbls (11.7 million tonnes) of crude oil in 2006.
LUKOIL-Sever operates in the Nenets Autonomous District. As at 1 January 2007, LUKOIL-Sever had estimated proved crude oil reserves of 210.8 mmbls (28.8 million tonnes) and estimated probable crude oil reserves of 219.8 mmbls (30.0 million tonnes). LUKOIL-Sever produced 9.6 mmbls (1.4 million tonnes) of crude oil in 2006.
In December 2001, we established NMNG as a wholly owned subsidiary to hold our subsoil licences in the northern portion of Timan-Pechora and in the Arkhangelsk region. As part of our efforts to develop our reserves in Timan-Pechora, we entered into a joint venture agreement with ConocoPhillips in September 2004, pursuant to which it acquired a 30% interest in NMNG. Under the terms of the joint venture agreement, ConocoPhillips paid us an acquisition price of \$529 million for a 30% interest in the joint venture's oil and gas resources, which included payment for its 30% share of working capital and for its 30% share of our capital investments in the joint venture's fields from 1 January 2004. The joint venture is governed jointly by ConocoPhillips and us. As at 1 January 2007, NMNG had estimated proved crude oil reserves of 1,081.8 mmbls (147.6 million tonnes) and estimated probable crude oil reserves of 606.7 mmbls (82.8 million tonnes). NMNG produced 3.5 mmbls (0.5 million tonnes) of crude oil in 2006.
We have licences to explore and develop certain areas of the Russian portion of the Caspian Sea. The licensed area comprises approximately 8,000 square kilometres (4,971 square miles). The majority of our northern Caspian hydrocarbons reserves relate to gas production. As at 31 December 2006, we had drilled a number of exploratory wells on several of our northern Caspian fields and discovered hydrocarbon deposits in each of these fields. As at 1 January 2007, we had 5,786.4 bcf (163.9 bcm) of proved and 8,565.2 bcf (242.6 bcm) of probable gas reserves in the northern Caspian region. We intend to continue drilling exploratory wells and to begin developing our new reserves in the near term.
In July 2003, we established a joint venture with Gazprom to develop fields in the Russian sector of the Caspian Sea. The main goal of the joint venture is to develop the Tsentralnaya geological structure in the Caspian Sea jointly with KazMunaiGaz, Kazakhstan's national oil company. In March 2005, we signed a joint venture agreement with KazMunaiGaz for the joint development of the Khvalynskoye field located in the northern part of the Caspian Sea. Each party has a 50% interest in the joint venture. We have commenced preparations to conduct a feasibility study for development of the field.
In November 2005, we discovered a new field in the northern Caspian region with potentially significant crude oil reserves. The field, named the Viktor Filanovsky field after a prominent Russian oilman, is a multilayer oil and gas condensate field in the Severny licence area in the northern part of the Caspian Sea. We continued our exploration activities at the field in 2006 and, through a second exploration well, we confirmed crude oil deposits in a previously discovered stratum as well as in an additional stratum at this field. The Filanovsky field is the first predominantly oil field within our northern Caspian licensed areas. The other five fields which we have discovered in the northern Caspian region contain primarily gas reserves. As at 1 January 2007, our estimated proved crude oil reserves in the northern Caspian region were 448.3 mmbls (61.2 million tonnes), and our estimated probable crude oil reserves were 598.4 mmbls (81.6 million tonnes). As at 1 January 2007, the Filanovsky field had estimated proved crude oil reseves of 268.0 mmbls (36.6 million tonnes) and estimate proved gas reserves of 325.6 bcf (9.2 bcm). As at the same date, the Filanovsky field had estimated probable crude oil reserves of 327.6 mmbls (44.7 million tonnes) and estimated probable gas reserves of 318.4 bcf (9.0 bcm).
As part of our long-term corporate development programme, we aim to increase our reserves and production from international operations to diversify our geographic and transportation risks and cost base. Our primary international areas of focus are currently Kazakhstan and Uzbekistan. We also have interests in international projects in Africa, the Middle East, South America and elsewhere in the CIS.
Exploration drilling at our international projects totaled 23,000 metres in 2006. In addition, 1,333 kilometres (828 miles) of 2D seismic exploration and 270 square kilometres (104 square miles) of 3D seismic exploration were carried out at our international projects in 2006.
The following table sets out our share of the crude oil and natural gas reserves as at 1 January 2007 of each of our international projects with proved and/or probable reserves.
| Our Share of Crude Oil Reserves as at 1 January 2007 (mmbls) 1111111111111111111111 |
Our Share of Gas Reserves as at 1 January 2007 (bcf) |
||||
|---|---|---|---|---|---|
| Area 11111111111111111 |
Our Equity Interest 11111 |
Proved 11111 |
Probable 11111 |
Proved 11111 |
Probable 11111 |
| Azerbaijan | |||||
| Shakh-Deniz1 | 10.0% | 10.5 | 11.5 | 314.2 | 272.5 |
| Kazakhstan | |||||
| Caspian Investments Resources2 | 100.0% | 209.7 | 76.2 | 0.0 | 0.0 |
| Karachaganak1 | 15.0% | 172.5 | 2.5 | 1,202.8 | 55.9 |
| Kumkol3 | 50.0% | 79.4 | 4.5 | 12.6 | 0.7 |
| Tengiz and Korolevskoye3 | 2.7% | 119.7 | 42.8 | 154.6 | 0.0 |
| Uzbekistan | |||||
| Kandim-Khauzak-Shady | 100.0% | 7.9 | 1.7 | 2,758.3 | 596.7 |
| Egypt4 | |||||
| Meleiha1 | 24.0% | 2.4 | 0.0 | 0.0 | 0.0 |
| WEEM 1111111111 |
100.0% | 5.9 11111 |
0.0 11111 |
0.0 11111 |
0.0 11111 |
| Total International | 608.0 | 139.2 | 4,442.5 | 925.8 |
Notes:
(1) Consolidated on a proportionate basis.
(2) On 20 April 2007, we sold 50% of Caspian Investments Resources to Mittal Investments S.a.r.L.
(3) Accounted for using the equity method.
(4) We are responsible for 24% of the costs of the Meleiha project and 100% of the costs of the WEEM project. See "– Egypt" for more information.
In 2006, our international crude oil production accounted for approximately 6.1% of our total crude oil production and our international production of gas available for sale accounted for approximately 8.7% of our total production of gas available for sale. The following table sets out our share of the crude oil production and natural gas production available for sale in 2006 at each of our international projects currently in production.
| Our Share of Oil Production (mbls per day)1 |
Our Share of Gas Production Available for sale (mmcf per day)1 1111111111111111111111 |
||||
|---|---|---|---|---|---|
| Year ended 31 December | |||||
| Area 11111111111111111 |
Our Equity Interest 11111 |
2006 11111 |
2005 11111 |
1111111111111111111111 2006 11111 |
2005 11111 |
| Azerbaijan | |||||
| Shakh-Deniz2 | 10.0% | 0.01 | – | – | – |
| Kazakhstan | |||||
| Caspian Investments Resources3 | 100.0% | 39.32 | 7.34 | – | 0.23 |
| Karachaganak2 | 15.0% | 31.20 | 30.99 | 97.18 | 94.70 |
| Kumkol4 | 50.0% | 35.86 | 31.56 | 3.97 | 5.26 |
| Tengiz and Korolevskoye4 | 2.7% | 7.26 | 8.00 | 13.84 | 16.68 |
| Egypt5 | |||||
| Meleiha2 | 24.0% | 0.84 | 0.95 | – | – |
| WEEM 1111111111 |
100.0% | 3.07 11111 |
3.22 11111 |
– 11111 |
– 11111 |
| Total International | 117.56 | 82.06 | 114.99 | 116.87 |
Notes:
(1) Production figures include imputed volumes based on our share of revenues attributable to cost and profit of oil and gas volumes and the weighted average commodity prices at the point of sale.
(2) Consolidated on a proportionate basis.
(3) On 20 April 2007, we sold 50% of Caspian Investments Resources to Mittal Investments S.a.r.L.
(4) Accounted for using the equity method.
(5) We are responsible for 24% of the costs of the Meleiha project and 100% of the costs of the WEEM project. See "– Egypt" for more information.
We participate in one of our exploration and production projects in Kazakhstan through LUKARCO, a joint venture with BP. We participate in four of our projects in Kazakhstan through Caspian Investments Resources, which we acquired in 2005 (under the name Nelson Resources Limited). On 20 April 2007, we sold 50% of Caspian Investments Resources to Mittal Investments S.a.r.L. We participate in our remaining international projects through other subsidiaries.
LUKARCO. The purpose of the LUKARCO joint venture was to enable us to cooperate with Atlantic Richfield Company, which has since been acquired by BP, in various exploration and development projects and in the development of related infrastructure in certain areas of Russia (including the northern Caspian region) and in other states of the former Soviet Union. Pursuant to the agreement, LUKARCO, a Dutch joint venture company was formed. We have a 54% interest in LUKARCO. BP owns the remaining 46%. Both parties, however, have equal voting rights in relation to all decisions taken by the joint venture.
Under the terms of the joint venture agreement, we must offer most upstream projects within the agreed areas to LUKARCO before offering them to any other non-Russian entity. Investments in projects are to be made either through LUKARCO itself or through one of LUKARCO's affiliates or an affiliate of one of LUKARCO's shareholders. Under the joint venture agreement, BP will make available up to \$4.5 billion in the form of debt financing for projects, and LUKOIL and BP will make available up to a total of \$500 million in the form of equity investments. We may guarantee some of the loans made by BP and we may be required to give performance guarantees in relation to certain projects. LUKARCO currently has a 5% interest in the Tengiz project in Kazakhstan and a 12.5% interest in the CPC. See "– Crude Oil Transportation – Pipelines" for more information about our participation in the CPC.
Caspian Investments Resources. In 2005, we acquired 100% of Nelson Resources Limited for approximately \$1,951 million, with substantial operations in Kazakhstan, which we have since renamed Caspian Investments Resources. On 20 April 2007, we sold 50% of Caspian Investments Resources to Mittal Investments for \$980 million. In addition, Mittal Investments committed to repay 50% of the Caspian Investments Resources' outstanding debt, which consisted of inter-company debt to other members of our Group and, as at the date of the sale, was approximately \$175 million. Through Caspian Investments Resources, we have an effective 25% interest in three of our projects in Kazakhstan (Arman, Buzachi Operating and Kazakhoil-Aktobe) and an effective 50% interest in the KarakudukMunai project in Kazakhstan. Caspian Investments Resources also entered into an agreement in November 2006 under which it will acquire, subject to the satisfaction of certain conditions, 25% of Zhambai Company from KazMunaiGaz, which would give us an effective 12.5% interest in the company. The company has interests the South Zhambai and South Zaburunye blocks, two geological exploration blocks in the Kazakh sector of the Caspian Sea.
D-222 (Yalama). We have an 80% interest in the D-222 Yalama project, offshore of Azerbaijan. We hold an exploration and production licence relating to this field and act as the operator for the project. The State Oil Company of Azerbaijan (SOCAR) owns a 20% stake. We drilled the first exploratory well at this field in 2005, which was a dry hole.
Shakh-Deniz. We have a 10% interest in a PSA to develop the Shakh-Deniz area of Azerbaijan. BP is the operator of the project and has a 25.5% interest in the PSA. The other companies with interests in the PSA are Statoil (25.5%), Total (10%), National Iranian Oil Company (10%), Turkish Petroleum (9%) and SOCAR (10%). Gas and condensate were encountered in the first exploratory well drilled in 1999. Further successful gas condensate wells were announced in early 2000, and commercial reserves were discovered in March 2001. In 2003, the operator commenced a stage-by-stage field development plan including a pre-drilling programme. In December 2006, the PSA consortium began commercial production of hydrocarbons from the first production well in the Shakh-Deniz field.
Arman. Caspian Investments Resources has a 50% interest in the PSA related to the development of the Arman field, giving us an effective 25% interest. Shell holds the remaining 50% interest in the PSA, which has a term of 30 years. The Arman field is located approximately 200 kilometres north of the Caspian Sea port of Aktau in Kazakhstan.
Atashsky Area. In January 2004, we signed an agreement with KazMunaiGaz and KazMunaiTeniz to conduct a geological survey on the Atashsky area, which covers approximately 9,700 square kilometres (3,745 square miles), on a parity basis. In 2006, we continued seismic exploration and our analysis of data from an exploration well in the area.
Buzachi Operating. Caspian Investments Resources has a 50% interest in the PSA related to the Buzachi Operating project to develop the North Buzachi field, giving us an effective 25% interest. CNPC International holds the remaining 50% interest in the PSA, which has a term of 25 years. The North Buzachi field is located approximately 180 kilometres north of Aktau in Kazakhstan. In 2006, the North Buzachi project commissioned 113 new production wells, and a new export pipeline was brought into operation for delivery of oil from the field to the KazTransOil transport system.
Karachaganak. The Karachaganak field was discovered in 1979 and has been operated under a PSA by the Karachaganak Petroleum Operating joint venture (KPO) since 1997. The term of the PSA is 40 years. We have a 15% interest in the joint venture. Our partners are BG Group (32.5%), Agip (32.5%) and Chevron (20%). BG Group and Agip jointly manage the operations for KPO. In 2006, a new more efficient oil export route was developed, carrying oil from Karachaganak to Samara, from where it can be delivered to the Transneft pipeline either to the Black Sea and Baltic Sea ports or directly to Central Europe via the Druzhba pipeline. The Karachaganak consortium plans to carry out preparatory work for expansion of production capabilities in 2007.
KarakudukMunai. Caspian Investments Resources has a 100% interest in the KarakudukMunai project to develop the Karakuduk field, giving us an effective 50% interest. At the time of our acquisition of Caspian Investments Resources, it had an effective 76% interest in the project, including through its 60% ownership of Chaparral Resources. In September 2006, Caspian Investments Resources acquired the remaining 40% of Chaparral Resources, giving it a 100% interest in the project. The Karakuduk field is located approximately 365 kilometres northeast of Aktau in Kazakhstan. In 2006, construction of an oil loading facility and terminal was completed, three new production wells were commissioned and a project for utilisation of petroleum gas was agreed with the relevant Kazakh governmental agencies.
Kazakhoil-Aktobe. Caspian Investments Resources has a 50% interest in the joint venture related to the Kazakhoil-Aktobe project to develop the Alibekmola and Kozhasai fields, giving us an effective 25% interest. KazMunaiGaz holds the remaining 50% interest in the joint venture, which has a term of 25 years. The Alibekmola and Kozhasai fields are located approximately 260 and 320 kilometres, respectively, south of Aktobe in Kazakhstan. A total of 11 wells were brought into operation as part of this project in 2006. Work continues on implementation of a project for utilisation of petroleum gas from the fields.
Kumkol. The Kumkol field was discovered in February 1983 and commenced production in May 1990. The northern portion of the field, known as Kumkol North, is defined by a separate licence issued in 1995 for a 25 year term. We have a 50% interest in Turgai Petroleum, which owns a 100% interest in and is the operator of Kumkol North. Our partner is CNPC, which owns the other 50% interest. The agreement relating to this project was entered into in April 1996 for a term expiring on December 20, 2020. Production at Kumkol North commenced in September 1995. In order to reduce oil transportation costs, a separate consortium formed by Turgai Petroleum and PetroKazakhstan constructed the 176.1-kilometre (109.4-mile) long Kumkol-Djusali oil pipeline system connecting the field to the Djusali oil loading terminal.
Tengiz. The Tengiz field was discovered in 1979 and has been operated under a project agreement by the TengizChevroil joint venture since 1993. LUKARCO has a 5% interest in the project, giving us an effective 2.7% interest. The project agreement has a term of 40 years. Our partners in this project include Chevron (50%), Exxon Mobil (25%) and KazMunaiGaz (20%).
Tyub-Karagan Area. In January 2004, we signed an agreement with KazMunaiGaz and KazMunaiTeniz under which we acquired a 50% interest in the PSA for the Tyub-Karagan area. The PSA for the Tyub-Karagan project has a term of 40 years. The Tyub-Karagan area is located in the central part of the Kazakhstan sector of the Caspian Sea and covers more than 1,350 square kilometres (839 square miles). 2D seismic surveys in the area were started in 2004, and we began drilling the first exploration well in May 2005. Exploration conducted at this well did not result in any oil and gas discoveries and the well was abandoned in August 2005. We continued our exploration activities in the area in 2006.
Zhambai. In November 2006, Caspian Investments Resources entered into an agreement with KazMunaiGaz pursuant to which it will acquire, subject to the satisfaction of certain conditions, 25% of Zhambai Company, which would give us an effective 12.5% interest in the company. Zhambai Company is currently owned 75% by KazMunaiGaz and 25% by Repsol YPF and has interests in the South Zhambai and South Zaburunye blocks, two geological exploration blocks in the Kazakh sector of the Caspian Sea. The total area of these blocks exceeds 2,000 square kilometres (772 square miles). The results of 2D seismic work indicate the presence of three structures we believe may contain deposits of hydrocarbons.
Aral Sea. In September 2005, we entered into an agreement with a consortium including Uzbekneftegaz (the Uzbek national oil company), Petronas Carigali Overseas (Indonesia), CNPC (China) and Korea National Oil Corporation. Pursuant to the agreement, the consortium signed a PSA in August 2006 with the government of Uzbekistan on the exploration and development of oil and gas fields in the Uzbek sector of the Aral Sea. Our share in the PSA is 20%.
Kandim-Khauzak-Shady. In June 2004, we signed a PSA with the National Holding Company Uzbekneftegaz on the Kandim-Khauzak-Shady project for the production of natural gas in the Bukharo-Khivinsky Region in southwestern Uzbekistan. The Kandim group of fields includes the Khauzak, Shady and Kungradskiy licence areas. We have a 100% interest in the PSA. Under the PSA, Uzbekneftegaz is entitled to a royalty of 10% of crude oil production. The term of the PSA is 35 years and estimated capital expenditures are \$1 billion. The first commercial production of natural gas is expected to commence in the fourth quarter of 2007. The project provides for the construction of a modern gas-chemical complex with a capacity of 211.9 bcf (6.0 bcm) per year, the first phase of which is scheduled to be completed in 2010.
In July 2006, we acquired a 63% interest in an exploration, development and production project on the deepwater block CI-205 offshore Cote d'Ivoire in the Gulf of Guinea from Oranto Petroleum International Ltd., a Nigerian company. Oranto International retained a 27% interest in the project. The National Petroleum Company of Cote d'Ivoire, PETROCI Holding, holds the remaining 10% of the project. The size of the block is 2,600 square kilometres (1,004 square miles) and its distance to shore is approximately 100 kilometres (62 miles). The PSA for this block was signed in July 2001. The exploration period is split into three phases with combined duration of seven years, and at present, the project is in the second exploration phase, in which the consortium is required to drill an exploration well. Upon a discovery of hydrocarbons, the block's development period will be 25 years with a possible extension for an additional ten years. Over the past five years, 2,600 square kilometres of 3D seismic and 4,900 line kilometres of 2D seismic data was acquired.
Meleiha. The Meleiha block consists of four main oil fields located in the western desert of Egypt. We are responsible for 24% of the costs of the project. To cover our costs, we receive a share in the "profit oil" from the project. In 2006, our share in the "profit oil" from the project was 5.03%. Our partners in the project are Egypt General Petroleum Corporation (EGPC) (56%) and the IFC (20%). Eni is the operator of the project.
WEEM Block. The West Eshet-Malahha (WEEM) is an oil and gas development concession in Egypt. We are responsible for 100% of the costs of the project. To cover our costs, we receive a share in the "profit oil" from the project. In 2006, our share in the "profit oil" from the project was 30.83%. The other party to the concession agreement is EGPC.
Anaran. In February 2003, we signed an agreement with Exploration and Production International, a division of the Norwegian company Norsk Hydro ASA for the exploration and production of the Anaran prospective onshore block located in western Iran. Our participation in the project was approved by the National Iran Oil Company (the NIOC) in September 2003. We have a 25% interest in the project and Norsk Hydro holds the remaining 75% interest. The Anaran block has four prospective structures with significant potential hydrocarbon reserves: Azar, Changuleh-West, Dehloran and Musian. Exploratory drilling has begun, and plans for transport infrastructure are under way. In December 2005, after analysing the results of exploration drilling of the Azar structure, we confirmed a major discovery on the Anaran exploration block. In June 2006, the NIOC signed a commercialisation report for Azar giving Norsk Hydro and us the exclusive right to negotiate to further develop the field. Negotiations and the drafting of the overall field development plan are expected to be completed in the second quarter of 2007.
Mogan and Lali. In February 2006, we signed a contract with the NIOC regarding joint geological and geophysical work at the Mogan and Lali oil and gas blocks in Iran. The work will include reprocessing and interpretation of drilling data, borehole logging measurements, exploration and geochemical rock studies.
West Qurnah-2. We have a 68.5% interest in a PSA relating to the development of the second stage of the West Qurnah oil field in Iraq. In connection with our strategic alliance with ConocoPhillips, subject to confirmation and the consents of governmental authorities and the parties to the PSA, we expect to enter into further agreements regarding the assignment of a 17.5% interest in the PSA to ConocoPhillips, which would reduce our effective interest to 51%. The PSA requires the parties to make a total investment of at least \$6 billion on a pro rata basis. As a result of the political situation in Iraq, we delayed our performance of certain obligations under the agreement. In December 2002 the former government of Iraq purported to terminate the PSA. Following the military campaign in Iraq in 2003, the provisional Iraqi administration expressed a desire to honour its obligations under the PSA. However, the future of our rights under the agreement remains uncertain. We cannot assure you that we will retain our rights under the PSA or that we will be able to begin developing the field when we are granted such opportunity by the Iraqi authorities or at any time after that. Because of the uncertainties surrounding our development of this field, no operating information relating to it has been included in this prospectus.
Block A. In March 2004, we signed an upstream agreement with a term of 40 years for the exploration, development and production of non-petroleum gas and condensate in Block A, an area in central Saudi Arabia near the Ghawar field, the world's largest oil field. We hold an 80% interest in the agreement. Saudi Aramco, the Saudi Arabian state oil company, holds the remaining 20% interest. Prior to 2009, we plan to drill nine exploration wells and our exploration works will cover 8,750 kilometres (5,437 miles). We began drilling the first exploration well in January 2006, after we had reprocessed vintage seismic data and conducted 2D and 3D seismic surveys. We announced our discovery of hydrocarbon accumulations in February 2007. Currently, we are commencing our detailed appraisal of the discovery to further evaluate its composition and potential. We expect that any gas produced from Block A will be supplied to Saudi Arabia's domestic market.
Condor Block. In June 2002, we signed a joint exploration agreement with Ecopetrol, Colombia's state-owned oil company, for the exploration and development of the Condor block in eastern Colombia. We have a 70% interest in the project. The total area of the block measures 3,089 square kilometres (1,193 square miles), and it is situated in the foothills of the Andes in the western part of the Llanos oil and gas basin. Based on the results of our exploration activities to date, we believe that the Condor block has potentially recoverable hydrocarbon deposits located in up to seven separate structures. In February 2007, we announced the discovery of potentially commercially recoverable crude oil reserves in the Medina structure of the Condor block. Reserves in this field will be estimated following analysis of information obtained during previously conducted drilling and after further exploration drilling.
Junin-3. In 2005, we signed an agreement with the National Oil & Gas Company of Venezuela (the PDVSA) to conduct exploration work at the Junin-3 block in Venezuela for a three-year period. The total block area is 640 square kilometres. In October 2005, we commenced the first stage of a project to measure and certify reserves at heavy oil fields located within the Junin-3 block. In June 2006, we and PDVSA completed the first stage of the project and in December 2006, we commenced the second stage of the project.
We recently signed a memorandum of understanding with Qatar Petroleum, pursuant to which we will work together to explore opportunities for cooperation in new and existing oil and gas projects in Qatar. In August 2006, we signed a memorandum of understanding with Sonatrach, the Algerian state oil company, regarding cooperation in exploration and development of oil and gas fields in Algeria, Russia and elsewhere, refining and marketing of liquid hydrocarbons and hydrocarbon research. In October 2006, we signed a memorandum of mutual understanding with Sonangol, Angola's state-owned oil and gas company, which gives us the opportunity to participate in geological exploration projects on the Angolan continental shelf.
We use the Transneft pipeline system, our own pipeline network or interests in other pipelines, rail cars and tankers to transport the crude oil which we produce within Russia, for export outside of Russia and to our refineries. We transport most of our crude oil production in Western Siberia through the Transneft pipeline system. LUKOIL-Western Siberia's Uraineftegas production unit transports its high quality light low-sulphur crude oil directly from its production facilities via a dedicated Transneft pipeline network to the Black Sea port of Tuapse, thus avoiding the blending which would otherwise occur. Substantially all of our European Russia crude oil production is transported via Transneft or is exported by tanker. In Timan-Pechora, production from LUKOIL-Komi is transported through the Transneft pipeline. We transport production from other fields in Timan-Pechora via pipeline to our existing terminal at Varandey on the Barents Sea and then shipped via tanker to international markets. The following discussions sets out further details about the crude oil transportation infrastructure that we use.
Transneft. Most of our crude oil production is transported through the Transneft pipeline system. Transneft is a state-owned pipeline monopoly. The Russian government regulates access to Transneft's pipeline network. 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 which equals approximately 35% of its crude oil so produced and delivered. Some Russian companies are able to obtain excess export quota through extra allocation from Transneft or by purchasing quota from other oil companies.
The FTS is responsible for setting Transneft's fees, which have risen in recent years and may continue to rise. The overall cost of transporting crude oil through the Transneft pipeline system depends on the location of the fields in relation to the ultimate destination (including the length of the transport route and whether deliveries are for export or for domestic consumption). See "Regulation – Sources of Regulation of the Russian Oil Industry – Crude Oil and Refined Product Transportation Regime" for more information on crude oil transportation.
The crude oil which we transport through the Transneft pipeline system is blended with crude oil of other producers which may differ in quality. Our sales of crude oil which we transport through the Transneft system are of the crude oil blend which results from the combination of different types and qualities of crude oil in the system, which is usually referred to as "Urals blend" crude oil. Therefore, the price we get for our oil may be lower than the price we could get for oil of the same quality if we could transport our crude oil independently of Transneft. See "Risk Factors – Risks Relating to Our Business – We depend on monopoly providers of crude oil and refined product transportation services, and we have no control over the infrastructure they maintain or the fees they charge" for more information about the risks related to our transportation of crude oil through the Transneft pipeline system.
Domestic crude oil pipelines. To avoid the blending which occurs in the main Transneft system, we use alternative pipelines to the extent possible. For example, we transport the crude oil produced at LUKOIL-Western Siberia's Uraineftegas production unit, which is a high quality light low-sulphur crude oil, directly from its production facilities to the Black Sea port of Tuapse via a dedicated Transneft pipeline network. We transport crude oil which we produce at our LUKOIL-Komi subsidiary to the Transneft system through our Kharyaga-Usa pipeline, which has an annual capacity of 88.0 mmbls (12.0 million tonnes). The opening of additional capacity via the Transneftcontrolled Baltic Pipeline System to the port of Primorsk in April 2005 has enabled us to transport more crude oil for export.
Caspian Pipeline Consortium. LUKARCO has a 12.5% interest in the CPC pipeline, which is a 1,510-kilometre (932-mile) oil pipeline connecting oil fields in western Kazakhstan to the CPC's marine export terminal at the Black Sea port of Novorossiysk in Russia. Other parties involved in the CPC are the government of Russia (24%), the government of Kazakhstan (19%), Chevron (15%), Rosneft-Shell Caspian Ventures (7.5%), Exxon Mobil (7.5%), the government of Oman (7%), Agip (2%), BG Group (2%), Kazakhstan Pipeline Ventures (1.75%) and Oryx (1.75%). The pipeline has a capacity of approximately 650,000 bpd (32.4 tonnes per year). The CPC plans to expand the pipeline's capacity to 1,345 thousand bpd (67.0 million tonnes per year) by 2009. Crude oil produced from several of our projects, including our Karachaganak, Kumkol and Tengiz projects, is transported to the CPC terminal at Novorossiysk through the CPC pipeline.
The CPC operates a "quality bank" system, under which exporters who supply high-quality hydrocarbons receive a price premium, and those who supply lower-quality hydrocarbons receive a price discount, to the average blend transported through the CPC pipeline. The blend of oil transported through the CPC pipeline is referred to as "CPC blend", the price for which is quoted separately with a premium over Urals blend.
International Pipelines. The Caspian Sea is land-locked. The export of oil from this region is therefore dependent on onshore pipelines. Currently, hydrocarbons are exported from the Caspian Sea via a northern route through Azerbaijan and Russia to the Russian Black Sea port at Novorossiysk and via a western route through Azerbaijan and Georgia to the Black Sea port at Supsa. As production volumes increase as a result of development of fields in Azerbaijan, the export capacity of the current infrastructure will be insufficient.
Potential solutions to transportation volume restrictions include expanding the capacity of the western route from Baku to Supsa and expanding existing swap arrangements with Iran. The swap arrangements with Iran involve the transport of oil by barge for consumption in northern Iran, and an equal amount of oil to be shipped from Iranian oil fields further south to replace the oil shipped to northern Iran.
In 2003, the construction of the 176.1-kilometre (109.4-mile) long Kumkol-Djusali oil pipeline system and an oilloading terminal at Djusali were completed in order to reduce oil transportation costs from the Kumkol project in Kazakhstan and the permit to operate the pipeline was issued by the Kazakhstan Ministry of Energy and Mineral Resources.
During 2000, we constructed a temporary terminal at Varandey on the Barents Sea for trial loading of oil extracted in the Timan-Pechora region. Based upon the success of this temporary terminal we submitted draft plans to the administration of the Nenets Autonomous District for construction of a permanent sea terminal at the site in 2002. In 2003, we completed the preparation of a plan for the construction of the permanent sea terminal. Once constructed, we expect the sea terminal to have the capacity to receive and reload 240,000 bpd (12.0 million tonnes per year). We currently transport crude oil inbound to the temporary terminal by pipeline and outbound from this terminal with our ice-breaking tankers through the Barents Sea to the Dutch port of Rotterdam, a major European oil-trading centre. An expanded Varandey terminal is a key part of our strategy to increase our ability to transport oil to markets in Europe, the United States and southeast Asia. As part of our efforts to develop our reserves in Timan-Pechora, we entered into a joint venture agreement with ConocoPhillips in September 2004, pursuant to which we sold a 30% interest in NMNG to ConocoPhillips. Under the terms of our agreements, ConocoPhillips will also participate in the design and financing of the Varandey terminal.
In 2002, we commenced the construction of a terminal located in Vysotsk, Vyborg's outer harbour on the Baltic Sea. Construction of the third stage of the Vysotsk terminal was completed in September 2006. The terminal has a total capacity of approximately 233,000 bpd (11.6 million tonnes per year). With the opening of additional capacity via the Baltic Pipeline System in April 2005, we ceased exporting crude oil through the Vysotsk terminal and now only export refined products via the terminal. In April 2007, we signed a supplemental agreement to the June 2006 agreement with Russian Railways developing railway transportation infrastructure to increase the supply capacity of refined products to our Vysotsk terminal. We expect this additional infrastructure to be completed by the end of 2007. See "– Recent Developments – Refining, Marketing and Distribution" for more information on this agreement.
We also own export terminals at Ilyinka in the Astrakhan Region (with a total capacity of approximately 40,000 bpd (2.0 million tonnes per year)) and at the port of Svetly in the Kaliningrad Region (with a total capacity of approximately 120,000 bpd (6.0 million tonnes per year)). We transport crude oil and light refined products from our Volgograd refinery to our Ilyinka terminal for loading onto combined river and sea tankers. We use the Ilyinka terminal to supply our crude oil and certain refined products to Iran under swap arrangements.
As at 31 December 2006, we owned two ice-breaking tankers held through Kalingradmorneft. Our ice-breaking tankers are capable of operating in the northern and Arctic seas. In May 2006, we sold eight ice-breaking tankers used in our shipping operations for \$190 million. LITASCO now leases the eight tankers we sold and uses these tankers with its other leased vessels in its distribution activities for the Group. We intend to sell our remaining two ice-breaking tankers in July 2007.
In 2006, we shipped approximately 5.9 mmbls (0.8 million tonnes) of crude oil exports, or 1.8% of our total crude oil exports, by rail car, primarily via the Russian Railways rail network. For information about rail transportation of refined products via rail, see "– Refining, Marketing and Distribution – Refined product sales".
We transport most of our gas through UGSS, which is responsible for gathering, transporting, dispatching and delivering substantially all natural gas supplies in Russia and is owned and operated by Gazprom. The UGSS transports natural gas from fields in Western Siberia and the Volga region towards the more heavily populated regions of European Russia, and onward to other CIS countries and Europe. Under Russian law, Gazprom is obliged to provide third-party access to the UGSS as long as there is spare transport capacity at the relevant time and place requested, the proposed gas shipments meet established quality and technical standards, input and output connections and quality control stations are available and customer demand exists at the relevant time. Historically, Gazprom has been able to deny third-party gas producers access to the UGSS, citing a lack of spare capacity. According to RPI, Inc., UGSS has between 32 and 38 bottlenecks which limit transmission capacity and operational flexibility.
Gazprom's management board recently approved a proposal to expand and upgrade facilities as necessary to better accommodate access requests from third-party gas producers. The costs of these expansions and upgrades would be borne by the third-party gas producers, either through increased transportation tariffs or loans to Gazprom which would be repaid through reduced transportation tariffs. In either case, Gazprom will retain ownership and operation of the UGSS and may still be able to influence access to the UGSS by application of access criteria other than capacity constraints.
The refining, marketing and distribution segment of our business comprises refining, sales and other deliveries of crude oil, sales of refined products, gas processing and retail marketing of refined oil products.
In 2006, we refined a total of 48.9 million tonnes of crude oil at our own refineries. We also refined 3.3 million tonnes under contract with domestic third-party refineries, primarily at refineries in Ufa, and 1.7 million tonnes under contract with international third-party refineries in 2006. We currently produce more crude oil than we can refine at our own facilities.
As part of our strategy to participate in more stages of the hydrocarbon production chain, we intend to increase our refining capacity both in Russia and internationally, upgrade our refineries to produce higher volumes of higher-value light products such as gasoline, jet fuel and diesel fuel, and expand into petrochemicals. We intend to acquire and/or construct additional refining capacity in Russia and abroad. We will continue to evaluate refinery acquisition and construction opportunities both in Russia and internationally and will attempt to acquire and/or construct additional facilities if they meet our value creation criteria. We also intend to continue to invest in our refineries to expand their capacities and to upgrade the quality of refined products and the proportion of higher value light products to improve the profitability of these facilities and improve returns from our downstream business.
We own four oil refineries in Russia, located in Perm, Volgograd, Ukhta and Nizhny Novgorod. These refineries, along with our mini-refineries in Urai and Kogalym, have a combined refining capacity of approximately 44.1 million tonnes per year and in 2006 refined a total of 39.5 million tonnes of crude oil. Outside of Russia, we own refineries in Bulgaria and Romania, which have a combined refining capacity of approximately 11.2 million tonnes per year and in 2006 refined a total of 9.4 million tonnes of crude oil. We also own a refinery in Ukraine, which has been closed since August 2005 for a large-scale reconstruction programme. We expect the reconstruction to be completed in the fourth quarter of 2007 (at which time the refinery will be reopened). The reconstruction programme we have commenced at our Ukrainian refinery is part of a larger effort to upgrade and modernise all of our refineries to improve utilisation rates and depth of refining and to increase production of refined products which comply with the most stringent current environmental requirements. We have invested, and expect to continue to invest, substantial amounts on our modernisation efforts at our refineries. In October 2004, we put our Romanian refinery back into operation after an upgrade and modernisation programme. Once we complete the upgrades of all of our refineries, we believe that a significant portion of the refined products at our refineries will be in compliance with European Union standards currently and expected to be in effect and provide attractive integration opportunities with southeastern European markets.
| Year ended 31 December 1111111111111111111111 |
|||||
|---|---|---|---|---|---|
| Refinery 111111111 |
Refining Capacity 11111 |
2006 11111 |
2005 11111 |
2004 11111 |
|
| (throughput – million tonnes of oil) | |||||
| Russia | |||||
| Perm | 12.0 | 11.9 | 11.0 | 11.1 | |
| Volgograd | 11.0 | 9.6 | 9.2 | 9.0 | |
| Ukhta1 | 3.7 | 3.6 | 3.4 | 2.9 | |
| Nizhny Novgorod 2 | 17.0 | 14.2 | 13.5 | 12.3 | |
| Mini refineries | 0.4 | 0.2 | 0.2 | 0.2 | |
| International | |||||
| Odessa3 | 2.8 | – | 1.4 | 2.4 | |
| Burgas4 | 8.8 | 7.1 | 6.5 | 5.7 | |
| Petrotel5 | 2.4 11111 |
2.3 11111 |
2.4 11111 |
0.4 11111 |
|
| Total | 58.1 11111 aaaaa |
48.9 11111 aaaaa |
47.6 11111 aaaaa |
44.0 11111 aaaaa |
|
The following table provides current refining capacity and historical throughput at each of our refineries for 2004, 2005 and 2006.
Notes:
(1) We currently own 99.41% of the Ukhta refinery.
(2) We currently own 89.33% of the Nizhny Novgorod refinery.
(3) We currently own 99.57% of the Odessa refinery.
(4) We currently own 99.17% of the Burgas refinery.
(5) We currently own 94.66% of the Petrotel refinery.
The following table sets out our production of certain refined products in 2006 expressed as a percentage of our total refined products production volume (excluding production from our mini-refineries).
| 2006 1111 | |
|---|---|
| Motor gasoline | 14.6% |
| Diesel fuel | 30.4% |
| Jet fuel | 5.3% |
| Ship fuel | 3.5% |
| Heating fuel | 0.9% |
| Vacuum gas oil | 8.9% |
| Naphtha | 3.7% |
| Fuel oil | 22.8% |
| Bitumen | 3.0% |
| Lubricants | 2.7% |
| Coke | 1.4% |
| Other refined products | 2.8% 1111 |
| Total | 100% 1111 aaaa |
Perm. We own 100% of the Perm refinery, which we acquired in 1991. The refinery was built in 1958 and currently has a refining capacity of 12.0 million tonnes per year. The refinery processes a blend of crude oils from the northern part of the Perm region and from Western Siberia. It produces a range of products, including gasoline, jet fuel, diesel fuel, lubricants, fuel oil, fuel grade petroleum cokes and bitumen. The refinery's facilities include catalytic cracking, catalytic reforming, delayed coking, lubricants production and hydrotreating units. We invested \$95.4 million in 2004, \$70.0 million in 2005 and \$98.7 million in 2006 at our Perm refinery in connection with our efforts to upgrade and modernise all of our refineries. We have commenced a large-scale modernisation programme at the Perm refinery to increase refining depth and to increase the refinery's production of higher quality refined products. We expect to complete the programme by 2016. We supply crude oil to the Perm refinery from our fields in Western Siberia and from the Perm region through the Transneft pipeline network and local intra-field pipelines which feed into an on-site crude oil reservoir park. We transport products from the Perm refinery through the Perm-Andreevka-Ufa oil product pipeline and by rail, river-class tanker and truck.
Volgograd. We own 100% of the Volgograd refinery, which we acquired in 1991. The refinery was originally built in 1957 and currently has a refining capacity of 11.0 million tonnes per year. The refinery processes a light blend of West-Siberian and Lower-Volga crude oils. It produces a range of products, including gasoline, diesel fuel, fuel oil, electrode coke, lubricants and bitumen. The refinery's facilities include catalytic reforming, coke calcination, delayed coking, bitumen production and hydrotreating units. The refinery also has gas refining facilities with an annual capacity of 240,000 tonnes of natural gas liquids. We invested \$44.3 million in 2004, \$97.3 million in 2005 and \$112.4 million in 2006 at our Volgograd refinery in connection with our efforts to upgrade and modernise all of our refineries. In August 2005, we installed the first stage of a coke calcination facility at the Volgograd refinery with annual capacity of 100,000 tonnes of calcinated coke. The second stage will be commissioned in 2009, raising total capacity to 280,000 tonnes, which is sufficient for calcifying all of the coke produced at this refinery. In 2006, we completed the installation of the refinery's catalytic reforming unit, which enables the refinery to produce a higher portion of higher-octane gasoline. The investment programme for the Volgograd refinery includes the construction of an isomerisation unit, which will allow us to upgrade the quality of gasoline produced at the refinery. We supply crude oil to our Volgograd refinery from our fields in Western Siberia of the lower Volga region in European Russia through the Transneft pipeline system. The Volgograd refinery transports its refined products by rail, river-class tanker or truck.
Ukhta. We own 99.41% of the Ukhta refinery, which we acquired in 1999. The refinery was originally built in 1934 and has a refining capacity of 3.7 million tonnes per year. The refinery processes a blend of crude oils from Komi fields and Yareg heavy oil. It produces a range of products including gasoline, diesel, fuel oil and bitumen. The refinery's facilities include primary petroleum processing, catalytic reforming, bitumen production and diesel fuel hydrodeparafinisation units. The refinery also has a tank car loading rack for light refined products. We invested \$51.8 million in 2004, \$38.0 million in 2005 and \$36.9 million in 2006 at our Ukhta refinery in connection with our efforts to upgrade and modernise all of our refineries. In 2006, we completed an upgrade to the refinery's catalytic reforming unit, which increased the unit's annual capacity from 300,000 tonnes to 380,000 tonnes. The Ukhta refinery receives crude oil by pipeline and rail. Its refined products are stored prior to shipment in an on-site reservoir park and are shipped by rail.
Nizhny Novgorod. We own 89.33% of the Nizhny Novgorod refinery, which we acquired in October 2001. The Nizhny Novgorod refinery has a refining capacity of 17.0 million tonnes per year. The refinery processes a blend of West Siberian oils. The refinery's production includes gasoline, diesel fuel, fuel oil, vacuum gas oil, jet fuel, bitumen and lubricants. The refinery's facilities include isomerisation, catalytic reforming, hydrotreating, bitumen production and lubricants production units. We invested \$84.6 million in 2004, \$79.4 million in 2005 and \$210.1 million in 2006 at our Nizhny Novgorod refinery in connection with our efforts to upgrade and modernise all of our refineries. We began a complex reconstruction and modernisation programme in July 2005, a process which is scheduled for completion in 2010. Total capital expenditures on this project are estimated at \$600 million, most of which will be spent on construction of catalytic cracking, alkylation and vis-breaking units. As part of this programme, we completed the construction of a gasoline isomerisation unit in 2006, which will allow us to upgrade the quality of the gasoline produced at the refinery. In 2006, we also upgraded the refinery's atmospheric and vacuum distillation and hydrotreatment units. Together, these upgraded units will enable us to produce diesel fuel and gasoline that meet existing European Union requirements, including with respect to sulphur content. A dedicated pipeline connects the refinery directly to the Transnefteproduct system, the state-owned refined products pipeline, which makes transportation costs comparatively less expensive than rail transport.
Odessa. We own 99.57% of the Odessa refinery in Ukraine (OAO LUKOIL-Odessky NPZ), which we acquired in May 2000. The refinery was built in 1937 and currently has a refining capacity of 2.8 million tonnes per year. Prior to our acquisition of the refinery in May 2000, it had stopped production due to a lack of supply of crude oil. Immediately upon acquisition, we began supplying crude oil to the facility and production of refined products. The refinery processes Urals blend crude oil. The refinery's production includes gasoline, diesel fuel, jet fuel, fuel oil, vacuum gas oil and bitumen. The refinery's facilities include isomerisation, catalytic reforming, hydrotreating and bitumen production. We invested \$25.7 million in 2004, \$8.9 million in 2005 and \$17.9 million in 2006 at our Odessa refinery in connection with our efforts to upgrade and modernise all of our refineries. We completed reconstruction of the refinery's desalting and atmospheric and vacuum distillation unit in 2005. In August 2005, we closed the Odessa refinery to begin a large-scale reconstruction programme. The programme centres on installation of a vis-breaker and power generating facilities and overhaul of the atmospheric and vacuum distillation and hydrotreatment units. We expect to complete the reconstruction programme in the fourth quarter of 2007, after which the refinery will be reopened. After completion of the reconstruction programme, the refinery's annual crude refining capacity will remain at 2.8 million tonnes, but refining depth will be increased to 78% and production of fuel oil will be reduced in favour of high-value products such as vacuum gas oil and highoctane gasoline. Before we shut our Odessa refinery for the reconstruction programme, crude oil was delivered to the refinery by pipeline and its refined products were delivered by truck, rail or pipeline to the port of Odessa.
Burgas. We own 99.17% of the Burgas refinery in Bulgaria (AO LUKOIL Neftokhim Burgas). In October 1999 we acquired, together with a local partner, a 58% interest in the Burgas refinery from the Government of Bulgaria. In July 2000 we purchased our local partner's interest. We increased our ownership interest to its present level in various acquisitions from minority shareholders from 2002 through 2005. The Burgas refinery was built in 1964 and has a refining capacity of 8.8 million tonnes per year.
The Burgas refinery processes Urals blend crude oil and fuel oil from the Odessa refinery. It produces a range of products, including gasoline, jet fuel, diesel fuel and fuel oil. In January 2005, the refinery began production of diesel fuel and gasoline that meets existing European Union standards, including with respect to sulphur content. The refinery's facilities include primary refining, fluid catalytic cracking, catalytic reforming, thermocracking, hydrotreating and sulphuric acid alkylation units. The refinery's complex also includes a petrochemicals plant and a polymerisation plant which produce petrochemical products. See "– Petrochemicals Operations" for more information about the Burgas refinery's involvement in our petrochemicals operations.
We are currently in the process of implementing an investment programme for the Burgas refinery. We invested \$34.0 million in 2004, \$63.8 million in 2005 and \$89.1 million in 2006 at our Burgas refinery in connection with our efforts to upgrade and modernise all of our refineries.
The Burgas refinery is located 30 kilometres from a port terminal on the Black Sea. This location allows the refinery to receive crude oil shipments by sea, and also to deliver its products by sea in addition to truck, rail and product pipelines. Approximately 40% of the Burgas refinery's output is distributed into the Bulgarian market and 60% is exported, primarily to Turkey.
Petrotel. We own 94.66% of the Petrotel refinery in Romania (Petrotel LUKOIL S.A.), which we acquired in a series of transactions from 1998 through 2002. The refinery was built in 1927 and has a refining capacity of approximately 2.4 million tonnes. When we purchased our initial interest in Petrotel in 1998, it was operating on a profitable basis. However, a recession commenced in 1999 which caused demand for refined products in Romania to decline significantly so that demand was substantially lower than the country's total refinery capacity. As a result, the leading domestic producer of crude oil reacted by reducing the crude oil transfer price to its own refineries. The resulting decrease in refined product prices effectively forced Petrotel out of the domestic wholesale market and its market share fell from 38% in 1999 to 6% in 2001. In August 2001, we shut down the refinery. We engaged Purvin & Gertz, international energy consultants, to perform a review of the Romanian downstream oil industry and Petrotel's competitive position. As a result of this study we undertook a comprehensive reconstruction plan to improve the quality of gasoline produced and bring it up to European Union standards.
In October 2004, we put the refinery back into operation after an upgrade and modernisation programme at an estimated cost of \$120.7 million. We invested \$86.4 million in 2004, \$32.1 million in 2005 and \$55.6 million in 2006 at our Petrotel refinery in connection with our efforts to upgrade and modernise all of our refineries. The refinery processes Urals blend crude oil. It produces a range of products, including diesel fuel and gasoline, and adjusts its product mix to match demand on the market. Its diesel fuel and gasoline production meets existing European Union standards, including with respect to sulphur content.
We have two Russian mini-refineries in Urai and Kogalym (with a combined annual capacity of 400,000 tonnes), and we also use other refineries within and outside Russia to refine crude oil under contract. This arrangement provides us with additional capacity on an as-needed basis. These refineries included refineries in Ufa, the Naftan and the Mozyr Refinery in Belarus and the Panchevo Refinery in Serbia. In 2006, we refined 3.3 million tonnes of crude oil under contract with domestic third-party refineries. We also refined 1.7 million tonnes under contract with international third-party refineries in 2006.
We currently process our gas production at four facilities: the Korobkovsky gas processing plant (in the Volgograd Region), the Permneftegazpererabotka plant (in the Perm Region), the Usinsk gas processing plant (in the Komi Republic) and the Lokosovsky gas processing plant (in the Tyumen region). We own 100%, 100%, 87.5% and 100%, respectively, of each of these processing plants. Collectively, these facilities processed 91.8 bcf (2.6 bcm) of gas feedstock and 4.6 mmbls (0.6 million tonnes) of natural gas liquids and produced 70.6 bcf (2.0 bcm) of stripped gas, 705,000 tonnes of LPG and 631,000 tonnes of liquid hydrocarbons in 2006. The Lokosovsky gas processing plant is currently our main gas processing facility in Russia. We completed reconstruction work at this plant in 2006 to increase its gas processing capacity to 67.1 bcf (1.9 bcm) per year, which will enable us to process petroleum gas from our Western Siberia fields.
We sell the crude oil which we do not refine in the domestic market, which includes certain sales directed by the Russian government, and in the international market, which includes exports from Russia and sales outside of Russia of crude oil production from our international projects.
The table below sets out our domestic and international crude oil sales for 2004, 2005 and 2006.
| 1111111111111111111111111111111113 2006 111111111123 |
2005 111111111123 |
2004 111111111123 |
|||||
|---|---|---|---|---|---|---|---|
| (mmbls) | (\$ millions) | (mmbls) | (\$ millions) | (mmbls) | (\$ millions) | ||
| Russia | 13.3 | 376 | 4.9 | 120 | 12.0 | 181 | |
| International | 300.7 11111 |
17,649 11111 |
336.6 11111 |
16,367 11111 |
337.4 11111 |
10,940 11111 |
|
| Total | 314.0 11111 aaaaa |
18,025 11111 aaaaa |
341.5 11111 aaaaa |
16,487 11111 aaaaa |
349.4 11111 aaaaa |
11,121 11111 aaaaa |
We sold 13.3 mmbls (1.8 million tonnes) of crude oil within Russia in 2006.
We sold 300.7 mmbls (41.0 million tonnes) of crude oil outside of Russia in 2006. Our international sales are primarily to purchasers in Europe. In 2006, 85.7% of our international crude oil sales was through our subsidiary, LITASCO (and its wholly owned subsidiaries).
LITASCO, a wholly owned subsidiary of LUKOIL INTERNATIONAL GmbH, is our primary marketing vehicle for international sales of crude oil and refined products. LITASCO (and its wholly owned subsidiaries) had sales to third parties of 257.8 mmbls (35.2 million tonnes) of crude oil and 29.3 million tonnes of refined products in 2006.
Through LITASCO (and its wholly owned subsidiaries and branch offices) we:
LITASCO's international trading network includes offices located in 15 countries worldwide.
We sold a total of 83.9 million tonnes of refined products in 2006. We sell a wide range of refined products, including gasoline, diesel fuel, fuel oil and lubricants. In 2006, we sold 19.2 million tonnes, or 22.8%, of our refined products in the domestic market and 64.7 million tonnes, or 77.2%, internationally. The table below provides information on our refined product sales for 2004, 2005 and 2006.
| 2006 111111111123 |
2005 111111111123 |
2004 111111111123 |
|||||
|---|---|---|---|---|---|---|---|
| (millions of tonnes) |
(\$ millions) | (millions of tonnes) |
(\$ millions) | (millions of tonnes) |
(\$ millions) | ||
| Russia | 19.2 | 8,151 | 19.9 | 6,725 | 19.7 | 4,665 | |
| International | 64.7 11111 |
37,459 11111 |
56.7 11111 |
29,216 11111 |
41.4 11111 |
15,317 11111 |
|
| Total | 83.9 11111 aaaaa |
45,610 11111 aaaaa |
76.6 11111 aaaaa |
35,941 11111 aaaaa |
61.1 11111 aaaaa |
19,982 11111 aaaaa |
We transport our refined products through Transnefteproduct's refined product pipeline, via ship, rail and truck. In 2006, we transported 32.2 million tonnes of refined products via rail, 1.7 million tonnes through the Transnefteproduct system and 3.7 million tonnes via ship, truck and other means.
Our retail distribution system is divided into a central office and regional distribution centres. Sales and distribution are managed centrally from our Moscow headquarters. Using data from internal sources on refined product production and projected demand from individual regions, the central sales and distribution office directs refineries to send refined products to regional distribution centres. The refinery then ships the product via the designated transport route to the regional distribution centre for onward distribution. The regional distribution centres receive instructions from the central selling and distribution centre on the destination of products. This centralised system helps us improve distribution efficiency by determining distribution according to regional demand and enables us to consider a greater number of markets for receipt of our products.
Domestically, we sell refined products through wholesale and retail channels. In 2006, we sold a total of 19.2 million tonnes of refined products domestically, including government-related sales. This included 4.0 million tonnes through our retail filling stations within Russia and 15.2 million tonnes through wholesale channels. See "– Retail Marketing" for more information about our domestic retail filling station network.
The Russian government has the authority to direct us to deliver crude oil or refined products to certain government-designated customers, which may take precedence over market sales. Government-directed deliveries may take several forms. We may be directed to make deliveries to government agencies, the military, railways, agricultural producers, remote regions, specific consumers or refineries or to domestic refineries in general. Additionally, some of our oil production licences require us to sell crude oil which we produce to local government agencies. Our deliveries of refined products under government-directed programmes in 2005 and 2006 were made at domestic market prices.
Such deliveries were made to, among others, law-enforcement agencies, the Defence Ministry, the Ministry of Internal Affairs, the Ministry of Emergencies, the Federal Agency on Railway Transport, the Federal Agency on State Reserves and to consumers located in the far north.
Internationally, we sell refined products to third parties through wholesale and retail channels. In 2006, we sold a total of 64.7 million tonnes of refined products in the international market, 20.5 million tonnes of which were exported from Russia. Over that period 7.2 million tonnes of refined products were sold through our retail filling stations outside Russia and 57.5 million tonnes through wholesale channels. See "– Retail Marketing" for more information about our international retail filling station network.
As at 31 December 2006, we owned or leased 5,169 retail filling stations in Russia, other countries of the CIS, Europe and the United States. We have one of the largest retail networks in Russia, where we own or lease 1,538 filling stations. We also have a network of 624 franchised stations which sell our products exclusively. Our franchise programme includes rigid quality control requirements including relating to LUKOIL corporate specifications and designs. In 2006, we began selling gasolines under our new EKTO brand in Russia which is an acronym from the Russian words for "ecological fuel". These gasolines have improved performance and environmental characteristics which meet Euro-3 standards and exceed Russian legal standards for gasoline. We also started selling diesel fuel under the EKTO brand in November 2006. In addition to automotive fuels, many of these stations provide car accessories and basic vehicle service, and increasingly offer goods such as fast food, convenience products and groceries.
The following table provides selected data on our retail filling station as at 31 December 2006.
| Russia 11111 |
CIS and Europe 11111 |
United States 11111 |
Total 11111 |
|
|---|---|---|---|---|
| Number of Stations which are | ||||
| LUKOIL owned or leased | 1,538 | 1,788 | 1,843 | 5,169 |
| Franchised | 120 11111 |
504 11111 |
0 11111 |
624 11111 |
| Total | 1,658 11111 aaaaa |
2,292 11111 aaaaa |
1,843 11111 aaaaa |
5,793 11111 aaaaa |
We intend to expand our network of retail filling stations in Russia in geographic areas which we consider to be more promising, such as Moscow, St. Petersburg and Yekaterinburg, among others, due to their relatively strong economic positions and strategic locations at intersections of various major Russian highways. Our efforts at optimisation in our retail network are focused on withdrawal of stations and tank farms with low efficiency levels. In 2006 in Russia, we sold 41 less efficient filling stations and closed 11. In the United States, we withdrew 122 less efficient filling stations. We also continue to build and acquire new, more efficient filling stations and upgrade existing ones. In 2006, we built 155 new stations, upgraded 148 and acquired 114. Capital expenditures in the retail sector in 2006 were \$553 million.
We have operations in 13 states in the northeast and mid-Atlantic regions of the United States. As at 31 December 2006, our U.S. retail network comprised 1,843 owned or leased retail filling stations.
In March 2005, we acquired a 100% interest in the Finnish companies Oy Teboil Ab and Suomen Petrooli Oy for \$160 million. Oy Teboil Ab and Suomen Petrooli Oy are primarily engaged in the wholesale and retail sale of refined products and the production and sale of lubricants. As at 31 December 2006, Teboil and Suomen Petrooli together operated 437 retail filling stations in Finland.
In December 2006, we signed an agreement with ConocoPhillips to purchase 376 of ConocoPhillips' retail filling stations in Europe, including 156 in Belgium and Luxembourg, 49 in Finland, 44 in the Czech Republic, 30 in Hungary, 83 in Poland and 14 in Slovakia. On 30 April 2007, we completed the acquisition of the filling stations located in Finland. We intend to re-brand these stations as Teboil stations within one year. We completed the acquisition of the remaining stations on 1 June 2007, which we intend to rebrand as LUKOIL stations.
We also have a significant share of the retail lubricant market in Russia and we have launched an advertising campaign in Russia to promote the sale of LUKOIL-branded packaged lubricants through our chain of retail filling stations.
We view our petrochemicals operations as an important part of our business strategy and believe that they provide us with strategic benefits, including more diversified revenues and an additional source of petrochemicals products necessary for our operations.We intend to develop our petrochemicals business primarily by upgrading our existing petrochemical facilities and constructing new facilities, and also by acquiring low-cost petrochemicals production assets and feedstock supplies in Russia. We believe that demand in the Russian and international markets for petrochemicals products will grow in the coming years and we intend to expand our petrochemicals production capacity to meet this demand.
Our petrochemicals operations are conducted through our three petrochemicals plants and our Burgas refinery. In Russia, we own the OOO Stavrolen and OOO Saratovorgsintez petrochemicals plants. The Stavrolen plant produces polyethylene, liquid pyrolysis fractions, propylene, benzene and other products, and the Saratovorgsintez plant produces acrylonitrile and other organic synthesis products. In March 2007, we commissioned a polypropylene production unit with an annual capacity of 120,000 tonnes at the Stavrolen petrochemical plant. Polypropylene produced at the Stavrolen plant will be sold to manufacturers in the Russian domestic market. We also have an effective 88.48% interest in OOO Karpatneftekhim, a petrochemicals plant in Ukraine, which produces polyethylene, vinyl chloride and other products. Karpatneftekhim was established in 2000 as a joint venture with the Ukrainian company Oriana. Additionally, our Burgas refinery has petrochemicals manufacturing capabilities. Products of the Burgas refinery include ethylene glycol, polyethylene, polypropylene, toluene, acrylonitrile and benzene.
We have been steadily increasing production of high value-added chemicals (polymers, monomers and organic synthesis products) at our petrochemicals plants over the last five years, in line with our strategy to develop our petrochemical business. At the same time, production of low value-added chemicals (such as pyrolysis products and fuel fractions) has been reduced. Total combined output of marketable chemicals from our petrochemicals facilities was 2.0 million tonnes in 2006, and our products were sold in Russia and exported to more than 50 countries. Capital expenditures in the petrochemicals sector were \$172 million in 2006.
The oil industry is intensely competitive. We compete with other major Russian oil companies and major international oil companies. Many of our international competitors have substantially greater financial resources and have been operating in a market-based, competitive economic environment for much longer than we have. The key activities in which we face competition are:
See "Risk Factors – Risks Relating to Our Business – We encounter competition from other oil companies in all areas of our operations, including the acquisition of licences, exploratory prospects and producing properties and may encounter competition from suppliers of alternative forms of energy sources" for more information about the risks related to our ability to compete effectively with Russian and international oil companies.
The integrated oil and gas industry is currently subject to several important influences which impact the industry's competitive landscape. In recent years, the oil and gas industry has experienced consolidation, as well as increased deregulation and integration in strategic markets. In addition, our ability to remain competitive will require, among other things, management's continued focus on reducing unit costs and improving efficiency, maintaining longterm growth in our reserves and production through continued technological innovation and our ability to capture international opportunities.
In the face of intense competition, oil and gas 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, we expect competition 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 we face domestically. We also expect competition to increase domestically due to the limited quantities of unexploited and unallocated oil reserves remaining in Russia and the effects of and financial resources provided by increasing levels of foreign investment into Russian oil projects. Internationally, we compete with the largest and most sophisticated oil and gas companies outside of Russia. In some cases, we may be at a disadvantage because foreign-domiciled companies may have access to greater financial and other resources, giving them a competitive advantage, both within Russia and internationally.
We are currently rated by three rating agencies: Moody's Investors Service Inc., Fitch Ratings Ltd and Standard & Poor's Ratings Services. Our current ratings are as follows:
| Moody's 111111111111112 |
Fitch 111111111111113 |
S&P 111111111111112 |
|||
|---|---|---|---|---|---|
| Long term implied | Baa1 | Long term | BBB- | Long term | BBB |
| Senior unsecured | Baa2 | Short term | F3 | Senior unsecured | BBB |
| Outlook | Stable | Outlook | Stable | Outlook | Stable |
The notes are expected to be assigned a rating of Baa2 by Moody's, BBB- by Fitch and BBB- by S&P.
A credit 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. Similar ratings on different types of notes do not necessarily mean the same thing. The ratings do not address the likelihood that the principal on the notes will be prepaid, paid on an expected final payment date or paid on any particular date before the legal final maturity date of the notes. The ratings do not address the marketability of the notes or any market price. Any change in the credit ratings of the notes or our company could adversely affect the price that a subsequent purchaser will be willing to pay for the notes. We recommend that you analyse the significance of each rating independently from any other rating.
Our operations are subject to a number of environmental laws and regulations in Russia and each of the other areas in which we operate. 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 our competitors, environmental liability risks are inherent in our operations. We have environmental liabilities due to past activities which have caused pollution of land, disturbance to land and generation of waste oils, sludge and drill cuttings. Additionally, we also have long-term obligations concerning the decommissioning of operational facilities and the remediation of soil or groundwater at certain of our facilities and liability for waste disposal or contamination on properties owned by others.
The following table provides data on our environmental and decommissioning liabilities as at 31 December 2006.
| LUKOIL | |||||
|---|---|---|---|---|---|
| Western Siberia | Komi | Other E&P | Total | ||
| 1111111 | 111111 | 111111 | 111111 | ||
| (in millions of U.S. dollars) | |||||
| Polluted land | 4.2 | 12.4 | 20.5 | 37.1 | |
| Asset retirement obligations | 355.0 | 57.3 | 206.1 | 618.4 | |
| 1111111 | 111111 | 111111 | 111111 | ||
| Total | 359.2 | 69.7 | 226.6 | 655.5 | |
| 1111111 | 111111 | 111111 | 111111 | ||
| aaaaaaa | aaaaaa | aaaaaa | aaaaaa |
We have undertaken significant efforts and have made significant expenditures to comply with environmental regulations. However, additional financial reserves or compliance expenditures could be required in the future due to changes in law, new information on environmental conditions or other unforeseen events, and those expenditures could have a material adverse effect on our business, financial condition or results of operations.
In addition, with the admission of Bulgaria and Romania to the European Union as at 1 January 2007, our refineries in these countries have become subject to stricter regulations relating to the quality of refined product production and environmental protection. As a result, we have had to make substantial investments to upgrade our refineries to comply with such regulations, including those that relate to asbestos, which was present at both such refineries. We estimate that the amount of future capital expenditures required to upgrade our Burgas and Petrotel refineries is approximately \$750 million and \$57 million, respectively. Although our plans call for significant expenditures to continue to upgrade our refineries, we cannot assure you that we will have adequate resources to fulfil these plans. Failure to meet certain international standards at our refineries could have a material adverse effect on our business, financial condition and results of operations and, therefore, our ability to meet our obligations under the notes and LUKOIL's ability to meet its obligations under the guarantees.
Russian legislation provides a basis for requiring those violating environmental regulations to remediate any environmental damage such violations have caused. However, to date there have been few attempts to enforce these requirements. Instead, environmental authorities have imposed relatively low fines for breaches of environmental and sanitation standards in what is effectively a "pay-to-pollute" scheme. Compensation also may be payable for any damage caused. Notwithstanding the relatively limited environmental enforcement in place in Russia and some other countries in which we operate, and the moderate level of any fines and fees imposed, we are committed to a long-term proactive policy to address environmental concerns and actively pursue policies which are designed to reduce pollution and its effects.
In addition, there may be indications that the Russian government's lenient approach towards environmental enforcement may be changing. In September 2006, the Russian Natural Resources Ministry cancelled its 2003 environmental approval of Sakhalin-II, an LNG project in Russia's Far East run by a consortium including Royal Dutch Shell, Mitsui & Co. and Mitsubishi Corporation, due to alleged environmental breaches. Further investigations by the Federal Natural Utilisation Control Service (Rosprirodnadzor) found multiple violations of environmental protection measures. In December 2006, 12 licences for water use held by a Sakhalin-II contractor were suspended for two months for violations of the Russian water code. This revocation would have made construction of Sakhalin-II infrastructure virtually impossible. In addition, the Russian government commenced criminal proceedings for unauthorised felling of timber on the Sakhalin-II licence area. Faced with this mounting regulatory pressure, the members of the Sakhalin-II consortium ceded control of a majority interest in the project to state-owned Gazprom in December 2006.
We allocate operating and cash expenditures in the amounts necessary to minimise risks of environmental loss and to comply with all pertinent environmental regulations. Although our operating and capital expenditures on the prevention, control, abatement or elimination of air, water and solid waste pollution are often not incurred as separately identifiable transactions, they often form a part of larger transactions, such as normal maintenance expenditures. We also create provisions for future environmental remediation. We believe our provisions are sufficient, based upon known requirements, and we do not believe that our costs will differ significantly from those of other companies engaged in similar industries, or that our competitive position will be adversely affected as a result.
In connection with our acquisition of KomiTEK in 1999, we inherited significant environmental problems. We agreed to remediate the consequences of approximately 350 oil spills which took place in the Usinsk Region of the Komi Republic. The recovery programme, including the reclamation of more than 745 hectares of damaged and contaminated land, was completed in November 2005 at a total cost of approximately \$155.5 million.
Our Petrotel refinery in Romania and our Burgas refinery in Bulgaria require the remediation of a substantial amount of environmental pollution which pre-dated our acquisition of these facilities. At the time of our acquisition of the Petrotel refinery in 1998 and 1999, there was an understanding that the Romanian government would retain liability for existing environmental pollution at the site. In connection with our acquisition of the Burgas refinery, we understand that the Bulgarian government retains liability for remediation of existing environmental pollution at the site, estimated at approximately \$80 to \$100 million. Specifically, we understand that the Bulgarian government intends to commit \$40 million in the first stage of remediation. There can be no assurance that the Romanian and Bulgarian governments will remediate the environmental pollution at these facilities in the way we expect. Accordingly, we could be exposed to additional remediation costs at these sites in excess of our planned expenditures.
Managed nuclear explosions were carried out within the Osinskoye oil field in 1969. This field is currently operated by LUKOIL-Permneft. Subsequent drilling allowed radioactively contaminated water to enter the oil reservoir, which eventually led to a ground-level radioactive contamination problem being identified in 1976. Between 1996 and 2001, we undertook a project at a cost of \$6 million to manage and contain associated radiological risks, and we believe that no further material liability exists. Well management procedures are in place to maintain a buffer zone around the location of the nuclear explosions. However, we cannot assure you that further ground water contamination of the surface soil will not occur.
In 2004, we approved the Environmental Safety Programme for 2004-2008. The programme contemplates 400 measures to protect the environment and ensure higher safety standards, with an expected total cost of approximately \$1.2 billion. The planned measures are structured in eight sub-programmes: clean air, clean water, waste, reclamation, accident suppression and avoidance, research and experimental activities, ecological management, and ecological monitoring. Our priority target is to improve waste management, including a disposal of waste accumulated at our facilities over decades, and to significantly reduce the build-up of new waste.
We believe that our prevention of pollution by means of low-waste, environment-friendly technologies is the only way to achieve further significant improvement of the environmental impact of our activities. This requires implementation of a clean production strategy, and such a strategy is now the basis of our environmental policy.
We had approximately 162,800, 145,400 and 148,600 employees, as at 31 December 2004, 2005 and 2006, respectively. We believe that our relations with our employees are satisfactory.
The insurance industry in the Russian Federation and certain other areas where we have operations is in the course of development. Our management believes that we have adequate property damage coverage for our main production assets. In respect of third party liability for property and environmental damage arising from accidents on our property or relating to our operations, we have insurance coverage that is generally higher than insurance limits set by local legal requirements. Our management believes that we have adequate insurance coverage of the risks which could have a material effect on our business, financial condition or results of operations.
The current members of our Board of Directors are as follows:
| Name 111111111111111 |
Position at LUKOIL 1111111111111111 |
Year of birth 111111111 |
|---|---|---|
| ALEKPEROV, Vagit Yusufovich | Director, President and Chairman of the Management Committee |
1950 |
| BEREZHNOI, Mikhail Pavlovich | Non-Executive Director | 1945 |
| GRAYFER, Valery Isaakovich | Chairman of the Board of Directors | 1929 |
| KUTAFIN, Oleg Emelyanovich | Non-Executive Director | 1937 |
| MAGANOV, Ravil Ulfatovich | First Executive Vice President and | 1954 |
| member of the Management Committee | ||
| MATZKE, Richard H. | Non-Executive Director | 1937 |
| MEYERS, Kevin O. | Non-Executive Director | 1953 |
| MIKHAILOV, Sergei Anatolyevich | Non-Executive Director | 1957 |
| SHERKUNOV, Igor Vladimirovich | Non-Executive Director | 1963 |
| SHOKHIN, Alexander Nikolaevich | Non-Executive Director | 1951 |
| TSVETKOV, Nikolai Alexandrovich | Non-Executive Director | 1960 |
The current members of our Management Committee who are not members of our Board of Directors are as follows:
| Name 111111111111111 |
Position at LUKOIL 1111111111111111 |
Year of birth 111111111 |
|
|---|---|---|---|
| BARKOV, Anatoly Alexandrovich | Vice President and Head of the Main Division of General Affairs, Corporate Security and Communications |
1948 | |
| CHELOYANTS, Jevan Krikorovich | Vice President and Head of the Main Technical Division |
1959 | |
| FEDUN, Leonid Arnoldovich | Vice President and Head of the Main Division of Strategic Development and Investment Analysis |
1956 | |
| KHAVKIN, Evgueni Leonidovich | Secretary of the Board of Directors and Head of the Office of the Board of Directors |
1964 | |
| KHOBA, Lyubov Nikolaevna | Chief Accountant | 1957 | |
| KUKURA, Sergey Petrovich | First Vice President for Economics and Finance |
1953 | |
| MASLIAEV, Ivan Alexeyevich | Head of the Main Division of Legal Support |
1958 | |
| MATYTSYN, Alexander Kuzmich | Vice President and Head of the Main Division of Treasury and Corporate Financing |
1961 | |
| MOSKALENKO, Anatoly Alekseyevich | Head of the Main Division of Human Resources |
1959 | |
| NEKRASOV, Vladimir Ivanovich | First Vice President for Refining, Marketing and Distribution |
1957 | |
| SHARIFOV, Vagit Sadiyevich | Vice President and Head of the Main Division of Control and Internal Audit |
1945 |
The business address of our Directors and members of our Management Committee is 11 Sretensky Bulvar, 101000, Moscow, Russian Federation, which is our registered and head office.
Under our shareholder agreement, dated as at 29 September 2004, with ConocoPhillips, ConocoPhillips had the right to nominate a representative to our Board of Directors. In January 2005, the ConocoPhillips nominee, Kevin O. Meyers, was elected to our Board. Mr. Meyers was re-elected to our Board at the annual general shareholders meeting in June 2006. The shareholder agreement also provides that once ConocoPhillips' ownership interest in LUKOIL reaches 12.5%, it will have the right to nominate a second representative to our Board of Directors. Since its initial acquisition of our shares, ConocoPhillips has increased its stake in our company through open market purchases on the London Stock Exchange and, as at 31 December 2006, it held the maximum permissible 20% of our shares.
Mr. Alekperov has served as our President since 1993 and as the Chairman of our Management Committee since 1993. He also serves as the Chairman of the Supervisory Board of LUKOIL INTERNATIONAL GmbH. From 1991 to 1993, Mr. Alekperov served as the President of the Oil Concern Langepasuraikogalymneft. From 1993 to 2000 he also served as the Chairman of our Board of Directors. From 1990 to 1991 he served as Deputy Minister and then First Deputy Minister of the Ministry of Oil and Gas of the Soviet Union and then Russia. In 1974 Mr. Alekperov earned a degree in Economics and Engineering from the Azerbaijani Institute of Oil and Chemistry.
Mr. Berezhnoi has served as a member of our Board of Directors since 1997. He also serves as the President of Non-State Pension Fund LUKOIL Garant, Chairman of the Board of Directors of CJSC Radio Company Novaya Volna and as a member of the Boards of Directors of OJSC Publishing House Izvestia. Mr. Berezhnoi earned a law degree in 1974 from the Saratov Law Institute.
Mr. Grayfer has served as the Chairman of our Board of Directors since 2000 and has been a member of our Board of Directors since 1996. In addition Mr. Grayfer has served as the General Director of OAO RITEK since 1992 and OAO Nazumgeodobycha since June 2006, and as the Chairman of the Board of Directors of CJSC Ritek-Vnedreniye since 1997. He is also a member of the Boards of Directors of JSCB Medprominvestbank and JSCB Nefteprombank. From 1985 to 1990, he served as Deputy Minister of the Ministry of Oil and Gas of the Soviet Union. Mr. Grayfer earned a degree in Science from the State Academy of Oil and Gas.
Mr. Kutafin has served as a member of our Board of Directors since 2001. He also served as the Legal Advisor to our President from 1996 to 2001. In addition he has been the head of the Moscow State Academy of Law since 1987. Mr. Kutafin earned a law degree from the Lomonosov Moscow State University in 1959.
Mr. Maganov has served as a member of our Board of Directors and Management Committee since 1994 and as a First Executive Vice President since 2006. He also serves as a member of the Board of Directors of LUKOIL INTERNATIONAL GmbH. He served as a First Vice President from 1994 to 2006 and as Vice President from 1993 to 1994. He has also served as the General Director of OJSC LUKOIL-Langepasneftegas, one of our subsidiaries, since 1993. Mr. Maganov worked in several capacities for Langepasneftegas from 1988 to 1993, including as Deputy General Director from 1991 to 1993. In 1977 he earned a degree in Engineering from the Gubkin State Academy of Oil and Gas.
Mr. Matzke has served as a member of our Board of Directors since 2002. He is also currently a director of SBM Offshore and PHI, Inc. Prior to his election to our Board of Directors, from 1997 to 2002 Mr. Matzke was a member of the Board of Directors of Chevron Corporation, where he was responsible for Chevron's worldwide oil and gas exploration and production. He joined Chevron in 1961 and was elected Director in 1997, and Vice Chairman in 2000. He was also President of Chevron Overseas Petroleum Inc. from 1997 to 2000. Mr. Matzke graduated from Iowa University in 1959 and from the University of Pennsylvania in 1961.
Mr. Meyers has served as a member of our Board of Directors since 2005. Since December 2006, he has served as President of ConocoPhillips Canada. From November 2004 to November 2006, he served as President of the Russia/Caspian region at ConocoPhillips. Mr. Meyers served as President of Alaska Phillips Petroleum from 2000 to 2002 and as President of Arco Alaska, Inc. from January 2000 to April 2000. He graduated from Capital University in 1975 with a degree in Chemistry and earned a Ph.D. in Chemical Engineering from the Massachusetts Institute of Technology in 1980.
Mr. Mikhailov has served as a member of our Board of Directors since 2003. He has also served as the General Director of OOO Management Consulting since 2001 and the General Director of ZAO Management Grouppa since 2002. He is also the chairman of the Board of Directors of CJSC Management Company Management Centre. He served in the Russian military from 1974 to 1992. From 1992 to 1996, he served as Deputy Minister of the Russian Federal Property Fund. From 1996 to 1997, Mr. Mikhailov was Head of the Restructuring and Investment Department of the Russian Ministry of Industry. Mr. Mikhailov earned a degree from the Dzerzhinsky Military Academy in 1979 and earned a degree in Economics from the Plekhanov Economics Academy in 1998.
Mr. Sherkunov has served as a member of our Board of Directors since 2001. He has been a member of the Board of ZAO IFD Capital since 2004. He also served as the General Director of LUKOIL-Reserve-Invest from 1998 to 2003 and as Chairman of the Board of Directors of CJSC CAPITAL Investment Group since 2003 and as General Director of CJSC CAPITAL Investment Group from 2002 to 2003. From 1993 to 1996 he served as Vice President of OJSC Insurance Company LUKOIL. In addition, Mr. Sherkunov is currently a member of the Board of OAO Soccer Club Spartak-Moscow and a member of the Board of OAO Petrocommerce Bank. Mr. Sherkunov earned a degree in Finance from the Moscow Financial Institute in 1985 and graduated from the Academy of Foreign Trade in 1993.
Mr. Shokhin has served as a member of our Board of Directors since 2005. From 1994 to 2002 he served as deputy of the State Duma of the Russian Federation. Mr. Shokhin has served as Chairman of the Supervisory Board of Renaissance Capital since 2002 and also as President of the State University School of Economics since 1995. In 1974 he graduated from the Lomonosov Moscow State University with a degree in economics.
Mr. Tsvetkov has served as a member of our Board of Directors since 1998. He also serves as a member of the Supervisory Board of, and counsel to the Chairman of the Management Board of, OAO BANK URALSIB; as Chairman of the Supervisory Board of OAO Financial Corporation URALSIB; as Chairman of the Boards of Directors of OOO Financial Corporation NIKoil, ZAO Delovoy Tsentr UralSib, ZAO Management Company UralSib, OAO Krasnogorskoe Agropromyshlennoe Obschestvo, OAO Zemelnaya Agropromyushlennaya Korporatsiya, OOO Management Investment Company UralSib, Child Charity Fund Meta and Child Charity Fund Viktoriya; and as a member of the Board of Directors of OAO Trade House Kopeyka. Prior to joining URALSIB he served as the head of our Department of Finance and Investment for two years. He served in the Russian military from 1977 to 1993. During that time, he earned degrees from the Tambov State Institute for Military Engineers in 1980 and the Zhukovsky Military Air Academy in 1988. Mr. Tsvetkov earned a marketing degree in 1996 from the Plekhanov Economic Academy.
On 3 February 2007, our Board of Directors announced the nominees for our new Board of Directors, who will be elected at our next annual general shareholders meeting on 28 June 2007. The 12 nominees include all of our current directors other than Mr. Kevin Meyers, plus Donald Evert Wallette, Jr., a nominee of ConocoPhillips, and Mr. Igor V. Belikov. Mr. Wallette has served as President of the Russia/Caspian region of ConocoPhillips since December 2006. Mr. Belikov is Director of the Russian Institute of Directors.
The beneficial ownership interests of each director (including interests held through trusts, funds and other investment vehicles) in our share capital, the existence of which is known to such director, including through the exercise of reasonable diligence, whether or not such interests are held through another party, as at 16 April 2007, which is the most recent practicable date prior to the date of this prospectus, were as follows:
| Percentage of Ordinary | |
|---|---|
| Name of Director 11111112 |
Shares Held 1111111111 |
| Vagit Yu. Alekperov | 16.9% |
| Mikhail P. Berezhnoi | 0.0046% |
| Valery I. Grayfer | 0.01% |
| Oleg E. Kutafin | 0.0002% |
| Ravil U. Maganov | 0.49% |
| Richard H. Matzke | None |
| Kevin O. Meyers | None |
| Sergei A. Mikhailov | 0.0031% |
| Igor V. Sherkunov | 0.04% |
| Alexander N. Shokhin | None |
| Nikolai A. Tsvetkov | 2.94% |
As at 16 April 2007, which is the most recent practicable date prior to the date of this prospectus, Mr. Leonid Fedun, a Vice President and member of our Management Committee, beneficially owned (including interests held through his connected persons and through trusts, funds and other investment vehicles) 8.33% of our share capital. Each of the other members of our Management Committee who are not members of our Board owns less than 1% of our share capital.
Our shareholders determine the compensation of our directors at each annual shareholders meeting. In addition to a basic sum, Board members receive extra remuneration for assuming the responsibilities of the chairman of our Board of Directors or a committee of our Board of Directors, for attending Board or committee meetings in person and for long-distance flights to attend Board or Committee meetings. The annual shareholders' meeting also determines a list of reimbursable expenses associated with duties of our directors. Remuneration and reimbursements payable to our Board members and members of the Audit Commission are determined by our shareholders at a general shareholders meeting. Remuneration of the Management Committee members consists of the following components:
Total remuneration paid to all members of the Board of Directors and the Management Committee for 2006 was approximately \$50 million.
In April 2003, our Board of Directors approved a three-year share incentive plan for directors and officers of LUKOIL and its subsidiaries, which came into force in January 2004. The plan provides that each participant purchases shares in LUKOIL from the plan operator on deferred payment terms at a pre-fixed price due in 2006, with such shares pledged in favour of the operator until full payment therefor or until their sale back to the operator at the end of the plan. The number of shares, or rights, allocated to the plan is approximately 9 million shares. These rights vested in December 2006. In February 2007, the compensation plan was settled through the issuance of approximately 7.3 million shares.
In December 2006, we introduced a new compensation plan to certain members of our management and key employees for the period from 2007 to 2009, which is based on assigned phantom shares and provides compensation consisting of two parts. The first part represents annual bonuses that are based on the number of assigned phantom shares and the amount of dividend per share. The second is based upon the appreciation of our common stock from 2007 to 2009 with rights vesting after the date of the compensation plan's termination. The number of assigned phantom shares was initially approximately 14 million shares. In 2007, additional employees were added to the plan, increasing the number of assigned phantom shares to approximately 15.5 million.
Members of our Board of Directors are elected by a majority vote of shareholder at shareholders' meetings by cumulative voting. Directors serve until the next annual general shareholders meeting and may be re-elected an unlimited number of times. Our Board of Directors has the authority to make overall management decisions for us, except those matters reserved to our shareholders. The current term of office for each of our directors expires at our next annual general shareholders meeting, which will take place on 28 June 2007.
We also maintain an audit committee of the Board of Directors. The audit committee analyses annual independent external audits of LUKOIL's financial statements and prepares recommendations to the Board of Directors for decisions on these issues. The audit committee is elected from among the non-executive members of the Board of Directors (who are members of our Board of Directors who are not also members of our Management Committee) and consists of three persons. At least one member of the committee must be an independent director if our Board of Directors has an independent director. The audit committee members are elected at the meeting of the new membership of the Board of Directors for a period lasting until the election of the next Board of Directors at our annual shareholders meeting. The current chairman of the committee is Oleg Kutafin and the other committee members are Mikhail Berezhnoi and Sergei Mikhailov.
Our human resources and compensation committee determines criteria for selecting candidates and considers and prepares recommendations for the Board of Directors to be used for making decisions on matters related to human resources and compensation of members of the company's management bodies and the Audit Commission. The human resources and compensation committee is elected from among the non-executive members of the Board of Directors (who are members of our Board of Directors who are not also members of our Management Committee) and consist of three persons. At least one member of the committee must be an independent director if our Board of Directors has an independent director. The members of the committee are elected at the meeting of the new membership of the Board of Directors for a period lasting until the election of the next Board of Directors at our annual shareholders meeting. The current chairman of the committee is Alexander Shokhin and the other committee members are Sergei Mikhailov and Nikolai Tsvetkov.
Our strategy and investment committee prepares proposals for the Board of Directors for establishing priority in our activities and in the development of our long-term development strategy. The strategy and investment committee is elected from among the members of our Board of Directors and consists of three persons. At least one member of the committee must be an independent director if our Board of Directors has an independent director. The members of the committee are elected at the meeting of the new membership of the Board of Directors for a period lasting until the election of the next Board of Directors at our annual shareholders meeting. The current chairman of the committee is Richard Matzke and the other committee members are Ravil Maganov, Kevin Meyers and Igor Sherkunov.
Our shareholders appoint our President, who is also the Chairman of our Management Committee, for a term of five years. Our Board of Directors determines the principal terms and conditions of the President's employment. The President is responsible for the day-to-day management of our activities. Our Management Committee is determined annually by our Board of Directors and currently consists of 13 members. Members of the Management Committee are nominated by the President and confirmed by our Board of Directors. Members of our Management Committee serve until our Board of Directors confirms the new members of our Management Committee. The Management Committee is our collective executive body and, under the direction of its Chairman, is responsible for our day-to-day management.
The Audit Commission verifies the accuracy of our financial reporting under Russian law and generally supervises our financial activity. The members of our Audit Commission are elected annually at each annual shareholders meeting and serve until the following annual shareholders meeting. Members of our Audit Commission may be shareholders, but may not be members of our Board of Directors or Management Committee. Remuneration payable to the members of our Audit Commission is approved by our shareholders. The Audit Commission has the right to call an extraordinary shareholders' meeting and may conduct an audit of our financial and business records at any time. In addition it must conduct an audit if requested by a majority of the shareholders at a shareholders' meeting or at the request of the Board of Directors or any shareholder or group of shareholders owning at least 10% of our voting shares. Our Audit Commission currently has three members. Currently the members of our Audit Commission are Vladimir Nikitenko, Tatyana Sklyarova and Pavel Kondratyev. On 3 February 2007, we announced that Vladimir Nikitenko, Pavel Kondratyev and Lyudmila Bulavina have been nominated for the new Audit Committee to be elected at our next annual general shareholders meeting on 28 June 2007.
None of our directors has or had any interest in any transaction effected by us during the current or immediately preceding financial year (or during an earlier financial year and remain in any respect outstanding or unperformed), which is or was unusual in its nature or conditions or significant to our business except as disclosed in the following five paragraphs. There are no potential conflicts of interest between any duties of the members of our Board of Directors or the Management Committee towards LUKOIL and their private interests and/or other duties, excepts as disclosed in the following five paragraphs.
LUKOIL Garant is a private pension fund that operates a benefit plan covering the majority of our employees. It also provides pension benefits and services to employees of other companies that are not related to us. Mr. Matytsyn, a member of our Management Committee, is a member of the Council of the Fund, which is the governing board of LUKOIL Garant. Mr. Berezhnoi, a member of our Board of Directors, is the President and Chairman of the Council of the Fund of LUKOIL Garant. As a result, we may be considered to have influence over LUKOIL Garant even though we do not have direct legal control. See note 14 to our consolidated financial statements included elsewhere in this prospectus for more information about the pension benefits we provide through LUKOIL Garant.
We have a 63.78% voting interest in OAO RITEK, one of our key Western Siberia subsidiaries. See "Business – Exploration and Production – Domestic Exploration and Production". Mr. Cheloyants, a member of our Management Committee, is the Chairman of the Board of Directors of RITEK. Mr. Grayfer, the Chairman of our Board of Directors, is the General Director of RITEK, a member of its Board of Directors and the Chairman of its Management Board.
Financial Corporation UralSib is comprised of a number of Russian financial services companies, including an investment bank, management company, brokerage, insurance company and registrar, including OAO Registrar NIKoil and ZAO URALSIB. NIKoil is our registrar. As at 30 April 2007, URALSIB Depositary Company held 3.75% of our shares as a nominee. Mr. Tsvetkov, a member of our Board of Directors, is Chairman of the Board of Directors of ZAO Management Company Uralsib, Chairman of the Management Board and member of the Supervisory Board of OAO Uralsib and Chairman of the Board of Directors of OOO Management Investment Company Uralsib. In addition, Mr. Tsvetkov and Mr. Alekperov are beneficial owners of UralSib.
In August 2004, we entered into an agreement to sell our 99% interest in OAO Bank Petrocommerce to Financial Group IFD Kapital, a related party whose beneficial owners, management and directors include certain members of our management and Board of Directors. We sold 78% of Bank Petrocommerce to IFD Kapital for \$169 million in September 2004, and we sold the remaining 21% interest for \$33 million in May 2006. We also purchased insurance services from IFD Kapital in the amount of \$138 million in 2004 and \$133 million in each of 2005 and 2006.
In May 2004, we acquired from ConocoPhillips 308 retail filling stations and contracted to supply refined products to an additional 471 retail filling stations in the northeastern United States for \$270 million. As part of our efforts to develop our reserves in Timan-Pechora, we entered into a joint venture agreement with ConocoPhillips in September 2004, pursuant to which we sold a 30% interest in NMNG to ConocoPhillips. NMNG has a number of loan agreements with ConocoPhillips, under which \$1,043 million was outstanding as at 31 December 2006. In addition, in December 2006, we signed an agreement with ConocoPhillips to purchase 376 of ConocoPhillips' retail filling stations in Europe. Mr. Meyers, a member of our Board of Directors, served as president of Russia/Caspian for ConocoPhillips from 2004 to 2006. Mr. Wallette succeeded Mr. Meyers as president of Russia/Caspian for ConocoPhillips in 2006 and is ConocoPhillips' nominee to our Board of Directors, to be elected at our next annual general shareholders meeting scheduled for 28 June 2007. See "– Members of the Board of Directors and the Management Committee" for more information on our corporate governance relationship with ConocoPhillips. See also "Risk Factors – Risks Related to Our Business" ConocoPhillips beneficially owns 20% of our shares and has a right to nominate two members of our Board of Directors, which affords it significant influence over LUKOIL and over Board and shareholder decisions".
We have entered into service contracts with the following directors:
We entered into an employment agreement, dated 28 June 2006, with Mr. Alekperov in his capacity as our President. His agreement expires on the date of the annual shareholders' meeting held in 2011. The agreement can be terminated early with one month's notice. If we terminate Mr. Alekperov's agreement prior to its expiration in 2011, we must pay him a severance amount equal to twice his annual salary.
We entered into an employment agreement with Mr. Maganov dated 19 July 2005 in his capacity as First Executive Vice President. The agreement was amended on 1 April 2006, 1 August 2006 and 31 October 2006. His agreement has an indefinite term. In the event that we wish to terminate his agreement early, he would be entitled to a severance payment of an amount equal to his annual salary.
We have also entered into an agreement with Mr. Matzke that provides that we will indemnify him for any loss that he may incur as a result of any action that relates to the performance of his duties as director, except in the case of intentional misconduct or breach of legal duties. Except as disclosed above, there are no service contracts existing or proposed between our directors and us.
The Issuer is a Netherlands company whose statutory seat is in Amsterdam and which was incorporated as a private company with limited liability (besloten vennootschap) under the laws of The Netherlands on 16 August 2006. Its number at the trade register is 34254022.
The authorised share capital of the Issuer at incorporation was €90,000 divided into 90,000 shares of par value €1 each. As at 31 December 2006, 18,000 shares have been issued and are fully paid at par value. The issued shares are owned by LUKOIL INTERNATIONAL GmbH, a wholly owned subsidiary of LUKOIL.
As of the date of this prospectus, the Issuer has no indebtedness or contingent liabilities and has provided no guarantees. Since the date of its incorporation and as at the date of this prospectus, the Issuer has not published any financial statements.
The Issuer has two managing directors, Mr. Stanislav Nikitin and Equity Trust Co. N.V., a limited liability company incorporated in The Netherlands. Mr. Nikitin is also deputy Head of the Main Division of Treasury and Corporate Financing at LUKOIL. Mr E.G.F. Baron van Tuyll van Serooskerken is the sole member of Equity Trust's Supervisory Board. Messrs. F. van der Rhee, R.G.A. de Schutter and J.C.W. van Burg are the members of Equity Trust's Management Board. The members of Equity Trust's Supervisory Board and Management Board perform no principal activities outside of Equity Trust which are significant with respect to Equity Trust or the Issuer. Other than Mr. Nikitin's position at LUKOIL, there are no potential conflicts of interest between any duties of the directors of the Issuer (and the directors of Equity Trust) towards either the Issuer or Equity Trust and their private interests and/or other duties.
The Issuer has no employees or property and no subsidiaries. The principal activity of the Issuer is to raise funds for LUKOIL.
The registered office of the Issuer is Atrium, Strawinskylaan 3105, 1077 ZX Amsterdam, The Netherlands, and its phone number is +31 20 406 44 44. The business address of Stanislav Nikitin is 11 Sretensky Bulvar, 101000, Moscow, Russian Federation and the business address of Equity Trust and the members of Equity Trust's Supervisory Board and Management Board is 7 Atrium, Strawinskylaan 3105, 1077 ZX Amsterdam, The Netherlands. Administrative services are provided to the Issuer by Equity Trust Co. N.V. and by LUKOIL Accounting and Finance Limited of Rotunda Point, 11 Hartfield Crescent, London SW19 3RL, United Kingdom.
The following table sets out details, in so far as is known to us, as at 30 April 2007 (being the latest practicable date prior to the date of this prospectus), unless otherwise indicated, of all shareholders (other than directors and members of our Management Committee but including nominee shareholders) that hold 5% or more of our share capital.
| Name of Shareholder 111111111 |
Percent of issued ordinary share capital 1111111112 |
|---|---|
| ZAO ING Bank Eurasia (nominee) | 66.98% |
| ConocoPhillips1 | 20% |
| OOO Special Depositary Company "Garant" (nominee) | 8.45% |
| ZAO KB Citibank (nominee) | 7.87% |
(1) In May 2007, ConocoPhillips reported in its Form 10-Q for the first quarter of 2007 filed with the SEC that, as at 31 March 2007, it owned 20% of our authorised and issued shares, which is the maximum permissible under our shareholder agreement and which is equivalent to approximately 20.6% based on estimated shares outstanding.
LUKOIL Garant is a private pension fund that operates a benefit plan covering the majority of our employees. It also provides pension benefits and services to employees of other companies that are not related to us. Mr. Matytsyn, a member of our Management Committee, is a member of the Council of the Fund, which is the governing board of LUKOIL Garant. Mr. Berezhnoi, a member of our Board of Directors, is the President and Chairman of the Council of the Fund of LUKOIL Garant. Due to these interlocking relationships, we may be considered to have influence over LUKOIL Garant even though we do not have direct legal control. See note 14 to our consolidated financial statements included elsewhere in this prospectus for more information on the pension benefits we provide through LUKOIL Garant.
We have a 63.78% voting interest in OAO RITEK, one of our key Western Siberia subsidiaries. See "Business – Exploration and Production – Domestic Exploration and Production". Mr. Cheloyants, a member of our Management Committee, is the Chairman of the Board of Directors of RITEK. Mr. Grayfer, the Chairman of our Board of Directors, is the General Director of RITEK, a member of its Board of Directors and the Chairman of its Management Board.
Financial Corporation UralSib is comprised of a number of Russian financial services companies, including an investment bank, management company, brokerage, insurance company and registrar, including OAO Registrar NIKoil and ZAO URALSIB. NIKoil is our registrar. As of 30 April 2007, URALSIB Depository Company held 3.75% of our shares as a nominee. Mr. Tsvetkov, a member of our Board of Directors, is Chairman of the Board of Directors of ZAO Management Company Uralsib, Chairman of the Management Board and member of the Supervisory Board of OAO Uralsib and Chairman of the Board of Directors of OOO Management Investment Company Uralsib. In addition, Mr. Tsvetkov and Mr. Alekperov are beneficial owners of UralSib.
In August 2004, we entered into an agreement to sell our 99% interest in OAO Bank Petrocommerce to Financial Group IFD Kapital, a related party whose beneficial owners, management and directors include certain members of our management and Board of Directors. We sold 78% of Bank Petrocommerce to IFD Kapital for \$169 million in September 2004, and we sold the remaining 21% interest for \$33 million in May 2006. We also purchased insurance services from IFD Kapital in the amount of \$138 million in 2004 and \$133 million in each of 2005 and 2006.
In May 2004, we acquired from ConocoPhillips 308 retail filling stations and contracted to supply refined products to an additional 471 retail filling stations in the northeastern United States for \$270 million. As part of our efforts to develop our reserves in Timan-Pechora, we entered into a joint venture agreement with ConocoPhillips in September 2004, pursuant to which we sold a 30% interest in NMNG to ConocoPhillips. NMNG has a number of loan agreements with ConocoPhillips, under which \$1,043 million was outstanding as at 31 December 2006. In addition, in December 2006, we signed an agreement with ConocoPhillips to purchase 376 of ConocoPhillips' retail filling stations in Europe. Mr. Meyers, a member of our Board of Directors, served as president of Russia/Caspian for ConocoPhillips from 2004 to 2006. Mr. Wallette succeeded Mr. Meyers as president of Russia/Caspian for ConocoPhillips in 2006 and is ConocoPhillips' nominee to our Board of Directors, to be elected at our next annual general shareholders meeting scheduled for 28 June 2007. See "– Members of the Board of Directors and the Management Committee" for more information on our corporate governance relationship with ConocoPhillips. See also "Risk Factors – Risks Related to Our Business ConocoPhillips beneficially owns 20% of our shares and has a right to nominate two members of our Board of Directors, which affords it significant influence over LUKOIL and over Board and shareholder decisions".
On 26 November 2002, Lukinter Finance B.V. issued and sold \$350,000,000 of its 3.5% convertible bonds due 2007. Each bond is convertible at the option of the holder into one global depositary receipt representing four ordinary shares of LUKOIL. The initial conversion price was \$83.693 per GDR (\$20.92 per ordinary share). LUKOIL provided a guarantee of the payment of principal and interest and the conversion rights relating to the bonds. Bonds of an aggregate principal amount of approximately \$4 million were outstanding as at 31 December 2006 unless previously purchased and cancelled, redeemed or converted, the bonds will be redeemed on 29 November 2007.
There are no and have been no governmental, legal or arbitration proceedings against us or any member of the Group (including any such proceedings which are pending or threatened of which we are aware) during the 12 months preceding the date of this prospectus, which may have, or have had in the recent past, significant effects on our or our Group's financial position or profitability, except as described in the following two paragraphs in respect of the dispute involving OAO "Arkhangelskgeoldobycha" (AGD), a company in our Group, and LUKOIL.
On November 27, 2001, Archangel Diamond Corporation (ADC), a Canadian diamond development company, filed a lawsuit in the District Court of Denver, Colorado against AGD and LUKOIL (together the Defendants). ADC alleged that the Defendants interfered with the transfer of a diamond exploration license to Almazny Bereg, a joint venture between ADC and AGD. ADC claimed total damages of approximately \$4.8 billion, including compensatory damages of \$1.2 billion and punitive damages of \$3.6 billion. On 15 October 2002, the District Court dismissed the lawsuit for lack of personal jurisdiction. The Colorado Court of Appeals upheld this ruling on 25 March 2004. On 21 November 2005, the Colorado Supreme Court affirmed the lower courts' ruling that no specific jurisdiction exists over the Defendants. By virtue of this finding, AGD (the holder of the diamond exploration licence) was dismissed from the lawsuit. The Colorado Supreme Court found, however, that the trial court made a procedural error by not holding an evidentiary hearing before making its ruling concerning general jurisdiction regarding LUKOIL, which is whether LUKOIL had systematic and continuous contacts in the State of Colorado at the time the lawsuit was filed. In a modified opinion dated 19 December 2005, the Colorado Supreme Court remanded the case to the Colorado Court of Appeals (instead of the District Court) to consider whether the lawsuit should have been dismissed on alternative grounds (i.e., forum non conveniens). On 29 June 2006, the Colorado Court of Appeals declined to dismiss the case based on forum non conveniens. We filed a petition for certiorari on 28 August 2006 asking the Colorado Supreme Court to review this decision. This petition has been rejected. On 5 March 2007, the Colorado Supreme Court remanded the case to the District Court. The District Court has not set a pretrial schedule, but should do so shortly. We do not believe that the ultimate resolution of this matter will have a material adverse effect on our financial condition.
On 20 February 2004, the Stockholm District Court overturned the decision of the Arbitral Tribunal of the Arbitration Institute of the Stockholm Chamber of Commerce (Arbitration Tribunal) made on 25 June 2001 dismissing ADC's action against AGD based on lack of jurisdiction. ADC's lawsuit against AGD was initially filed with the Arbitral Tribunal claiming alleged non-performance under an agreement between the parties and its obligation to transfer the diamond exploration license to Almazny Bereg. This lawsuit claimed compensation of damages amounting to \$492 million. In March 2004, AGD filed an appeal against the Stockholm District Court decision with the Swedish Court of Appeals. On 15 November 2005, the Swedish Court of Appeals denied AGD's appeal and affirmed the Stockholm District Court decision. On 13 December 2005, AGD filed an appeal against the Swedish Court of Appeals decision with the Swedish Supreme Court. On 13 April 2006 the Swedish Supreme Court denied the application of AGD for appeal against the Swedish Court of Appeal's decision dated 15 November 2005. On 6 May 2006, a Notice of Arbitration was received on behalf of ADC. On 20 December 2006, the first session of the Arbitration Tribunal with participation of both parties took place in order to define procedural issues related to the tribunal. As a result of the hearing, the Arbitration Tribunal issued a detailed procedural order setting out the rules and timetable for the conduct of the arbitration. The hearing in relation to issues primarily relating to liability, if any, is currently scheduled to take place in June 2008. Our management does not believe that the ultimate resolution of this matter will have a material adverse effect on the Group's financial condition.
We are involved in various other claims and legal proceedings arising in the normal course of business. While these claims may seek substantial damages against us and are subject to uncertainty inherent in any litigation, we do not believe that the ultimate resolution of such matters will have a material adverse impact on our operating results or financial condition.
There are no and have been no governmental, legal or arbitration proceedings against the Issuer (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, which may have, or have had in the recent past, significant effects on the Issuer's financial position or profitability.
Our initial charter was registered with the Moscow Registration Chamber on 22 April 1993 with a registration number of 24020, and the current version of our charter was registered with the Ministry of Taxes and Excise for the Central District of Moscow on 25 July 2002 under registration number 2027708000494. On 17 July 2002, LUKOIL was entered into the Unified State Registrar of Legal Entities of the Russian Federation under registration number 1027700035769. The address of our registered office is Sretensky bulvar 11, Moscow 101000, Russian Federation, and our telephone number is +7 (495) 627 4444.
The following is the text of the terms and conditions of the notes which, subject to amendment, will be endorsed on each Definitive Note (as defined below) and will be attached and (subject to the provisions thereof) apply to the Global Notes.
The U.S.\$500,000,000 6.356 per cent. Notes due 2017 (the "Notes", which expression includes any further Notes issued pursuant to Condition 16 and forming a single series therewith) of LUKOIL International Finance B.V. (the "Issuer") were authorised by a written resolution of the board of directors of the Issuer dated 14 May 2007, and the guarantee of the Notes (the "Guarantee") was authorised by a resolution of the board of directors of OAO LUKOIL (the "Guarantor") passed on 23 April 2007.
The U.S.\$500,000,000 6.656 per cent. Notes due 2022 (the "Notes", which expression includes any further Notes issued pursuant to Condition 16 and forming a single series therewith) of LUKOIL International Finance B.V. (the "Issuer") were authorised by a written resolution of the board of directors of the Issuer dated 14 May 2007, and the guarantee of the Notes (the "Guarantee") was authorised by a resolution of the board of directors of OAO LUKOIL (the "Guarantor") passed on 23 April 2007.
The Notes are constituted by a trust deed dated 7 June 2007 (the "Trust Deed") between the Issuer, the Guarantor and Citicorp Trustee Company 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. These terms and conditions include summaries of, and are subject to, the detailed provisions of the Trust Deed. The Issuer and the Guarantor have entered into an agency agreement dated 7 June 2007 (the "Agency Agreement") with the Trustee, Citibank, N.A., London Branch, as principal paying agent (the "Principal Paying Agent" and, together with any other paying agents appointed under the Agency Agreement, the "Paying Agents") and as registrar (the "Registrar") and as transfer agent (the "Transfer Agent"). The Registrar, Paying Agents and Transfer Agent are together referred to herein as the "Agents". Copies of the Trust Deed and the Agency Agreement are available for inspection during normal business hours at the specified office of the Trustee, being at the date hereof Citigroup Centre, Canada Square, Canary Wharf, London E14 5LB, United Kingdom, 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 are deemed to have notice of those provisions of the Agency Agreement applicable to them. Capitalised terms used but not defined in these Terms and Conditions shall have the respective meanings given to them in the Trust Deed.
The Notes are issued in fully registered form, without interest coupons attached, in denominations of U.S.\$100,000 or integral multiples of U.S.\$1,000 in excess thereof ("authorised denominations") and, provided that 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.
(a) Guarantee
The Guarantor has in the Trust Deed unconditionally and irrevocably guaranteed the payment when due of all sums expressed to be payable by the Issuer under the Trust Deed and the Notes (the "Guarantee"). The Guarantor's obligations in respect of the Guarantee are contained in the Trust Deed.
The Guarantor has undertaken in the Trust Deed that so long as any of the Notes remains outstanding (as defined in the Trust Deed) it will not take any action for the liquidation or windingup of the Issuer.
The Notes constitute unsubordinated and (subject to Condition 4) unsecured obligations of the Issuer and shall at all times rank pari passu and without any preference among themselves. Subject to Condition 4, each of the Issuer and the Guarantor shall ensure that at all times the claims of the Noteholders against them under the Notes and the Guarantee, respectively, rank in right of payment at least pari passu with the claims of all their other unsecured and unsubordinated creditors save those whose claims are preferred by any mandatory operation of law.
(a) Register
The Registrar shall maintain the Register in respect of the Notes in accordance with the provisions of the Agency Agreement. The Register shall be kept at the specified office for the time being of the Registrar and shall record the names and addresses of the holders of the Notes, particulars of the Notes and all transfers thereof. In these Conditions, the "holder" of a Note means the person in whose name such Note is for the time being registered in the Register (or, in the case of a joint holding, the first named thereof) and "Noteholder" shall be construed accordingly.
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.
Subject to Conditions 3(f) and 3(g) 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 the 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(d). Neither the part transferred nor the balance not transferred may be less than the applicable authorised denomination.
Within five business days of the surrender of a Definitive Note in accordance with Condition 3(c) 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 the 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.
(e) 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.
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.
All transfers of Notes and entries on the Register are subject to the detailed regulations concerning the transfer and registration of Notes set out in the First Schedule to the Agency Agreement. The regulations may be changed by the Issuer and the Guarantor with the prior written approval of the Trustee, the Transfer Agent 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 will be available at the specified office of the Registrar in London.
So long as any of the Notes remains outstanding (as defined in the Trust Deed):
without in any such case at the same time or prior thereto procuring that the Notes or, as the case may be, the Guarantor's obligations under the Guarantee (x) are secured equally and rateably with such Relevant Indebtedness for so long as such Relevant Indebtedness is so secured or (y) have the benefit of such other guarantee, indemnity or other like obligations or such other security (in each case) as the Trustee in its absolute discretion shall deem to be not materially less beneficial to the Noteholders or (z) as shall be approved by an Extraordinary Resolution (as defined in the Trust Deed) of the Noteholders.
(a) Mergers
The Guarantor shall not enter into or become subject to, and shall not permit the Issuer or any Principal Subsidiary to enter into or become subject to, any reorganisation (including, without limitation, any amalgamation, demerger, merger or corporate reconstruction) or to change its corporate structure if such a reorganisation or change would have a Material Adverse Effect.
(b) Payment of Taxes
So long as any amount remains outstanding hereunder, the Guarantor shall, and shall ensure that its Subsidiaries shall, pay or discharge or cause to be paid or discharged, before the same shall become overdue, all taxes, assessments and governmental charges levied or imposed upon, or upon the income, profits or assets of the Guarantor or any Subsidiary, provided, however, that none of the Guarantor nor any of its Subsidiaries shall be required to pay or discharge or cause to be paid or discharged any such tax, assessment, charge or claim (x) whose amount, applicability or validity is being contested in good faith by appropriate proceedings and for which adequate reserves in accordance with US GAAP or other appropriate provision has been made or (y) if such failure to pay or discharge shall not have a Material Adverse Effect.
The Notes bear interest from the Issue Date (as defined below) at the rate of 6.356 per cent. per annum, payable in equal instalments semi-annually in arrear on 7 June and 7 December in each year, commencing on 7 December 2007.
The Notes bear interest from the Issue Date (as defined below) at the rate of 6.656 per cent. per annum, payable in equal instalments semi-annually in arrear on 7 June and 7 December in each year, commencing on 7 December 2007.
The Notes 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 the Notes 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 the Notes 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 other than a semi-annual interest period ending on 7 June and 7 December in each year, it will be calculated on the basis of a 360-day year consisting of 12 months of 30 days each and, in the case of an incomplete month, the number of days elapsed.
Unless previously redeemed, or purchased and cancelled, the Notes will be redeemed at their principal amount on 7 June 2017.
Unless previously redeemed, or purchased and cancelled, the Notes will be redeemed at their principal amount on 7 June 2022.
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 (i) the Issuer satisfies the Trustee immediately prior to the giving of such notice that it (or, if the Guarantee was called, the Guarantor) has or will become obliged to pay additional amounts as provided or referred to in Condition 9 as a result of any change in, or amendment to, the laws or regulations of The Netherlands or the Russian Federation or any political or governmental subdivision or any authority thereof or therein having power to tax, or any change in the application or official interpretation of such laws or regulations, which change or amendment becomes effective on or after 7 June 2007 and (ii) such obligation cannot be avoided by the Issuer (or the Guarantor, as the case may be) taking reasonable measures available to it; provided that no such notice of redemption shall be given earlier than 60 days prior to the earliest date on which the Issuer (or the Guarantor, as the case may be) would be obliged to pay such additional amounts were a payment in respect of the Notes (or the Guarantee, as the case may be) then due. Prior to the publication of any notice of redemption pursuant to this paragraph, the Issuer shall deliver to the Trustee (x) a certificate signed by two directors of the Issuer (or the Guarantor, as the case may be) stating that the obligation referred to in (i) above cannot be avoided by the Issuer (or the Guarantor, as the case may be) 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 (or the Guarantor, as the case may be) 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.
The Issuer may compel any beneficial owner of Notes sold pursuant to Rule 144A under the Securities Act to sell its interest in such Notes, or may sell such interest on behalf of such holder, if such holder is a US person that is not a qualified institutional buyer (as defined in Rule 144A under the Securities Act) and a qualified purchaser (as defined in Section 2(a)(51) of the Investment Company Act). Any sale by the Issuer on behalf of a beneficial owner shall be at a price equal to the least of (x) the purchase price therefor paid by the beneficial owner, (y) 100 per cent. of the principal amount thereof or (z) the fair market value thereof.
The Issuer may also choose to redeem the Notes prior to 7 June 2017, in whole or in part, on not less than 30 nor more than 60 days' irrevocable notice to the Noteholders, by paying a redemption price equal to the sum of:
The Issuer may also choose to redeem the Notes prior to 7 June 2022, in whole or in part, on not less than 30 nor more than 60 days' irrevocable notice to the Noteholders, by paying a redemption price equal to the sum of:
plus accrued and unpaid interest thereon, if any, to the redemption date.
The Issuer shall not be entitled to redeem the Notes otherwise than as provided in paragraphs (a) and (b) above and this paragraph (d). All Notes in respect of which any such notice of redemption is given under this Condition 7 shall be redeemed on the date specified in such notice in accordance with this Condition 7.
(e) Purchase
The Issuer, the Guarantor and any of their respective Subsidiaries may at any time purchase Notes in the open market or otherwise at any price.
(f) Cancellation
All Notes redeemed or purchased pursuant to this Condition 7 shall be cancelled forthwith and may not be held or resold. Any Notes so cancelled may not be reissued.
Payments of principal (whenever due) and interest due on redemption shall be made by the Paying Agents by US Dollar cheque drawn on a bank in New York City, or by transfer to a US Dollar account maintained by the payee with, a bank in New York City and shall only be made upon surrender (or, in the case of part payment only, endorsement) of the relevant Definitive Notes at the specified office of any Paying Agent.
Payments of interest (other than interest due on redemption) shall be made by the Paying Agents by US Dollar cheque drawn on a bank in New York City, or by transfer to a US Dollar account maintained by the payee with, a bank in New York City not later than the due date for such payment.
All payments in respect of the Notes are subject in all cases to any applicable fiscal or other laws and regulations, but without prejudice to the provisions of Condition 9. No commissions or expenses shall be charged to the Noteholders in respect of such payments.
If the due date for any payment of principal or interest under this Condition 8 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, "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 US 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.
Each payment in respect of a Note will be made to the person shown as the holder in the Register at the opening of business (in the place of the Registrar's specified office) on the fifteenth day before the due date for such payment. Any cheque will be mailed to the holder of the relevant Note at his address appearing in the Register.
The initial Agents and their initial specified offices are listed below. The Issuer and the Guarantor, acting together, reserve the right to vary or terminate the appointment of all or any of the Agents at any time and appoint additional or other payment or transfer agents, provided that they will maintain (i) a Principal Paying Agent, (ii) Paying Agents and a Transfer Agent having specified offices in at least one major European city approved by the Trustee, being at least London so long as the Notes are admitted to the Official List of the Financial Services Authority in its capacity as competent authority under the Financial Services and Markets Act 2000 and admitted to trading on the London Stock Exchange's EEA Regulated Market 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 or any other European Union Directive implementing the conclusions of the ECOFIN Council meeting of 26 27 November 2000 on the taxation of savings income. Notice of any such change will be provided as described in Condition 17 below.
In this Condition, "EEA Regulated Market" means a Market as defined by Article 1(13) of the Investment Services Directive 93/22/EEC.
All payments of principal and interest in respect of the Notes by or on behalf of the Issuer or under the Guarantee by the Guarantor 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 Netherlands or the Russian Federation or any political subdivision or any authority thereof or therein having power to tax, unless such withholding or deduction is required by law. In that event, the Issuer or (as the case may be) the 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:
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 in New York City 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.
If the Issuer or the Guarantor becomes subject at any time to any taxing jurisdiction other than (or in addition to) The Netherlands or the Russian Federation, respectively, references in these Conditions to The Netherlands or the Russian Federation shall be construed as references to The Netherlands or (as the case may be) the Russian Federation and/or such other jurisdiction.
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 shall (subject to its rights under the Trust Deed to be indemnified), give notice to the Issuer that the Notes are immediately due and repayable if any of the following events occurs (each an "Event of Default"):
(b) a default is made by the Issuer or the Guarantor in the performance or observance of any covenant, condition or provision contained in the Trust Deed, in the Notes or on its part to be performed or observed (other than the covenant to pay the principal and interest in respect of any of the Notes) and (except where the Trustee certifies in writing that, in its opinion, such default is not capable of remedy when no such notice as mentioned below shall be required) such default continues for the period of 45 days next following the service by the Trustee on the Issuer or the Guarantor of notice requiring such default to be remedied; or
(c) any other present or future Indebtedness of the Issuer, the Guarantor or any Principal Subsidiary becomes due and payable prior to its stated maturity otherwise than at the option of the Issuer, the Guarantor, the relevant Principal Subsidiary (as the case may be) or (provided that no event of default, howsoever described, has occurred) any person entitled to such Indebtedness, taking into account any applicable grace periods; provided that, either, (i) the individual amount of the relevant Indebtedness, guarantee or indemnity in respect of which the event mentioned above in this paragraph (c) has occurred and is continuing equals or exceeds U.S.\$50,000,000 or (ii) the aggregate amount of the relevant Indebtedness, guarantees and indemnities in respect of which one or more of the events mentioned above in this paragraph (c) have occurred and is continuing equals or exceeds U.S.\$150,000,000 or, in the case of an amount specified in (i) or (ii) above, its equivalent (as reasonably determined by the Trustee) (on the basis of the middle spot rate for the relevant currency against the US Dollar as quoted by any leading bank on the day on which such calculation is made); or
transfers or expropriates all or (in the opinion of the Trustee) a material part of the assets, licences or shares of the Issuer, the Guarantor or any Principal Subsidiary; or
and, except in the case of (a) above, the Trustee shall have certified in writing to the Issuer that the event is, in its opinion, materially prejudicial to the interests of the Noteholders.
Upon any such notice being given to the Issuer, the Notes will immediately become due and repayable at their principal amount together with interest incurred to such date.
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.
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 Issuer and the Guarantor may reasonably require. Mutilated or defaced Definitive Notes must be surrendered before replacements will be issued.
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 concerning the quorum required at any meeting of Noteholders or the majority required to pass an Extraordinary Resolution, or (vi) to modify or cancel the Guarantee, 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.
The Trustee may agree with the Issuer and the Guarantor, without the consent of the Noteholders, to (i) any modification of any of the provisions of the Trust Deed 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 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.
The Trust Deed contains provisions permitting the Trustee to agree with the Issuer and the Guarantor, 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 of any previous substituted company, as principal debtor under the Trust Deed and the Notes. In the case of such substitution, the Trustee may agree with the Issuer and the Guarantor, without the consent of the Noteholders, to a change of 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 Noteholders. Notice of any such substitution will be provided as described in Condition 17 below.
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 Guarantor, the Trustee or any other Person, any indemnification or payment in respect of any tax consequences of any such exercise upon individual Noteholders.
At any time after the Notes become due and payable, the Trustee may, at its discretion and without further notice, institute such proceedings against the Issuer and/or the Guarantor as it may think fit to enforce the terms of the Trust Deed and the Notes (whether by arbitration pursuant to the Trust Deed or by litigation), but it need not take any 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 to its satisfaction. No Noteholder may proceed directly against the Issuer or the Guarantor unless the Trustee, having become bound so to proceed, fails to do so within a reasonable time and such failure is continuing.
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, the Guarantor and any entity related to the Issuer or the Guarantor without accounting for any profit.
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. Any such other securities shall be constituted by a deed supplemental to the Trust Deed. 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.
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. Any such notice shall be deemed to have been given on the fourth day after the date of mailing. In addition, notices will be published in a leading newspaper having general circulation in London (which is expected to be the Financial Times) 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.
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, (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 Guarantor, shall indemnify each Noteholder, on the written demand of such Noteholder addressed to the Issuer and the Guarantor and delivered to the Issuer and the Guarantor 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 Noteholder 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 Guarantor and shall give rise to a separate and independent cause of action, will apply irrespective of any indulgence granted by the Trustee 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 and/or the Notes or any other judgment or order.
No person shall have any right to enforce any term or condition of the Notes under the Contracts (Rights of Third Parties) Act 1999.
(a) Governing law
The Notes (including for the avoidance of doubt Condition 20) and the Trust Deed are governed by, and shall be construed in accordance with, English law.
Subject to Condition 20, the courts of England are to have jurisdiction to settle any disputes which may arise out of or in connection with the Notes or the Trust Deed and accordingly any legal action or proceedings arising out of or in connection with the Notes or the Trust Deed ("Proceedings") may be brought in such courts and any final and conclusive judgment in any Proceedings brought in the courts of England shall be conclusive and binding and may be enforced in the courts of any other jurisdiction. Each of the Issuer and the Guarantor has in the Trust Deed irrevocably submitted to the jurisdiction of such courts and waives any objection to Proceedings in such courts whether on the ground of venue or on the ground that the Proceedings have been brought in an inconvenient forum. These submissions are made for the benefit of each of the Noteholders and shall not limit the right of any of them to take Proceedings in any other court of competent jurisdiction nor shall the taking of Proceedings in one or more jurisdictions preclude the taking of Proceedings in any other jurisdiction (whether concurrently or not).
Each of the Issuer and the Guarantor has appointed LUKOIL Accounting & Finance Limited at its registered office (being, at the date hereof, Rotunda Point, 11 Hartfield Crescent, London SW19 3RL, England) as its agent in England to receive service of process in any Proceedings in England in connection with the Notes or the Trust Deed.
The Issuer and the Guarantor consent generally in respect of any Proceedings or Disputes to the giving of any relief or the issue of any process in connection with such Proceedings or Disputes including (without limitation) the making, enforcement or execution against any property whatsoever (irrespective of its use or intended use) of any judgment or award which may be made or given in such Proceedings or Disputes.
(e) Waiver of immunity
To the extent that either the Issuer or the Guarantor may in any jurisdiction claim for itself or its assets or revenues immunity from suit, execution, attachment (whether in aid of execution, before the making of a judgment or an award or otherwise) or other legal process including in relation to the enforcement of an arbitration award and to the extent that such immunity (whether or not claimed) may be attributed in any such jurisdiction to the Issuer, the Guarantor or their respective assets or revenues, the Issuer and the Guarantor agree not to claim and irrevocably waive such immunity to the full extent permitted by the laws of such jurisdiction.
In these Conditions, the following terms shall have the following meanings:
"Affiliate" has the meaning ascribed to it under Rule 405 of the Securities Act;
"Applicable Premium" means, with respect to a Note at any time, the excess of (a) the present value at such redemption date of such Note, plus any required interest payments that would otherwise be due to be paid on such Note from such redemption date through 7 June 2017, together with any accrued and unpaid interest as of such redemption date, if any, calculated using a discount rate equal to the Treasury Rate at such redemption date plus 50 basis points, over (b) the principal amount of such Note, provided that if the value of Applicable Premium at any time would otherwise be less than zero, then in such circumstances for the purposes of these Conditions the value of Applicable Premium will be equal to zero.
"Applicable Premium" means, with respect to a Note at any time, the excess of (a) the present value at such redemption date of such Note, plus any required interest payments that would otherwise be due to be paid on such Note from such redemption date through 7 June 2022, together with any accrued and unpaid interest as of such redemption date, if any, calculated using a discount rate equal to the Treasury Rate at such redemption date plus 50 basis points, over (b) the principal amount of such Note, provided that if the value of Applicable Premium at any time would otherwise be less than zero, then in such circumstances for the purposes of these Conditions the value of Applicable Premium will be equal to zero.
"Auditors" means the auditors of the Group's US GAAP consolidated financial statements for the time being or, if they are unable or unwilling to carry out any action requested of them under terms of the Notes, such other internationally recognised firm of accountants as may be approved in writing by the Trustee for this purpose;
"business day" means (except where expressly defined otherwise) a day on which commercial banks are open for business (including dealings in foreign currencies) in the city where the Registrar has its specified office;
"Consolidated Assets" means the total amount of assets appearing on the consolidated balance sheet of the Guarantor, prepared in accordance with US GAAP, as of the date of the most recently prepared consolidated financial statements;
"Closing Date" means 7 June 2007;
"Domestic Relevant Indebtedness" means any Relevant Indebtedness which is denominated and payable in roubles, is not quoted, listed or ordinarily dealt in or traded on any stock exchange, over the counter or other recognised securities market outside the Russian Federation and which on issue was placed only with investors within the Russian Federation;
"European Union" means the European Union, including the countries of Austria, Belgium, Bulgaria, Cyprus, the Czech Republic, Denmark, Estonia, Finland, France, Germany, Greece, Hungary, Ireland, Italy, Latvia, Lithuania, Luxembourg, Malta, The Netherlands, Poland, Portugal, Romania, Slovakia, Slovenia, Spain, Sweden and the United Kingdom but not including any country which becomes a member of the European Union after the Issue Date;
"Event of Default" has the meaning assigned to such term in Condition 10;
"Group" means the companies which are consolidated in the most recent accounts of the Guarantor prepared in accordance with US GAAP;
"Indebtedness" means any indebtedness, in respect of any Person for, or in respect of, moneys borrowed; any amount raised by acceptance under any credit facility; any amount raised pursuant to any note purchase facility or the issue of bonds, notes, debentures, loan stock or any similar instrument; any amount raised pursuant to any issue of shares which are expressed to be redeemable; any amount of money raised under any other transaction (including any forward sale or purchase agreement) having the commercial effect of a borrowing; the amount of any liability in respect of a capital lease that would at that time be required to be capitalised on a balance sheet in accordance with US GAAP and (without double counting) the amount of any liability in respect of any guarantee or indemnity (whether on or off balance sheet) for any of the items referred to above; provided that, for the avoidance of doubt, Indebtedness shall not include moneys raised by way of the issue of share capital (whether or not for cash consideration and excluding shares which are expressed to be redeemable) and any premium on such share capital; and provided further that Indebtedness shall not include Indebtedness among the Issuer, Guarantor and Subsidiaries; and provided further that Indebtedness shall not include any trade credit extended to such Person in connection with the acquisition of goods and/or services on arm's length terms and in the ordinary course of trading of that Person.
"Material Adverse Effect" means a material adverse effect on (a) the financial condition or operations of the Guarantor or the Group, or (b) the Issuer's or the Guarantor's ability to perform its obligations under the Notes and the Guarantee, respectively or (c) the validity, legality or enforceability of the Notes or the Guarantee or the rights or remedies of the Noteholders under the Notes or the Guarantee.
"Permitted Security Interest" means:
or any Subsidiary provided that such Security Interest was not created in contemplation of such event and that no such Security Interest shall extend to other property, income or assets of such company or the Group;
"Person" means any individual, corporation, partnership, joint venture, association, joint stock company, trust, unincorporated organisation, limited liability company or government or other entity;
"Principal Subsidiary" means:
all as shown in the most recent audited accounts (consolidated or aggregated if available) of the Subsidiary and the Group; and
(b) any Subsidiary to which is transferred the whole or substantially the whole of the undertaking and assets of a Subsidiary of the Guarantor which immediately prior to the transfer was a Principal Subsidiary of the Guarantor.
The Trustee shall be entitled to rely on a certificate of the Auditors as to whether a Subsidiary constitutes a Principal Subsidiary and will not be responsible to any Person for any loss occasioned by relying on such a certificate;
"Relevant Indebtedness" means any present or future Indebtedness in the form of, or represented by, notes, debentures, bonds or other securities (but for the avoidance of doubt, excluding term loans, credit facilities, credit agreements and other similar facilities and evidence of indebtedness under such loans, facilities or credit agreements) which either are by their terms payable, or confer a right to receive payment, in any currency and are for the time being, or ordinarily are quoted, listed or ordinarily dealt in or traded on any stock exchange, over-thecounter or other securities market;
"Subsidiary" means any corporation or other business entity of which the Issuer or the Guarantor owns or controls (either directly or through one or more Subsidiaries) 50 per cent. or more of the issued share capital or other ownership interest having ordinary voting power to elect a majority of the directors, managers or trustees of such corporation or other business entity;
"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 redemption date to 7 June 2017. 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 redemption 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 redemption date to 7 June 2017 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 redemption date to 7 June 2017 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; and
"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 redemption date to 7 June 2022. 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 redemption 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 redemption date to 7 June 2022 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 redemption date to 7 June 2022 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; and
"US Dollars", "U.S.\$" or the sign "\$" means such coin or currency of the United States of America as at the time of payment shall be legal tender for the payment of public and private debts.
There will appear at the foot of the Conditions endorsed on each Definitive Note the name and specified office of the Agents as set out at the end of this Offering Circular.
In connection with its purchase of Rule 144A Notes, the purchaser hereof (the Investor), by virtue of its acceptance of this prospectus, will be deemed to represent, acknowledge and agree as follows:
Note or the 2022 Rule 144A Global Note, as the case may be, and vice versa, certain certifications will be required pursuant to the relevant agency agreement.
THIS NOTE AND THE GUARANTEES HEREOF HAVE NOT BEEN AND WILL NOT BE REGISTERED UNDER THE UNITED STATES SECURITIES ACT OF 1933 (THE SECURITIES ACT) OR WITH ANY SECURITIES REGULATORY AUTHORITY OF ANY STATE OR OTHER JURISDICTION OF THE UNITED STATES AND THIS NOTE 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 BELIEVE IS A QUALIFIED INSTITUTIONAL BUYER WITHIN THE MEANING OF RULE 144A (A QIB) THAT IS ALSO A QUALIFIED PURCHASER (QP) WITHIN THE MEANING OF SECTION 2(a)(51) OF THE UNITED STATES INVESTMENT COMPANY ACT OF 1940 (THE INVESTMENT COMPANY ACT) PURCHASING FOR ITS OWN ACCOUNT OR FOR THE ACCOUNT OF ONE OR MORE QIBS EACH OF WHICH IS A QP WHOM THE HOLDER HAS INFORMED, IN EACH CASE, THAT SUCH OFFER, SALE, PLEDGE OR OTHER TRANSFER IS BEING MADE IN RELIANCE ON RULE 144A, AND IN AN AMOUNT NOT LESS THAN US\$100,000 PRINCIPAL AMOUNT OF NOTES OR (2) TO NON-U.S. PERSONS (AS DEFINED IN REGULATION S) IN AN OFFSHORE TRANSACTION IN ACCORDANCE WITH RULE 903 OR RULE 904 OF REGULATION S UNDER THE SECURITIES ACT (REGULATION S), 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. TRANSFERS IN VIOLATION OF THE FOREGOING WILL BE OF NO FORCE OR EFFECT, WILL BE VOID AB INITIO, AND WILL NOT OPERATE TO TRANSFER ANY RIGHTS TO THE TRANSFEREE, NOTWITHSTANDING ANY INSTRUCTIONS TO THE CONTRARY TO THE ISSUER OF THIS NOTE, THE TRUSTEE OR ANY INTERMEDIARY. NO REPRESENTATION CAN BE MADE AS TO THE AVAILABILITY OF ANY EXEMPTION UNDER THE SECURITIES ACT FOR RESALES OF THIS NOTE.
IF THE BENEFICIAL OWNER HEREOF IS A U.S. PERSON WITHIN THE MEANING OF REGULATION S, SUCH BENEFICIAL OWNER REPRESENTS THAT (1) IT IS A QIB THAT IS ALSO A QP; (2) IT IS NOT A BROKER-DEALER WHICH OWNS AND INVESTS ON A DISCRETIONARY BASIS LESS THAN US\$25,000,000 IN SECURITIES OF UNAFFILIATED ISSUERS; (3) IT IS NOT A PARTICIPANT-DIRECTED EMPLOYEE PLAN, SUCH AS A 401(k) PLAN; (4) IT IS HOLDING THIS NOTE FOR ITS OWN ACCOUNT OR FOR THE ACCOUNT OF ONE OR MORE QIBS, EACH OF WHICH IS A QP; (5) IT WAS NOT FORMED FOR THE PURPOSE OF INVESTING IN THE ISSUER OR THIS NOTE; (6) IT, AND EACH ACCOUNT FOR WHICH IT HOLDS NOTES, WILL HOLD AND TRANSFER AT LEAST US\$100,000 IN PRINCIPAL AMOUNT OF NOTES; (7) IT UNDERSTANDS THAT THE ISSUER MAY RECEIVE A LIST OF PARTICIPANTS HOLDING POSITIONS IN ITS SECURITIES FROM ONE OR MORE BOOK-ENTRY DEPOSITARIES AND (8) IT WILL PROVIDE NOTICE OF THE FOREGOING TRANSFER RESTRICTION TO ITS SUBSEQUENT TRANSFEREES. THE BENEFICIAL OWNER HEREOF HEREBY ACKNOWLEDGES THAT IF AT ANY TIME WHILE IT HOLDS AN INTEREST IN THIS NOTE IT IS A U.S. PERSON WITHIN THE MEANING OF REGULATION S WHO IS NOT A QIB THAT IS ALSO A QP, THE ISSUER MAY (A) COMPEL IT TO SELL ITS INTEREST IN THIS NOTE TO A PERSON WHO IS (I) A U.S. PERSON WHO IS ALSO A QP AND WHO IS OTHERWISE QUALIFIED TO PURCHASE THIS NOTE IN A TRANSACTION EXEMPT FROM REGISTRATION UNDER THE SECURITIES ACT OR (II) NOT A U.S. PERSON WITHIN THE MEANING OF REGULATION S OR (B) COMPEL THE BENEFICIAL OWNER TO SELL ITS INTEREST IN THIS NOTE TO THE ISSUER OR AN AFFILIATE OF THE ISSUER OR TRANSFER ITS INTEREST IN THIS NOTE TO A PERSON DESIGNATED BY OR ACCEPTABLE TO THE ISSUER AT A PRICE EQUAL TO THE LEAST OF (X) THE PURCHASE PRICE THEREFOR PAID BY THE BENEFICIAL OWNER, (Y) 100% OF THE PRINCIPAL AMOUNT THEREOF OR (Z) THE FAIR MARKET VALUE THEREOF. THE ISSUER HAS THE RIGHT TO REFUSE TO HONOUR A TRANSFER OF AN INTEREST IN THIS NOTE TO A U.S. PERSON WHO IS NOT A QIB AND A QP. THE ISSUER HAS NOT BEEN AND WILL NOT BE REGISTERED UNDER THE INVESTMENT COMPANY ACT.
THE ISSUER MAY COMPEL THE HOLDER OF THIS NOTE TO CERTIFY PERIODICALLY THAT SUCH HOLDER IS A QIB (DURING SUCH TIME THAT THIS NOTE IS A "RESTRICTED SECURITY" WITHIN THE MEANING OF RULE 144(a)(3) UNDER THE SECURITIES ACT) AND A QP.
In connection with its purchase of the Regulation S Notes, the Investor and each subsequent purchaser of Regulation S Notes in resales prior to the expiration of the distribution compliance period, by virtue of its acceptance of this prospectus hereof, will be deemed to represent, acknowledge and agree as follows:
Each series of notes will be evidenced on issue by (i) in the case of Regulation S Notes, Regulation S Global Notes 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, Rule 144A Global Notes 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 at any time. 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 the 40-day distribution compliance period, it will transfer such interest only to a person whom the seller reasonably believes (a) to be a non-U.S. person in an offshore transaction in accordance with Rule 903 or Rule 904 of Regulation S or (b) to be a person who takes delivery in the form of an interest in a Rule 144A Global Note (if 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 relevant 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 relevant agency agreement, and with respect to Rule 144A Global Notes, as set forth in Rule 144A, and the notes will bear the legends set forth thereon regarding such restrictions set forth under "Transfer Restrictions". A beneficial interest in the 2017 Regulation S Global Note or the 2022 Regulation S Global Note may be transferred to a person who takes delivery in the form of an interest in the 2017 Rule 144A Global Note or the 2022 Rule 144A Global Note, as the case may be, and only upon receipt by the Registrar of a written certification (in the form provided in the relevant agency agreement) to the effect that the transferor reasonably believes that the transferee is a QIB that is also a QP and that such transaction is in accordance with any applicable securities laws of any State of the United States or any other jurisdiction. Beneficial interests in the 2017 Rule 144A Global Note or the 2022 Rule 144A Global Note may be transferred to a person who takes delivery in the form of an interest in the 2017 Regulation S Global Note or the 2022 Regulation S Global Note, as the case may be, only upon receipt by the Registrar of a written certification (in the form provided in the relevant agency agreement) from the transferor to the effect that the transfer is being made in accordance with Regulation S.
Any beneficial interest in the 2017 Regulation S Global Note or the 2022 Regulation S Global Note that is transferred to a person who takes delivery in the form of an interest in the 2017 Rule 144A Global Note or the 2022 Rule 144A Global Note, as the case may be, will, upon transfer, cease to be an interest in the 2017 Regulation S Global Note or the 2022 Regulation S Global Note, as the case may be, and become an interest in the 2017 Rule 144A Global Note or the 2022 Rule 144A Global Note, as the case may be, and, accordingly, will thereafter be subject to all transfer restrictions and other procedures applicable to beneficial interests in the 2017 Regulation S Global Note or the 2022 Regulation S Global Note, as the case may be, for as long as it remains such an interest. Any beneficial interest in the 2017 Rule 144A Global Note or the 2022 Rule 144A Global Note that is transferred to a person who takes delivery in the form of an interest in the 2017 Regulation S Global Note or the 2022 Regulation S Global Note, as the case may be, will, upon transfer, cease to be an interest in the 2017 Rule 144A Global Note or the 2022 Rule 144A Global Note, as the case may be, and become an interest in the 2017 Regulation S Global Note or the 2022 Regulation S Global Note, as the case may be, and, accordingly, will thereafter be subject to all transfer restrictions and other procedures applicable to beneficial interests in the 2017 Regulation S Global Note or the 2022 Regulation S Global Note, as the case may be, 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.
Each Global Note contains provisions that apply to the notes that they represent, some of which modify the effect of the above Terms and Conditions of the Notes. The following is a summary of those provisions:
Payments of principal and interest in respect of notes evidenced by a Global Note will be made to the person who appears at the relevant time on the register of noteholders against presentation for endorsement by the Principal Paying Agent and, if no further payment falls to be made in respect of the relevant notes, surrender of such Global Note to or to the order of the Principal Paying Agent or such other Paying Agent as shall have been notified to the relevant noteholders for such purpose. A record of each payment so made will be endorsed in the appropriate schedule to the relevant Global Note, which endorsement will be prima facie evidence that such payment has been made in respect of the relevant notes.
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.
The holder of each Global Note will be treated as being two persons for the purposes of any quorum requirements of, or the right to demand a poll at, a meeting of noteholders and in any such meeting as having one vote in respect of notes for which the relevant Global Note may be exchangeable.
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.
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, and 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) principal in respect of any notes is not paid when due and payable.
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.
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 (a) 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 (b) 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 l44A, a certification that the transfer is being made in compliance with the provisions of Rule l44A 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".
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 Investment Company Act.
For each series of notes evidenced by both a Regulation S Global Note and a Rule 144A Global Note, custodial and depository 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 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 depository and custodial relationships. Euroclear and Clearstream, Luxembourg have established an electronic bridge between their two systems across which their respective customers may settle trades 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.
DTC has advised the Issuer as follows: DTC is a limited purpose trust company organised under the laws of the State of New York, a "banking organization" 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, which clear through or maintain a custodial relationship with a DTC Direct Participant, either directly or indirectly.
Investors may hold their interests in the 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 l44A Global Notes for exchange for individual Rule 144A Definitive Notes (which will bear the legend applicable to transfers pursuant to Rule 144A).
The Regulation S Global Notes representing the 2017 Regulation S Notes and the 2022 Regulation S Notes each will have an 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 Rule 144A Global Notes representing the 2017 Rule 144A Notes and the 2022 Rule 144A Notes each will have a CUSIP number and will be deposited with a 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.
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 the 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 payments made on account of ownership interests in any Global Note or for maintaining, supervising or reviewing any records relating to such ownership interests.
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 l44A 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.
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 Eurobonds.
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 (SDFS) 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.
When book-entry interests in notes are to be transferred from the account of a DTC participant holding a beneficial interest in the 2017 Rule 144A Global Note or the 2022 Rule 144A Global Note to the account of a Euroclear or Clearstream, Luxembourg accountholder wishing to purchase a beneficial interest in the 2017 Regulation S Global Note or the 2022 Regulation S Global Note, as the case may be (subject to the certification procedures provided in the relevant agency agreement), the DTC participant will deliver instructions for delivery to the relevant Euroclear or Clearstream, Luxembourg accountholder to DTC by 12 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 relevant Rule l44A Global Note will instruct the Registrar to (i) decrease the amount of notes registered in the name of Cede & Co. and evidenced by such 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 Clearstream, Luxembourg and evidenced by the relevant 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.
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 l44A Global Note (subject to the certification procedures provided in the relevant agency agreement), 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 (a) transmit appropriate instructions to the custodian of the relevant 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 (b) instruct the Registrar to (i) decrease the amount of notes registered in the name of the nominee of the common depositary for Euroclear and Clearstream, Luxembourg and evidenced by the relevant Regulation S Global Note; and (ii) increase the amount of notes registered in the name of Cede & Co. and evidenced by the relevant 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 procedure, 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.
It is expected that 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 15c6-1 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 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 advisors.
Credit Suisse Securities (Europe) Limited and Deutsche Bank AG, London Branch (the Managers) have, pursuant to a Subscription Agreement dated 4 June 2007, jointly and severally agreed with the Issuer and LUKOIL, subject to the satisfaction of certain conditions, to subscribe for the notes at 100% of the principal amount of the notes less total concessions and commissions of 0.30% of such principal amount of 2017 notes and 0.35% of such principal amount of 2022 notes, in each case plus accrued interest, if any. In addition, the Issuer has agreed, under certain circumstances, 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 notes have not been and will not be registered under the Securities Act or the securities laws of any State or other jurisdiction of the United States and may not be offered or sold within the United States except in certain transactions exempt from the registration requirements of the Securities Act. Each Manager has represented, warranted and agreed that it will not offer or sell the notes (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 Closing Date, within the United States or to, or for the account or benefit of U.S. persons, and it will have sent to each dealer to which it sells notes during the distribution compliance period a confirmation or other notice setting forth the restrictions on offers and sales of the notes within the United State or to, or for the account or benefit of, U.S. persons. Terms used in this paragraph have the meanings given to them by Regulation S.
Notes offered and sold outside the United States may be sold in reliance on Regulation S. The Subscription Agreement provides that the Managers may directly or through their respective U.S. broker-dealer affiliates arrange for the offer and resale of notes within the United States only to persons whom they reasonably believe are QIBs and QPs who can represent that (a) they are QPs who are QIBs within the meaning of Rule 144A; (b) they are not broker-dealers who own and invest on a discretionary basis less than US\$25 million in securities of unaffiliated issuers; (c) they are not a participant-directed employee plan, such as 401(k) plan; (d) they are acting for their own account, or the account of one or more QIBs each of which is a QP; (e) they are not formed for the purpose of investing in the Issuer or the notes; (f) each account for which they are purchasing will hold and transfer at least US\$100,000 in principal amount of notes at any time; (g) they understand that the Issuer may receive a list of participants holding positions in its securities from one or more book-entry depositaries; and (h) they will provide notice of the transfer restrictions set forth in this prospectus to any subsequent transferees.
In addition,until 40 days after commencement of the offer, an offering or sale of notes within the United States by a dealer which is not participating in the offering may violate the registration requirements of the Securities Act if such offer or sale is made otherwise than in accordance with Rule 144A under the Securities Act.
This prospectus has been prepared by the Issuer and LUKOIL for use in connection with the offer and sale of the notes outside the United States to non-U.S. persons in relation on Regulation S and the resale of the notes in the United States and for the listing of notes on the London Stock Exchange. The Issuer and the Managers reserve the right to reject any offer to purchase the notes, in whole or in part, for any reason. This prospectus does not constitute an offer to any person in the United States or to any U.S. person other than any QIB who is also a QP and to whom an offer has been made directly by one of the Managers or its U.S. broker-dealer affiliate. Distribution of this prospectus by any non-U.S. person outside the United States or by any QIB that is also a QP within the United States to any U.S. person or to any other person within the United States, other than any QIB that is also a QP and those persons, if any, retained to advise such non-U.S. person or QIB that is also a QP with respect thereto, is unauthorised and any disclosure without the prior written consent of the Issuer of any of its contents to any such U.S. person or person within the United States, other than any QIB that is also a QP and those persons, if any, retained to advise such non-U.S. person or QIB that is also a QP, is prohibited.
Each Manager has represented, warranted and undertaken that:
(i) it has complied and will comply with all applicable provisions of the FSMA and the rules and instruments issued thereunder with respect to anything done by it in relation to the notes in, from or otherwise involving the United Kingdom; and
(ii) 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 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 the Guarantor.
Each of the Managers has represented, warranted and agreed that the notes will not be offered, transferred or sold as part of their initial distribution or at any time thereafter 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; it being understood and agreed that the Managers may distribute the prospectus to persons in the Russian Federation in a manner that does not constitute advertisement (as defined in Russian law) of the notes and may sell the notes to Russian persons in a manner that does not constitute "placement" or "public circulation" of the notes in the Russian Federation (as defined in Russian law).
The offering of the notes has not been registered with the Commissione Nazionale per la Società e la Borsa (CONSOB) (the Italian securities and exchange commission) pursuant to the Italian securities legislation and, accordingly each Manager has represented and agreed that it has not offered, sold or distributed any notes nor distributed any copies of this prospectus relating to the notes, and will not offer, sell or distribute the notes nor distribute any copies of this prospectus or any other document relating to the notes in the Republic of Italy in a public solicitation (sollecitazione all'investimento) within the meaning of Article 1, paragraph 1, letter (t) of Legislative Decree no. 58 of 24 February 1998 (the Financial Services Act), unless an exemption applies. Accordingly, the notes in Italy shall only be offered or sold:
Moreover and subject to the foregoing, each Manager has represented and agreed that the notes may not be offered, sold or delivered and neither this prospectus nor any other material relating to the notes may be distributed or made available in Italy unless such offer, sale or delivery of notes or distribution or availability of copies of this prospectus or any other material relating to the notes in the Italy is made:
The following is a summary of certain tax considerations that may be relevant to a holder of notes. However, prospective investors should consult their own advisers regarding the tax consequences of an investment in the notes.
The following is a summary of certain material Netherlands tax consequences of purchasing, owning and disposing of the notes. It does not purport to be a complete analysis of all possible tax situations that may be relevant to a decision to purchase, own or dispose of the notes. In particular, this discussion does not consider any specific facts or circumstances that may apply to a particular purchaser. This summary does not allow any conclusions to be drawn with respect to issues not specifically addressed. This summary is based on the laws of The Netherlands currently in force and as applied on the date of this prospectus, which are subject to change, possibly with retroactive of retrospective effect.
It is assumed that the notes and income received or capital gains derived therefrom, are not attributable to employment activities of the holder of the notes.
All payments made by the Issuer under the notes may be made free of withholding or deduction of, for or on account of any taxes of whatever nature imposed, levied, withheld or assessed by The Netherlands or any political subdivision or taxing authority thereof or therein.
A holder of notes who is an individual will not be subject to any Dutch taxes on income or capital gains in respect of any benefit derived or deemed to be derived from notes, including any payment under notes and any gain realised on the disposal of notes, except if:
If a holder of notes is an individual who does not come under exception (a) nor under exception (b) above, and if he derives or is deemed to derive benefits from notes, including any payment thereunder and any gain realised on the disposal thereof, such benefits are taxable as benefits from miscellaneous activities in The Netherlands if he, or an individual who is a connected person in relation to him as meant in article 3.91, paragraph 2, letter b, or letter c, of the Dutch Income Tax Act 2001 (Wet inkomstenbelasting 2001), has a substantial interest (aanmerkelijk belang) a deemed substantial interest in the Issuer.
A person has a substantial interest in the Issuer if such person – either alone or, in the case of an individual, together with his partner, if any – has, directly or indirectly, either the ownership of shares representing five per cent. or more of the total issued and outstanding capital (or the issued and outstanding capital of any class of shares) of the Issuer, or rights to acquire, directly or indirectly, shares, whether or not already issued, that represent five per cent. or more of the total issued and outstanding capital (or the issued and outstanding capital of any class of shares) of the Issuer or the ownership of profit participating certificates (winstbewijzen) that relate to five per cent. or more of the annual profit of the Issuer or to five per cent. or more of the liquidation proceeds of the Issuer.
A person who is entitled to the benefits from shares or profit participating certificates (for instance a holder of a right of usufruct) is deemed to be a holder of shares or profit participating certificates, as the case may be, and such person's entitlement to such benefits is considered a share or a profit participating certificate, as the case may be. A deemed substantial interest may be present if shares, profit participating certificates or rights to acquire shares or profit participating certificates in the Issuer have been acquired or are deemed to have been acquired on a non-recognition basis.
Furthermore, a holder of notes who is an individual and who does not come under exception (a) nor under exception (b) above may, inter alia, derive benefits from notes that are taxable as benefits from miscellaneous activities in the following circumstances, if such activities are performed or deemed to be performed in The Netherlands:
A holder of notes other than an individual will not be subject to any Dutch taxes on income or capital gains in respect of any benefit derived or deemed to be derived from notes, including any payment under notes and any gain realised on the disposal of notes, except if:
A holder of notes will not become subject to Netherlands taxation on income or capital gains by reason only of the issue of the notes or the performance by the Issuer of its obligations thereunder.
Dutch gift, estate or inheritance taxes will not be levied on the occasion of the transfer of a note by way of gift or on the death of an individual holder, unless:
There is no Dutch registration tax, transfer tax, capital tax, stamp duty or any other similar tax or duty, other than court fees and contributions for the registration with the Trade Register of the Chamber of Commerce, payable in The Netherlands in respect of or in connection with the execution, delivery and enforcement by legal proceedings (including any foreign judgment in the courts of The Netherlands) of the notes or the performance of the Issuer's obligations under the notes.
There is no Dutch value added tax payable in respect of payments in consideration for the issue of the notes or in respect of the payment of interest or principal under the notes or the transfer of the notes, other than the Value Added Tax which may be due with respect to advisory fees incurred in relation to such payments.
The following is a summary of certain Russian tax considerations relevant to the purchase, ownership and sale, redemption or disposal of the notes. The summary is based on the laws of Russia in effect on the date of this prospectus. This summary does not seek to address the applicability of, and procedures in relation to, taxes levied by the regions, municipalities or other non-federal authorities of the Russian Federation. Nor does this summary 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 involved in obtaining double tax treaty relief. Prospective investors should consult their own advisers regarding the tax consequences of investing in the notes in their particular circumstance. No representations with respect to the Russian tax consequences to any particular holder are made hereby.
The provisions of the Russian Tax Code applicable to holders of, and transactions with, the notes are uncertain and lack interpretive guidance. Both the substantive provisions of the Russian Tax Code and the interpretation and application of those provisions by the Russian tax authorities to applicable financial instruments may be subject to more rapid and unpredictable change and inconsistency than in jurisdictions with more developed capital markets and tax systems. In particular, the 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 stated by the law. Similarly, in the absence of binding precedents, court rulings on tax or related matters by different courts relating to the same or similar circumstances may also be inconsistent or contradictory.
For the purposes of this summary, a "non-resident holder" means an individual that is not considered a tax resident in Russia under the Russian personal income tax law when they earn income from the notes or a legal entity or organisation in each case not organised under Russian law that holds and disposes of the notes, other than through a permanent establishment (as defined under Russian tax law and relevant tax treaties) in Russia.
A non-resident holder should not be subject to any Russian taxes in respect of payments of interest and principal on the notes received from the Issuer.
A non-resident holder also generally should not be subject to any Russian taxes in respect of gain or other income realised on a redemption, sale or other disposition of the notes outside of Russia, provided that the proceeds of such sale, redemption, or disposal are not received from a source within Russia.
In the event that proceeds from a sale, redemption or disposal of notes are received from a source within Russia, a non-resident holder that is a legal entity or organisation should not be subject to Russian tax in respect of such proceeds, although there is some residual uncertainty regarding the treatment of the portion of proceeds, if any, that is attributable to accrued interest. Any proceeds of such sales proceeds attributable to accrued interest may potentially be subject to Russian withholding tax on income at the rate of 20%, subject to any available double tax treaty relief, even if the disposal otherwise results in a capital loss. Non-resident holders that are legal entities and organisations should consult their own tax advisers with respect to this possibility.
If proceeds from a disposal of the notes are received from a source within Russia, a non-resident holder who is an individual will generally be subject to personal income tax at a rate of 30% on the gain from such disposal (the gain generally being calculated as the gross proceeds from such disposal less any available cost deduction which includes the purchase price of the notes), subject to any available double tax treaty relief. In addition, there is a risk that the taxable base may be affected by changes in the exchange rates between the currency of acquisition of the notes, the currency of sale of the notes and rubles. There is some uncertainty regarding the treatment of the portion of proceeds (if any) attributable to accrued interest. Proceeds attributable to accrued interest may be taxed at a rate of 30%, irrespective of any capital gain or loss on the disposal of the notes. The tax may be withheld at source of payment or, if the tax is not withheld, then the non-resident individual may be liable to file a tax return and pay the tax.
A resident noteholder who is a non-resident holder will be subject to all applicable Russian taxes in respect of gains from disposition of the notes and interest received on the notes. Resident noteholders should consult their own tax advisers with respect to their tax position regarding the notes.
Payments in respect of interest under the guarantees are likely to be characterised as Russian source income. Accordingly, such payments should be subject to withholding tax at the rate of 20% in the event that a payment under a guarantee is made to a non-resident holder that is a legal entity or organisation and 30% in the event that a payment under a guarantee is made to an individual, subject to reduction or elimination under any applicable double tax treaty. We cannot assure you that such withholding tax would not be imposed upon the full amount of payment under a guarantee, including in respect of the principal amount of the notes.
Payments under the guarantees should not be subject to Russian value added tax.
The Russian Federation has concluded double tax treaties with a number of countries and honours some double tax treaties concluded by the former Union of Soviet Socialist Republics. These tax treaties may contain provisions that reduce or eliminate Russian tax due with respect to income received from a source within Russia by a non-resident noteholder on a disposition of notes. To obtain the benefit of such tax treaty provisions, the noteholder must comply with the certification, information and reporting requirements in force in Russia. Currently, a noteholder which is not an individual would need to provide the payer of income with a certificate of tax residence issued by the competent tax authority of the relevant treaty country. An individual noteholder must provide tax authorities with a certificate of tax residence issued by the competent authority of the relevant treaty country, appropriate documentary proof of income received and the tax payment made outside Russia on income with respect to which treaty benefits are claimed. Because of uncertainties regarding the form and procedures for providing such documentary proof, individuals in practice may not be able to obtain advance treaty relief on receipt of proceeds from a source within Russia, whilst obtaining a refund of the taxes withheld can be extremely difficult, if not impossible.
Non-resident holders who are individuals should consult their own tax advisers with respect to the tax consequences on the disposal of the notes and on the tax consequences of the receipt of proceeds from a source within Russia in respect of a disposal of the notes.
The tax discussion contained in this document is not given in the form of a covered opinion within the meaning of Circular 230 issued by the U.S. Secretary of the Treasury. Thus, we are required to inform you that you cannot rely upon any advice contained in this document for the purpose of avoiding U.S. federal tax penalties. The tax discussion contained in this document was written to support the promotion or marketing of the transactions or matters described in this document. Each taxpayer should seek advice based on the taxpayer's particular circumstances from an independent tax advisor.
The following is a summary of the material U.S. federal income tax consequences of the acquisition, ownership and disposition of the notes by U.S. Holders (as defined below), but does not purport to be a complete analysis of all the potential tax considerations. This summary is based upon the Internal Revenue Code of 1986, as amended (the Code), the Treasury Regulations promulgated or proposed thereunder (the Regulations) and administrative and judicial interpretations thereof, all as of the date hereof and all of which are subject to change at any time, possibly on a retroactive basis. No assurance can be given that the treatment of the notes described herein will be respected by the Internal Revenue Service (the IRS) or, if challenged, by a court. This summary is limited to the tax consequences to those persons who are initial purchasers of the notes and who hold the notes as capital assets within the meaning of Section 1221 of the Code. This summary does not purport to deal with all aspects of U.S. federal income taxation that might be relevant to particular U.S. Holders in light of their particular investment circumstances or status, nor does it address specific tax consequences that may be relevant to particular persons (including, for example, financial institutions, broker-dealers, insurance companies, partnerships or other passthrough entities, expatriates, tax-exempt organisations, persons that have a functional currency other than the U.S. dollar or persons in special situations, such as those who have elected to mark securities to market or those who hold the notes as part of a straddle, hedge, conversion transaction or other integrated investment). In addition, this summary does not address tax considerations applicable to U.S. Holders that own (directly or indirectly) 10% or more of the voting stock of LUKOIL. This summary does not address U.S. federal alternative minimum, estate and gift tax consequences or consequences under the tax laws of any state, local or foreign jurisdiction. We have not sought any ruling from the IRS with respect to the statements made and the conclusions reached in this summary, and we cannot assure you that the IRS will agree with such statements and conclusions.
This summary is for general information only. U.S. Holders are urged to consult their tax advisors concerning the U.S. federal income taxation and other tax consequences to them of acquiring, owning and disposing of the notes, as well as the application of state, local and foreign income and other tax laws.
For purposes of this summary, a "U.S. Holder" means a beneficial owner of a note that is: (1) an individual who is a citizen or resident of the United States, (2) a corporation (or other entity taxable as a corporation) created or organised under the laws of the United States, any state thereof, or the District of Columbia, (3) an estate the income of which is subject to U.S. federal income tax regardless of its source, or (4) a trust if (a) a court within the United States is able to exercise primary supervision over the administration of the trust, and one or more U.S. persons have the authority to control all substantial decisions of the trust, or (b) a valid election to be treated as a U.S. person is in effect with respect to such trust.
For purposes of this summary, a partnership or other entity treated as a partnership for U.S. federal income tax purposes will not be treated as a U.S. Holder. A partnership for U.S. federal income tax purposes is not subject to U.S. federal income tax on income derived from holding a note. The U.S. taxation of a partner in a partnership will depend on the nature of the partnership's activities. If you are a partner in a partnership which holds the notes, you should consult your tax advisor about the U.S. tax consequences of acquiring, owning and disposing of the notes.
Payments of interest on a note will be taxable to a U.S. Holder as ordinary income at the time it is received or accrued, in accordance with such U.S. Holder's regular method of accounting for U.S. federal tax purposes. Payments of interest on the notes will constitute income from sources outside the United States and generally will be treated as "passive income" for foreign tax credit limitation purposes.
As discussed in "Taxation – The Russian Federation", under current law payments made by LUKOIL under the guarantees to holders of the notes who are not Russian residents may become subject to Russian withholding taxes. In this circumstance, LUKOIL may become liable for the payment of additional amounts to U.S. Holders (see "Terms and Conditions of the Notes – Taxation") so that U.S. Holders receive the same amounts they would have received had no Russian withholding taxes been imposed. For U.S. federal income tax purposes, U.S. Holders would be treated as having received the amount of Russian taxes withheld by the Issuer with respect to a note, and as then having paid over the withheld taxes to the Russian taxing authorities. As a result of this rule, the amount of interest income included in gross income for U.S. federal income tax purposes by a U.S. Holder with respect to a payment of interest may be greater than the amount of cash actually received (or receivable) by the U.S. Holder from the Issuer with respect to the payment.
Subject to certain limitations, a U.S. Holder generally will be entitled to a credit against its U.S. federal income tax liability, or a deduction in computing its U.S. federal taxable income, for Russian income taxes withheld and paid by the Company. For purposes of the foreign tax credit limitation, foreign source income is classified in one of two "baskets", and the credit for foreign taxes on income in either basket is limited to U.S. federal income tax allocable to income in such basket. Interest on the notes generally will constitute foreign source income in the passive basket. In certain circumstances, a U.S. Holder may be unable to claim foreign tax credits (and may instead be allowed deductions) for foreign taxes imposed on interest if the notes are held under arrangements in which the U.S. Holder's expected profit is insubstantial. Prospective purchasers should consult their tax advisers concerning the foreign tax credit implications of the payment of these Russian taxes.
A U.S. Holder generally will recognise gain or loss on the sale, exchange or retirement of a note equal to the difference between the amount realised on the sale or retirement (excluding any amount attributable to accrued by unpaid interest, which will be taxable as interest income as described above) and the U.S. Holder's tax basis in the note. A U.S. Holder's tax basis in a note generally will be the U.S. dollar cost of the note to such holder. Any gain or loss recognised by a U.S. Holder on the sale, exchange or retirement of a note will be capital gain or loss and will be long-term capital gain or loss if the note was held by the U.S. Holder for more than one year. Longterm capital gains recognised by individuals are eligible for reduced rates of taxation. The deductibility of capital losses is subject to limitations. Gain or loss realised by a U.S. Holder on the sale, exchange or retirement of a note generally will be U.S. source gain or loss.
Payments of principal and interest on, and the proceeds of the sale or other disposition of notes by a U.S. paying agent or other U.S. intermediary will be reported to the IRS along with certain information, including the beneficial owner's name, address and taxpayer identification number, the aggregate amount of interest or other amounts paid to that beneficial owner during the calendar year and the amount of tax withheld, if any. This obligation, however, does not apply with respect to certain payments to U.S. Holders, including corporations and tax-exempt organisations, provided that they establish entitlement to an exemption.
In the event that a U.S. Holder subject to the reporting requirements described above fails to supply its correct taxpayer identification number in the manner required by applicable law, or underreports its tax liability, backup withholding may apply to each payment of interest and principal on the notes and on proceeds from a sale or other disposition of the notes. The backup withholding obligation, however, does not apply with respect to payments to certain U.S. Holders, including corporations and tax-exempt organisations, provided that they establish entitlement to an exemption.
Backup withholding is not an additional tax and may be refunded or credited against the U.S. Holder's U.S. federal income tax liability, provided that the required information is furnished to the IRS.
U.S. Holders should consult their own tax advisors regarding their qualifications for an exemption from backup withholding and the procedure for obtaining such exemption, if applicable.
The European Union has adopted a Directive (2003/48/EC) regarding the taxation of savings income in the form of interest payments or similar income. From 1 July 2005 EU member states are required to provide to the tax authorities of other EU member states details of payments of interest and other similar income paid by a person to an individual resident in another EU member state. However, Austria, Belgium and Luxembourg are instead required to impose a withholding system for a transitional period (unless during such period they elect otherwise). A number of non-EU countries and territories have adopted similar measures.
(1) The Regulation S Global Notes have been accepted for clearance through Euroclear and Clearstream, Luxembourg under the following reference numbers:
| ISIN 1111211 |
Common Code 1111112 |
|
|---|---|---|
| 2017 Regulation S Global Note | XS0304273948 | 030427394 |
| 2022 Regulation S Global Note | XS0304274599 | 030427459 |
The address of Euroclear is 1 Boulevard du Roi Albert II, B-1210 Brussels, Belgium and the address of Clearstream, Luxembourg is 42 Avenue JF Kennedy L-1855 Luxembourg.
(2) The Rule 144A Global Notes have been accepted for clearance through the facilities of DTC, Euroclear and Clearstream, Luxembourg and the Rule 144A Notes are expected to be eligible for trading in the U.S. on PORTAL, under the following reference numbers:
| ISIN 1111211 |
CUSIP 1111112 |
|
|---|---|---|
| 2017 Rule 144A Global Note | US549876AB61 | 549876AB6 |
| 2022 Rule 144A Global Note | US549876AA88 | 549876AA8 |
The address of DTC is 55 Water Street, New York, New York 10041-0099, United States of America.
any financial statements. In addition, under Dutch law, the Issuer is not required to appoint statutory auditors.
The legal system in Russia has experienced frequent and substantial changes in the last 15 years. Several fundamental Russian laws have been adopted during these years, including:
At the federal level, regulatory authority over the oil industry is divided primarily between the Ministry of Industry and Energy, which replaced the Ministry of Energy pursuant to Presidential Decree No. 314 of 9 March 2004 (Decree No. 314), and the Ministry of Natural Resources. The Ministry of Industry and Energy sets governmental policy for the industry and drafts legislation regulating the energy sector. Law enforcement authority and the functions of providing state services and property management have been transferred from the Ministry of Energy to the newly established Federal Energy Agency.
The Ministry of Natural Resources is involved in the licensing of subsoil resources and also regulates exploration and geological prospecting for the oil and gas industries. On the basis of Decree No. 314, the control and surveillance functions of the Ministry of Natural Resources have been transferred to the newly established Federal Service for the Supervision of the Use of Natural Resources, and the law enforcement functions related to subsoil use have been transferred to the newly established Federal Agency for Subsoil Use.
The Federal Agency for Subsoil Use is subordinate to the Ministry of Natural Resources and, among other things, is responsible for organising tenders and auctions for the award of subsoil licences, issuing and terminating subsoil licenses and supervising the compliance by licence holders with the terms of such licences.
The Federal Service for Environmental, Technological and Nuclear Surveillance is a federal authority which, among other things, issues or authorises other organisations to issue industrial safety certificates.
The Federal Tariff Service, which replaced the Federal Energy Commission following Decree No. 314, and the Ministry of Industry and Energy coordinate the activities of various federal executive agencies to address issues in the oil industry, including, among others, issues related to Transneft's access and tariffs.
Generally, regional authorities with jurisdiction over the specific area in which an oil and gas project, pipeline, refinery or other enterprise is located have substantial authority. Regional and local authorities usually control regional and local (respectively) land-use allocations.
Under the Regulations on Licensing of Subsoil Use of 15 July 1992 (the Regulations), and the Russian Federal Law on Subsoil dated 21 February 1992 (the Subsoil Law), combined subsoil exploration and production licences were granted for up to 25 years. Additionally, licences could be issued separately: for five years for exploration and for 20 years for production. However, since January 2000, subsoil production licences are granted for the term of operation of the field, calculated on the basis of a feasibility study for the development of the natural resource deposits providing for the rational use and protection of the subsoil.
A licence holder has the right to develop and sell oil extracted from the licence area. The Russian Federation, however, retains ownership of all subsoil resources at all times, and the licence holder only has rights to the crude oil or other relevant types of mineral resources when extracted.
Most of the currently existing production licences owned by companies derive from (1) pre-existing rights granted during the Soviet era and up to the enactment of the Subsoil Law to state-owned enterprises that were subsequently reorganised in the course of post-Soviet privatisations, or (2) tender or auction procedures held in the post-Soviet period.
At present, subsoil licences are generally issued by the Federal Agency for Subsoil Use. The Russian Civil Code, the Subsoil Law and the Regulations contain the major requirements relating to tenders and auctions for the award of subsoil licences. The Subsoil Law allows for production licences to be issued without a tender or auction procedure only in limited circumstances, such as instances when a mineral deposit is discovered by the holder of an exploration licence at its own expense during the exploration phase.
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 licensee. The licensing agreement sets out the terms and conditions for the use of the subsoil licence.
Under a licensing agreement, the licensee makes certain environmental, safety and production commitments. For example, the licensee makes a production commitment to bring the field into production by a certain date and to extract an agreed upon volume of natural resources each year. The licence agreement may also contain commitments with respect to the region's social and economic development.
Governmental authorities may undertake periodic reviews for ensuring compliance by subsoil licence users with the terms of their licences and applicable legislation. We have received notices from regional authorities that have alleged areas of non-compliance with the terms of our 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, we have engaged the authorities in negotiations over the timing and focus of certain investments and activities in an effort to remedy any such non-compliance.
A licensee can be fined for failing to comply with the subsoil production licence and the subsoil production licence can be revoked, suspended or limited in certain circumstances, including:
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 licensee; and
Accordingly, we cannot assure you that one or more of our licences will not be revoked, suspended or limited, notwithstanding the remedial actions we have taken or propose to take in the future. Any such revocation, suspension or limitation of our rights under our licences may result in a reduction in the size of our reserves and/or have a material adverse effect on our business, financial condition or results of our operations.
When the licence expires, the licensee 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 law, certain provisions in a licensing agreement are left to the discretion of the licensing authorities and are often negotiated between the parties. However, commitments relating to safety and the environment are generally not negotiated.
The fulfilment of a licence's conditions is a major factor in the good standing of the licence. If the subsoil licensee fails to fulfil the licence's conditions, upon notice, the licence may be terminated by the licensing authorities. However, if a subsoil licensee cannot meet certain deadlines or achieve certain volumes of exploration work or production output as set forth in a licence, it may apply to amend the relevant licence conditions, though such amendments may be denied.
If the licensee does not agree with a decision of the licensing authorities, including a decision relating to a licence termination or the refusal to re-issue an existing licence, the licensee may appeal the decision through administrative or judicial proceedings. In certain cases of termination, the licensee has the right to attempt to cure the violation within three months of its receipt of notice of the violation. If the issue has been resolved within such a three-month period, no termination or other action may be taken.
Licences cannot be sold or transferred to another entity except in certain limited circumstances specified by the Subsoil Law, such as to a reorganised company or a subsidiary in which the licensee has a 50% or greater share. Generally, a licence cannot be held by more than one legal entity. A subsoil production licence gives its holder exclusive rights to develop and produce mineral resources in an identified licence area (including subsurface zones) for the term of the licence.
Amendments introduced to the Subsoil Law in 2000 and 2004 provide that, upon expiration of a licence, it is subject to renewal and extension for the economic life of the relevant field at the initiative of the licence holder as long as the licence holder did not violate the terms of its licence and as long as completion of the exploration, appraisal, production or remediation activities is necessary. Since the law applies both to newly issued and old licences, we believe that our licences will be renewed upon their expiration for the remainder of the economic life of each respective field.
In addition to a subsoil production licence, we are required to obtain rights to use surface land within the specified licensed area. Under the Land Code dated 25 October 2001, companies generally have one of the following rights with regard to land in the Russian Federation: (1) ownership, (2) lease, or (3) right of free use for a fixed term.
Most land plots in the Russian Federation are owned by federal, regional or municipal authorities who, through public auctions or tenders, can sell, lease or grant other use rights to the land to third parties.
Companies may have also been granted a right of perpetual use of land that was acquired prior to the enactment of the Land Code; however, the Federal Law on Introduction of the Land Code of 25 October 2001, with certain exceptions, requires companies using land pursuant to rights of perpetual use either to purchase the land from, or to enter into a lease agreement relating to, the land with the relevant federal, regional or municipal authority owner of the land by 1 January 2006. We hold land use permits to carry on the business currently conducted within the area of each of our licences.
The Subsoil Law provides for the basic framework of payments applicable to licence holders, including: (1) onetime payments in cases specified in the licence, (2) regular payments for the subsoil use (i.e., rentals paid for the right to conduct prospecting and exploration works), (3) payments for geological subsoil information, (4) fees for the right to participate in auctions or tenders and (5) fees for the issuance of licences.
Our operations are subject to extensive federal and regional environmental laws and regulations. These laws and regulations set standards for health and environmental quality, provide for penalties and other liabilities for the violation of such standards and establish, in certain circumstances, obligations to compensate for environmental damage and restore environmental conditions.
The Russian Federal Law on Environmental Protection dated 10 January 2002, as amended, establishes a "payto-pollute" regime administered by the Federal Service for Environmental, Technological and Nuclear Surveillance, which issues pollution discharge limits. In accordance with Decree No. 314, control over environmental quality and subsoil use is exercised by the newly established Federal Service for the Supervision of the Use of Natural Resources.
Fees are assessed for both pollution within the limits agreed on emissions and effluents and for pollution in excess of these limits. There are additional fines for certain other breaches of environmental regulations. The environmental protection legislation contains an obligation to make compensation payments to the budget for all environmental losses caused by pollution. In the event of a dispute concerning losses caused by breaches of environmental laws and regulations, the prosecutor's office or other authorised governmental bodies may bring suit, and although there is no private right of action for monetary relief, courts may impose clean-up obligations subject to the agreement of the parties in lieu of or in addition to imposing fines.
Subsoil licences generally require certain environmental commitments. Although the commitments may be stringent in a particular licence, the penalties for failing to comply and clean-up requirements are generally low.
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.
We have received, and anticipate receiving in the future, notices and meeting minutes from regional authorities that allege that we have violated certain environmental regulations. We have worked and will continue to work with each of these authorities to address such allegations.
The Subsoil Law and Regulations also provide 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 licensee to submit, for the approval of regional authorities, a proposed plan detailing the timeframe and actions the licensee 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 Law on Environmental Protection.
While protection of the environment is apparently not an issue of immediate priority to the current Russian government, it is widely expected that, as the economic situation improves, enforcement of existing legislation and environmental standards and rules will become more stringent, and that more comprehensive legislation will be adopted, which could have a material adverse effect on our business, financial condition or results of operations.
We are currently flaring a portion of the gas produced in our fields, for which we are subject to insignificant stateimposed charges for excess gas flared. These charges are levied in accordance with regulations of the Ministry of Natural Resources and of the Russian government. Limitations on gas flaring may be established in our licences.
From 1995, as part of a scheme to deregulate prices and liberalise export controls, the Russian government established equal pipeline and sea terminal access procedures for all oil companies in proportion to the actual production volume of each company. This system allowed Russian oil companies to export, on average, 35% of the produced oil.
Currently the allocation of pipeline and sea terminal access rights is overseen by the Ministry of Industry and Energy. The Ministry of Industry and Energy approves quarterly schedules that, inter alia, detail the precise volumes of oil that each oil producer can pump through the Transneft system. Once the access rights are allocated, oil producers generally cannot increase their allotted capacity in the export pipeline system, although they do have limited flexibility in altering delivery routes. Oil producers are generally allowed to assign their access rights to a third party.
In August 2001, the Russian government began implementing reforms relating to the allocation of pipeline and sea terminal access rights. As at 11 September 2001, pipeline and sea terminal access rights are distributed among oil producers and their parent companies in proportion to the volumes of oil produced and delivered to the Transneft pipeline system (and not in proportion to mere oil production volumes).
Transneft has a very limited ability to transport individual batches of crude oil with the result that crude oil of differing qualities, delivered in the pipeline system, is blended. Transneft does not currently operate a system whereby companies shipping heavy and sour crude would compensate the shippers of higher-quality crude oil for the deterioration in the crude quality arising from blending. Although the introduction of such a compensatory system is currently under discussion between Transneft and the Russian government, these proposals cause aggressive resistance from regions with low-grade quality reserves. Therefore, our sales of crude oil that we transport through the Transneft system are of the crude oil blend that results from the combination of different types and qualities of crude oil in the system, which is usually referred to as "Urals blend" crude oil. As a result, the price we get for our oil may be lower than the price that we could get for oil of the same quality if we could transport our oil independently of Transneft.
In accordance with Decree No. 314, the tariffs for using Transneft's pipelines are set by the Federal Tariff Service.
The Russian Federal Law on Production Sharing Agreements, dated 30 December 1995, as amended (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 (a PSA) 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 fields as eligible for production sharing agreements. Currently, few of these fields are subject to effective production sharing agreements. We do not currently participate in a PSA in Russia.
Effective from 1 January 2005, the base rate was 419 rubles per tonne extracted and is adjusted depending on the international market price of Urals blend crude oil and the ruble exchange rate. The tax rate is zero when the average Urals blend international market price for the relevant tax period is less than or equal to \$9.00 per barrel. Each \$1.00 per barrel increase in the international Urals blend price over the threshold (\$9.00 per barrel) results in an increase of the tax rate by \$1.61 per tonne extracted (or \$0.22 per barrel extracted using a conversion factor of 7.33). This method of determining the crude oil extraction tax was applied until 31 December 2006.
Effective from 1 January 2007, the crude oil extraction tax rate varies depending on the development and depletion of a particular oil field. The tax rate is zero for extra-heavy crude oil and for crude oil produced in certain regions of Eastern Siberia, depending on the period and volume of production. For crude oil produced in other regions, the relevant tax rate (calculated in accordance with the procedure described above) is multiplied by a coefficient characterizing the depletion of a particular oil field. The coefficient is equal to 1.0 for oil fields with a depletion rate below 80%. Each 1% increase in the depletion rate of a particular oil field above 80% results in a 0.035 decrease in the coefficient. The minimum value of the coefficient is 0.3. The depletion rate is based on crude oil production and reserves information reported to the Russian government.
The mineral extraction tax on natural gas production is calculated using a flat rate. From time to time, Russian legislative authorities amend the tax rate. The current rate of 147 rubles per mcm of natural gas extracted has been effective since 1 January 2006.
The crude oil export duty rate is calculated on a three-layer progressive scale. The rate is zero when the average Urals blend international market price is less than or equal to approximately \$15.00 per barrel (\$109.50 per tonne). If the Urals blend price is between \$15.00 and \$20.00 per barrel (\$109.50 and \$146.00 per tonne), each \$1.00 per barrel increase in the Urals blend price over \$15.00 per barrel (\$109.50 per tonne) results in a \$0.35 per barrel increase in the crude oil export duty rate. If the Urals blend price is between \$20.00 and \$25.00 per barrel (\$146.00 and \$182.50 per tonne), each \$1.00 per barrel increase in the Urals blend price over \$20.00 per barrel (\$146.00 per tonne) bound results in a \$0.45 per barrel increase in the crude oil export duty rate. Each \$1.00 dollar per barrel increase in the Urals blend price over \$25.00 per barrel (\$182.50 per tonne) results in a \$0.65 per barrel increase in the crude oil export duty rate.
The Russian government sets export tariff rates for two-month periods. The rates in a specific two-month period are based on Urals blend international market prices in the immediately preceding two months. Thus, the calculation method that the Russian government employees to determine export tariff rates results in a two-month gap between movements in crude oil prices and the revision of the export duty rate based on those crude oil prices.
Export duty rates on refined products are set by the Russian government. The export duty rate depends on internal demand for refined products and international crude oil market conditions. Crude oil and refined products exported to CIS countries, other than Ukraine, are not subject to export duties. On 1 January 2007, customs regulations between Russia and Belorussia were amended such that crude oil exported from Russia to Belorussia is now subject to export duties. From 1 February 2007, the applicable export duty rate on crude oil exports from Russian to Belorussia is equal to the export duty rate set by the Russian government multiplied by a coefficient of 0.293.
Regular subsoil use payments depend on the size of the licence area provided to the exclusive user of the subsoil. The current annual minimum and the maximum rates of regular payments are set as follows: (1) the rate for the right to prospect and evaluate oil fields ranges from 120 rubles/square kilometre (50 rubles/square kilometre for offshore areas) to 360 rubles/square kilometre (150 rubles/square kilometre for offshore areas); and (2) the rate for the right to explore oil fields ranges from 5,000 rubles/square kilometre (4,000 rubles/square kilometre for offshore areas) to 20,000 rubles/square kilometre (16,000 rubles/square kilometre for offshore areas).
The excise tax rates for the following oil products are:
| Oil Product 111111111111111111111111111111111 |
Rate per tonne 112111111111 |
|---|---|
| Gasoline under 80 octane | 2,657 rubles |
| Gasoline over 80 octane | 3,629 rubles |
| Diesel fuel | 1,080 rubles |
| Motor oil | 2,951 rubles |
| Straight-run gasoline | 2,657 rubles |
The expressions below shall have the following meanings throughout this prospectus unless the context requires otherwise:
References to:
"alkylation" is a refining process that combines low molecular weight olefins (primarily a mixture of propylene and butylene) with isobutene in the presence of a catalyst (either sulphuric acid or hydrofluoric acid) to produce alkylate, which is composed of a mixture of high-octane branched-chain paraffinic hydrocarbons.
"atmospheric distillation" means the refining process of separating crude oil components at atmospheric pressure by heating to high temperatures and subsequent condensing of the fractions by cooling.
"catalytic cracking" means a refining process whereby crude oil is broken down into simpler hydrocarbon compounds at the molecular level by means of extreme heat and exposure to a chemical catalyst.
"catalytic reforming" means a refining process to convert low octane naphtha into high octane blending components by rearranging (rather than cracking) molecules.
"coke" means a solid material similar to coal produced from processing crude oil.
"completion" means the installation of permanent equipment for the production of oil or gas.
"condensate" is a term used to describe light liquid hydrocarbons separated from crude oil after production and sold separately.
"development well" means a well drilled within the known area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
"distillation" means the first stage in the refining process in which crude oil is heated and unfinished refined products are initially separated at their various boiling points.
"downstream" is a term used to refer to all petroleum activities from the refining of crude oil into refined products to the distribution, marketing and shipping of the products. The opposite of downstream is upstream.
"enhanced oil recovery" is a generic term for any process, such as water flooding, whereby oil is produced other than by natural reservoir pressure.
"exploratory well" means a well drilled to find and produce oil or gas in an unproven area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.
"field" means an area consisting of a single or multiple reservoirs all grouped in or related to the same individual geological structure or stratigraphic condition.
"fraction" means that part of petroleum separated from other parts at a particular boiling range.
"gas available for sale" means the amount of gas produced excluding gas used for internal consumption.
"hydrocarbons" means compounds formed from the elements hydrogen (H) and carbon (C) and may be in solid, liquid or gaseous forms.
"hydrotreating" is a refining process for treating petroleum fractions from atmospheric or vacuum distillation units and other petroleum in the presence of catalysts and substantial quantities of hydrogen to remove impurities.
"isomerisation" means a refining process that uses a catalyst to change the chemical or physical properties of a compound without adding or removing anything from the original material.
"mazut" is a term used in Russia to denote fuel oil.
"naphtha" is a generic term used for refined, partly refined or unrefined petroleum products and liquid products of natural gas that boil between 347 and 464 degrees Fahrenheit.
"natural gas" means petroleum that consists principally of light hydrocarbons. It can be divided into lean gas, primarily methane but often containing some ethane and smaller quantities of heavier hydrocarbons (also called sales gas) and wet gas, primarily ethane, propane and butane as well as smaller amounts of heavier hydrocarbons; partially liquid under atmospheric pressure.
"operator" means a company appointed by venture stake holders to take primary responsibility for day-to-day operations of exploration and production activities.
"petrochemicals" means chemicals such as ethylene, propylene and benzene that are derived from petroleum.
"petroleum" is a collective term for hydrocarbons, whether solid, liquid or gaseous. The proportion of different compounds in a petroleum find varies from discovery to discovery. If a reservoir primarily contains light hydrocarbons, it is described as a gas field. If heavier hydrocarbons predominate, it is called an oil field. An oil field may feature free gas above the oil and contain a quantity of light hydrocarbons, also called associated gas.
"petroleum gas" means gas occurring in combination with crude oil, as distinct from gas occurring separately or manufactured from crude oil.
"probable reserves" are those reserves that, on the available evidence and taking into account technical and economic factors, have a better than 50% chance of being produced.
"proved reserves" are those reserves that, on the available evidence and taking into account technical and economic factors, have a better than 90% chance of being produced.
"pyrolysis" means the transformation of a compound into one or more other substances by heat alone.
"reservoir" means a porous and permeable underground rock formation where crude oil or gas has naturally accumulated.
"royalty" as employed in the Reserves Report is a tax on production that is equal to the royalty percentage multiplied by the gross revenue to the interest of the Company.
"seismic" is the use of shock waves generated by controlled explosions to ascertain the nature and contour of geological structures.
"2D seismic" means seismic data that is acquired and processed to yield a two-dimensional picture of the subsurface.
"3D seismic" means seismic data that is acquired and processed to yield a three-dimensional picture of the subsurface.
"thermocracking" means the use of heat to reduce the size of the hydrocarbon molecular structure and convert heavy oils into lighter, value-added products.
"upstream" is a term that includes exploring for oil, developing oil fields and producing oil from the oil fields. The opposite of upstream is downstream.
"vacuum distillation" means distillation under less than atmospheric pressure, which lowers the boiling temperature of the liquid being distilled. This technique is used to prevent cracking or decomposition (a change in the chemical makeup of a hydrocarbon.
"vis-breaking" means thermal cracking used to reduce the viscosity of long or short residues.
Audited Consolidated Financial Statements of OAO LUKOIL and its subsidiaries prepared in accordance with US GAAP as of December 31, 2006 and 2005 and for each of the years in the three-year period ended December 31, 2006
| Independent Auditor's Report | F-2 |
|---|---|
| Consolidated Balance Sheets as of December 31, 2006 and 2005 | F-3 |
| Consolidated Statements of Income for the years ended December 31, 2006 and 2005 and 2004 | F-4 |
| Consolidated Statements of Stockholders' Equity and Comprehensive Income for the years ended December 31, 2006 and 2005 and 2004 |
F-5 |
| Consolidated Statements of Cash Flows for the years ended December 31, 2006 and 2005 and 2004 |
F-6 |
| Notes to Consolidated Financial Statements | F-7 |
The Board of Directors of OAO LUKOIL:
We have audited the accompanying consolidated balance sheets of OAO LUKOIL and its subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income, stockholders' equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2006. These consolidated financial statements are the responsibility of the management of OAO LUKOIL. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of OAO LUKOIL and its subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
/s/ KPMG Limited
KPMG Limited Moscow, Russian Federation April 19, 2007
| Note | 2006 | 2005 | |
|---|---|---|---|
| Assets | |||
| Current assets | |||
| Cash and cash equivalents | 3 | 752 | 1,650 |
| Short-term investments | 44 | 111 | |
| Accounts and notes receivable, net | 5 | 5,158 | 5,533 |
| Inventories | 6 | 3,444 | 2,619 |
| Prepaid taxes and other expenses | 3,693 | 2,107 | |
| Other current assets | 406 | 287 | |
| Assets held for sale | 10 | 75 | 190 |
| Total current assets | 13,572 | 12,497 | |
| Investments | 7 | 1,442 | 1,110 |
| Property, plant and equipment | 8 | 31,316 | 25,464 |
| Deferred income tax assets | 13 | 362 | 181 |
| Goodwill and other intangible assets | 9 | 791 | 680 |
| Other non-current assets | 754 | 413 | |
| Total assets | 48,237 | 40,345 | |
| Liabilities and Stockholders' equity | |||
| Current liabilities | |||
| Accounts payable | 2,759 | 2,167 | |
| Short-term borrowings and current portion of long-term debt | 11 | 1,377 | 853 |
| Taxes payable | 1,663 | 2,087 | |
| Other current liabilities | 1,132 | 729 | |
| Total current liabilities | 6,931 | 5,836 | |
| Long-term debt | 12, 16 | 4,807 | 4,137 |
| Deferred income tax liabilities | 13 | 2,116 | 1,830 |
| Asset retirement obligations | 8 | 608 | 387 |
| Other long-term liabilities | 352 | 332 | |
| Minority interest in subsidiary companies | 523 | 1,019 | |
| Total liabilities | 15,337 | 13,541 | |
| Stockholders' equity | 15 | ||
| Common stock | 15 | 15 | |
| Treasury stock, at cost | (1,098) | (527) | |
| Additional paid-in capital | 3,943 | 3,730 | |
| Retained earnings | 30,061 | 23,586 | |
| Accumulated other comprehensive loss | (21) | – | |
| Total stockholders' equity | 32,900 | 26,804 | |
| Total liabilities and stockholders' equity | 48,237 | 40,345 |
| Revenues Sales (including excise and export tariffs) 23 67,684 55,774 33,845 Equity share in income of affiliates 7 425 441 213 Total revenues 68,109 56,215 34,058 Costs and other deductions Operating expenses (4,657) (3,487) Cost of purchased crude oil, petroleum and chemical products (22,374) (19,398) Transportation expenses (3,863) (3,519) Selling, general and administrative expenses (2,885) (2,578) Depreciation, depletion and amortization (1,851) (1,315) Taxes other than income taxes 13 (8,075) (6,334) Excise and export tariffs (13,570) (9,931) Exploration expenses (209) (317) (Loss) gain on disposals and impairments of assets (148) 52 Income from operating activities 10,477 9,388 6,034 Interest expense (302) (275) Interest and dividend income 111 96 180 Currency translation gain (loss) 169 (134) 135 Other non-operating (expense) income (118) (44) 21 Minority interest (80) (121) Income before income taxes 10,257 8,910 6,008 Current income taxes (2,906) (2,301) Deferred income taxes 133 (166) Total income tax expense 13 (2,773) (2,467) Net income 7,484 6,443 4,248 Per share of common stock (US dollars): Basic 15 9.06 7.91 5.20 Diluted 15 9.04 7.79 5.13 |
Note | 2006 | 2005 | 2004 |
|---|---|---|---|---|
| (2,880) | ||||
| (10,124) | ||||
| (2,784) | ||||
| (2,024) | ||||
| (1,075) | ||||
| (3,505) | ||||
| (5,248) | ||||
| (171) | ||||
| (213) | ||||
| (300) | ||||
| (62) | ||||
| (1,614) | ||||
| (146) | ||||
| (1,760) | ||||
Consolidated Statements of Stockholders' Equity and Comprehensive Income For the years ended December 31, 2006 and 2005 and 2004 (Millions of US dollars, unless otherwise noted)
| 2006 | 2005 | 2004 | ||||
|---|---|---|---|---|---|---|
| Stockholders' equity |
Comprehen- Stockholders' sive income |
equity | sive income | Comprehen- Stockholders' equity |
Comprehen sive income |
|
| Common stock | ||||||
| Balance as of January 1 | 15 | 15 | 15 | |||
| Balance as of December 31 | 15 | 15 | 15 | |||
| Treasury stock | ||||||
| Balance as of January 1 | (527) | (706) | (435) | |||
| Stock purchased | (782) | – | (502) | |||
| Stock disposed | 211 | 179 | 231 | |||
| Balance as of December 31 | (1,098) | (527) | (706) | |||
| Additional paid-in capital | ||||||
| Balance as of January 1 | 3,730 | 3,564 | 3,522 | |||
| Premium on non-outstanding shares issued |
22 | 47 | – | |||
| Proceeds from sale of treasury stock in excess of carrying |
||||||
| amount | 191 | 119 | 42 | |||
| Balance as of December 31 | 3,943 | 3,730 | 3,564 | |||
| Retained earnings | ||||||
| Balance as of January 1 | 23,586 | 17,938 | 14,371 | |||
| Net income | 7,484 | 7,484 | 6,443 | 6,443 | 4,248 | 4,248 |
| Dividends on common stock | (1,009) | (795) | (681) | – | ||
| Balance as of December 31 | 30,061 | 23,586 | 17,938 | |||
| Accumulated other comprehensive loss, net of tax |
||||||
| Balance as of January 1 | – | – | (1) | |||
| Foreign currency translation adjustment |
– | – | – | – 1 |
1 | |
| Effect of initial adoption of SFAS No. 158 |
(21) | – | – | – – |
||
| Balance as of December 31 | (21) | – | – | |||
| Total comprehensive income for the year |
7,484 | 6,443 | 4,249 | |||
| Total stockholders' equity as of | ||||||
| December 31 | 32,900 | 26,804 | 20,811 | |||
| Share activity | ||||||
| 2006 | 2005 | 2004 | ||||
| (thousands of | shares) | (thousands of shares) |
(thousands of shares) |
|||
| Common stock, issued | ||||||
| Balance as of January 1 | 850,563 | 850,563 | 850,563 | |||
| Balance as of December 31 | 850,563 | 850,563 | 850,563 | |||
| Treasury stock | ||||||
| Balance as of January 1 | (21,667) | (33,884) | (26,336) | |||
| Purchase of treasury stock | (9,017) | – | (17,846) |
Disposal of treasury stock 7,052 12,217 10,298 Balance as of December 31 (23,632) (21,667) (33,884)
| Note | 2006 | 2005 | 2004 | |
|---|---|---|---|---|
| Cash flows from operating activities | ||||
| Net income | 7,484 | 6,443 | 4,248 | |
| Adjustments for non-cash items: | ||||
| Depreciation, depletion and amortization | 1,851 | 1,315 | 1,075 | |
| Equity share in income of affiliates | (106) | (397) | (169) | |
| Dry hole costs | 91 | 170 | 42 | |
| Loss (gain) on disposals and impairments of assets | 148 | (52) | 213 | |
| Deferred income taxes | (133) | 166 | 146 | |
| Non-cash currency translation loss (gain) | 86 | (26) | (4) | |
| Non-cash investing activities | (123) | (133) | (123) | |
| All other items – net | (38) | 151 | 97 | |
| Changes in operating assets and liabilities: | ||||
| Accounts and notes receivable | 340 | (1,314) | (694) | |
| Short-term loans receivable of a banking subsidiary | 48 | (23) | (101) | |
| Net movements of customers deposits placed in a | ||||
| banking subsidiary | (11) | 49 | (90) | |
| Inventories | (816) | (735) | (571) | |
| Accounts payable | 592 | 245 | 306 | |
| Taxes payable | (430) | 705 | 310 | |
| Other current assets and liabilities | (1,344) | (467) | (505) | |
| Net cash provided by operating activities | 7,639 | 6,097 | 4,180 | |
| Cash flows from investing activities | ||||
| Capital expenditures | (6,426) | (3,982) | (3,248) | |
| Proceeds from sale of property, plant and equipment | 310 | 51 | 99 | |
| Purchases of investments | (312) | (242) | (540) | |
| Proceeds from sale of investments | 216 | 234 | 242 | |
| Sale of interests in subsidiaries and affiliated | ||||
| companies | 71 | 588 | 183 | |
| Acquisitions of subsidiaries and minority | ||||
| shareholding interest (including advances related to | ||||
| these acquisitions), net of cash acquired | (1,374) | (2,874) | (477) | |
| Net cash used in investing activities | (7,515) | (6,225) | (3,741) | |
| Cash flows from financing activities | ||||
| Net movements of short-term borrowings | 700 | (638) | (170) | |
| Proceeds from issuance of long-term debt | 1,092 | 2,474 | 1,191 | |
| Principal repayments of long-term debt | (1,077) | (704) | (778) | |
| Dividends paid | (1,007) | (746) | (661) | |
| Financing from related party | – | 101 | – | |
| Purchase of treasury stock | (782) | – | (502) | |
| Proceeds from sale of treasury stock | – | 46 | 273 | |
| Other – net | 15 | 6 | (3) | |
| Net cash (used in) provided by financing activities | (1,059) | 539 | (650) | |
| Effect of exchange rate changes on cash and cash equivalents | 37 | (18) | 33 | |
| Net (decrease) increase in cash and cash equivalents | (898) | 393 | (178) | |
| Cash and cash equivalents at beginning of year | 1,650 | 1,257 | 1,435 | |
| Cash and cash equivalents at end of year | 3 | 752 | 1,650 | 1,257 |
| Supplemental disclosures of cash flow information | ||||
| Interest paid | 377 | 296 | 291 | |
| Income taxes paid | 2,980 | 2,402 | 1,803 |
The primary activities of OAO LUKOIL (the "Company") and its subsidiaries (together, the "Group") are oil exploration, production, refining, marketing and distribution. The Company is the ultimate parent entity of this vertically integrated group of companies.
The Group was established in accordance with Presidential Decree 1403, issued on November 17, 1992 under which, on April 5, 1993, the Government of the Russian Federation transferred to the Company 51% of the voting shares of fifteen enterprises, and Government Resolution 861 issued on September 1, 1995 under which, during 1995, a further nine enterprises were transferred to the Group. Since 1995 the Group has carried out a share exchange program to increase its shareholding in each of the twenty-four founding subsidiaries to 100%.
From formation, the Group has expanded substantially through consolidation of its interests, acquisition of new companies and establishment of new businesses.
The Russian Federation has been experiencing political and economic change, which has affected and will continue to affect the activities of enterprises operating in this environment. Consequently, operations in the Russian Federation involve risks, which do not typically exist in other markets.
The accompanying financial statements reflect management's assessment of the impact of the business environment in the countries in which the Group operates on the operations and the financial position of the Group. The future business environments may differ from management's assessment.
These consolidated financial statements have been prepared by the Company in accordance with accounting principles generally accepted in the United States of America ("US GAAP").
These consolidated financial statements include the financial position and results of the Company, controlled subsidiaries of which the Company directly or indirectly owns more than 50% of the voting interest, unless minority interest shareholders have substantive participating rights, and variable interest entities where the Group is determined to be the primary beneficiary. Other significant investments in companies of which the Company directly or indirectly owns between 20% and 50% of the voting interest and over which it exercises significant influence but not control, are accounted for using the equity method of accounting. Investments in companies of which the Company directly or indirectly owns more than 50% of the voting interest but where minority interest shareholders have substantive participating rights are accounted for using the equity method of accounting. Investments in other companies are recorded at cost. Equity investments and investments in other companies are included in "Investments" in the consolidated balance sheet.
The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Significant items subject to such estimates and assumptions include the carrying value of oil and gas properties and other property, plant and equipment, goodwill impairment assessment, asset retirement obligations, deferred income taxes, valuation of financial instruments, and obligations related to employee benefits. Eventual actual amounts could differ from those estimates.
Revenues from the production and sale of crude oil and petroleum products are recognized when title passes to customers. Revenues include excise on petroleum products sales and duties on export sale of crude oil and petroleum products.
Revenues from non-cash sales are recognized at the fair market value of the crude oil and petroleum products sold.
The Company maintains its accounting records in Russian rubles. The Company's functional currency is the US dollar and the Group's reporting currency is the US dollar.
For operations in the Russian Federation, hyperinflationary economies and other operations where the US dollar is the functional currency, monetary assets and liabilities have been translated into US dollars at the rate prevailing at each balance sheet date. Non-monetary assets and liabilities have been translated into US dollars at historical rates. Revenues, expenses and cash flows have been translated into US dollars at rates, which approximate actual rates at the date of the transaction. Translation differences resulting from the use of these rates are included in the consolidated statement of income.
For the majority of operations outside the Russian Federation, the US dollar is the functional currency. For certain other operations outside the Russian Federation, where the US dollar is not the functional currency and the economy is not hyperinflationary, assets and liabilities are translated into US dollars at year-end exchange rates and revenues and expenses are translated at average exchange rates for the year. Resulting translation adjustments are reflected as a separate component of comprehensive income.
Foreign currency transaction gains and losses are included in the consolidated statement of income.
As of December 31, 2006, 2005 and 2004, exchange rates of 26.33, 28.78 and 27.75 Russian rubles to the US dollar, respectively, have been used for translation purposes.
The Russian ruble and other currencies of republics of the former Soviet Union are not readily convertible outside of their countries. Accordingly, the translation of amounts recorded in these currencies into US dollars should not be construed as a representation that such currency amounts have been, could be or will in the future be converted into US dollars at the exchange rate shown or at any other exchange rate.
Cash and cash equivalents include all highly liquid investments with an original maturity of three months or less.
Cash funds for which restrictions on immediate use exist are accounted for within other non-current assets.
Accounts and notes receivable are recorded at their transaction amounts less provisions for doubtful debts. Provisions for doubtful debts are recorded to the extent that there is a likelihood that any of the amounts due will not be obtained. Non-current receivables are discounted to the present value of expected cash flows in future periods using the original discount rate.
Inventories, consisting primarily of stocks of crude oil, petroleum products and materials and supplies, are stated at the lower of cost or market value. Cost is determined using an "average cost" method.
Debt and equity securities are classified into one of three categories: trading, available-for-sale, or held-tomaturity.
Trading securities are bought and held principally for the purpose of selling in the near term. Held-to-maturity securities are those securities in which a Group company has the ability and intent to hold until maturity. All securities not included in trading or held-to-maturity are classified as available-for-sale.
Trading and available-for-sale securities are recorded at fair value. Held-to-maturity securities are recorded at cost, adjusted for the amortization or accretion of premiums or discounts. Unrealized holding gains and losses on trading securities are included in the consolidated statement of income. Unrealized holding gains and losses, net of the related tax effect, on available-for-sale securities are reported as a separate component of comprehensive income until realized. Realized gains and losses from the sale of available-for-sale securities are determined on a specific identification basis. Dividends and interest income are recognized in the consolidated statement of income when earned.
A permanent decline in the market value of any available-for-sale or held-to-maturity security below cost is accounted for as a reduction in the carrying amount to fair value. The impairment is charged to the consolidated statement of income and a new cost base for the security is established. Premiums and discounts are amortized or accreted over the life of the related held-to-maturity or available-for-sale security as an adjustment to yield using the effective interest method and such amortization and accretion is recorded in the consolidated statement of income.
Oil and gas properties are accounted for using the successful efforts method of accounting whereby property acquisitions, successful exploratory wells, all development costs, and support equipment and facilities are capitalized. Unsuccessful exploratory wells are expensed when a well is determined to be non-productive. Other exploratory expenditures, including geological and geophysical costs are expensed as incurred.
Group continues to capitalize costs of exploratory wells and exploratory-type stratigraphic wells for more than one year after the completion of drilling if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. If these conditions are not met or if information that raises substantial doubt about the economic or operational viability of the project is obtained, the well would be assumed impaired, and its costs, net of any salvage value, would be charged to expense.
Depreciation, depletion and amortization of capitalized costs of oil and gas properties is calculated using the unitof-production method based upon proved reserves for the cost of property acquisitions and proved developed reserves for exploration and development costs.
Production and related overhead costs are expensed as incurred.
Depreciation of assets not directly associated with oil production is calculated on a straight-line basis over the economic lives of such assets, estimated to be in the following ranges:
| Buildings and constructions | 5 – 40 | Years |
|---|---|---|
| Machinery and equipment | 5 – 20 | Years |
In addition to production assets, certain Group companies also maintain and construct social assets for the use of local communities. Such assets are capitalized only to the extent that they are expected to result in future economic benefits to the Group. If capitalized, they are depreciated over their estimated economic lives.
The Group records the fair value of liabilities related to its legal obligations to abandon, dismantle or otherwise retire tangible long-lived assets in the period in which the liability is incurred. A corresponding increase in the carrying amount of the related long-lived asset is also recorded. Subsequently, the liability is accreted for the passage of time and the related asset is depreciated using the unit-of-production method.
Goodwill represents the excess of the cost of an acquired entity over the net of the amounts assigned to assets acquired and liabilities assumed. It is assigned to reporting units as of the acquisition date. Goodwill is not amortized, but is tested for impairment at least on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The impairment test requires estimating the fair value of a reporting unit and comparing it with its carrying amount, including goodwill assigned to the reporting unit. If the estimated fair value of the reporting unit is less than its net carrying amount, including goodwill, then the goodwill is written down to its implied fair value.
Intangible assets with indefinite useful lives are tested for impairment at least annually. Intangible assets that have limited useful lives are amortized on a straight-line basis over the shorter of their useful or legal lives.
Long lived assets, such as oil and gas properties, other property, plant, and equipment, and purchased intangibles subject to amortization, are assessed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset group may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset group to the estimated undiscounted future cash flows expected to be generated by that group. If the carrying amount of an asset group exceeds its estimated undiscounted future cash flows, an impairment charge is recognized by writing down the carrying amount to the estimated fair value of the asset group, generally determined as discounted future net cash flows. Assets to be disposed of are separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated. The assets and liabilities of a disposed group classified as held for sale are presented separately in the appropriate asset and liability sections of the balance sheet.
Deferred income tax assets and liabilities are recognized in respect of future tax consequences attributable to temporary differences between the carrying amounts of existing assets and liabilities for the purposes of the consolidated financial statements and their respective tax bases and in respect of operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse and the assets be recovered and liabilities settled. The effect on deferred income tax assets and liabilities of a change in tax rates is recognized in the consolidated statement of income in the reporting period which includes the enactment date.
The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income in the reporting periods in which the originating expenditure becomes deductible. In assessing the realizability of deferred income tax assets, management considers whether it is more likely than not that the deferred income tax assets will be realized. In making this assessment, management considers the scheduled reversal of deferred income tax liabilities, projected future taxable income, and tax planning strategies.
Interest-bearing borrowings are initially recorded at the value of net proceeds received. Any difference between the net proceeds and the redemption value is amortized at a constant rate over the term of the borrowing. Amortization is included in the consolidated statement of income each year and the carrying amounts are adjusted as amortization accumulates.
If borrowings are repurchased or settled before maturity, any difference between the amount paid and the carrying amount is recognized in the consolidated statement of income in the period in which the repurchase or settlement occurs.
The expected costs in respect of pension obligations of Group companies are determined by an independent actuary. Obligations in respect of each employee are accrued over the reporting periods during which the employee renders service in the Group.
Purchases by Group companies of the Company's outstanding stock are recorded at cost and classified as treasury stock within Stockholders' equity. Shares shown as Authorized and Issued include treasury stock. Shares shown as Outstanding do not include treasury stock.
Basic earnings per share is computed by dividing net income available to common stockholders by the weightedaverage number of shares of common stock outstanding during the reporting period. A calculation is carried out to establish if there is potential dilution in earnings per share if convertible securities were to be converted into shares of common stock or contracts to issue shares of common stock were to be exercised. If there is such dilution, diluted earnings per share is presented.
Certain conditions may exist as of the balance sheet date, which may result in losses to the Group but the impact of which will only be resolved when one or more future events occur or fail to occur.
If a Group company's assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of the liability can be estimated, then the estimated liability is accrued and charged to the consolidated statement of income. If the assessment indicates that a potentially material loss is not probable, but is reasonably possible, or is probable, but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss, is disclosed in the notes to the consolidated financial statements. Loss contingencies considered remote or related to unasserted claims are generally not disclosed unless they involve guarantees, in which case the nature of the guarantee is disclosed.
Estimated losses from environmental remediation obligations are generally recognized no later than completion of remedial feasibility studies. Group companies accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Such accruals are adjusted as further information becomes available or circumstances change. Costs of expected future expenditures for environmental remediation obligations are not discounted to their present value.
The Group's derivative activity is limited to certain petroleum products marketing and trading outside of its physical crude oil and petroleum products businesses and hedging of commodity price risks. Currently this activity involves the use of futures and swaps contracts together with purchase and sale contracts that qualify as derivative instruments. The Group accounts for these activities under the mark-to-market methodology in which the derivatives are revalued each accounting period. Resulting realized and unrealized gains or losses are presented in the consolidated statement of income on a net basis. Unrealized gains and losses are carried as assets or liabilities on the consolidated balance sheet.
In February 2007, FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities." This Statement expands the possibility of using fair value measurements and permits enterprises to choose to measure certain financial assets and financial liabilities at fair value. Enterprises shall report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent period.
The Statement is effective in the first quarter 2008. The Group is currently assessing the effect of adoption of SFAS No. 159.
In September 2006, the FASB issued SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106 and 132(R)." This Statement requires an employer that sponsors one or more single-employer defined benefit plans to: (a) Recognize the funded status of a benefit plan in its statement of financial position; (b) Recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost; (c) Measure defined benefit plan assets and obligations as of the date of the employer's fiscal year-end statement of financial position (with limited exceptions); (d) Disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition asset or obligation. The provisions of this Statement are effective December 31, 2006, except for the requirement to measure plan assets and benefit obligations as of the date of the employer's fiscal year-end, which is effective December 31, 2008. The adoption of the provisions of SFAS No. 158 did not have a material impact on the Group's results of operations, financial position or cash flows (refer to Note 14 "Pension benefits").
In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements," which establishes a single authoritative definition of fair value, sets out a framework for measuring fair value and requires additional disclosures about fair value measurements. This Statement does not require any new fair value measurements but is expected to increase the consistency of those measurements. The Group is required to adopt the provisions of SFAS No. 157 in the first quarter 2008 and does not expect any material impact on its financial statements upon adoption.
In June 2006, the FASB issued FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109" (FIN 48). This Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with FASB Statement No. 109, "Accounting for Income Taxes." The Group is required to adopt the provisions of FIN 48 in the first quarter 2007 and is currently assessing the effect of adoption.
In June 2006, the FASB ratified the consensus reached by the EITF on Issue No. 06-3, "How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)." The consensus requires disclosure of either the gross or net presentation, and any such taxes reported on a gross basis should be disclosed in the interim and annual financial statements. The Group adopted the provisions of EITF Issue No. 06-3 in 2006. The adoption of the Issue did not have a material impact on the Group's financial statements.
In December 2004, the FASB issued SFAS No. 123(R), "Share-Based Payment," which revises SFAS No. 123 and supersedes Accounting Principles Board (APB) Opinion No. 25 regarding stock-based employee compensation plans. SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be valued at fair value on the date of grant and as of each reporting date, and to be expensed over the applicable vesting period. The adoption of the provisions of SFAS No. 123(R) during 2006 did not have a material impact on the Group's results of operations, financial position or cash flows.
| As of December 31, 2006 |
As of December 31, 2005 |
|
|---|---|---|
| Cash held in Russian rubles | 119 | 346 |
| Cash held in other currencies | 321 | 905 |
| Cash of a banking subsidiary in other currencies | 130 | 102 |
| Cash held in related party banks in Russian rubles | 97 | 173 |
| Cash held in related party banks in other currencies | 85 | 124 |
| Total cash and cash equivalents | 752 | 1,650 |
The consolidated statement of cash flows excludes the effect of non-cash transactions, which are described in the following table:
| Year ended | Year ended | Year ended | |
|---|---|---|---|
| December 31, 2006 | December 31, 2005 | December 31, 2004 | |
| Non-cash investing activity | 123 | 133 | 123 |
| Non-cash acquisition of minority interest | |||
| in a subsidiary | 314 | – | – |
| Settlement of bond liability with the Company's | |||
| common stock | 91 | 300 | – |
| Total non-cash transactions | 528 | 433 | 123 |
The following table shows the effect of non-cash transactions on investing activity:
| Year ended December 31, 2006 |
Year ended December 31, 2005 |
Year ended December 31, 2004 |
|
|---|---|---|---|
| Net cash used in investing activity | 7,515 | 6,225 | 3,741 |
| Non-cash acquisition of minority interest in | |||
| a subsidiary | 314 | – | – |
| Non-cash investing activity | 123 | 133 | 123 |
| Total investing activity | 7,952 | 6,358 | 3,864 |
| As of December | As of December | ||
|---|---|---|---|
| 31, 2006 | 31, 2005 | ||
| Trade accounts and notes receivable (net of provisions of \$84 million and | |||
| \$80 million as of December 31, 2006 and 2005, respectively) | 3,873 | 3,410 | |
| Current VAT and excise recoverable | 1,097 | 1,772 | |
| Short-term loans receivable of a banking subsidiary | – | 48 | |
| Other current accounts receivable (net of provisions of \$38 million and | |||
| \$46 million as of December 31, 2006 and 2005, respectively) | 188 | 303 | |
| Total accounts and notes receivable | 5,158 | 5,533 |
| As of December | ||
|---|---|---|
| 31, 2006 | 31, 2005 | |
| Crude oil and petroleum products | 2,713 | 1,975 |
| Materials for extraction and drilling | 323 | 250 |
| Materials and supplies for refining | 28 | 29 |
| Other goods, materials and supplies | 380 | 365 |
| Total inventories | 3,444 | 2,619 |
| As of December | As of December | ||
|---|---|---|---|
| 31, 2006 | 31, 2005 | ||
| Investments in equity method affiliates and joint ventures | 1,157 | 934 | |
| Long-term loans given by non-banking subsidiaries | 261 | 165 | |
| Other long-term investments | 24 | 11 | |
| Total long-term investments | 1,442 | 1,110 |
The summarized financial information below is in respect of equity method affiliates and corporate joint ventures. The companies are primarily engaged in crude oil exploration, production, marketing, refining and distribution operations in the Russian Federation and crude oil production and marketing in Kazakhstan.
| Year ended | Year ended | Year ended | ||||
|---|---|---|---|---|---|---|
| December 31, 2006 | December 31, 2005 | December 31, 2004 | ||||
| Group's | Group's | Group's | ||||
| Total | Share | Total | Share | Total | Share | |
| Revenues | 2,367 | 1,251 | 2,972 | 1,383 | 2,885 | 1,313 |
| Income before income taxes | 1,315 | 690 | 1,214 | 605 | 761 | 392 |
| Less income taxes | (529) | (265) | (338) | (164) | (362) | (179) |
| Net income | 786 | 425 | 876 | 441 | 399 | 213 |
| As of December 31, 2006 |
As of December 31, 2005 |
||||
|---|---|---|---|---|---|
| Group's | Group's | ||||
| Total | Share | Total | Share | ||
| Current assets | 1,668 | 829 | 2,650 | 859 | |
| Property, plant and equipment | 2,140 | 1,168 | 2,171 | 1,129 | |
| Other non-current assets | 53 | 25 | 71 | 32 | |
| Total assets | 3,861 | 2,022 | 4,892 | 2,020 | |
| Short-term debt | 161 | 70 | 1,599 | 347 | |
| Other current liabilities | 511 | 264 | 590 | 249 | |
| Long-term debt | 1,003 | 518 | 904 | 487 | |
| Other non-current liabilities | 24 | 13 | 6 | 3 | |
| Net assets | 2,162 | 1,157 | 1,793 | 934 |
| At cost | Net | |||
|---|---|---|---|---|
| As of December | As of December | As of December | As of December | |
| 31, 2006 | 31, 2005 | 31, 2006 | 31, 2005 | |
| Exploration and Production: | ||||
| Western Siberia | 16,911 | 14,237 | 8,673 | 6,669 |
| European Russia | 15,378 | 13,245 | 10,277 | 8,122 |
| International | 5,238 | 4,527 | 4,594 | 4,150 |
| Total | 37,527 | 32,009 | 23,544 | 18,941 |
| Refining, Marketing, Distribution and | ||||
| Chemicals: | ||||
| Western Siberia | 19 | 27 | 16 | 22 |
| European Russia | 7,281 | 6,374 | 4,700 | 3,921 |
| International | 3,988 | 3,537 | 2,605 | 2,254 |
| Total | 11,288 | 9,938 | 7,321 | 6,197 |
| Other: | ||||
| Western Siberia | 157 | 159 | 72 | 78 |
| European Russia | 307 | 215 | 267 | 190 |
| International | 140 | 73 | 112 | 58 |
| Total | 604 | 447 | 451 | 326 |
| Total property, plant and equipment | 49,419 | 42,394 | 31,316 | 25,464 |
As of December 31, 2006 and 2005, the asset retirement obligation amounted to \$618 million and \$397 million, respectively, of which \$10 million was included in "Other current liabilities" in the consolidated balance sheets as of each balance sheet date. During 2006 and 2005, asset retirement obligations changed as follows:
| 2006 | 2005 | |
|---|---|---|
| Asset retirement obligations as of January 1 | 397 | 317 |
| Accretion expense | 39 | 30 |
| New obligations | 113 | 40 |
| Changes in estimates of existing obligations | 39 | 26 |
| Spending on existing obligations | (8) | (7) |
| Property dispositions | (3) | (4) |
| Foreign currency translation and other adjustments | 41 | (5) |
| Asset retirement obligations as of December 31 | 618 | 397 |
The carrying value of goodwill and other intangible assets as of December 31, 2006 and 2005 was as follows:
| As of December | As of December | ||
|---|---|---|---|
| 31, 2006 | 31, 2005 | ||
| Amortized intangible assets | |||
| Software | 327 | 205 | |
| Licenses and other assets | 52 | 58 | |
| Goodwill | 412 | 417 | |
| Total goodwill and other intangible assets | 791 | 680 |
All goodwill amounts relate to the refining, marketing and distribution segment.
In December 2006, a Group company completed the sale of its 100% interest in LUKOIL Shelf Limited and LUKOIL Overseas Orient Limited for \$40 million. LUKOIL Shelf Limited and LUKOIL Overseas Orient Limited render drilling services in the Caspian Sea shelf and own the Astra jack-up rig.
In May 2006, the Group completed the sale of its remaining 21% ownership interest in OAO Bank Petrocommerce for \$33 million. The sale was made to a related party, whose management and directors include members of the Group's management and Board of Directors. The carrying value of this investment as of the date of transaction was equal to the selling price.
In December 2005, the Company made a decision to sell ten tankers. A Group company finalized the sale of eight tankers in May 2006 for a price that approximated their carrying value of \$190 million. As of December 31, 2005, the Group classified these tankers as assets held for sale in the consolidated balance sheet. The sale of the remaining two tankers is expected to be finalized in July 2007 for a price that approximates their carrying value of \$75 million. As of December 31, 2006, the Group classified these tankers as assets held for sale in the consolidated balance sheet.
| As of December | As of December | ||
|---|---|---|---|
| 31, 2006 | 31, 2005 | ||
| Short-term borrowings from third parties | 949 | 315 | |
| Short-term borrowings from related parties | 52 | 1 | |
| Current portion of long-term debt | 376 | 537 | |
| Total short-term borrowings and current portion of long-term debt | 1,377 | 853 |
Short-term borrowings are unsecured and primarily payable in US dollars. The weighted-average interest rate on short-term borrowings from third parties was 5.64% and 5.55% per annum as of December 31, 2006 and 2005, respectively.
| As of December | As of December | |
|---|---|---|
| 31, 2006 | 31, 2005 | |
| Long-term loans and borrowings from third parties | ||
| (including loans from banks in the amount of \$3,204 million and | ||
| \$4,107 million as of December 31, 2006 and 2005, respectively) | 3,277 | 4,233 |
| Long-term loans and borrowings from related parties | 1,043 | 65 |
| 3.5% Convertible US dollar bonds, maturing 2007 | 4 | 94 |
| 7.25% Russian ruble bonds, maturing 2009 | 228 | 208 |
| 7.10% Russian ruble bonds, maturing 2011 | 304 | – |
| 7.40% Russian ruble bonds, maturing 2013 | 228 | – |
| Capital lease obligations | 99 | 74 |
| Total long-term debt | 5,183 | 4,674 |
| Current portion of long-term debt | (376) | (537) |
| Total non-current portion of long-term debt | 4,807 | 4,137 |
Long-term loans and borrowings are primarily repayable in US dollars, maturing from 2007 through 2035. Approximately 14% of this debt is secured by export sales and property, plant and equipment. The weightedaverage interest rate on long-term loans and borrowings from third parties was 6.23% and 5.82% per annum as of December 31, 2006 and 2005, respectively.
A Group company has an unsecured syndicated loan agreement, arranged by Citibank, ABN AMRO Bank, BNP Paribas, Sumitomo Banking Corporation and Societe Generale with an outstanding amount of \$1,934 million as of December 31, 2006, maturing in 2008. Borrowings under this agreement bear interest at LIBOR plus 0.7% per annum. This loan facility was used for financing the acquisition of Nelson Resources Limited ("Nelson") (refer to Note 17 "Business combinations").
The Company has a secured syndicated loan agreement, arranged by ABN AMRO Bank and Citibank, with an outstanding amount of \$286 million as of December 31, 2006, maturing in 2008. Borrowings under this agreement bear interest at LIBOR plus 1.35% per annum.
A Group company has an unsecured syndicated loan agreement with CALYON and ABN AMRO with an outstanding amount of \$236 million as of December 31, 2006. Borrowings under this agreement bear interest at LIBOR plus 0.95% per annum and have maturity dates up to 2010.
A Group company has a secured loan agreement, arranged by Credit Suisse, supported by an Overseas Private Investment Corporation guarantee, with an outstanding amount of \$213 million as of December 31, 2006. Borrowings under this agreement bear interest at LIBOR plus 4.8% per annum and have maturity dates up to 2015.
A Group company has a number of loan agreements with Natexis bank with a total outstanding amount of \$165 million as of December 31, 2006. These agreements have maturity dates up to 2009. Borrowings under these agreements bear interest at a range from LIBOR plus 0.9% to LIBOR plus 2.5% per annum.
A Group company has a loan agreement with Vnesheconombank with an outstanding amount of \$129 million as of December 31, 2006. Borrowings under this agreement bear interest at a fixed rate of 3% per annum and have maturity dates up to 2011.
Group companies have a number of loan agreements with International Finance Corporation with a total outstanding amount of \$107 million as of December 31, 2006. These agreements have maturity dates up to 2011. Borrowings under these agreements bear interest at a range from LIBOR plus 1.6% to LIBOR plus 2.5% per annum.
As of December 31, 2006 the Group has a number of other fixed rate loan agreements with a number of banks and organizations totaling \$119 million, maturing from 2007 to 2017. The weighted average interest rate under these loans was 2.83% per annum.
As of December 31, 2006 the Group has a number of other floating rate loan agreements with a number of banks and organizations totaling \$88 million, maturing from 2007 to 2018. The weighted average interest rate under these loans was 5.38% per annum.
A Group company has a number of loan agreements with ConocoPhillips, the Group's related party, with an outstanding amount of \$1,043 million as of December 31, 2006. Borrowings under these agreements bear interest at fixed rate ranging from 6.8% to 8.2% per annum and have maturity dates up to 2035. These agreements are a part of the Company's broad-based strategic alliance with ConocoPhillips and this financing is used to develop oil production and distribution infrastructure in the Timan-Pechora region of the Russian Federation.
On November 29, 2002, a Group company issued 350,000 3.5% convertible bonds with a face value of \$1,000 each, maturing on November 29, 2007, and exchangeable for 12.112 (previously 11.948) global depository receipts ("GDRs") of the Company per bond. The bonds are convertible into GDRs on or after January 9, 2003 up to the maturity dates. The GDRs are exchangeable into four shares of common stock of the Company. Bonds not converted by the maturity date must be redeemed for cash. The redemption price at maturity will be 120.53% of
the face value in respect of these bonds. A Group company may redeem the bonds for cash prior to maturity, subject to certain restrictions and early redemption charges. The carrying amount of the bonds is being accreted to their redemption value with the accreted amount being charged to the consolidated statement of income.
As of December 31, 2006, bondholders had converted 346,259 bonds into 16.8 million shares of common stock of the Company. Subsequent to period end bondholders had not converted any additional bonds.
Group companies held sufficient treasury stock to permit the full conversion of the bonds to GDRs.
In December 2006, the Company issued 14 million non-convertible bonds with a face value of 1,000 Russian rubles each. Eight million bonds were placed with a maturity of 5 years and a coupon yield of 7.10% per annum and six million bonds were placed with a maturity of 7 years and a coupon yield of 7.40% per annum. All bonds were placed at the face value and have a half year coupon period.
In November 2004, the Company issued 6 million non-convertible bonds with a face value of 1,000 Russian rubles each, maturing on November 23, 2009. For a period of 7 days commencing on November 13, 2007 the bonds holders have the right to demand the Company repurchase the bonds. The bonds have a half year coupon period and bear interest at 7.25% per annum.
Annual maturities of total long-term debt during the next five years, including the portion classified as current, are \$376 million in 2007, \$2,300 million in 2008, \$380 million in 2009, \$288 million in 2010, \$404 million in 2011 and \$1,435 million thereafter.
The Group is taxable in a number of jurisdictions within and outside of the Russian Federation and, as a result, is subject to a variety of taxes as established under the statutory provisions of each jurisdiction.
The total cost of taxation to the Group is reported in the consolidated statement of income as "Total income tax expense" for income taxes, as "Excise and export tariffs" for excise taxes, export tariffs and petroleum products sales taxes and as "Taxes other than income taxes" for other types of taxation. In each category taxation is made up of taxes levied at various rates in different jurisdictions.
Operations in the Russian Federation are subject to Federal and city income tax rates that total 9.5% and a regional income tax rate that varies from 10.5% to 14.5% at the discretion of the individual regional administration. The combined statutory tax rate in the Russian Federation is 24%.
There are not currently, and have not been during the three years ended December 31, 2006, any provisions in the taxation legislation of the Russian Federation to permit the Group to reduce taxable profits in a Group company by offsetting tax losses in another Group company against such profits. Tax losses of a Group company in the Russian Federation may, however, be used fully or partially to offset taxable profits in the same company in any of the ten years following the year of loss, subject to the restriction that no more than 50% of the taxable profit in 2006 can be reduced by loss relief. Starting from January 1, 2007 this restriction will no longer apply.
Domestic and foreign components of income before income taxes were:
| Year ended | Year ended | Year ended | |
|---|---|---|---|
| December 31, 2006 | December 31, 2005 | December 31, 2004 | |
| Domestic | 9,215 | 7,992 | 5,167 |
| Foreign | 1,042 | 918 | 841 |
| Income before income taxes | 10,257 | 8,910 | 6,008 |
Domestic and foreign components of income taxes were:
| Year ended | Year ended | Year ended | |
|---|---|---|---|
| December 31, 2006 | December 31, 2005 | December 31, 2004 | |
| Current | |||
| Domestic | 2,419 | 2,194 | 1,511 |
| Foreign | 487 | 107 | 103 |
| Current income tax expense | 2,906 | 2,301 | 1,614 |
| Deferred | |||
| Domestic | (40) | 61 | 76 |
| Foreign | (93) | 105 | 70 |
| Deferred income tax (benefit) expense | (133) | 166 | 146 |
| Total income tax expense | 2,733 | 2,467 | 1,760 |
The following table is a reconciliation of the amount of income tax expense that would result from applying the Russian combined statutory income tax rate to income before income taxes to total income taxes:
| Year ended | Year ended | Year ended | |
|---|---|---|---|
| December 31, 2006 | December 31, 2005 | December 31, 2004 | |
| Income before taxes | 10,257 | 8,910 | 6,008 |
| Notional income tax at Russian statutory rate | 2,462 | 2,138 | 1,442 |
| Increase (reduction) in income tax due to: | |||
| Non-deductible items, net | 476 | 407 | 301 |
| Foreign rate differences | 47 | (12) | 4 |
| Domestic rate differences | (232) | (125) | (23) |
| Foreign currency effect | 5 | (5) | 6 |
| Change in valuation allowance | 15 | 64 | 30 |
| Total income tax expense | 2,773 | 2,467 | 1,760 |
Taxes other than income taxes were:
| Year ended December 31, 2006 |
Year ended December 31, 2005 |
Year ended December 31, 2004 |
|
|---|---|---|---|
| Mineral extraction tax | 7,281 | 5,590 | 2,971 |
| Social taxes and contributions | 356 | 324 | 330 |
| Property tax | 247 | 233 | 111 |
| Other taxes and contributions | 191 | 187 | 93 |
| Taxes other than income taxes | 8,075 | 6,334 | 3,505 |
Deferred income taxes are included in the consolidated balance sheets as follows:
| As of December 31, 2006 |
As of December 31, 2005 |
|
|---|---|---|
| Other current assets | 68 | 52 |
| Deferred income tax assets – non-current | 362 | 181 |
| Other current liabilities | (69) | (18) |
| Deferred income tax liabilities – non-current | (2,116) | (1,830) |
| Net deferred income tax liability | (1,755) | (1,615) |
The following table sets out the tax effects of each type of temporary differences which give rise to deferred income tax assets and liabilities:
| As of December | As of December 31, 2005 |
||
|---|---|---|---|
| 31, 2006 | |||
| Accounts receivable | 27 | 15 | |
| Long-term liabilities | 209 | 145 | |
| Inventories | 8 | 5 | |
| Property, plant and equipment | 141 | 131 | |
| Accounts payable | 24 | 27 | |
| Long-term investments | 3 | 3 | |
| Operating loss carry forwards | 312 | 121 | |
| Other | 104 | 69 | |
| Total gross deferred income tax assets | 828 | 516 | |
| Less valuation allowance | (149) | (134) | |
| Deferred income tax assets | 679 | 382 | |
| Property, plant and equipment | (2,064) | (1,747) | |
| Accounts payable | (64) | (8) | |
| Accounts receivable | – | (9) | |
| Long-term liabilities | (162) | (117) | |
| Inventories | (42) | (30) | |
| Long-term investments | (16) | (66) | |
| Other | (86) | (20) | |
| Deferred income tax liabilities | (2,434) | (1,997) | |
| Net deferred income tax liability | (1,755) | (1,615) |
As a result of business combinations, during 2006 the Group recognized a net deferred tax liability of \$279 million.
As of December 31, 2006, retained earnings of foreign subsidiaries included \$12,130 million for which deferred taxation has not been provided because remittance of the earnings has been indefinitely postponed through reinvestment and, as a result, such amounts are considered to be permanently invested. The amount of deferred tax liability on this amount is not practicable to calculate.
In accordance with SFAS No. 52 "Foreign currency translation" and SFAS No. 109, "Accounting for Income Taxes," deferred tax assets and liabilities are not recognized for exchange rate effects resulting from the translation of transactions and balances from the Russian ruble to the US dollar using historical exchange rates. Also, in accordance with SFAS No. 109, no deferred tax assets or liabilities are recognized for the effects of the related statutory indexation of property, plant and equipment.
Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred income tax assets are deductible, management believes it is more likely than not that Group companies will realize the benefits of the deductible temporary differences and loss carry forwards, net of existing valuation allowances as of December 31, 2006 and 2005.
As of December 31, 2006, the Group had operating loss carry forwards of \$1,255 million of which \$4 million expire during 2007, \$4 million expire during 2008, \$5 million expire during 2009, \$72 million expire during 2010, \$28 million expire during 2011, \$12 million expire during 2012, \$24 million expire during 2013, \$30 million expire during 2014, \$67 million expire during 2015, \$387 million expire during 2016, \$35 million expire during 2017, \$69 million expire during 2026, and \$518 million have indefinite carry forward.
The Company sponsors a post employment and post retirement benefits program. The primary component of the post employment and postretirement benefits program is a defined benefit pension plan that covers the majority of the Group's employees. This plan is administered by a non-state pension fund, LUKOIL-GARANT, and provides pension benefits primarily based on years of service and final remuneration levels. The Company also provides several long-term employee benefits such as death-in-service benefit and lump-sum payments upon retirement of a defined benefit nature and other defined benefits to certain old age and disabled pensioners who have not vested any pensions under the pension plan.
The Company's pension plan primarily consists of a defined benefit plan enabling employees to contribute a portion of their salary to the plan and at retirement to receive a lump sum amount from the Company equal to all past contributions made by the employee up to 7% of their annual salary. Employees also have the right to receive upon retirement the benefits accumulated under the previous pension plan that was replaced in December 2003. These benefits have been fixed and included in the benefit obligation as of December 31, 2006 and 2005. The amount was determined primarily based on a formula including past pensionable service and relative salaries as of December 31, 2003.
On December 31, 2006, the Group adopted the provisions of SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132(R)." This Statement requires employers to recognize the funded status of all postretirement defined benefit plans in the statement of financial position with corresponding adjustments to accumulated other comprehensive income. The adjustment to accumulated other comprehensive income at adoption represents the net unrecognized actuarial gains and unrecognized prior service costs, both of which were previously netted against the plan's funded status in the statement of financial position. These amounts will be subsequently recognized as net periodic benefit cost. Further, actuarial gains and losses that arise in subsequent periods and are not recognized as net periodic benefit cost in the same periods will be recognized as a component of other comprehensive income. These amounts will be subsequently recognized as a component of net periodic benefit cost on the same basis as the amounts recognized in accumulated other comprehensive income at adoption of SFAS No. 158.
The Company uses December 31 as the measurement date for its post employment and post retirement benefits program. An independent actuary has assessed the benefit obligations as of December 31, 2006 and 2005.
The following table provides information about the benefit obligations, plan assets and actuarial assumptions used as of December 31, 2006 and 2005. The benefit obligations below represent the projected benefit obligation of the pension plan.
| 2006 | 2005 | |
|---|---|---|
| Benefit obligations | ||
| Benefit obligations as of January 1 | 202 | 198 |
| Effect of exchange rate changes | 18 | (8) |
| Service cost | 14 | 9 |
| Interest cost | 19 | 17 |
| Plan amendments | 12 | 4 |
| Actuarial loss | 13 | 2 |
| Benefits paid | (20) | (20) |
| Benefit obligations as of December 31 | 258 | 202 |
| Plan assets | ||
| Fair value of plan assets as of January 1 | 73 | 63 |
| Effect of exchange rate changes | 6 | (3) |
| Return on plan assets | 9 | 9 |
| Employer contributions | 26 | 24 |
| Benefits paid | (20) | (20) |
| Fair value of plan assets as of December 31 | 94 | 73 |
| Funded status | (164) | (129) |
| Unamortized prior service cost | – | 53 |
| Unrecognized actuarial gain | – | (45) |
| Net amount recognized | (164) | (121) |
| Amounts recognized in the consolidated balance sheet as of December 31, 2006, under SFAS No. 158 |
||
| Accrued benefit liabilities included in "Other long-term liabilities" | (164) | – |
| Amounts recognized in the consolidated balance sheet as of | ||
| December 31, 2005, under prior accounting rules | ||
| Accrued benefit liabilities included in "Other long-term liabilities" | – | (121) |
| Assumptions: | ||
| Discount rate | 6.6% | 9.2% |
| Expected return on plan assets | 9.9% | 10.0% |
The effect of adoption of SFAS No. 158 on the financial statements is described below:
| Before application of SFAS No.158 |
Effect of adopting SFAS No.158 |
After application of SFAS No.158 |
|
|---|---|---|---|
| Other long-term liabilities | (137) | (27) | (164) |
| Accumulated other comprehensive loss | – | 21 | 21 |
| Deferred tax asset | – | 6 | 6 |
Included in accumulated other comprehensive loss as of December 31, 2006, are the following before-tax amounts that have not yet been recognized in net periodic benefit cost:
| Unamortized prior service cost | 61 |
|---|---|
| Unrecognized actuarial gain | (34) |
The real returns on bonds and equities are based on what is observed in the international markets over extended periods of time. In the calculation of the expected return on assets no use is made of the historical returns LUKOIL-GARANT has achieved.
In addition to the plan assets, LUKOIL-GARANT holds assets in the form of an insurance reserve. The purpose of this insurance reserve is to satisfy pension obligations should the plan assets not be sufficient to meet pension obligations. The Group's contributions to the pension plan are determined without considering the assets in the insurance reserve.
The plans are funded on a discretionary basis through a solidarity account, which is held in trust with LUKOIL-GARANT. LUKOIL-GARANT does not allocate separately identifiable assets to the Group or its other third party clients. All funds of plan assets and other individual pension accounts are managed as a pool of investments.
The asset allocation of the investment portfolio maintained by LUKOIL-GARANT for the Group and its clients was as follows:
| As of December | As of December | ||
|---|---|---|---|
| Type of assets | 31, 2006 | 31, 2005 | |
| Promissory notes of Russian issuers | 24% | 30% | |
| Russian corporate bonds | 23% | 20% | |
| Bank deposits | 9% | 16% | |
| Equity securities of Russian issuers | 21% | 10% | |
| Russian state bonds | 2% | 9% | |
| Shares of OAO LUKOIL | 8% | 5% | |
| Shares in investment funds | 8% | 5% | |
| Russian municipal bonds | 1% | 3% | |
| Other assets | 4% | 2% | |
| 100% | 100% |
The investment strategy employed by LUKOIL-GARANT includes an overall goal to attain a maximum investment return, while guaranteeing the principal amount invested. The strategy is to invest with a medium-term perspective while maintaining a level of liquidity through proper allocation of investment assets. Investment policies include rules and limitations to avoid concentrations of investments.
The investment portfolio is primarily comprised of two types of investments: securities with fixed yield and equity securities. The securities with fixed yield include mainly high yield corporate bonds and promissory notes of banks with low and medium risk ratings. Maturities range from one to three years.
The following table details the targeted investment mix for 2007 and the maximum limits on investment type.
| Type of investment | 2007 Target Allocation |
Maximum Allocation Allowed |
|---|---|---|
| Russian corporate bonds | 31% | 50% |
| Promissory notes of Russian issuers | 5% | 50% |
| Equity securities of Russian issuers | 28% | 50% |
| Russian municipal bonds | 31% | 50% |
| Other, including bank deposits | 5% | 50% |
| 100% |
Components of net periodic benefit cost were as follows:
| Year ended December 31, 2006 |
Year ended December 31, 2005 |
Year ended December 31, 2004 |
|
|---|---|---|---|
| Service cost | 14 | 9 | 7 |
| Interest cost | 19 | 17 | 14 |
| Less expected return on plan assets | (8) | (6) | (5) |
| Amortization of prior service cost | 6 | 5 | 5 |
| Actuarial gain | (2) | (3) | (5) |
| Curtailment gain | – | – | (8) |
| Total net periodic benefit cost | 29 | 22 | 8 |
Total employer contributions for 2007 are expected to be \$21 million.
The following benefit payments, which reflect expected future services, as appropriate, are expected to be paid:
| 2007 | 2008 | 2009 | 2010 | 2011 | 5-year period 2007-2011 |
5-year period 2012-2016 |
|
|---|---|---|---|---|---|---|---|
| Pension benefits | 51 | 14 | 15 | 13 | 14 | 107 | 63 |
| Other long-term employee benefits | 24 | 13 | 13 | 13 | 14 | 77 | 72 |
| Total expected benefits to be paid | 75 | 27 | 28 | 26 | 28 | 184 | 135 |
| As of December | As of December 31, 2005 |
||
|---|---|---|---|
| 31, 2006 | |||
| (thousands of | (thousands of | ||
| shares) | shares) | ||
| Authorized and issued common stock, par value of 0.025 Russian rubles each | 850,563 | 850,563 | |
| Common stock held by subsidiaries, not considered as outstanding | (1,268) | (2,477) | |
| Treasury stock | (23,632) | (21,667) | |
| Outstanding common stock | 825,663 | 826,419 |
Profits available for distribution to common stockholders in respect of any reporting period are determined by reference to the statutory financial statements of the Company prepared in accordance with the laws of the Russian Federation and denominated in Russian rubles. Under Russian Law, dividends are limited to the net profits of the reporting year as set out in the statutory financial statements of the Company. These laws and other legislative acts governing the rights of shareholders to receive dividends are subject to various interpretations.
The Company's net profits were 55,130 million Russian rubles, 66,327 million Russian rubles and 78,028 million Russian rubles, respectively for 2006, 2005 and 2004, pursuant to the statutory financial statements, which at the US dollar exchange rates as of December 31, 2006, 2005 and 2004 amounted to \$2,094 million, \$2,304 million and \$2,812 million, respectively.
At the annual stockholders' meeting on June 28, 2006, dividends were declared for 2005 in the amount of 33.00 Russian rubles per common share, which at the date of the meeting was equivalent to \$1.22. Dividends payable of \$7 million are included in "Other current liabilities" in consolidated balance sheet as of December 31, 2006 and 2005.
At the annual stockholders' meeting on June 28, 2005, dividends were declared for 2004 in the amount of 28.00 Russian rubles per common share, which at the date of the decision was equivalent to \$0.98.
At the annual stockholders' meeting on June 24, 2004, dividends were declared for 2003 in the amount of 24.00 Russian rubles per common share, which at the date of the meeting was equivalent to \$0.83.
The calculation of diluted earnings per share for these years was as follows:
| Year ended December 31, 2006 |
Year ended December 31, 2005 |
Year ended December 31, 2004 |
|
|---|---|---|---|
| Net income | 7,484 | 6,443 | 4,248 |
| Add back interest on 3.5% Convertible US dollar | |||
| bonds, maturing 2007 (net of tax at effective rate) | 4 | 26 | 27 |
| Total diluted net income | 7,488 | 6,469 | 4,275 |
| Weighted average number of outstanding common shares (thousands of shares) |
826,131 | 814,417 | 817,294 |
| Add back treasury shares held in respect of convertible debt (thousands of shares) |
2,557 | 15,957 | 16,847 |
| Weighted average number of outstanding common | |||
| shares, after dilution (thousands of shares) | 828,688 | 830,374 | 834,141 |
The Group uses derivative instruments in its international petroleum products marketing and trading operations. The types of derivative instruments used include futures and swap contracts, used for hedging purposes, and purchase and sale contracts that qualify as derivative instruments. The Group maintains a system of controls over these activities that includes policies covering the authorization, reporting and monitoring of derivative activity. The Group recognized the following financial results from the use of derivative instruments: income of \$183 million, expense of \$171 million and expense of \$55 million during 2006, 2005 and 2004, respectively. The result is included in "Cost of purchased crude oil, petroleum and chemical products" in the consolidated statements of income. The fair value of derivative contracts outstanding and recorded on the consolidated balance sheets was a net asset of \$43 million and a net liability of \$26 million as of December 31, 2006 and 2005, respectively.
The fair values of cash and cash equivalents, current accounts and notes receivable, and liquid securities are approximately equal to their value as disclosed in the consolidated financial statements.
The fair value of long-term receivables included in other non-current assets approximates the amounts disclosed in the consolidated financial statements as a result of discounting using estimated market interest rates for similar financing arrangements. The fair value of long-term debt differs from the amount disclosed in the consolidated financial statements. The estimated fair value of long-term debt as of December 31, 2006 and 2005 was \$5,299 million and \$5,081 million, respectively, as a result of discounting using estimated market interest rates for similar financing arrangements. These amounts include all future cash outflows associated with the long-term debt repayments, including the current portion, and interest.
In June 2006, a Group company acquired 100% of the share capital of Khanty-Mansiysk Oil Corporation ("KMOC") from Marathon Oil Corporation for \$847 million (including \$249 million repayment of KMOC debt), which is subject to finalisation of working capital and other adjustments in accordance with the purchase agreement. KMOC owns approximately 95% of the share capital of OAO Khantymansiysk-neftegazgeologia and 100% of the share capital of OAO Paitykh Oil and OAO Nazymgeodobycha ("KMOC subsidiaries"). KMOC's subsidiaries operate oil and gas fields in the West Siberian region of the Russian Federation.
KMOC's results of operations are included in the Group's consolidated statement of income from June 2006.
The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition.
| Current assets | 91 |
|---|---|
| Property, plant and equipment | 897 |
| Other non-current assets | 38 |
| Total assets acquired | 1,026 |
| Current liabilities | (23) |
| Non-current deferred tax liabilities | (133) |
| Long-term debt | (249) |
| Minority interest | (14) |
| Other long-term liabilities | (9) |
| Total liabilities assumed | (428) |
| Net assets acquired | 598 |
During the period from October 14 to December 5, 2005, a Group company acquired 100% of the share capital of Nelson for \$1,951 million. Nelson is an exploration and production company operating in western Kazakhstan. Nelson owns an effective 76% interest in the Karakuduk field, 50% interest in Alibekmola, Kozhasai, North Buzachi and Arman fields. In addition, Nelson holds an option to acquire a 25% interest in two exploration blocks in the Kazakhstan sector of the Caspian Sea – South Zhambai and South Zaburunye. The purpose of the acquisition was to increase the Group's presence in the Kazakhstan oil and gas sector and its international oil and gas reserves. Nelson's results of operations are included in the Group's consolidated statement of income from October 14, 2005.
The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition.
| Current assets | 170 |
|---|---|
| Property, plant and equipment | 2,794 |
| Other non-current assets | 55 |
| Total assets acquired | 3,019 |
| Current liabilities | (166) |
| Non-current deferred tax liabilities | (769) |
| Long-term debt | (87) |
| Minority interest | (31) |
| Other non-current liabilities | (15) |
| Total liabilities assumed | (1,068) |
| Net assets acquired | 1,951 |
In September 2006, a Group company acquired the remaining 40% of share capital of Chaparral Resources Inc., Nelson group company and the owner of 60% interest in the Karakuduk field, for \$89 million. The acquisition increased the Group's ownership stake in Chaparral Resources Inc. and effective interest in the Karakuduk field to 100%.
In November 2006, a Group company entered into an agreement with Mittal Investments S.A.R.L. to sell 50% of its interest in Caspian Investment Resources Ltd. ("Caspian", formerly Nelson), for \$980 million. In accordance with the agreement, Mittal Investments S.A.R.L. agreed to assume a liability in the amount of approximately \$160 million, which represents 50% of Caspian's outstanding debt to Group companies. The transaction is expected to be finalized in the second quarter 2007. As of December 31, 2006 Caspian is consolidated as a 100% owned subsidiary.
During the period from November to December 2005, a Group company acquired 51% of the share capital of OAO Primorieneftegaz for \$261 million. OAO Primorieneftegaz is a Russian oil and gas exploration company operating in European Russia. Subsequently, in May 2006, a Group company acquired the remaining 49% of the share capital of OAO Primorieneftegaz for 4.165 million shares of common stock of the Company (at a market value of approximately \$314 million), thereby increasing the Group's ownership stake in OAO Primorieneftegaz to 100%.
In November 2005, a Group company acquired the remaining 50% of the share capital of ZAO SeverTEK for \$318 million from Neste Oil Corporation (including \$98 million repayment of ZAO SeverTEK debt). The acquisition increased the Group's ownership stake in ZAO SeverTEK to 100%. ZAO SeverTEK is an exploration and production company operating within the Komi Republic of the Russian Federation.
In July 2005, a Group company acquired 66.0% of the share capital of OOO Geoilbent for \$180 million. OOO Geoilbent is an exploration and production company operating in the West Siberian region of the Russian Federation. All decisions over OOO Geoilbent's financing and operating activities required approval by at least a 66.7% majority of the voting rights. Because the minority shareholder of OOO Geoilbent held substantive participating rights, the Group accounted for its investment in OOO Geoilbent using the equity method of accounting. In January 2007, a Group company acquired the remaining 34.0% of the share capital of OOO Geoilbent for \$300 million, thereby increasing the Group's ownership stake in OOO Geoilbent to 100%.
In March 2005, a Group company acquired a 100% interest in Oy Teboil Ab and Suomen Petrooli Oy for \$160 million. Oy Teboil Ab and Suomen Petrooli Oy are marketing and distribution companies mainly engaged in operating a chain of retail petrol stations, wholesale of refined products and production and sale of lubricants in Finland.
In January 2005, a Group company acquired an additional 22% interest in LUKOIL Neftochim Bourgas AD for \$56 million (20.7% interest was acquired from a related party for \$52 million). The acquisition increased the Group's ownership stake in LUKOIL Neftochim Bourgas AD to 93.2%. In August 2005, a Group company acquired an additional 4% interest in LUKOIL Neftochim Bourgas AD for \$10 million, thereby increasing the Group's ownership stake in LUKOIL Neftochim Bourgas AD to 97.2%.
Purchases of interests in KMOC, Nelson, Chaparral Resources Inc., OAO Primorieneftegaz, ZAO SeverTEK, OOO Geoilbent, Oy Teboil Ab, Suomen Petrooli Oy and LUKOIL Neftochim Bourgas AD did not have a material impact on the Group's consolidated operations for the period ended December 31, 2006 and 2005. Therefore, no pro-forma income statement information has been provided in these consolidated financial statements.
On June 30, 2005, the Company completed the formation of a joint venture with ConocoPhillips within the framework of their broad-based strategic alliance. This joint venture was created by selling ConocoPhillips an interest in the Company's wholly owned subsidiary OOO Narianmarneftegaz ("NMNG") for \$529 million. The purpose of the joint venture is to develop oil reserves in the Timan-Pechora region of the Russian Federation. The Group and ConocoPhillips have equal voting rights over the joint venture's activity and effective ownership interests of 70% and 30%, respectively. NMNG's total assets were approximately \$2.6 billion and \$1.9 billion as of December 31, 2006 and 2005, respectively.
The Group determined that NMNG is a variable interest entity as the Group's voting rights are not proportionate to its ownership rights and all of NMNG's activities are conducted on behalf of the Group and ConocoPhillips, its related party. The Group is considered to be the primary beneficiary and has consolidated NMNG.
As a result of the transaction, the Group recognized gain of \$152 million which is included in the consolidated statement of income for the year ended December 31, 2005.
During 2005, the Group and ConocoPhillips agreed to provide financing to NMNG by means of long-term loans in the proportion of their effective ownership interests. The loan maturities are 30 years, with the option to be extended for a further 35 years with the agreement of both parties. As of December 31, 2005, these loans bore interest at 0.1% per annum. The loan proceeds were originally accounted for by NMNG primarily as equity contributions as a result of recording the loan obligations at their present value based on market interest rates. The difference between the proceeds and the present value represented contributions to NMNG's equity.
In the second quarter of 2006, the Group and ConocoPhillips reached an agreement to amend the contractual interest rates of the loans. As of December 31, 2006 borrowings under these agreements bear fixed interest at a range from 6.8% to 8.2% per annum. As a result of the amendment, the financing received from the Group and ConocoPhillips was transferred from equity to long-term debt by NMNG.
As of December 31, 2006, the outstanding amount due to ConocoPhillips from NMNG was \$848 million, which consists of a number of loans with a weighted-average interest rate of 7.91% per annum. This amount is presented within "Long-term loans and borrowings from related parties".
The Group has entered into various guarantee arrangements. These arrangements arose in transactions related to enhancing the credit standing of an affiliated company LUKARCO and borrowings of the Group's suppliers.
The following table provides the undiscounted maximum amount of potential future payments for each major group of guarantees:
| As of December | As of December | ||
|---|---|---|---|
| 31, 2006 | 31, 2005 | ||
| Guarantees of equity investees' debt | 410 | 454 | |
| Guarantees of third parties' debt | 8 | 19 | |
| Total | 418 | 473 |
LUKARCO, an investee recorded under the equity method of accounting has a loan facility on which \$678 million was drawn as of December 31, 2006. Borrowings under this loan bear interest at LIBOR plus 2.5% per annum, maturing by May 1, 2012. To enhance the credit standing of LUKARCO, the Company guarantees 54% of the interest payment as well as the repayment of 54% of the loan at maturity. As of December 31, 2006, the total amount of the Company's guarantee was \$410 million, which includes \$44 million related to accrued interest on the outstanding amount. Payments are due if the Company is notified that LUKARCO is not able to fulfill its obligations at maturity date. The Company's guarantee is secured by its 54% interest in LUKARCO with the carrying value of \$358 million and \$259 million as of December 31, 2006 and 2005, respectively. There are no material amounts being carried as liabilities for the Group's obligations under this guarantee.
The Group owns and operates refineries in Bulgaria (LUKOIL Neftochim Bourgas AD) and Romania (Petrotel-LUKOIL). As a result of Bulgaria and Romania joining the European Union in 2007, LUKOIL Neftochim Bourgas AD and Petrotel-LUKOIL are required to upgrade their refining plants to comply with the requirements of European Union legislation in relation to the quality of produced petroleum products and environmental
protection. These requirements are stricter than existing Bulgarian and Romanian legislation. The Group estimates the amount of future capital commitment required to upgrade LUKOIL Neftochim Bourgas AD and Petrotel-LUKOIL to be approximately \$750 million and \$57 million, respectively.
Group companies have commitments under the terms of existing license agreements in the Russian Federation of \$1,379 million over the next 5 years and of \$352 million thereafter. Management believes that a significant portion of these commitments will be fulfilled by the services to be provided by Eurasia Drilling Company and ZAO Globalstroy-Engineering as discussed below.
In connection with the sale of LUKOIL-Burenie in 2004 the Group signed a five year contract for drilling services. Under the terms of the contract, drilling services of \$773 million, \$697 million, and \$702 million will be provided by LUKOIL-Burenie (now Eurasia Drilling Company) during 2007, 2008, and 2009, respectively.
The Company has signed a four-year agreement for the provision of construction, engineering and technical services with ZAO Globalstroy-Engineering. The volume of these services is based on the Group's capital construction program, which is re-evaluated on an annual basis. The Group estimates the amount of capital commitment under this agreement for 2007 to be approximately \$1,255 million.
A Group company has commitment to purchase equipment for modernization of the petrochemical refinery in Ukraine over the next 3 years. The outstanding portion of this commitment is approximately \$156 million.
Group companies have commitments for capital expenditure contributions in the amount of \$343 million related to various production sharing agreements over the next 32 years.
Group companies have investment commitments relating to oil deposits in Iraq of \$495 million to be spent within 3 years from when exploitation becomes possible. Due to significant changes in the political and economic situation in Iraq the future of this contract is not clear, however, the Group is actively pursuing its legal right to this contract in Iraq in alliance with ConocoPhillips.
A Group company has commitments of \$1,451 million primarily for the lease of vessels and petroleum distribution outlets over the next 9 years. Commitments for minimum rentals under these leases as of December 31, 2006 are as follows:
| As of December | |
|---|---|
| 31, 2006 | |
| 2007 | 341 |
| 2008 | 267 |
| 2009 | 215 |
| 2010 | 124 |
| 2011 | 122 |
| beyond | 382 |
The insurance industry in the Russian Federation and certain other areas where the Group has operations is in the course of development. Management believes that the Group has adequate property damage coverage for its main production assets. In respect of third party liability for property and environmental damage arising from accidents on Group property or relating to Group operations, the Group has insurance coverage that is generally higher than insurance limits set by the local legal requirements. Management believes that the Group has adequate insurance coverage of the risks, which could have a material effect on the Group's operations and financial position.
Group companies and their predecessor entities have operated in the Russian Federation and other countries for many years and, within certain parts of the operations, environmental related problems have developed.
Environmental regulations are currently under consideration in the Russian Federation and other areas where the Group has operations. Group companies routinely assess and evaluate their obligations in response to new and changing legislation.
As liabilities in respect of the Group's environmental obligations are able to be determined, they are charged against income over the estimated remaining lives of the related assets or recognized immediately depending on their nature. The likelihood and amount of liabilities relating to environmental obligations under proposed or any future legislation cannot be reasonably estimated at present and could become material. Under existing legislation, however, management believes that there are no significant unrecorded liabilities or contingencies, which could have a materially adverse effect on the operating results or financial position of the Group.
Certain Group companies contribute to Government sponsored programs, the maintenance of local infrastructure and the welfare of their employees within the Russian Federation and elsewhere. Such contributions include assistance with the construction, development and maintenance of housing, hospitals and transport services, recreation and other social needs. The funding of such assistance is periodically determined by management and is appropriately capitalized or expensed as incurred.
The taxation systems in the Russian Federation and other emerging markets where Group companies operate are relatively new and are characterized by numerous taxes and frequently changing legislation, which is often unclear, contradictory, and subject to interpretation. Often, differing interpretations exist among different tax authorities within the same jurisdictions and among taxing authorities in different jurisdictions. Taxes are subject to review and investigation by a number of authorities, which are enabled by law to impose severe fines, penalties and interest charges. In the Russian Federation a tax year remains open for review by the tax authorities during the three subsequent calendar years; however, under certain circumstances a tax year may remain open longer. Recent events within the Russian Federation suggest that the tax authorities are taking a more assertive position in their interpretation and enforcement of tax legislation. Such factors may create taxation risks in the Russian Federation and other emerging markets where Group companies operate substantially more significant than those in other countries where taxation regimes have been subject to development and clarification over long periods.
The tax authorities in each region may have a different interpretation of similar taxation issues which may result in taxation issues successfully defended by the Group in one region being unsuccessful in another region. There is some direction provided from the central authority based in Moscow on particular taxation issues.
The Group has implemented tax planning and management strategies based on existing legislation at the time of implementation. The Group is subject to tax authority audits on an ongoing basis, as is normal in the Russian environment and other republics of the former Soviet Union, and, at times, the authorities have attempted to impose additional significant taxes on the Group. Management believes that it has adequately met and provided for tax liabilities based on its interpretation of existing tax legislation. However, the relevant tax authorities may have differing interpretations and the effects on the financial statements, if the authorities were successful in enforcing their interpretations, could be significant.
"Income tax expense" and "Taxes other than income taxes" in the consolidated statement of income for 2005 include \$163 million in relation to the results of tax audits of the Group companies for periods prior to the 2004 financial year.
On November 27, 2001, Archangel Diamond Corporation ("ADC"), a Canadian diamond development company, filed a lawsuit in the District Court of Denver, Colorado against OAO "Arkhangelskgeoldobycha" ("AGD"), a Group company, and the Company (together the "Defendants"). ADC alleged that the Defendants interfered with the transfer of a diamond exploration license to Almazny Bereg, a joint venture between ADC and AGD. ADC claimed total damages of approximately \$4.8 billion, including compensatory damages of \$1.2 billion and punitive damages of \$3.6 billion. On October 15, 2002, the District Court dismissed the lawsuit for lack of
personal jurisdiction. This ruling was upheld by the Colorado Court of Appeals on March 25, 2004. On November 21, 2005, the Colorado Supreme Court affirmed the lower courts' ruling that no specific jurisdiction exists over the Defendants. By virtue of this finding, AGD (the holder of the diamond exploration license) was completely dismissed from the lawsuit. The Supreme Court found, however, that the trial court made a procedural error by not holding an evidentiary hearing before making its ruling concerning general jurisdiction, which is whether the Company had systematic and continuous contacts in the State of Colorado at the time the lawsuit was filed. In a modified opinion dated December 19, 2005, the Colorado Supreme Court remanded the case to the Colorado Court of Appeals (instead of the District Court) to consider whether the lawsuit should have been dismissed on alternative grounds (i.e., forum non conveniens). On June 29, 2006, the Colorado Court of Appeals declined to dismiss the case based on forum non conveniens. The Company filed a petition for certiorari on August 28, 2006 asking the Colorado Supreme Court to review this decision. On March 5, 2007 the Colorado Supreme Court remanded the case to the District Court. The District Court has not set a pretrial schedule, but should do so shortly. Management does not believe that the ultimate resolution of this matter will have a material adverse effect on the Group's financial condition.
On February 20, 2004, the Stockholm District Court overturned the decision of the Arbitral Tribunal of the Arbitration Institute of the Stockholm Chamber of Commerce ("Arbitration Tribunal") made on June 25, 2001 dismissing ADC's action against AGD based on lack of jurisdiction. ADC's lawsuit against AGD was initially filed with the Arbitral Tribunal claiming alleged non-performance under an agreement between the parties and its obligation to transfer the diamond exploration license to Almazny Bereg. This lawsuit claimed compensation of damages amounting to \$492 million. In March 2004, AGD filed an appeal against the Stockholm District Court decision with the Swedish Court of Appeals. On November 15, 2005, the Swedish Court of Appeals denied AGD's appeal and affirmed the Stockholm District Court decision. On December 13, 2005, AGD filed an appeal against the Swedish Court of Appeals decision with the Swedish Supreme Court. On April 13, 2006 the Swedish Supreme Court denied the application of AGD for appeal against the Swedish Court of Appeal's decision dated November 15, 2005. On May 6, 2006 a Notice of Arbitration was received on behalf of ADC. On December 20, 2006 the first session of the Arbitration Tribunal with participation of both parties took place in order to define procedural issues related to the tribunal. As a result of the hearing the Arbitration Tribunal issued a detailed procedural order setting out the rules and timetable for the conduct of the arbitration. The hearing in relation to issues primarily relating to liability, if any, is currently scheduled to take place in June 2008. Management does not believe that the ultimate resolution of this matter will have a material adverse effect on the Group's financial condition.
The Group is involved in various other claims and legal proceedings arising in the normal course of business. While these claims may seek substantial damages against the Group and are subject to uncertainty inherent in any litigation, management does not believe that the ultimate resolution of such matters will have a material adverse impact on the Group's operating results or financial condition.
In the rapidly developing business environment in the Russian Federation, companies and individuals have frequently used nominees and other forms of intermediary companies in transactions. The senior management of the Company considers that the Group has appropriate procedures in place to identify and properly disclose transactions with related parties in this environment and has disclosed all of the relationships identified which it deemed to be significant. Related party sales and purchases of oil and oil products were primarily to and from affiliated companies and the Company's shareholder ConocoPhillips. Insurance services are provided by the related parties, whose management and directors include members of the Group's management. Purchases of construction services were primarily from affiliated companies.
Below are related party transactions not disclosed elsewhere in the financial statements. Refer also to Notes 3, 10, 11, 12, 14, 17, 18, 19 and 22 for other transactions with related parties.
Sales of oil and oil products to related parties were \$754 million, \$605 million and \$153 million for the years ended December 31, 2006, 2005 and 2004, respectively.
Other sales to related parties were \$19 million, \$58 million and \$63 million for the years ended December 31, 2006, 2005 and 2004, respectively.
Purchases of oil and oil products from related parties were \$1,739 million, \$2,248 million and \$770 million for the years ended December 31, 2006, 2005 and 2004, respectively.
Purchases of construction services from related parties were \$13 million, \$378 million and \$648 million for the years ended December 31, 2006, 2005 and 2004, respectively.
Other purchases from related parties were \$49 million, \$54 million and \$71 million for the years ended December 31, 2006, 2005 and 2004, respectively.
Purchases of insurance services from related parties were \$133 million, \$133 million and \$138 million during the years ended December 31, 2006, 2005 and 2004, respectively.
Amounts receivable from related parties, including loans and advances, were \$121 million and \$160 million as of December 31, 2006 and 2005, respectively. Amounts payable to related parties were \$89 and \$127 million as of December 31, 2006 and 2005, respectively.
In December 2006 the Company entered into an agreement with its related party ConocoPhillips to purchase 376 fueling stations in six countries in Europe. The agreement is expected to be finalized in the second quarter of 2007.
During the period from 2003 to 2006, the Company had a compensation plan available to certain members of management, which provides compensation based upon share appreciation rights on the Company's common stock. The number of shares or rights allocated to individuals under the plan was approximately 9 million shares. These rights vested in December 2006. The Group has accrued a liability of \$537 million and \$283 million, included in "Other current liabilities", as of December 31, 2006 and 2005, respectively. The Group recorded \$280 million, \$263 million and \$65 million of compensation expense during the years ended December 31, 2006, 2005 and 2004, respectively. In February 2007, the compensation plan was settled through the issuance of approximately 7.3 million shares.
In December 2006, the Company introduced a new compensation plan to certain members of management for the period from 2007 to 2009, which is based on assigned phantom shares and provides compensation consisting of two parts. The first part represents annual bonuses that are based on the number of assigned phantom shares and amount of dividend per share. The second is based upon the Company's common stock appreciation from 2007 to 2009 with rights vesting after the date of the compensation plan's termination. The number of assigned phantom shares is approximately 14 million shares.
Presented below is information about the Group's operating and geographical segments for the years ended December 31, 2006, 2005 and 2004 in accordance with SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information."
The Group has four operating segments – exploration and production; refining, marketing and distribution; chemicals and other business segments. These segments have been determined based on the nature of their operations. Management on a regular basis assesses the performance of these operating segments. The exploration and production segment explores for, develops and produces primarily crude oil. The refining, marketing and distribution segment processes crude oil into refined products and purchases, sells and transports crude oil and refined petroleum products. The chemicals segment refines and sells chemical products. Activities of the other business operating segment include the development of businesses beyond the Group's traditional operations.
Geographical segments have been determined based on the area of operations and include three segments. They are Western Siberia, European Russia and International.
| Refining | ||||||
|---|---|---|---|---|---|---|
| Exploration | marketing and | |||||
| 2006 | and production | distribution | Chemicals | Other | Elimination | Consolidated |
| Sales | ||||||
| Third parties | 1,659 | 64,116 | 1,869 | 40 | - | 67,684 |
| Inter-segment | 18,989 | 1,786 | 22 | 216 | (21,013) | - |
| Total sales | 20,648 | 65,902 | 1,891 | 256 | (21,013) | 67,684 |
| Operating expenses and | ||||||
| total cost of purchases | 3,232 | 42,835 | 1,561 | 138 | (20,735) | 27,031 |
| Depreciation, depletion | ||||||
| and amortization | 1,269 | 542 | 19 | 21 | – | 1,851 |
| Interest expense | 451 | 341 | 2 | 187 | (679) | 302 |
| Income tax expense | 1,617 | 1,129 | 23 | 4 | – | 2,773 |
| Net income | 3,578 | 3,652 | 96 | 272 | (114) | 7,484 |
| Total assets | 34,152 | 32,168 | 794 | 7,340 | (26,217) | 48,237 |
| Capital expenditures | 5,120 | 1,475 | 172 | 119 | – | 6,886 |
| Refining | ||||||
| Exploration | marketing and | |||||
| 2005 | and production | distribution | Chemicals | Other | Elimination | Consolidated |
| Sales | ||||||
| Third parties | 1,047 | 53,064 | 1,628 | 35 | – | 55,774 |
| Inter-segment | 14,821 | 1,041 | 22 | 138 | (16,022) | – |
| Total sales | 15,868 | 54,105 | 1,650 | 173 | (16,022) | 55,774 |
| Operating expenses and | ||||||
| total cost of purchases | 2,602 | 34,652 | 1,314 | 126 | (15,809) | 22,885 |
| Depreciation, depletion | ||||||
| and amortization | 824 | 464 | 15 | 12 | – | 1,315 |
| Interest expense | 73 | 335 | 2 | 50 | (185) | 275 |
| Income tax expense | 1,111 | 1,317 | 35 | 4 | – | 2,467 |
| Net income | 3,362 | 3,059 | 122 | 52 | (152) | 6,443 |
| Total assets | 25,480 | 23,682 | 586 | 5,130 | (14,533) | 40,345 |
| Capital expenditures | 2,918 | 1,129 | 77 | 53 | – | 4,177 |
| Refining | ||||||
| Exploration | marketing and | |||||
| 2004 | and production | distribution | Chemicals | Other | Elimination | Consolidated |
| Sales | ||||||
| Third parties | 1,614 | 30,807 | 1,384 | 40 | – | 33,845 |
| Inter-segment | 8,379 | 822 | 13 | 103 | (9,317) | - |
| Total sales | 9,993 | 31,629 | 1,397 | 143 | (9,317) | 33,845 |
| Operating expenses and | ||||||
| total cost of purchases | 2,610 | 18,469 | 1,119 | 89 | (9,283) | 13,004 |
| Depreciation, depletion | ||||||
| and amortization | 676 | 377 | 8 | 14 | – | 1,075 |
| Interest expense | 76 | 272 | 2 | 93 | (143) | 300 |
| Income tax expense | 568 | 1,159 | 20 | 13 | – | 1,760 |
| Net income | 1,221 | 2,908 | 175 | 117 | (173) | 4,248 |
| Total assets | 17,827 | 17,029 | 462 | 3,143 | (8,700) | 29,761 |
| Capital expenditures | 2,289 | 1,070 | 71 | 17 | – | 3,447 |
Notes to Consolidated Financial Statements (Millions of US dollars, except as indicated)
| 2006 | 2005 | 2004 | |
|---|---|---|---|
| Sales of crude oil within Russia | 376 | 120 | 181 |
| Export of crude oil and sales of crude oil by foreign subsidiaries | 17,649 | 16,367 | 10,940 |
| Sales of petroleum products within Russia | 8,151 | 6,725 | 4,665 |
| Export of petroleum products and sales of petroleum products by foreign subsidiaries |
37,459 | 29,216 | 15,317 |
| Sales of chemicals within Russia | 569 | 469 | 332 |
| Export of chemicals and sales of chemicals by foreign subsidiaries | 1,260 | 1,134 | 1,021 |
| Other sales within Russia | 1,167 | 821 | 713 |
| Other export sales and other sales of foreign subsidiaries | 1,053 | 922 | 676 |
| Total sales | 67,684 | 55,774 | 33,845 |
| 2006 | Western Siberia European Russia International | Elimination | Consolidated | ||
|---|---|---|---|---|---|
| Sales | |||||
| Third parties | 318 | 10,693 | 56,673 | – | 67,684 |
| Inter-segment | 11,673 | 26,773 | 33 | (38,479) | – |
| Total sales | 11,991 | 37,466 | 56,706 | (38,479) | 67,684 |
| Operating expenses and total cost | |||||
| of purchases | 1,751 | 13,859 | 49,673 | (38,252) | 27,031 |
| Depreciation, depletion and | |||||
| amortization | 568 | 781 | 502 | – | 1,851 |
| Interest expense | 17 | 104 | 234 | (53) | 302 |
| Income taxes | 849 | 1,530 | 394 | – | 2,773 |
| Net income | 2,769 | 4,117 | 978 | (380) | 7,484 |
| Total assets | 12,967 | 25,483 | 18,921 | (9,134) | 48,237 |
| Capital expenditures | 1,487 | 3,944 | 1,455 | – | 6,886 |
| 2005 | Western Siberia European Russia International | Elimination | Consolidated | ||
|---|---|---|---|---|---|
| Sales | |||||
| Third parties | 250 | 8,656 | 46,868 | – | 55,774 |
| Inter-segment | 8,947 | 21,098 | 31 | (30,076) | – |
| Total sales | 9,197 | 29,754 | 46,899 | (30,076) | 55,774 |
| Operating expenses and total cost | |||||
| of purchases | 1,372 | 10,829 | 40,590 | (29,906) | 22,885 |
| Depreciation, depletion and | |||||
| amortization | 389 | 618 | 308 | – | 1,315 |
| Interest expense | 17 | 160 | 133 | (35) | 275 |
| Income taxes | 539 | 1,716 | 212 | – | 2,467 |
| Net income | 2,116 | 4,015 | 925 | (613) | 6,443 |
| Total assets | 9,301 | 21,207 | 14,361 | (4,524) | 40,345 |
| Capital expenditures | 1,100 | 2,146 | 931 | – | 4,177 |
Notes to Consolidated Financial Statements (Millions of US dollars, except as indicated)
| 2004 | Western Siberia European Russia International | Elimination | Consolidated | ||
|---|---|---|---|---|---|
| Sales | |||||
| Third parties | 698 | 6,739 | 26,408 | – | 33,845 |
| Inter-segment | 4,780 | 12,081 | 20 | (16,881) | – |
| Total sales | 5,478 | 18,820 | 26,428 | (16,881) | 33,845 |
| Operating expenses and total cost | |||||
| of purchases | 1,457 | 6,334 | 22,045 | (16,832) | 13,004 |
| Depreciation, depletion and | |||||
| amortization | 366 | 533 | 176 | - | 1,075 |
| Interest expense | 33 | 234 | 92 | (59) | 300 |
| Income taxes | 236 | 1,351 | 173 | - | 1,760 |
| Net income | 607 | 3,295 | 682 | (336) | 4,248 |
| Total assets | 5,625 | 16,796 | 10,579 | (3,239) | 29,761 |
| Capital expenditures | 1,082 | 1,767 | 598 | – | 3,447 |
This section provides unaudited supplemental information on oil and gas exploration and production activities in accordance with SFAS No. 69, "Disclosures About Oil and Gas Producing Activities" in six separate tables:
Amounts shown for equity companies represent the Group's share in its exploration and production affiliates, which are accounted for using the equity method of accounting.
| Total consolidated |
Group's share in equity |
||||
|---|---|---|---|---|---|
| As of December 31, 2006 | International | Russia | companies | companies | Total |
| Unproved oil and gas properties | 351 | 511 | 862 | 13 | 875 |
| Proved oil and gas properties | 4,883 | 30,488 | 35,371 | 743 | 36,114 |
| Accumulated depreciation, depletion, and amortization |
(644) | (13,099) | (13,743) | (166) | (13,909) |
| Capitalized cosst related to asset retirement obligation |
4 | 329 | 333 | 3 | 336 |
| Accumulated depreciation of capitalized cost related to asset retirement obligation |
– | (26) | (26) | – | (26) |
| Net capitalized costs | 4,594 | 18,203 | 22,797 | 593 | 23,390 |
| Total consolidated |
Group's share in equity |
||||
|---|---|---|---|---|---|
| As of December 31, 2005 | International | Russia | companies | companies | Total |
| Unproved oil and gas properties | 196 | 531 | 727 | 17 | 744 |
| Proved oil and gas properties | 4,331 | 26,785 | 31,116 | 782 | 31,898 |
| Accumulated depreciation, depletion, and amortization |
(377) | (12,672) | (13,049) | (173) | (13,222) |
| Capitalized cosst related to asset retirement obligation |
– | 166 | 166 | 4 | 170 |
| Accumulated depreciation of capitalized cost related to asset retirement obligation |
– | (19) | (19) | – | (19) |
| Net capitalized costs | 4,150 | 14,791 | 18,941 | 630 | 19,571 |
Supplementary Information on Oil and Gas Exploration and Production Activities (Unaudited) (Millions of US dollars, except as indicated)
| Total consolidated |
Group's share in equity |
||||
|---|---|---|---|---|---|
| As of December 31, 2004 | International | Russia | companies | companies | Total |
| Unproved oil and gas properties | 202 | 666 | 868 | 23 | 891 |
| Proved oil and gas properties | 1,256 | 23,922 | 25,178 | 735 | 25,913 |
| Accumulated depreciation, depletion, and amortization |
(154) | (12,154) | (12,308) | (174) | (12,482) |
| Capitalized cost related to asset retirement obligation |
1 | 70 | 71 | 1 | 72 |
| Accumulated depreciation of capitalized cost related to asset retirement obligation |
– | (7) | (7) | – | (7) |
| Net capitalized costs | 1,305 | 12,497 | 13,802 | 585 | 14,387 |
II. Costs incurred in oil and gas property acquisition, exploration, and development activities
| Year ended December 31, 2006 | Total consolidated |
Group's share in equity companies |
Total | ||
|---|---|---|---|---|---|
| International | Russia | companies | |||
| Acquisition of properties - proved | 50 | 529 | 579 | – | 579 |
| Acquisition of properties - unproved | 5 | 769 | 774 | – | 774 |
| Exploration costs | 192 | 276 | 468 | 11 | 479 |
| Development costs | 594 | 3,901 | 4,495 | 157 | 4,652 |
| Total costs incurred | 841 | 5,475 | 6,316 | 168 | 6,484 |
| Year ended December 31, 2005 | Total | Group's share in equity companies |
Total | ||
|---|---|---|---|---|---|
| International | Russia | consolidated companies |
|||
| Acquisition of properties - proved | 1,726 | 183 | 1,909 | 80 | 1,989 |
| Acquisition of properties - unproved | 690 | 370 | 1,060 | 100 | 1,160 |
| Exploration costs | 171 | 252 | 423 | 3 | 426 |
| Development costs | 260 | 2,235 | 2,495 | 124 | 2,619 |
| Total costs incurred | 2,847 | 3,040 | 5,887 | 307 | 6,194 |
| Year ended December 31, 2004 | Total consolidated |
Group's share in equity |
|||
|---|---|---|---|---|---|
| International | Russia | companies | companies | Total | |
| Acquisition of properties - proved | 224 | 16 | 240 | – | 240 |
| Acquisition of properties - unproved | 22 | 49 | 71 | – | 71 |
| Exploration costs | 81 | 225 | 306 | 3 | 309 |
| Development costs | 108 | 1,875 | 1,983 | 117 | 2,100 |
| Total costs incurred | 435 | 2,165 | 2,600 | 120 | 2,720 |
The Group's results of operations for oil and gas producing activities are presented below. In accordance with SFAS No. 69, sales and transfers to Group companies are based on market prices. Income taxes are based on statutory rates. The results of operations exclude corporate overhead and interest costs.
Supplementary Information on Oil and Gas Exploration and Production Activities (Unaudited) (Millions of US dollars, except as indicated)
| Total consolidated |
share in equity |
||||
|---|---|---|---|---|---|
| Year ended December 31, 2006 | International | Russia | companies | companies | Total |
| Revenue | |||||
| Sales | 1,207 | 14,241 | 15,448 | 714 | 16,162 |
| Transfers | – | 11,747 | 11,747 | 374 | 12,121 |
| Total revenues | 1,207 | 25,988 | 27,195 | 1,088 | 28,283 |
| Production costs (excluding production taxes) | (151) | (2,161) | (2,312) | (97) | (2,409) |
| Exploration expense | (52) | (157) | (209) | (5) | (214) |
| Depreciation, depletion, and amortization | (261) | (973) | (1,234) | (50) | (1,284) |
| Accretion expense | – | (29) | (29) | – | (29) |
| Taxes other than income taxes | (17) | (15,644) | (15,661) | (258) | (15,919) |
| Related income taxes | (316) | (1,659) | (1,975) | (322) | (2,297) |
| Total results of operations for producing | |||||
| activities | 410 | 5,365 | 5,775 | 356 | 6,131 |
| Year ended December 31, 2005 | International | Russia | Total consolidated companies |
Group's share in equity companies |
Total |
|---|---|---|---|---|---|
| Revenue | |||||
| Sales | 620 | 12,327 | 12,947 | 720 | 13,667 |
| Transfers | – | 8,072 | 8,072 | 268 | 8,340 |
| Total revenues | 620 | 20,399 | 21,019 | 988 | 22,007 |
| Production costs (excluding production taxes) | (93) | (1,672) | (1,765) | (137) | (1,902) |
| Exploration expense | (192) | (125) | (317) | (1) | (318) |
| Depreciation, depletion, and amortization | (106) | (718) | (824) | (60) | (884) |
| Accretion expense | – | (30) | (30) | – | (30) |
| Taxes other than income taxes | (6) | (11,160) | (11,166) | (285) | (11,451) |
| Related income taxes | (160) | (1,548) | (1,708) | (181) | (1,889) |
| Total results of operations for producing | |||||
| activities | 63 | 5,146 | 5,209 | 324 | 5,533 |
| Total consolidated |
Group's share in equity |
||||
|---|---|---|---|---|---|
| Year ended December 31, 2004 | International | Russia | companies | companies | Total |
| Revenue | |||||
| Sales | 243 | 8,841 | 9,084 | 754 | 9,838 |
| Transfers | - | 4,456 | 4,456 | 47 | 4,503 |
| Total revenues | 243 | 13,297 | 13,540 | 801 | 14,341 |
| Production costs (excluding production taxes) | (54) | (1,509) | (1,563) | (62) | (1,625) |
| Exploration expense | (40) | (131) | (171) | (5) | (176) |
| Depreciation, depletion, and amortization | (28) | (648) | (676) | (39) | (715) |
| Accretion expense | – | (8) | (8) | – | (8) |
| Taxes other than income taxes | (2) | (5,544) | (5,546) | (172) | (5,718) |
| Related income taxes | (3) | (1,310) | (1,313) | (315) | (1,628) |
| Total results of operations for producing | |||||
| activities | 116 | 4,147 | 4,263 | 208 | 4,471 |
Proved reserves are the estimated quantities of oil and gas reserves which geological and engineering data demonstrate will be recoverable with reasonable certainty in future years from known reservoirs under existing economic and operating conditions (i.e. prices and costs as of the date the estimate is made). Proved reserves do not include additional quantities of oil and gas reserves that may result from extensions of currently proved areas or from applying secondary or tertiary recovery techniques not yet tested and determined to be economic.
Reserves are estimated using the definitions of reserves prescribed by the US Society of Petroleum Engineers and the World Petroleum Congress requirements. The proved reserves include volumes which are recoverable up to and after license expiry dates.
Proved developed reserves are the quantities of proved reserves expected to be recovered through existing wells with existing equipment and operating methods.
Due to the inherent uncertainties and the necessarily limited nature of reservoir data, estimates of reserves are inherently imprecise, require the application of judgment and are subject to change as additional information becomes available.
Management has included within proved reserves significant quantities which the Group expects to produce after the expiry dates of certain of its current production licenses in the Russian Federation. These licenses expire between 2011 and 2026, with the most significant expiring between 2011 and 2014. Management believes the licenses will be extended to produce subsequent to their current expiry dates. The Group is in the process of extending all of its production licenses in the Russian Federation. The Group has already extended a portion of these licenses and expects to extend the remaining licenses for indefinite periods. To date there have been no unsuccessful license renewal applications.
Estimated net proved oil and gas reserves and changes thereto for the years 2006, 2005 and 2004 are shown in the tables set out below.
| Group's share in equity |
|||||
|---|---|---|---|---|---|
| Millions of barrels | Consolidated subsidiaries | Total | |||
| International | Russia | Total | companies | ||
| Crude oil | |||||
| January 1, 2004 | 255 | 15,318 | 15,573 | 404 | 15,977 |
| Revisions of previous estimates | 8 | (63) | (55) | 65 | 10 |
| Purchase of hydrocarbons in place* | 12 | 22 | 34 | (1) | 33 |
| Extensions and discoveries | – | 606 | 606 | 18 | 624 |
| Production | (11) | (596) | (607) | (28) | (635) |
| Sales of reserves | – | (35) | (35) | (2) | (37) |
| December 31, 2004 | 264 | 15,252 | 15,516 | 456 | 15,972 |
| Revisions of previous estimates | (43) | 29 | (14) | (6) | (20) |
| Purchase of hydrocarbons in place* | 174 | 266 | 440 | (86) | 354 |
| Extensions and discoveries | 28 | 472 | 500 | 6 | 506 |
| Production | (15) | (619) | (634) | (30) | (664) |
| Sales of reserves | – | (34) | (34) | – | (34) |
| December 31, 2005 | 408 | 15,366 | 15,774 | 340 | 16,114 |
| Revisions of previous estimates | 15 | (278) | (263) | 12 | (251) |
| Purchase of hydrocarbons in place | – | 226 | 226 | – | 226 |
| Extensions and discoveries | 14 | 527 | 541 | 10 | 551 |
| Production | (27) | (648) | (675) | (28) | (703) |
| Sales of reserves | – | (10) | (10) | – | (10) |
| December 31, 2006 | 410 | 15,183 | 15,593 | 334 | 15,927 |
| Proved developed reserves | |||||
| December 31, 2004 | 124 | 10,205 | 10,329 | 322 | 10,651 |
| December 31, 2005 | 255 | 10,070 | 10,325 | 258 | 10,583 |
* Purchase of hydrocarbons in place for equity companies includes transfers of reserves to the consolidated group upon those equity companies becoming subject to consolidation.
December 31, 2006 217 9,714 9,931 245 10,176
The minority interest share included in the above total proved reserves was 563 million barrels, 580 million barrels and 259 million barrels as of December 31, 2006, 2005 and 2004, respectively. The minority interest share included in the above proved developed reserves was 191 million barrels, 172 million barrels and 125 million barrels as of December 31, 2006, 2005 and 2004, respectively. Substantially all minority interests relate to the reserves in the Russian Federation.
Supplementary Information on Oil and Gas Exploration and Production Activities (Unaudited) (Millions of US dollars, except as indicated)
| Group's share | |||||
|---|---|---|---|---|---|
| Billions of cubic feet | Consolidated subsidiaries | in equity companies |
Total | ||
| International | Russia | Total | |||
| Natural gas | |||||
| January 1, 2004 | 2,155 | 22,152 | 24,307 | 166 | 24,473 |
| Revisions of previous estimates | (268) | (754) | (1,022) | 55 | (967) |
| Purchase of hydrocarbons in place | 1,174 | 2 | 1,176 | – | 1,176 |
| Extensions and discoveries | – | 93 | 93 | 2 | 95 |
| Production | (32) | (133) | (165) | (9) | (174) |
| Sales of reserves | – | (4) | (4) | (1) | (5) |
| December 31, 2004 | 3,029 | 21,356 | 24,385 | 213 | 24,598 |
| Revisions of previous estimates | 402 | (520) | (118) | (4) | (122) |
| Purchase of hydrocarbons in place* | – | 8 | 8 | (6) | 2 |
| Extensions and discoveries | 273 | 742 | 1,015 | 5 | 1,020 |
| Production | (35) | (155) | (190) | (10) | (200) |
| December 31, 2005 | 3,669 | 21,431 | 25,100 | 198 | 25,298 |
| Revisions of previous estimates | 667 | 795 | 1,462 | 5 | 1,467 |
| Purchase of hydrocarbons in place | – | 3 | 3 | – | 3 |
| Extensions and discoveries | – | 398 | 398 | 1 | 399 |
| Production | (60) | (494) | (554) | (11) | (565) |
| Sales of reserves | – | (5) | (5) | – | (5) |
| December 31, 2006 | 4,276 | 22,128 | 26,404 | 193 | 26,597 |
| Proved developed reserves | |||||
| December 31, 2004 | 1,363 | 3,420 | 4,783 | 175 | 4,958 |
* Purchase of hydrocarbons in place for equity companies includes transfers of reserves to the consolidated group upon those equity companies becoming subject to consolidation.
December 31, 2005 1,102 4,834 5,936 153 6,089 December 31, 2006 1,108 6,234 7,342 138 7,480
The minority interest share included in the above total proved reserves was 43 billion cubic feet, 23 billion cubic feet and 20 billion cubic feet as of December 31, 2006, 2005 and 2004, respectively. The minority interest share included in the above proved developed reserves was 27 billion cubic feet, 15 billion cubic feet and 15 billion cubic feet as of December 31, 2006, 2005 and 2004, respectively. Substantially all minority interests relate to the reserves in the Russian Federation.
The standardized measure of discounted future net cash flows, related to the above oil and gas reserves, is calculated in accordance with the requirements of SFAS No. 69. Estimated future cash inflows from production are computed by applying year-end prices for oil and gas to year-end quantities of estimated net proved reserves. Adjustment in this calculation for future price changes is limited to those required by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pre-tax net cash flows, less the tax bases of related assets. Discounted future net cash flows have been calculated using a ten percent discount factor. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced.
The information provided in the tables set out below does not represent management's estimate of the Group's expected future cash flows or of the value of the Group's proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations. The arbitrary valuation prescribed under SFAS No. 69 requires assumptions as to the timing and amount of future development and production costs. The calculations should not be relied upon as an indication of the Group's future cash flows or of the value of its oil and gas reserves.
| As of December 31, 2006 | Total | Group's share | |||
|---|---|---|---|---|---|
| consolidated | in equity | ||||
| International | Russia | companies | companies | Total | |
| Future cash inflows | 24,767 | 421,215 | 445,982 | 13,896 | 459,878 |
| Future production and development costs | (9,476) | (284,993) | (294,469) | (5,699) | (300,168) |
| Future income tax expenses | (2,867) | (30,307) | (33,174) | (2,271) | (35,445) |
| Future net cash flows | 12,424 | 105,915 | 118,339 | 5,926 | 124,265 |
| Discount for estimated timing of cash | |||||
| flows (10% p.a.) | (6,282) | (66,489) | (72,771) | (3,038) | (75,809) |
| Discounted future net cash flows | 6,142 | 39,426 | 45,568 | 2,888 | 48,456 |
| Minority share in discounted future net | |||||
| cash flows | – | 1,158 | 1,158 | – | 1,158 |
Included as a part of the \$300 billion of future production and development costs are \$6.6 billion of future dismantlement, abandonment and rehabilitation costs.
| As of December 31, 2005 | Group's share | ||||
|---|---|---|---|---|---|
| consolidated companies |
in equity companies |
Total | |||
| International | Russia | ||||
| Future cash inflows | 21,028 | 375,279 | 396,307 | 12,290 | 408,597 |
| Future production and development costs | (9,471) | (200,288) | (209,759) | (4,513) | (214,272) |
| Future income tax expenses | (3,563) | (40,135) | (43,698) | (2,220) | (45,918) |
| Future net cash flows | 7,994 | 134,856 | 142,850 | 5,557 | 148,407 |
| Discount for estimated timing of cash flows (10% p.a) |
(4,140) | (86,622) | (90,762) | (2,898) | (93,660) |
| Discounted future net cash flows | 3,854 | 48,234 | 52,088 | 2,659 | 54,747 |
| Minority share in discounted future net cash flows |
– | 1,730 | 1,730 | – | 1,730 |
Included as a part of the \$214 billion of future production and development costs are \$5.6 billion of future dismantlement, abandonment and rehabilitation costs.
| As of December 31, 2004 | Total consolidated companies |
Group's share in equity companies |
Total | ||
|---|---|---|---|---|---|
| International | Russia | ||||
| Future cash inflows | 8,290 | 290,189 | 298,479 | 9,630 | 308,109 |
| Future production and development costs | (4,507) | (162,246) | (166,753) | (4,434) | (171,187) |
| Future income tax expenses | (537) | (29,268) | (29,805) | (1,276) | (31,081) |
| Future net cash flows | 3,246 | 98,675 | 101,921 | 3,920 | 105,841 |
| Discount for estimated timing of cash flows (10% p.a) |
(1,919) | (64,896) | (66,815) | (1,980) | (68,795) |
| Discounted future net cash flows | 1,327 | 33,779 | 35,106 | 1,940 | 37,046 |
| Minority share in discounted future net | |||||
| cash flows | – | 531 | 531 | – | 531 |
Included as a part of the \$171 billion of future production and development costs are \$4.4 billion of future dismantlement, abandonment and rehabilitation costs.
VI. Principal sources of changes in the standardized measure of discounted future net cash flows
| Consolidated companies | 2006 | 2005 | 2004 |
|---|---|---|---|
| Discounted present value as at January 1 | 52,088 | 35,106 | 31,258 |
| Net changes due to purchases and sales of minerals in place | 571 | 1,761 | 31 |
| Sales and transfers of oil and gas produced, net of production costs | (9,014) | (7,771) | (6,260) |
| Net changes in prices and production cost estimates | 17,496 | 24,556 | 8,550 |
| Net changes in mineral extraction taxes | (30,592) | (5,770) | (2,669) |
| Extensions and discoveries, less related costs | 1,753 | 2,619 | 1,548 |
| Development costs incurred during the period | 2,383 | 2,495 | 1,983 |
| Revisions of previous quantity estimates | 223 | (320) | (416) |
| Net change in income taxes | 4,002 | (5,346) | (1,084) |
| Other changes | (300) | 149 | 8 |
| Accretion of discount | 6,958 | 4,609 | 2,157 |
| Discounted present value at December 31 | 45,568 | 52,088 | 35,106 |
| Group's share in equity companies | 2006 | 2005 | 2004 |
| Discounted present value as at January 1 | 2,659 | 1,940 | 1,115 |
| Net changes due to purchases and sales of minerals in place | - | (473) | (20) |
| Sales and transfers of oil and gas produced, net of production costs | (728) | (565) | (562) |
| Net changes in prices and production costs estimates | 906 | 2,389 | 936 |
| Net changes in mineral extraction taxes | (632) | (455) | (149) |
| Extensions and discoveries, less related costs | 45 | 62 | 64 |
| Development costs incurred during the period | 47 | 124 | 117 |
| Revisions of previous quantity estimates | 153 | (82) | 388 |
| Net change in income taxes | (13) | (432) | (224) |
| Other changes | 104 | (88) | 143 |
| Accretion of discount | 347 | 239 | 132 |
| Discounted present value at December 31 | 2,888 | 2,659 | 1,940 |
| Total | 2006 | 2005 | 2004 |
| Discounted present value as at January 1 | 54,747 | 37,046 | 32,373 |
| Net changes due to purchases and sales of minerals in place | 571 | 1,288 | 11 |
| Sales and transfers of oil and gas produced, net of production costs | (9,742) | (8,336) | (6,822) |
| Net changes in prices and production costs estimates | 18,402 | 26,945 | 9,486 |
| Net changes in mineral extraction taxes | (31,224) | (6,225) | (2,818) |
| Extensions and discoveries, less related costs | 1,798 | 2,681 | 1,612 |
| Development costs incurred during the period | 2,430 | 2,619 | 2,100 |
| Revisions of previous quantity estimates | 376 | (402) | (28) |
| Net change in income taxes | 3,989 | (5,778) | (1,308) |
| Other changes | (196) | 61 | 151 |
| Accretion of discount | 7,305 | 4,848 | 2,289 |
| Discounted present value at December 31 | 48,456 | 54,747 | 37,046 |
LUKOIL International Finance B.V. Atrium Strawinskylaan 3105 1077 ZX Amsterdam The Netherlands
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To the Company
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Citicorp Trustee Company Limited Citigroup Centre Canada Square, Canary Wharf London E14 5LB United Kingdom
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To the Company as to English, Russian and United States law
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Akin Gump Strauss Hauer & Feld Akin Gump Strauss Hauer & Feld LLP
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