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TNK-BP Investor presentation March 2011. 2 2 Important notice These materials include statements that are, or may be deemed to be, ‘‘forward-looking statements’’.

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Presentation on theme: "TNK-BP Investor presentation March 2011. 2 2 Important notice These materials include statements that are, or may be deemed to be, ‘‘forward-looking statements’’."— Presentation transcript:

1 TNK-BP Investor presentation March 2011

2 2 2 Important notice These materials include statements that are, or may be deemed to be, ‘‘forward-looking statements’’. These forward-looking statements can be identified by the use of forward-looking terminology, including, but not limited to, the terms ‘‘believes’’, ‘‘estimates’’, ‘‘anticipates’’, ‘‘expects’’, ‘‘intends’’, ‘‘may’’, ‘‘target’’, ‘‘will’’, or ‘‘should’’ or, in each case, their negative or other variations or comparable terminology or by discussions of strategy, plans, objectives, goals, future events or intentions. These forward-looking statements include all matters that are not historical facts. They include, but are not limited to, statements regarding the intentions, beliefs and statements of current expectations of TNK-BP International Limited and its subsidiaries (“TNK-BP”) concerning, amongst other things, TNK-BP’s results of operations, financial condition, liquidity, prospects, growth, potential acquisitions, strategies and as to the industries and locations in which TNK-BP operates. By their nature, forward-looking statements involve risk and uncertainty because they relate to future events and circumstances that may or may not occur. Forward-looking statements are not guarantees of future performance and the actual results of TNK-BP's operations, financial condition and liquidity and the development of the country, regions, political environment and industries in which TNK-BP operates may differ materially from those described in, or suggested by, the forward- looking statements contained in these materials. TNK-BP does not intend, and does not assume any obligation, to update or revise any forward- looking statements or information set out in these materials, whether as a result of new information, future events or otherwise. TNK-BP does not make any representation, warranty or prediction that the results anticipated by such forward-looking statements will be achieved. These materials contain reserves data for TNK-BP which has been extracted without material adjustment from the Reserves Reports prepared for TNK-BP by independent petroleum engineers using three different methods. These methods include the U.S. Securities and Exchange Commission ("SEC") standards, the U.S. Society of Petroleum Engineers, Inc. ("SPE") standards and a variation of the SEC standards pursuant to which reserves are calculated through the economic life of the fields ("SEC-LOF"). The SEC-LOF standards differ in certain material respects from the SEC standards and the SPE standards. Unless otherwise indicated reserves data contained in these materials are based on the SEC-LOF standards as in effect on the date of the Reserve Report from which such data has been extracted. The SEC has adopted significant revisions to the SEC standards on oil and gas reporting, which became effective on 1 January 2010. The main revisions that may have an impact on TNK-BP’s reserve quantities relate to the use of a 12-month average price to estimate reserves rather than the price on the last day of the year and to the use of new technology and the enlargement of the areas for which reserves may be determined. These materials do not constitute or form part of and should not be construed as, an offer to sell or issue or the solicitation of an offer to buy or acquire any securities in any jurisdiction or an inducement to enter into investment activity. No part of these materials, nor the fact of its distribution, should form the basis of, or be relied on in connection with, any contract or commitment or investment decision whatsoever. These materials may not be forwarded, distributed or reproduced in whole or in part, in any manner whatsoever, without TNK-BP’s express consent.

3 3 3 TNK-BP at a glance   East Siberia West Siberia Yamal (early development) Orenburg    Uvat Among largest private oil & gas producers globally Ranking in world’s top 10 private oil and gas producers Russia’s top 3 vertically integrated oil company Producing 1,734 mboed, 3.4% organic growth Fully integrated business Russia’s top 3 refiner Five and a half refineries (including one in Ukraine), total capacity 772 mbpd Refining cover of 43% Extensive retail network with over 1,400 retail sites in Russia, Ukraine and Belarus Ample reserve base 8.6 bn boe of proved reserves (SEC-LOF), 30+ bn boe of PRMS 3P reserves Reserve life of 14 years (SEC-LOF) and 50 years of PRMS 3P reserves Industry-leading F&D costs and exploration success rate Strong financial profile Investment grade credit ratings Strong credit metrics Robust financial performance Reserves and refining capacity as at end 2009, production, refining and retail data for 9M10  Refineries Greenfield projects YANOS refinery, 50/50 owned with Gazprom Neft  Brownfield projects Legend: Exciting growth opportunities New generation of greenfield projects Growing gas business International expansion

4 4 4 Strong competitive position World class reserve replacement and F&D costs Among the world’s largest oil producers* Strong production growth Source: UBS Global Integrated Oil & Gas Analyser, 2009 * Excluding fully state-owned companies Source: CDU TEK, TNK-BP data, daily liquids production without JVs, 9M10 v 9M09Source: company reports, TNK-BP data, Reserve Replacement Ratio (RRR) based on SEC-LOF reserve data TNK-BP Rosneft Gazprom Neft BP Chevron Conoco Phillips Exxon Mobil R&D Shell 0% 20% 40% 60% 80% 100% 120% 140% 160% 05101520253035404550 3Y average F&D costs (2007-2009), $/boe 3Y average organic RRR (2007-2009) Ample reserve base – world class reserve life globally 3.0% Source: UBS Global Integrated Oil & Gas Analyser, 2009. Reserve life based on 2008 disclosure and SEC methodology except Lukoil which is based on PRMS methodology

5 5 Strategy for growth World-class corporate governance Monetize our gas portfolio Enhance margins Convert resources to reserves to production A LEADER IN THE RUSSIAN OIL & GAS INDUSTRY International portfolio Technology People Grow production to 100 mln tonnes by 2015 20-25% production from greenfields by 2015 Yamal: up to 750 mboed by 2020 42%  50% refining cover Retail expansion 30 bcma gas production by 2020 “20/20/20”: –20% of total production and EBITDA by 2020 HSE Ethics Process fitness

6 6 9M10 operational & financial highlights EBITDA at $7.2 bn, up 9% on 9M09 Net Income at $3.9 bn, up 5% on 9M09 Operating cash flow at $6.9 bn, up 50% on 9M09 6 Days Away From Work Cases frequency down 4% in 9M10 v 9M09 Zero major vehicle accidents in 9M10 Spills frequency down 15% in 9M10 v 9M09 3.4% production growth (liquids and gas, excl. Slavneft) in 9M10 v 9M09 A long-term transportation agreement signed with Gazprom for Rospan gas in 3Q10 New discoveries of c. 300 mmboe in Yamal, Uvat and Orenburg during 9M10 Robust 3Q10 and 9M10 refining margins of over $12/bbl Operational availability for 2010 forecast at 97% – historical highest All-time high average daily throughput in 9M10 at 715 mbpd Strong sales growth in retail of 3% in 9M10 v 9M09 8 licenses acquired through auctions and M&A in Orenburg in 9M10, adding >250 mmboe, including 3 licenses in 3Q10 Agreement reached with BP to acquire BP’s upstream and pipeline assets in Vietnam and Venezuela for $1.8 bn A memorandum of understanding signed with PetroVietnam on oil and gas cooperation A memorandum of understanding signed to develop tight sand gas in Eastern Ukraine on a production-sharing basis 9M10 FinancialsHSE PortfolioUpstream DownstreamInternational activity

7 7 Acquisitions in Venezuela and Vietnam Venezuela Extra Heavy Oil Brownfield Opportunity Stakes in three Empresa Mixtas / JVs with state- owned PDVSA: PetroMonagas, PetroPerija and Boquerón Vietnam Integrated Gas Project – Offshore Gas Fields, Pipeline & Power Plant Stakes across gas value chain: offshore gas assets (Block 06-01), Nam Con Son gas pipeline and Phu My 3 power plant TNK-BP and BP p.l.c. have reached an agreement for TNK-BP to acquire BP's upstream and pipeline assets in Vietnam and Venezuela for an overall consideration of $1.8 billion The acquisitions will be financed entirely from the company’s available resources Subject to pre-emption rights and the fulfillment of other agreed pre-closing conditions, the companies expect the transaction to be completed in the first half of 2011 Altogether, the acquisitions of the assets in Venezuela and Vietnam will bring TNK-BP net proved and probable (2P) reserves of c. 290 million barrels of oil equivalent on a working interest basis, or c. 260 million barrels of oil equivalent on an entitlement basis (following taxes paid according to Production Sharing Agreement) The assets would add c. 40 mboed to TNK-BP production on an entitlement basis

8 8 Taxation regime: recent developments Positive changes in taxation regime – already introduced Export duty suspended for 22 East Siberian fields (incl. Verkhnechonskoye, Suzunskoye, Tagulskoye) during 1H10, a reduced per barrel rate of 0.45 * (Urals price – $50) applies from 1 July 2010 MET holidays introduced to encourage development of new fields in East Siberia Accelerated VAT refund effective from 2010 – positive for working capital Non taxable threshold for MET up from $9 to $15 per barrel from 1 January 2009 Corporate income tax rate reduced from 24% to 20% effective 1 January 2009 Export duty calculation methodology changed effective 1 December 2008, reducing duty lag effect Changes in taxation regime – under discussion Ministry of energy proposes the “60-66” taxation system providing for lowering of the crude export duty by c. 7% and levelling crude export duties for dark and light oil products at 66% of the crude export duty in 2011 MET holidays for 10 years to encourage development of new fields in YaNAO – under discussion by Russian Government bodies MET benefits for small oil fields with production of up to 5 mln tonnes Negative changes in taxation regime – already introduced Government Decree on crude MET increase by 6.5% in 2012, by 5.4% in 2013, and on gas MET increase by 61% in 2011 with further inflation indexation Government Decree on gradual duties levelling for light and dark oil products starting with 1 February 2011 at 67% of crude export duty for dark oil products (instead of 70%) and at 46.7% of crude export duty for dark oil products (instead of 40%) to reach 60% by 1 January 2013

9 9 9 Reserves and production Resource base (PRMS) Ample reserve base Maintaining a world class reserve base: –SEC-LOF: 8.6 bn boe proved reserves, reserve life of 14 years –PRMS: 11.7 bn boe proved reserves, reserve life of 19 years An established track record of successful reserve replacement: –SEC-LOF: 3-year average RRR of 146% –PRMS: 3-year average RRR of 258% Industry leading exploration success rate and F&D costs: –Exploration success rate: 3-year average of 73% –F&D costs: 3-year average of $3.6/boe, with $2.2/boe in 2009 Sustainable production growth Hydrocarbon production of 1,734 mboed in 9M10, up 3.4% on 9M09 Liquids production of 1,525 mbpd in 9M10, up 3.0% on 9M09 Impressive liquids production growth in Orenburg, up 8.8% in 9M10 v 9M09 Increasing share of greenfield barrels in total liquids production: 10.8% in 9M10, more than doubled on 9M09 Production in Western Siberia down 3.5% in 9M10 v 9M09 Hydrocarbon production Reserves as at end 2009, 3-year averages for 2007-2009. Reserves and production data exclude Slavneft

10 10    Samotlor     Other West Siberia fields 3P Reserves: 4.9 bn boe 9M10 liquids production: 266 mbpd Moscow Orenburg Nizhnevartovsk Nyagan Novosibirsk Brownfield asset base Orenburg fields 3P Reserves: 2.4 bn boe 9M10 liquids production: 411 mbpd Samotlor field 3P Reserves: 7.6 bn boe 9M10 liquids production: 565 mbpd Nyagan fields 3P Reserves: 4.7 bn boe 9M10 liquids production: 105 mbpd Brownfield assets located in West Siberia and Orenburg 3P reserves of 19.6 bn boe Currently deliver 89% of total liquids output West Siberia Production maintained broadly flat through application of select new technology and processes +90% water cut Samotlor Giant field, 5 th largest ever discovered More than 40 years in production Delivers 37% of TNK-BP’s total liquids production Will remain a reliable producer going forward Orenburg 60-70 years in production Delivers 27% of TNK-BP’s total liquids production Outstanding liquids production growth –6.6% 2009 v 2008 –8.8% in 9M10 v 9M09 Achieved primarily through accessing satellite formations and building on infrastructural synergies Reserves as at end 2009, Nyagan reserves exclude Kamennoye

11 11  Uvat Rospan Russkoye Tagulskoye Suzunskoye Messoyakha*       Verkhnechonskoye Greenfields: building for the future Verkhnechonskoye 3P Reserves: 1.9 bn boe Start-up: 2008 9M10 liquids production: 51 mbpd Uvat 3P Reserves: 1.1 bn boe Start-up: 2009 9M10 liquids production: 78 mbpd Yamal projects 3P Reserves: 3.1 bn boe Potential start-up: 2015-2016 *Messoyakha (3P + 3C resources – 3.2 bn boe) is owned by a 50/50 JV between TNK-BP and Gazprom Neft  Kamennoye 3P Reserves: 2.4 bn boe Start-up: 2009 (north) 9M10 liquids production: 36 mbpd (north) Rospan 3P Reserves: 2.7 bn boe (liquids + gas) Potential plateau: 16 bcma 9M10 gas production: 1.9 bcm (43 mboed) 9M10 condensate production: 13 mbpd Currently approx. 11% of total liquids production, potential to reach 20-25% by 2015 Producing greenfields Major project delivery on time and on budget Select application of technology – safe for people and environment Projects in early development Capable of delivering up to approx. 750 mboed by 2020 Projects at phase of commercial production  Greenfield projects under development Gas project   Legend: Reserves as at end 2009, Kamennoye reserves are for the whole field Developing new production centers of international significance

12 12 Producing greenfields: Verkhnechonskoye ESPO – a new strategic export route for Russian crude An alternative supply for Asia Pacific and US markets ESPO blend gains ground in the international market, trades at a premium to Urals Single ESPO tariff set by Transneft at the end of 2009 Zero export duty applied to Verkhnechonskoye exports during 1H 2010, a reduced per barrel rate of 0.45 * (Urals price – $50) applies from 1 July 2010 MET holidays for first 25 mln tonnes if produced until 2017 Project overview Largest oil field in East Siberia discovered in 1978 Developed in partnership with Rosneft 2010 milestones Current 2010 production forecast at c. 19.5 mm bbl, up 8% on plan Next phase of the full field development plan supported by the Board of Directors, including 90 wells, related infrastructure, power station 5 th drilling rig deployed 23+ mm bbl p.a. oil treatment unit commissioned 26 MW power station commissioned Surface pressure maintenance facilities installed 3P reserves: 1.9 bn boe9M10 production: 51 mbpdPeak production: 150 mbpdPeak year: 2017  Verkhnechonskoye Source: Reuters

13 13 Producing greenfields: Uvat Project overview 21 fields in 15 license plots in the south of Tyumen region, West Siberia, some 700 km away from Tyumen city Eastern Hub: production centre launched in 2009 (Urnenskoye and Ust- Tegusskoye fields) Central Uvat: pilot production commenced at Tyamkinskoye field in March 2010, ahead of plan Development partly financed with regional government grants 2010 milestones Current 2010 production forecast at c. 29.5 mm bbl, up 14% on plan Gas Turbine Power Plant (GTPP) 1 st phase (22 MW) – construction completed Continue with Tyamkinskoye pilot targeting full field development in 2011 Uvat infrastructure: –Road construction under way for all year access –41 mm bbl p.a. Central Processing Facility commissioned 3P reserves: 1.1 bn boe9M10 production: 78 mbpdPeak production: 200 mbpdPeak year: 2017 Western Uvat Central Uvat Eastern Uvat Kalchinsky field Tyamkinsky field Protozanovsky field Urnenskoye field Ust-Tegusskoye field

14 14 Targeted application of technology Brownfields Decline reduction Water shut off ESP mean time between failures Energy efficiency Ineffective well stock reduction Low cost drilling Effective gas utilization Greenfields Heavy oil extraction Complex well designs Completions Water management Seismic and modelling Gas utilization Field automation 14 Technology challenges Technology examples Significant energy savings Increased oil recovery factor: in some cases from a production ratio of only 1-2% oil and 98-99% water to a ratio of almost 20% oil and 80% water Dual Completions Water Shut-Off Opex/Capex reduction Accelerates oil production Involves additional oil reserves into production 100% independent production from 2 formations; 1 st in Russia

15 15 Yamal – a major new production area for TNK-BP and Russia One of the few remaining undeveloped hydrocarbon provinces in Russia and the world Mineral extraction tax holidays and a reduced export duty currently apply for certain fields Yamal integrated program being developed by the government A major potential source of TNK-BP’s future growth but significant challenges to overcome: –Lack of transportation infrastructure –Current Russian oil & gas taxation does not stimulate new developments –Technical challenge of developing the reserves: quality of oil (Russkoye) and complex reservoirs (Tagul, Messoyakha) Project 3P + 3C resources, bn boe Potential year of launch Field summary Suzun0.32015Best explored field with well-understood geology and high quality light oil Tagul1.92016Complicated field with numerous reservoirs and medium-quality crude Russkoye2.22015Large but technically challenging field (highly viscous oil, gas caps) Russko- Rechenskoye 0.12016Small field adjacent to Tagul on the west Messoyakha (50%) 1.62017Potentially gigantic field, technically challenging (multiple layers, heavy oil)

16 16 © THK-BP presentation name TNK-BP gas portfolio Ukraine Nyagan Rospan Orenburg Novosibirsk Yamal Verkhnechonsk Nizhnevartovsk Associated gas utilization at Krasnoleninskoye field East-Urengoyskoye and Novo- Urengoyskoye gas and condensate fields 506 bcm reserves (A+B+C1) 2009 production 2.4 bcma, plateau up to 16 bcma in 2017+ Associated gas utilization at Suzunskoye, Tagulskoye, Russkoye, Russko- Rechenskoye and Messoyakha fields Gas utilization at Verkhnechonskoye field 8 bcma of associated gas production Processing JV with Sibur at Belozerny and Nizhnevartovsky GPP (current capacity 9.4 bcma, 10.1 bcma after extension in 2012) 25% in Nizhnevartovsk GRES (1,600 MW) Gas caps project Associated gas utilization at Verkh- Tarskoye field 2009 production 1.5 bcma (natural gas and APG) with a potential to reach 3-4 bcma Zaikinskiy GPP (capacity 1.1 bcma, under enhancement to 2.2+ bcma) Assessment of unconventional gas potential Associated Gas Natural Gas Gas Processing Plant Associated Gas 9.7 bcm Natural Gas 2.4 bcm Gas Sales in 2009

17 17 Rospan – a gas growth opportunity Gazprom, ENI, ENEL Defined Greater Achimov Horizon Largest TNK-BP’s natural gas asset, located in Urengoy region 3P gas reserves: 1.4 bn boe; A+B+C1: 506 bcm Capable of producing 16 bcma of gas and up to 5 mln tonnes of condensate a year starting from 2017 Existing gas production 1.9 bcm in 9M10 (up 12% v 9M09), 2.4 bcm in FY09 Long-term gas transportation agreement signed with Gazprom in September 2010 (up to 13.2 bcma in 2016) Work in progress on long-term sales agreements A full field development plan is being worked on Total estimated capex c. $6 bn TNK-BP (Rospan) Gazprom (Urengoygazprom) (Arcticgas) Major gas pipeline Railway Compressor station Novy Urengoi Urengoyskaya-3 -1 -2 Novy Urengoi Korotchaevo Urengoyskaya-3 Urengoyskaya -1 -1 Urengoyskaya-2

18 18 Increasing APG utilization APG in TNK-BP, 2009 Utilization level – 84.4% In production – total 143 fields Production of APG – 12.5 bcma $1.8 bn investments planned to significantly increase TNK-BP’s APG utilization level in 2010- 2013: Orenburg Integrated project Expansion of Zaikinsky GPP Nizhnevarovsk Associated gas processing JV with Sibur NVGRES Nyagan Construction of a power generation unit Construction of a gas turbine power plant at Kamennoye field (completion in 2010) Uvat Construction of a gas turbine power plant Verkchnechonskoye Considering different options including gas reinjection for storage and future use Yamal Considering various projects including power generation, gas reinjection, supply to the gas pipe APG utilization, %

19 19 TNK-BP is a major consumer of power and gas producer – demands 13.4 bln kWph (Upstream – 12.1 bln kWph, Downstream – 1.3 bln kWph) Cost of power is a significant part of oil production costs and continues to grow TNK-BP plans to invest over $700 mln in development of power generation projects in 2010-2012 The company considers construction of power plants (captive & commercial) in the regions of its operations, including Nizhnevartovsk, Irkutsk, Orenburg, Ryazan and Yamal Gas to power to power savings Nizhnevartovsk GRES TNK-BP – Sibur JV Yugragazpererabotka TNK-BP – Sibur JV (Yugragazpererabotka)

20 20 Downstream overview ТНК RNPK St. Petersburg Saratov Ukraine Kiev LINIK Mozyr Rostov Minsk Donetsk Moscow Belarus Dnepropetrovsk ТНК BP ТНК  BP ТНК Russia BP ТНК Krasnodar YANOS ТНК ТНК ТНК ТНК ТНК  Sustainable business model: Competitive refinery Best retail site networks and other sales channels in the East of Ukraine  ТНК ТНК Chelyabinsk Ekaterinburg Ufa Kazan N.Novgorod  Samara Priority development: Major competitive refinery – Ryazan Best retail networks Efficient logistics Saratov Refinery: Quality projects and “quick win” commercial projects YANOS: Important factor for enhanced presence on St. Petersburg market  Refinery Depot  Airport BP ТНК Retail network Third largest refiner in Russia Four refineries in Russia plus 50% in Yanos refinery, LINIK refinery in Ukraine Refineries strategically positioned to serve key markets in Russia and Ukraine A retail chain of more than 1,400 sites in Russia, Ukraine and Belarus Strategy to maximize integrated value of the business, building on coordinated growth of all business units BP ТНК

21 21 Refining throughput of 715 mbpd in 9M10 (all-time high) Robust refining margins benefiting from fiscal regime – over $12/bbl in 3Q10 and 9M10 Operational availability for 2010 forecast at 97% – historical highest (v 91% in 2009 taking into account refinery units turnaround cycle) Refining cover of 43% in 9M 2010* Stable throughput and high operating availability Refining 3Q10 throughput exceeding the plan by over 2.3 mm bbl Strong refining performance generated additional $103 mln EBITDA in 9M10 from units mode optimization, high operational availability, logistics and cost optimization Continued modernization of refining portfolio to produce fuel to meet European quality standards Refining margins outperform other regions Source: BP trading conditions update, Company data

22 22 Marketing New range of products under TNK and BP brands B2B business expansion: jet fuels, bitumen, lubricants and marine fuel Strengthening position in the premium market through construction of new BP outlets and focused rebranding of well-located retail sites into BP brand TNK-BP actively promotes exchange trade of oil products domestically, share of light product sales made through the exchange approaching 16% in 3Q10 New branded fuel, PULSAR, launched in 2009 and is being rolled out to an increasing number of regions Work in progress on further regional retail expansion Brand# of sites at 30 Sept 10 Company owned and operated sites BP77 TNK810 Jobber sites547 TNK-BP retail network in Russia, Ukraine and Belarus Throughput per site

23 23 Outlook Focus on HSE to maintain improvement momentum Targeted production growth of approximately 3% in 2010 and 1-3% in 2011 Further development of VCNG and Uvat Yamal – plans of regional infrastructure development Rospan – full field development plan being prepared Cost focus – particularly energy efficiency Building capability for refinery upgrades Revisit current Ukraine business model Progressing Venezuela and Vietnam deal to successful completion in 1H11 Selective M&A opportunities – small retail / gas Operations Portfolio

24 Additional information

25 25 TNK-BP corporate structure Note: Showing principal holding and operating companies

26 26 Board of Directors Viktor Vekselberg Chairman, Renova Group representatives of AAR representatives of BP independent directors Brian Gilvary Deputy Group CFO, BP David Peattie Head of BP Russia Tony Hayward Former Chief Executive, BP Len Blavatnik Chairman, Access Industries Alex Knaster Chairman of Pamplona Capital Management, Alfa Group Mikhail Fridman Chairman Lord Robertson of Port Ellen Deputy Chairman Gerhard Schroeder Independent Director Alexander Shokhin Independent Director James Leng Independent Director

27 27 Management structure members of the Management Board CFO J. Muir EVP Gas and Power M. Slobodin EVP Upstream S. Brezitsky EVP Downstream / Executive Director D. Baudrand EVP Technology F. Sommer EVP Support Services A. Tyomkin EVP Strategy & Business Development S. Miroshnik EVP Legal I. Maydannik CEO Interim M. Fridman Executive Director G. Khan Deputy CEO M. Barskiy* * M. Barskiy planned to become CEO in 2011 Advisor of the CEO V. Vekselberg СОО B. Schrader

28 28 Minority stakes in three producing Empresa Mixtas (JVs): State-owned PDVSA – major partner (except for Boqueron where OMV also has 13.3% stake) Current net crude production c. 25 mboed (sustainable in the long term) Net reserves of 207 mmboe on a working interest basis PetroMonagas is the largest asset acquired Venezuelan assets PetroMonagas, PetroPerija & Boqueron Boquerón PetroPerija Petromonagas Junin 6 (NPC) Ayacucho 2 (TNK-BP) Petromonagas (BP) Brownfield extra heavy oil opportunity Overview PetroMonagas (16.7%) Located in best portion of Faja Heavy Oil Belt (8.5 deg API oil) On production for 10 years Excellent reservoir quality and thick reservoir section Integrated project, extra-heavy crude converted into lighter export-bound synthetic crude and transported by pipeline to upgrader on the coast Current net production c. 19 mboed, net 2P reserves of 191 mmboe on a working interest basis PetroPerija (40.0%) 5 separate fields located on western side of Lake Maracaibo Three fields in production (Alpuf, Alturitas and San Jose), two fields non- producing (Machiques, San Julian) Boqueron (26.7%) Mature field, production peaked in 2001

29 29 High quality, low risk vertically integrated gas and power value chain Strategic asset for Vietnam, largest in-country gas producer, > 30% of Vietnam electricity generation (5-6% of Vietnam’s total power demand) State-owned PetroVietnam is an anchor investor in all assets as well as in all adjacent blocks in the region Strong protection against political risks Presence across entire value chain ensures transparency and strong governance Vietnamese assets Block 06.1, Nam Con Son Pipeline and Phu My 3 Power Plant Integrated gas projectOverview Block 06.1 – Upstream gas production (35.0%) Located in the Nam Con Basin 370km off the Southern coast of Vietnam − Contains two gas condensate fields Lan Tay (in production) and Lan Do (in development) − Gas from Lan Tay used in power generation and fertiliser production at Phu My complex The Vietnamese assets would add of 30 mboed gross production (on a working interest basis), or 15 thousand barrels per day on a net entitlement basis Nam Con Son Pipeline & Terminal (NSCP) – Midstream (32.7%) NCSP system includes pipeline (399 km), onshore Dinh Co Gas Processing Terminal and metering station at Phu My Key hydrocarbon transportation and processing infrastructure asset contracted to 650 mmscfd / 6.7 bcma of gas Only gas pipeline in Nam Con Son basin, links upstream fields to Phu My Power complex Phu My 3 – Power Plant (33.3%) Generation capacity of 750MW

30 30 Orenburg – an expanding business Liquids production 2010 production forecast – approx. 20 mln tonnes, up 19% on 2006 Potential to increase production by 25% up to 25 mln tonnes by 2015 Gas production 2010 production forecast – 2 bcma, generating approx. $100 mln in revenues Potential to increase production up to 5 bcma by 2015 Gas processing and utilisation Two major new gas processing facilities now under construction with capacity of 1.7 bcma and the technology to strip liquids from wet gas On track to eliminate excess flaring from 2013 Gas monetisation options Advantaged access to the 16 bcma Samara region gas market Different alternative gas monetisation options are also considered, including electricity generation TNK-BP’s Orenburg assets

31 31 Across TNK-BP Significant energy savings Increased oil recovery factor TNK-BP technology examples Dual Completions Water Shut-Off UVAT / Orenburg Opex/Capex reduction Accelerates oil production Involves additional oil reserves into production 100% independent production from 2 formations; 1 st in Russia Fiber Frac Kamennoye, Samotlor Improvement in Frac success rate Formation damage decrease Lower water cuts after frac (incremental oil rate increase) А В С Multi FRAC Conventional single FRAC Horizontal well with Multi Frac Access to additional resources Significant incremental oil rate increase comparing to single Frac technique Nyagan, Talinskoe, Em-Yogovskiy, Samotlor

32 32 Production from sidetrack wells Increase refinery throughputs Implement Quality Fuels Program Optimal highly activated catalysts TNK-BP technology examples Refining Excellence Streamline Modeling Samotlor Recovery factor increase Application of flow simulation streamline models for sector and full-scale modeling Seismic imaging Yamal, Uvat Access to additional resources Optimized drilling (significantly lower number of wells) Orenburg / Samotlor Significant increase in oil production Energy savings The Rotaflex pump was applied for the first time in the world in a sidetrack branch

33 33 Gas business strategy: monetization of gas potential Goals for Company’s gas business development to 2020 Gas value assurance for “stranded resources” – (Rospan, gas caps) – i.e. reserves monetization Reduce gas flaring – attain maximum possible associated gas utilization Broaden gas options – to improve leverage and provide growth (organic/inorganic options) Unlock the Company’s significant gas potential Extend the gas value chain

34 34 World gas reserves and TNK-BP position 05001 0001 5002 0002 5003 0003 500 Norway Egypt Canada Azerbaijan TNK-BP Total Bolivia Romania TNK-BP Rospan United Kingdom TNK-BP Gas Cap TNK-BP Assoc. Gas TNK-BP Other Germany Italy bcm TNK-BP comparative gas reserves Source: BP Statistical Review 2009, TNK-BP data (ABC1 reserves)Source: company reports, TNK-BP data TNK-BP potential 2020

35 35 Russian gas production and macro environment Source: CDU TEK, TNK-BP estimatesSource: CDU TEK Source: FTS, TNK-BP estimatesSource: TNK-BP estimates

36 36 Strong refining presence and an extensive marketing network Nizhnevartovsk Built in 1998 Capacity: 26 mbpd Utilisation: 90% Krasnoleninsk Built in 1998 Capacity: 4 mbpd Utilisation: 78% YANOS (50%) Modernised in 2006 Capacity: 286 mbpd (100%) Conversion ratio: 63% Light products output: 57% Utilisation: 96% Lisichansk Modernised in 2008 Capacity: 144 mbpd Conversion ratio: 71% Light products output: 58% Utilisation: 71% Saratov Modernised in 2004 Capacity: 132 mbpd Conversion ratio: 70% Light products output: 44% Utilisation: 88% 1,434 retail sites Moscow Orenburg Nizhnevartovsk Nyagan Novosibirsk Ryazan Modernised in 2006 Capacity: 323 mbpd Conversion ratio: 63% Light products output: 55% Utilisation: 91% Refining data as at end 2009, retail sites as at end 9M10 Retail sites Refinery assets Legend:

37 37 Projects in refining in Russia 37 Projects Integrity and Quality Efficiency and growth TNK-BP’s Russian refining development program is focusing on: Sustainability of operations and achievement of highest HSE standards Compliance with RF technical regulation for gasoline, diesel and jet fuel, gasoline pool octane improvement Throughput expansion, deep conversion and fuel oil reduction projects RNPK: VT4, Hydro cracking VGO, AVT 5, Reconstruction of FCC SNPZ: Visbreaking, AVT6 upgrade RNPK: Isomerization unit, Hydrotreater upgrade, MTBE SNPZ: Isomerization unit, Hydrotreater upgrade Area

38 38 Ukraine: an overview Dnepropetro vsk Odesa L’viv Dnepropetrovsk Donets’k Kyiv Khar’kiv Lisichansk 249 jobber sites 170 own sites: 3 BP 167 TNK, Golden Gepard, Vikoil LINIK is the best plant in the country, certified for quality management, environmental and H&S quality Most advantageous position and ample capacity to supply both Company owned and other channels in the highly populated east part of the country, as well as in the Kiev core market Production of diesel compliant with Euro 4 since 2007 Turnaround of the refinery in May-June 2010 completed (every 2 years) Refining modernization plans: –To meet Euro 4 for all fuels from 1 January 2011 ($70 mln investment planned) –To increase light products output TNK-BP has 21%+ retail footprint in Kiev and an extensive jobber network all over the country TNK-BP exercises dual brand strategy and plans to leverage the premium brand BP and the logistic advantage in the east of the country Plans to further expand own retail network and increase market share May 2010 – acquisition of Vikoil with 118 retail sites, 8 depots, 49 oil trucks and 122 land plots in 13 regions Priority market Current own retail market share ~21% Area of TNK-BP presence Refining Marketing M&A Lisichansk refinery Modernized in 2008 Capacity: 144 mbpd Conversion ratio: 71% Light products output: 58% Utilization: 71%

39 39 Other downstream areas Strategic goal – expand trading activity to international oil markets and grow towards capturing additional value along the value chain Gradual international expansion will allow to: Diversify the market routes Access new sources of trading value and enter new markets Better compete with our Russian peers and the growing number of other large producers that are accessing this value Support and monetize any future TNK-BP assets or positions outside of Russia participating in the related geographies Increase TNK-BP profits and make it more resistant to adverse market movements Strategic goal – maximize Downstream integrated value on refining products (jet, bitumen, lubes, bunkering fuel) based on: Deriving profit from the most favorable customer segments or/and logistics Deriving profit from specific production opportunities (by-products) Profit of a customer offer and brand – when applicable … and by means of the following criteria for separate businesses: Leadership in the industry (#1 or #2) Significant growth potential Unique value proposition (offer) Material integral margin for Downstream and substantiality B2B International expansionB2B

40 40 Health, safety & environment Health and Safety DAFWC* frequency improving, down 4% on 9M09 Zero major vehicle accidents in 9M10 v 3 major vehicle accidents in 9M09 Zero MVAR** in 9M10 v MVAR of 0.006 in 9M09 Environment Spills frequency also continuously improving: –Number of spills per thousand tonnes produced down 15% on 9M09 –Spilt tonnes per thousand tonnes produced down 49% on 9M09 40 * Number of days away from work cases per 200 thousand man- hours worked ** Number of major or severe vehicle accidents per 1 m km driven *** The International Association of Oil and Gas Producers DAFWC 2009 OGP*** average 2009 OGP Top Quartile DAFWC Frequency – 12 Month Rolling Average Spills Frequency – 12 Month Rolling Average Number of spills per thousand tonnes produced Spilt tonnes per thousand tonnes produced

41 41 Upstream 41 Production Impressive liquids production growth in Orenburg, up 8.8% in 9M10 v 9M09 Production in Western Siberia down 3.5% in 9M10 v 9M09 Share of greenfield barrels in total liquids production more than doubled: 10.8% in 9M10 v 4.6% 9M09 Uvat Production up 126% in 9M10 v 9M09 to 78 mbpd Verkhnechonskoye (VCNG) Production up 148% in 9M10 v 9M09 to 51 mbpd, 5 th rig assembly commenced Cost management Continuous focus on costs: –Further improvement in ESP mean time between failure to 545 days as at end 9M10, up 11% v end 9M09 –Approx. $80 mln savings in 9M10 as a result of cost optimisation initiatives –Ongoing work with contractors to reduce cost of services 3.0% (liquids) to 1,525 mbpd 3.4% (liquids & gas) to 1,734 mboed 9M10 v 9M09 daily production growth (excl. Slavneft) Production (oil & gas, excl. Slavneft)

42 42 Technology and exploration 42 Cost optimization Pilot programs of $100 mln being tried across the company Successes on water shut-off and horizontal waterflood in Samotlor E&A program New discoveries / appraisal success in 9M10: –Brownfields: 90 mmboe of recoverable reserves from 2 new fields in Orenburg –Greenfields: >200 mmboe of reserves in Yamal (Tagul) and Uvat Seismic acquisition in 9M10: –2D: 4,405 km with focus on Greenfields (Uvat, Yamal) and Bluefields (Astrakhan, Timan-Pechora) –3D: Brownfields 1,121 km 2, Greenfields 1,218 km 2 20 exploration wells completed in 9M10 with 65% success ratio License acquisition Acquisition of 3 licenses in federal auctions in Orenburg region in 3Q10 (including the large Pokrovsko-Sorochinsky area) with estimated resources of >200 mmboe. Overall, >250 mmboe of resources added through auctions and M&A in 9M10 National Petroleum Consortium (NPC)* update Subsoil rights transferred to the JV by Venezuelan presidential decree in July Operating and funding framework established to enable JV start-up * NPC is a JV between 5 Russian oil majors and Venezuelan PDVSA for the development of Junin 6 field

43 43 Downstream 43 Refining Operational availability for 2010 forecast at 97% – historical highest (v 91% in 2009 taking into account refinery units TAR cycle) Robust refining margins of over $12/bbl in 3Q10 and 9M10 AVT-2 unit debottlenecking at RNPK completed in 3Q10 All-time high average daily throughput in 9M10 at 715 mbpd 3Q10 throughput exceeding the plan by 319 k tonnes Strong refining performance generated additional $103 mln EBITDA in 9M10 from units mode optimization, high operational availability, logistics and cost optimization STL TNK-BP continues to actively participate in exchange trading of oil products, with approx. 16% of 3Q domestic light product sales made through the exchange Increasing VCNG sales through ESPO: 512 k tonnes in 3Q10, up 10% on 2Q10. Total of 1,409 k tonnes in 9M10 1-year term contract signed with PetroVietnam for crude deliveries via ESPO Geneva-based trader: project team moving ahead with approved plans Retail Strengthening position in premium markets in 3Q10: –St. Petersburg: 2 BP sites put into operation in September and 3 BP sites under construction –Moscow: 13 sites in reconstruction to BP brand, 1 new BP site under construction PULSAR branded fuel launched in St. Petersburg in September Streamlining of organizational structure by consolidating retail network in Russia Work in progress on further regional retail expansion

44 44 Gas 44 Rospan A long-term transportation agreement signed with Gazprom in 3Q10 with 6-year access to the pipeline system granted for up to 13.2 bcma in 2016 A full field development plan is being prepared Long-term sales agreements with major customers are being prepared Rospan gas production at 1.9 bcm in 9M10, up 12% on 9M09 due to additional pipeline access negotiated with Gazprom Associated gas Associated gas sales up by 5% in 9M10 on 9M09 due to on- going efforts to increase APG utilization plus turnaround idle time optimization at YugraGasPererabotka gas processing plant Associated gas utilization at 84.1% in 9M10, improving on 9M09, consistent with our commitment to increase utilization Approval given to TNK-BP’s first Kyoto Protocol project NV GRES JV Main Equipment Supplier and General Design Contractor selected for the 3 rd unit Rospan gas production Associated petroleum gas (APG) sales and utilization rate 1.7 1.9 0 2 9M099M10 bcm 7.07.0 7.47.4 83.3% 84.1% 0 1 2 3 4 5 6 9M099M10 bcm APG salesAPG utilization

45 45 Financial highlights

46 46 Business environment Stronger markets in 9M10 v 9M09: Urals higher by $19/bbl (34%) Duty lag benefit lower by $4.5/bbl 3Q10 markets flat v 2Q10: Urals slightly lower by $1.4/bbl (-2%) Duty lag higher by $2.8/bbl Negative impact of forex in 9M10 v 9M09: RUR/$ strengthened 7% from 32.5 to 30.3 Negative forex effect on costs partly offset by a positive effect on domestic sales 3Q10 average RUR/$ flat v 2Q10 1Q104Q091Q093Q092Q092Q10 3Q10 2009 2010

47 47 Revenues Price: Urals up 34% Domestic crude price higher by 24% Product prices up 21-41% Average realisations increased by 31% * excl. Slavneft Price Volume Volume: Production growth of 58 mboed (+3.4%)* Changes in sales structure towards products Period-on-period stock effect

48 48 3.7 3.9 - 3 6 9M09Price-MarketPrice-Duty lagForexTariffsOperationsOne-offsOther9M10 $ bn 48 Net income – 9M10 v 9M09 Environment: Price: Urals up $19/bbl (34%) Duty lag: negative effect of $4.5/bbl Forex: negative effect on costs from stronger RUR Tariffs: transportation and electricity tariffs up c. 21% Performance: Operations: production up 58 mboed (+3.4%) One-offs: largely comparative effect of prior year one-off benefits

49 49 Costs Forex negative effect: $0.2 bn Tariff increase of 19% Benefit from optimization of transportation routes and volume effects c.4% Overall cost increase of 18% Forex negative effect : $0.2 bn Inflationary increase of 8% Overall cost increase of 17%

50 50 Taxes Taxes other than Income Tax higher by 54%: Urals price: causes 55% increase in Export Duties and MET ($5.4 bn) and negative duty lag effect ($0.7 bn) Volume: decreased exports partly offset by increased production Income tax higher by 18%: Taxable profits: higher in 9M10 One-offs: reduction of tax audit provision in 9M09

51 51 Sources and uses of cash – 9M10 Operations: strong pre-tax inflows of $22.9 bn Taxes: $16.0 bn paid in total Capex: $2.7 bn of organic investments Debt: $1.9 bn repaid with $1.2 bn of new debt raised Dividends: $2.2 bn paid in respect of 4Q09-2Q10 earnings $ bn Net debt repayment

52 52 Debt and liquidity Debt maturity profile as of 30 September 2010 TNK-BP debt position Portfolio of undrawn committed bank lines in excess of $500m maintained with 7 Russian and international banks Average portfolio life increased by 18% to 4.7 years v end 2009 Strong free cash balances maintained Investment grade credit ratings with stable outlook maintained $2 bn bank club loan facility signed with 16 banks in October 2010, consisting of $1 bn term loan and $1 bn committed tranche 31.12.0331.12.0930.09.10 Gross debt$2.8 bn$7.0 bn$6.3 bn Gearing18%28%20% Fixed / Floating46% / 54%66% / 34%87% / 13% USD denominated62%96% LT / ST debt68% / 32%80% / 20%84%/16% Unsecured / Secured51% / 49%93% / 7%100% / 0% Average life2.9 years4.0 years4.7 years

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