Microsoft PowerPoint - TNK-BP Investor Presentation Jul 2010 F

TNK BPTNK-BPInvestor PresentationJuly 2010

2

Important noticeThese materials include statements that are, or may be deemed to be, ‘‘forward-looking statements’’. These forward-looking statements can beidentified by the use of forward looking terminology including but not limited to the terms ‘‘believes’’ ‘‘estimates’’ ‘‘anticipates’’ ‘‘expects’’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 ofstrategy, plans, objectives, goals, future events or intentions. These forward-looking statements include all matters that are not historical facts. Theyinclude, but are not limited to, statements regarding the intentions, beliefs and statements of current expectations of TNK-BP International Limitedand 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 statementsinvolve risk and uncertainty because they relate to future events and circumstances that may or may not occur. Forward-looking statements are notguarantees 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 notmake any representation, warranty or prediction that the results anticipated by such forward-looking statements will be achieved.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 forTNK-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 reservesare calculated through the economic life of the fields ("SEC-LOF"). The SEC-LOF standards differ in certain material respects from the SECstandards and the SPE standards Unless otherwise indicated reserves data contained in these materials are based on the SEC-LOF standards asstandards and the SPE standards. Unless otherwise indicated reserves data contained in these materials are based on the SEC-LOF standards asin effect on the date of the Reserve Report from which such data has been extracted. The SEC has adopted significant revisions to the SECstandards on oil and gas reporting, which became effective on 1 January 2010. The main revisions that may have an impact on TNK-BP’s reservequantities 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 newtechnology 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 orThese 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 oracquire 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.

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3

Table of contents

1. Company introduction

2. 1H 2010 operational and financial results

– Business update

– Financial performance

– 2010 outlook

3. New projects updatep j p

4. Additional information

3

Company introductionCompany introduction

5

TNK-BP – one of the leading oil gcompanies globally

• Ranks in the top ten private oil producers in the world

• Third largest oil company in Russia

• 1H 2010 liquids production 1,521 mbpd*

Russia leads global oil production TNK-BP 3rd largest oil producer in Russia

mmbpd mmbpd

5

10

1.5

2.0

2.5

0

5

0.0

0.5

1.0

5

Source: EIA Short-Term Energy Outlook, July 2010, daily liquids production in 1H 2010 Source: CDU TEK, TNK-BP data, daily liquids production in 1H 2010 without JVs

* All TNK-BP data on reserves and production in this presentation are shown without Slavneft unless otherwise stated

6

TNK-BP at a glance

Refineries

Greenfield projects

YANOS refinery 50/50 owned

Financials

Brownfield projects

Yamal (early development)

Reserves*: 5.8bn boe

YANOS refinery, 50/50 ownedwith Gazprom Neft EBITDA

1H10 – $4.7bn

2009 – $9.0bn

2008 $10 1b

West Siberia

Reserves: 19.6bn boe

2008 – $10.1bn

2007 - $9.6bn

Net income

East Siberia

Reserves: 1.9bn boe

ese es 9 6b boe

Orenburg

Reserves: 2.4bn boe

1H10 – $2.4bn

2009 – $5.0bn

2008 – $5.3bn

2007 – $5.3bn

Uvat

Reserves: 1.1bn boe

Liquids

Reserves: 27.4bn boe

Gas

Reserves: 3.4bn boe

Refining

Throughput: 686 mbpd

Retail

1,478 sites under BP and TNK

$

Operations

6

Production: 1,521 mbpd 1H 2010 sales: 6.6 bcm Refining cover: 42% brands

3P reserves as of 31 Dec 2009, production, refining and retail data for 1H 2010; refining cover for Russia and Ukraine

*Incl. Rospan

7

Strong competitive positionWorld class F&D costs vs RRRAmong top companies in production and RLI globally

13

2

2.5

3

ctio

n, m

mbp

d

12

14

16

18

ex (R

LI),

year

s TNK-BP

RosneftChevron100%

120%

140%

160%

RR

R (2

007-

2009

)

1.5

0.5

1

1.5

Liqu

ids

prod

uc

2

4

6

8

10

Res

erve

life

ind

Gazprom Neft

BPChevron

Conoco Phillips

Exxon MobilR&D Shell

20%

40%

60%

80%

aver

age

orga

nic

R

0 0

Source: UBS Global Integrated Oil & Gas Analyser, 2009Production FY 2009 estimate. Reserve life based on 2008 disclosure and SEC data

Source: company reports, TNK-BP data, Reserve Replacement Ratio (RRR) based on SEC-LOF reserve data

0%0 5 10 15 20 25 30 35 40 45 50

3Y average F&D costs (2007-2009), $/boe

3Y

One of the leaders in oil & gas production growth among Russian vertically integrated majors

oduct o 009 est ate ese e e based o 008 d sc osu e a d S C data

8%

11%

2%

5%

8%

7Source: CDU TEK, TNK-BP data, daily oil and gas production without JVs, 1H 2010 vs 1H 2009

-4%

-1%

Rosneft TNK-BP Gazprom Neft Lukoil Tatneft Surgutneftegas

1H 2010 operational and financial resultsBusiness updateFinancial performance2010 outlook

9

1H10 HighlightsOperational performanceOperational performance

• HSE: Disappointing 1Q record reversed in 2Q due to increased operational focus:- Zero fatalities in 2Q- Zero major vehicle accidents

The lowest level of Days Away from Work Cases (DAFWC) recorded since the start of operations- The lowest level of Days Away from Work Cases (DAFWC) recorded since the start of operations• Production

- 4.5% growth (liquids and gas, excl. Slavneft) v 1H09, 3.7% growth (liquids and gas, incl. Slavneft)- 0.7% growth v 1Q10, making 11 quarters of consecutive production growth (liquids and gas, excl. Slavneft)

Upstream• Upstream - Rospan obtained assurances of access to the gas pipeline system operated by Gazprom until 2016- New discoveries in Yamal (10 new reservoirs in Tagulskoye field with 112 mmbbl of oil and 67 mmboe of gas) and

Orenburg (22 mmbbl of oil) - Exploration success ratio of 69%- Exploration success ratio of 69%

• Downstream - Operational availability of Russian refineries further improving and estimated at >97% as of 1H10- Robust refining margin of $11.8/bbl in 1H10 (double the 1H09 level)

FinancialFinancial- EBITDA of $4.7bn, 22% up on 1H09- Net Income of $2.4bn, 21% up on 1H09- Strong cash from operations of $3.9bn

Portfolio

9

Portfolio- 2 licences acquired in federal auctions and 3 licences purchased in Orenburg- Continued retail expansion to markets in Russia and Ukraine

10

Health, Safety & EnvironmentHealth and Safety DAFWC Frequency - 12 Month Rolling Average

0.12

0.16

0.20

Health and Safety

• The lowest DAFWC* level recorded since the start of operations (15% improvement in 1H10 v 1H09)

DAFWC Frequency 12 Month Rolling Average

0.163

0 09

0 00

0.04

0.08• Zero major vehicle accidents in 1H10

• 19% improvement in Severe Vehicle Accident Rate** (SVAR) v 1H09

0.065

0.09

0.0330.00

2007 2008 2009 2010Accident Rate (SVAR) v 1H09

Environment

• 247 km of pipeline replaced in 1H10 bringing th t t l i 2004 t 3 792 k 0 20 Spills Frequency - 12 Month Rolling Average

DAFWC 2009 OGP*** Average

2009 OGPTop Quartile

the total since 2004 to 3,792 km

• 21% reduction in oil spills in 1H10 v 1H090.12

0.16

0.20 p q y g g0.174

0 084

* N b f d f k 200 th d h0.00

0.04

0.08

0.016

0.084

0.027

10

* Number of days away from work cases per 200 thousand man-hoursworked** Number of major or severe vehicle accidents per 1 m km driven*** The International Association of Oil and Gas Producers

2007 2008 2009 2010Number of spills per thousand tons produced

Spilt tons per thousand tons produced

Upstream: ProductionGreenfields

• Increasing share of greenfield barrels in total production

• 1H10 greenfield production up 134% on 1H09

1,400

1,600

1,800 mboed Production (Oil & Gas, excl. Slavneft)

1H09

• Further increase in production in 2Q10 over 1Q10:

U t 14 2% 1Q10 t 80 b d 400

600

800

1,000

1,200

– Uvat: up 14.2% v 1Q10 to 80 mbpd

– VCNG: up 27.5% v 1Q10 to 52 mbpd -

200

400

2Q07 3Q07 4Q07 1Q08 2Q08 3Q08 4Q08 1Q09 2Q09 3Q09 4Q09 1Q10 2Q10

Greenfields Other Brownfields Orenburg Samotlor

1H10 v 1H09 daily production growth

Brownfields

• Sustaining production in West Siberia (2Q10 y p g(excl. Slavneft)

3.6% (liquids) to 1,521 mbpd4 5% (liquids & gas) to 1 743 mboed

g (production up 2 mbd on 1Q10)

• Impressive liquids production growth in Orenburg:

11

4.5% (liquids & gas) to 1,743 mboed– up 9.9% 1H10 v 1H09

– up 1.5% 2Q10 v 1Q10

12

Upstream: Costs and CapexCost management Upstream Lifting Costs$/bbl

• Continuous focus on costs:

– Further improvement in ESP’s mean time between failure to >530 days

– Energy efficiency programs being implemented

p g

5.0gy y p g g p

– Cost optimisation plans developed, implementation targeted for 2H10

– Ongoing work with contractors to reduce cost of services

5.0

services

• Lifting costs driven by sector inflation and forex, with energy being the most significant driver of cost increase:

– Energy tariffs up 26% in 1H10 v 1H09Upstream Capex, 1H10

1Q08 2Q08 3Q08 4Q08 1Q09 2Q09 3Q09 4Q09 1Q10 2Q10

– Total lifting costs up 24% in 1H10 v 1H09

Capex• Substantial capex spent on greenfield developments

Upstream Capex, 1H10

• Substantial capex spent on greenfield developments

• Success in well dual completion technology

• Increasing upstream activity in 2Q10 with $0.9bn capex compared to $0.6bn in 1Q10

Brownfields

Brownfield infrastructure and integrityGreenfields

12

• Plan to further intensify upstream activity in 2H10 offsetting unfavourable weather condition influence in 1Q

13

Technology and ExplorationE&A ProgramE&A Program• New discoveries:

– Yamal: 10 new reservoirs in Tagulskoye field with 112 mmbbl of oil and 67 mmboe of gas

– Orenburg: 22 mmbbl of oil

• Significant seismic acquisition in greenfields and bluefields in 1H10:

– 2D: Brownfields – 100 km, Greenfields – 2,833 km, Bluefields (Astrakhan, Timan-Pechora) – 1,472 km

– 3D: Brownfields – 58 km2, Greenfields – 1,149 km2

• 13 exploration wells completed in 1H10 with 69% success ratio

M&A• Purchase from third party of 3 licenses in Orenburg region with estimated resources of 30 mmboe• Purchase from third party of 3 licenses in Orenburg region with estimated resources of 30 mmboe

• 2 further Orenburg licences acquired in federal auctions with resources of 35 mmboe

• Continue to review strategically aligned inorganic options

Technical Assurance• Further enhancement of geological models for Verkhnechonskoe (5th rig to be added in 4Q10), further analysis of

Urnenskoe (Uvat), Russkoe & Tagulskoe (Yamal) is ongoing

133 t h l il t j t li d th t t b lti i 1 4 bbl f i t l

13

• 133 technology pilot projects applied across the upstream asset base resulting in approx. 1.4 mmbbl of incremental production (dual completion, water shut-off, new acid bottom hole treatment technologies, energy saving pilots, proppant fracturing)

14

• Technology plan in place to access new or untapped reserves, optimize lifting cost, accelerate production

2010 Technology Pilots

• Strategic partnerships with service companies to deliver specific solutions

W t h t ff j t

Status: pilot completed with scale-up potentialDual completion (Uvat)Status: pilot completed

with scale-up potentialWell intervention

• Water shut off projectsEnergy savings due to lower water production (Orenburg, Samotlor)

• Gelled, emulsified and foamed acid bottom hole treatmentNew technologies for carbonate formations (Orenburg)

• Proppant fracturing pilots

Fully independent operation of separate reservoirs using one wellbore

• Drilling CAPEX reduction• Proppant fracturing pilotsFracturing technology increasing well rates (Verkhnechonskoye, Uvat)

• Artificial lift energy savings programArtificial lift design enabling maximum ESP performance (Samotlor)

Status: research and

• Acceleration of new assets development (by optimizing the critical path on drilling schedule)

• Add reserves – increase recovery Status: research and efficiency assessment factors by optimal production

regimes for different layers

• Elimination of license risks: ability to monitor and independently manage each level’s parameters

• Horizontal well waterfloodingTargeting more efficient and higher volume injection without exceeding fracturing pressure preventing injected water from breaking into other f ti (R b hik f ti t S tl )

Reservoir management

(such as bottom hole pressure, watercut) to comply with regulations

• Ability to continue producing from a layer while others are tested or

formations (Ryabchik formation at Samotlor)• Gas utilization program

Utilization of various types of gas (free gas, associated gas, gas caps) for gas re-injection (enhanced oil recovery) and underground gas storage (for fields - Samotlor, Verkhnechonskoye, & Orenburg and Y l i )

14

yhave pump failure Yamal regions)

• Bright Water technology A 'flow diverting‘ nanotechnology developed by BP and others, aimed at increasing of sweep efficiency and recovery factor

15

Downstream

Refining• Operational availability further improving, estimated at > 97% as of 1H10

• Robust refining margin of $11.8/bbl in 1H10 (v $5.9/bbl in 1H09) and $12.2/bbl in 2Q10 (v $4.8/bbl in 2Q09)

D b ttl ki f ll fi i ll d i d th h t f 1 8 bbl i 1H10 l d l d• Debottlenecking of all refineries allowed increased throughput of 1.8 mmbbl in 1H10 v planned volumes and incremental EBITDA of $29m

• Ryazan refinery turnaround successfully completed ahead of schedule with zero accidents

STL• Starting from May the share of exchange sales of domestic products reached 17% and achieved robust margins

• First six-month term contract signed for ESPO crude with Mitsubishi

Retail• Strengthening position on premium markets – a new BP site commissioned in St. Petersburg to bring the total number

to 6 BP sites with another 5 under construction

• New branded fuel, PULSAR, launched in southern and central Russia (Rostov, Krasnodar and Tula). PULSAR sales volumes in 1H made 40% of 95 grade fuel in Moscow and Moscow region

• Targeted retail expansion strategy agreed and implementation commenced

15

16

GasRospan Rospan gas production

• A letter for long-term access to the pipeline system received from Gazprom for up to 13.2 bcma in 2016

• A full field development plan is being prepared

2bcm

p p g p p• Transportation and long-term sales agreements are

being prepared• Rospan gas production up by 25% 1H10 v 1H09,

t d b i d d d f G

1.21.5

supported by increased demand from Gazprom

Associated petroleum gas (APG) sales and utilization rate

0

1H09 1H10

Associated gas

• Associated gas sales up by 7% 1H10 v 1H09,

84.5% 86.1%

4

5

6bcm

supported by a cold winter in 2010• Associated gas utilization up by 2% 1H10 v 1H09,

consistently with our commitment to increase utilization

4.74 5.08

1

2

3

16

ut at o0

1H09 1H10

APG sales APG utilization

18

Financial Highlights

$b

2Q10 1H10

$bn

• EBITDA 4.72.4

• Net Income 2.41.2

• Cash from Operations 3.92.0

• Capex (organic) 1.61.0

18

• Gearing 26%26%

19

PriceUrals

Business Environment

60

80

100$/bbl Urals

Duty Reference PriceDomestic

Stronger markets in 1H10 v 1H09:

• Urals higher by $25/bbl (50%)

• Negative Duty lag of $0.2/bbl compared with $6 2/bbl benefit in 1H09

20

40

60 $6.2/bbl benefit in 1H09

2Q10 markets flat v 1Q10:

Exchange rate (Average)

- • Urals slightly higher by $1.6/bbl (2%)

• Negative Duty lag of $1.3/bbl compared with $0.9/bbl benefit in 1Q10

1H09 1H102H09

35

40RUR/USD

Negative impact of forex in 1H10 v 1H09:

• RUR/$ strengthened 9% from 33 to 30

25

30

g

• Negative forex effect on costs partly offset by a positive effect on domestic sales

19

20 2Q10 average RUR/$ flat v 1Q101H09 1H102H09

20

Revenues$21bn

$bn

Export

Domestic Produc

$15bn

$21bn

Domestic

Domestic

Export

Export

Domesticct

Cru

ExportExport

udePrice Volume

P i

1H09 Export Domestic Export Domestic Export Domestic Export Domestic 1H10

Crude CrudeProduct Product

Price:• Urals up 50%• Domestic crude price higher by 47%

Volume:• Production growth of 75 mboed (+4.5%)*• 1.2 m tonnes increase in inventory

20

• Product prices up 25-68%• Average realisations increased by 44%

causing sales volumes to fall by 1%

* excl. Slavneft

21

Costs

F ti ff t $0 1b• Forex negative effect: $0.1bn

• Tariff increase (21%)

B fit f ti i ti f

Transportation

2

3$bn

• Benefit from optimization of transportation routes and volume effects (9%)

1.5 1.81

• Overall cost increase of 19%1H09 Forex Tariff Routes 1H10

Opex & SG&A4$bn

• Forex negative effect : $0.2bn2

3

4

• Inflationary increase (8%)

• Overall cost increase of 17%

2.82.41

1H09 Forex Inflation 1H10

21

22

Taxes

Taxes other than Income Tax higherTaxes other than Income Tax$bn

Taxes other than Income Tax higher by 79%:

• Urals price: causes 85% increase

10

pin Export Duties and MET ($4.6bn) and negative duty lag effect ($0 7bn)

9.7

5.4

5

($0.7bn)

• Volume: decreased exports partly offset by increased production

5.4

-1H09 Price Volume Other 1H10

I hi h b 24%

Income Tax1.2

$bn

Income tax higher by 24%:

• Taxable profits: higher in 1H100.7

0.8

0.6

22

• One-offs: reduction of tax audit provision in 1H09-

1H09 Taxableprofit

One-offs Other 1H10

23

Net Income – 1H10 v 1H09

4$bn

4

2.42.0

2

-1H09 Price -

MarketPrice -

Duty lagForex Tariffs Operations One-offs Other 1H10

Environment:• Price: Urals up $25/bbl (50%)• Duty lag: negative effect of $6.4/bbl

Performance:• Operations: higher margin from Greenfields

productionDuty lag: negative effect of $6.4/bbl

• Forex: negative effect on costs from stronger RUR

• Tariffs: transportation and electricity

• One-offs:- gain in 1H10 from custom duty cash receipt - increased provision for legal cases in 1H10- reduction of tax audit provisions in 1H09

23

Tariffs: transportation and electricity tariffs up more than 20%

- reduction of tax audit provisions in 1H09

24

Income Statement - 2Q10 v 1Q10$bn %$bn %

2Q10 1Q10 Change

Revenues 10.5 10.2 3% Urals up 2% together with increased sales volumes

Export Duties (2 9) (3 0) -4% lower volumes exported partly offset by higher UralsExport Duties (2.9) (3.0) lower volumes exported partly offset by higher Urals

MET (1.6) (1.5) 8% production growth and Urals price increase

Costs (2.8) (2.6) 6% lower activity in 1Q10 due to severe weatherCosts (2.8) (2.6) y

Other (0.8) (0.8) 3% increased oil products purchases offset by gain from custom duty cash receipt

EBITDA 2 4 2 3 4%EBITDA 2.4 2.3 4%

DD&A (0.5) (0.4) 4% continued capital investment

Income tax & other (0 7) (0 6) 34% provision increase re legal cases in 2Q10Income tax & other (0.7) (0.6) 34% provision increase re legal cases in 2Q10

Net Income* 1.2 1.3 -9%

24

*Net Income attributable to majority shareholders

25

Income Statement - 2Q10 v 2Q09$bn %$bn %

2Q10 2Q09 Change

Revenues 10.5 8.2 29% Urals up 32% partly offset by changes in sales mix

Export Duties (2 9) (1 6) 77% higher Urals price and lower duty lag benefitExport Duties (2.9) (1.6) 77% higher Urals price and lower duty lag benefit

MET (1.6) (1.0) 56% increased Urals effect partly offset by higher inventory levels

Costs (2.8) (2.3) 18% adverse forex effect together with inflation impact

O ( ) 8% i f d h iOther (0.8) (0.9) 8% gain from custom duty cash receipt

EBITDA 2.4 2.4 1%

DD&A (0.5) (0.5) 0%( ) ( )

Income tax & other (0.7) (0.6) 20%

Net Income* 1.2 1.3 -8%

*Net Income attributable to majority shareholders

25

26

Sources and Uses of Cash

• Operations: strong pre-tax inflows of $14 2bn

$bn

$14.2bn

• Taxes: $10.3bn paid in total

C $1 8b f i i t t10

15

• Capex: $1.8bn of organic investments

• Debt: $1.7bn repaid with $1.2bn of new debt raised

Operations

Taxes

5

10

debt raised

• Dividends: $1.7bn paid in respect of 4Q09-1Q10 earnings

Capex

Dividends

5

Net debt repayment

gSources Uses

26

27

Debt and LiquidityTNK-BP debt position

• $1.0bn Eurobond successfully issued inJanuary

31.12.03 31.12.09 30.06.10

Gross debt $2.8bn $7.0bn $6.6bn

Gearing 18% 28% 26%

Fi d / Fl i 46% / 4% 66% / 34% 83% / 1 %• $495m of short-term debt pre-paid

• Secured debt removed from theportfolio by prepayment of $360m PXFf ilit i M

Fixed / Floating 46% / 54% 66% / 34% 83% / 17%

USD denominated 62% 96% 96%

LT / ST debt 68% / 32% 80% / 20% 90%/10%

Unsecured / Secured 51% / 49% 93% / 7% 100% / 0%

facility in May

• Portfolio of undrawn committed banklines in excess of $500m maintained

Debt maturity profile as of 30 June 2010

Average life 2.9 years 4.0 years 4.8 years

Other$bn• Average portfolio life increased by 19%

to 4.8 years v end 2009

• Strong free cash balances maintained 1.0

1.5 EurobondsBank debt

$bn

• Investment grade credit ratings withstable outlook maintained 0.5

27

0.02H 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

28

TNK-BP credit spreads vs Lukoil

500

550

New 2015 5-year / 6.25% 2020 New 10-year / 7.25% LUKOIL 2014 5-year 6.375% LUKOIL 2019 10-year / 7.25%

450

350

400

o B

ench

mar

k (b

ps)

250

300Spre

ad t

200

250

28

1501-Jan-10 1-Feb-10 1-Mar-10 1-Apr-10 1-May-10 1-Jun-10 1-Jul-10

30

2010 outlookOperationsOperations

• Focus on HSE to maintain improvement momentum

• Continued production growth (1-2%)

• Further development of VCNG and Uvat, with 5th rig to be introduced at VCNG in 4Q10

• Yamal – plans of regional infrastructure development

• Rospan – full field development plan being prepared

• Cost focus – particularly energy efficiency

B ildi bilit f fi d• Building capability for refinery upgrades

Portfolio

• Selective M&A opportunities

Financing

• Secure appropriate financing as planned

30

New projects update

32

Greenfields: foundation for production pgrowthGreenfield projects under development Yamal projectsRospanProjects at phase of commercial productionGas project

Further exploration focus areas

p j3P Reserves: 3.1bn boe

Potential start-up: 2015-2016

p3P Reserves: 2.7bn boe (liquids + gas)

Potential plateau: 16 bcma

1H10 gas production: 1.5 bcm (51 mboed)

1H10 condensate production: 15 mbpd

Messoyakha*

Timan-Pechora

RospanRusskoyeTagulskoye

SuzunskoyeMessoyakha

V kh h kKamennoye

Kamennoye3P Reserves: 2.4bn boe

Start-up: 2009 (north)

1H10 oil production:54 mbpd

Astrakhan Uvat

Verkhnechonskoyea e oye54 mbpd

Verkhnechonskoye3P Reserves: 1.9bn boe

Start-up: 2008

Uvat3P Reserves: 1.1bn boe

Start-up: 2009

32

Start-up: 2008


Start-up: 2009


*Messoyakha (3P + 3C resources – 3.2bn boe) is owned by a 50/50 JV between TNK-BP and Gazprom neft

33

Producing greenfields: Verkhnechonskoye3P reserves: 1.9 bn boe 1H 2010 production: 47 mbpd Peak production: 150 mbpd Peak year: 2017

Project overview• Largest oil field in East

Siberia discovered in

Recent developments:• In Feb 2010, Board of Directors

supported the next phase of the

2010 milestones:• 18 mm bbl estimated production

plan for 2010Siberia discovered in 1978, developed in partnership with Rosneft

• Tax incentives currently apply (zero MET,

supported the next phase of the Full Field Development plan, including 90 wells, related infrastructure, power station

• Reservoir model updated to

plan for 2010• 23+ mm bbl p.a. oil treatment unit

to be commissioned• 26 MW power plant to be

commissionedR i t

ESPO – a strategic and lucrative export route to which Verkhnechonskoye is an important supplier

pp y ( ,reduced export duty)

penhance production delivery – 5th

rig to be introduced in 4Q 2010

• Reservoir pressure management facilities to be completed

• An alternative supply for Far East consumers

• ESPO blend gains ground in the international market, trades at a premium to UralsVerkhnechonskoye

• Single ESPO tariff set by Transneft at the end of 2009

• Zero export duty applied to Verkhnechonskoyeexports during 1H 2010, a reduced per barrel rate of

33

0.45 * (Urals price – $50) applies from 1 July 2010

• MET holidays for first 25 mln tons if produced until 2017

Source: Reuters

34

Producing greenfields: Uvat3P reserves: 1.1 bn boe 1H 2010 production: 75 mbpd Peak production: 200 mbpd Peak year: 2017

Project overview• 21 fields in 15 license

l t i th th f

Recent developments:• In Feb 2010, Board of

Directors supported

2010 milestones:• 26 mm bbl production plan for 2010

plots in the south of Tyumen region, West Siberia, some 700 km away from Tyumencity

Directors supported the next phase worth $589 million of the Full Field Development plan of

• Gas Turbine Power Plant (GTPP) 1st phase (22 MW) to be commissioned by October 2010

• Continue with Tyamkinskoye pilot targeting Full Field Development in 2011

city

• Eastern Hub: a new production centre launched in 2009 (Urnenskoye and Ust

Eastern Hub and the development of the Uvat region infrastructure ($162 million)

• Uvat infrastructure:• Road construction under way for all year access

• 41 mm bbl p.a. Central Processing Facility to be commissioned in August 2010(Urnenskoye and Ust-

Tegusskoye fields)

• Central Uvat: pilot production

d t

million) commissioned in August 2010

Western Uvatcommenced at Tyamkinskoye field in March 2010, ahead of plan

Eastern Uvat

Kalchinsky fieldTyamkinsky field

Protozanovsky field Ust-Tegusskoye field

34

• Development partly financed with regional government grants

Central Uvat Urnenskoye field

35

Yamal - a major new production area j pfor TNK-BP and Russia

• One of the few remaining undeveloped hydrocarbon provinces in Russia and the worldg p y p• Mineral extraction tax holidays and a reduced export duty currently apply for certain fields• Yamal integrated development program being discussed at government level

Significance for TNK-BP

• A major potential source of TNK-BP’s future growthbut significant challenges to overcome

Major challenges to development• Lack of transportation infrastructure• Current Russian oil & gas taxation does not

stimulate new developmentsbut significant challenges to overcome stimulate new developments• Technical challenge of developing the reserves:

quality of oil (Russkoye) and complex reservoirs(Suzun, Tagul)

TNK-BP’s Yamal projects

3P + 3C resources,

bn boe

Potential year of first production

Field summary

Suzun 0.3 2015 Best explored field with well-understood geology and high quality light oil

Tagul 1.9 2016 Complicated field with numerous reservoirs and medium-quality crude

Russkoye 2.2 2015 Large but technically challenging field (highly viscous oil, gas caps)

35

Russko-Rechenskoye 0.1 2016 Small f ield adjacent to Tagul on the west

Messoyakha (50%) 1.6 2017 Potentially gigantic field, technically challenging (multiple layers, heavy oil)

3636

Yamal infrastructureTransportation infrastructure a key factor for p yYamal development, timing of full field development depends on availability of pipeline options

• Vankor-Purpe pipeline: operated by Rosneftonly

• Transneft’s Zapolyarnoye – Purpe: a new p y y poption currently being studied by Transneftand the oil companies under the aegis of the Russian Government

• TNK-BP’s Suzun-Tagul-Russkoye-Zapolyarnoye pipeline

• TNK-BP/Gazpromneft’s Messoyakha-TNK BP/Gazpromneft s MessoyakhaPyakyakha pipeline

36

© THK-BP presentation name

TNK-BP gas portfolioNyagan RospanAssociated Gas Gas Sales in 2009

Yamal

• Associated gas utilization at Krasnoleninskoyefield

• East-Urengoyskoye and Novo-Urengoyskoye gas and condensate fields• 460 bcm reserves (A+B+C1)• 2009 production 2.4 bcma,

Natural Gas

Gas Processing Plant• Associated Gas 9.7 bcm • Natural Gas 2.4 bcm

Ukrainep

plateau up to 16 bcma in 2017+ • Associated gas utilization at Suzunskoye, Tagulskoye and Russko-Rechenskoye fields• Assessment of

unconventional gas potential

Verkhnechonsk• Gas utilization at Verkhnechonskoye fieldVerkhnechonskoye field

Orenburg Novosibirsk Nizhnevartovsk• 8 bcma of associated gas production• Processing JV with Sibur at Belozerny and Nizhnevartovsky GPP

• Associated gas utilization at Verkh

• 2009 production 1.5 bcma (natural gas and APG) with a potential to reach

37

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)

utilization at Verkh-Tarskoye field

gas and APG) with a potential to reach 3-4 bcma• Zaikinskiy GPP (capacity 1.1 bcma, under enhancement to 2.2+ bcma)

Gas business strategy: monetization of gygas potential

Goals for Company’s gas business development to 2020Goals for Company’s gas business development to 2020

Gas value assurance for “ t d d ” Reduce gas flaring –

Broaden gas options – to improve leverage andE d h l“stranded resources” -

(Rospan, gas caps) – i.e. reserves monetization

Reduce gas flaring attain maximum possible associated gas utilization

improve leverage and provide growth

(organic/inorganic options)

Extend the gas value chain

Secure long-term t

Small-scale gas-to-j

Proceed with growth i S th R i

Enhance wholesale k i iaccess to

infrastructureOptions for forming integrated JV’s based on company’s gas

power projects Investments in liquids processing

in South RussiaNew gas projects in CIS countries Unconventional gas projects (Ukraine)

marketing operation (long-term contracts with end-users) Evaluate retail market optionsy g

assetsj ( )p

Large commercial gas-to-power projects

3838

Unlock the Company’s significant gas potential

Rospan - gas growth opportunityRospan full field development

• Largest TNK-BP’s natural gas asset, located in Urengoy region

p p

Urengoyskaya - 3

Urengoyskaya-3

• 3P gas reserves: 1.4 bn boe; A+B+C1: 460 bcm

• Total estimated capex c.USD 5 bn

• Existing gas production 1.5 bcm in 1H10 (25% up g g p ( % pvs. 1H09), 2.4 bcm in FY09

• A letter for full long-term access to the pipeline system received from Gazprom in June 2010

Novy

Urengoi

Urengoyskaya - 1

U k 2

Novy

Urengoi Urengoyskaya-1

- 1

• Transportation and long-term sales agreements are being prepared

• Rospan is capable to produce 16 bcma of gas d t 5 l t f d t t ti

Urengoyskaya - 2Urengoyskaya-2

Gazprom, ENI, ENEL

D fi d G t A hi H i

and up to 5 mln tons of condensate a year starting from 2016

TNK BP

Gazprom(Urengoygazprom) (Arcticgas)

Korotchaevo

39

Defined Greater Achimov HorizonTNK-BP(Rospan)

Major gas pipelineRailway

Compressor station

Increasing APG utilizationOver $1.3bn investments planned to significantlyi TNK BP’ APG tili ti l l b 2012

APG utilization, %increase TNK-BP’s APG utilization level by 2012:Orenburg

• Integrated project

• Expansion of Zaikinsky GPP

75.5 77.6 79.8

68.4

79.684.4

60

70

80

90

y

Nizhnevarovsk

• Associated gas processing JV with Sibur

• NVGRES20

30

40

50

Nyagan

• Construction of a power generation unit

• Construction of a gas turbine power plant atKamennoye field (completion in 2010)

0

10

20

2004 2005 2006 2007 2008 2009

APG in TNK-BP, 2009

y ( p )

Uvat

• Construction of a gas turbine power plant

Verkchnechonskoye

TNK-BP Lukoil Rosneft

• Utilization level – 84.4%

• In production – total 143 fields

• Production of APG – 12.5 bcma

• Considering different options including gasreinjection for storage and future use

Yamal

• Considering various projects including power

40

g p j g pgeneration, gas reinjection, supply to the gaspipe

• TNK-BP is a major consumer of power and gas producer

Gas to power to power savingsNi h t kNi h t k GRESGRESTNK BP is a major consumer of power and gas producer

- TNK-BP demands 13.4 bln kWph (Upstream - 12.1 blnkWph, Downstream – 1.3 bln kWph)

• Cost of power is a significant part of oil production costs

Nizhnevartovsk Nizhnevartovsk GRESGRES

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 in the regions of its operations, including Nizhnevartovsk, Irkutsk, Orenburg, Ryazan and Yamal

TNKTNK--BPBP –– SiburSibur JVJV• Upon completion of this process TNK-BP’s captive power generation will increase from current 4% in 2009 (0.4 blnkWph) to 54% in 2020, significantly cutting electricity costs – up to $400 mln annually

TNKTNK--BP BP –– SiburSibur JVJV(YugragazpererabotkaYugragazpererabotka)

41

UkraineRefining

LINIK i th b t l t i th t tifi d fPriority market

C ilArea of TNK-BP presence

Lisichansk

• 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

Current own retail market share

~21%

DnepropetrovskDonets’k

Kyiv

Khar’kivthe highly populated east part of the country, as well as in the Kiev core market

• Production of diesel compliant with Euro 4 since 2007• Turn-around of the refinery in May-June 2010

completed (every 2 years)

Odesa

L’viv Dnepropetrovskp ( y y )

• Refining modernization plans: – To meet Euro 4 for all fuels from 1 Jan 2011

(USD 70 mln investment planned)– To increase light products output

170 own sites: 3 BP

167 TNK, Golden Gepard, Li i h k fi

To increase light products outputMarketing• 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

278 jobber sites

Golden Gepard, VikOil Lisichansk refinery

Modernized in 2008

Capacity: 144 mbpd

Conversion ratio: 71%

• 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

42

Light products output: 58%

Utilization: 71%M&A• May 2010 - acquisition of Vikoil with 118 retail sites,

8 depots, 49 oil trucks and 122 land plots in 13 regions

43

Projects in refining in RussiaTo significantly enhance the economic performance and competitiveness of TNK-BP refineries

• Increase refined product output

• Maximize crude throughput

I li ht d t i ld

g y

• Increase light product yield

• Targeted quality upgrades

• Energy efficiency

• Improve organizational capability

• A number of small and medium size

Saratov refinery

• A number of major upgrade projects are

Ryazan refinery

projects with a short payback period are being considered

• Hydrotreater upgrade in progress• Construction of an isomerization unit

being contemplated• Hydrotreater upgrade in progress• Major projects (including VGO

Hydrotreater Fluid Catalytic Cracker)

43

• Construction of an isomerization unit under way

Hydrotreater, Fluid Catalytic Cracker) previously implemented

Retail expansionMacro viewCurrent TNK-BP retail presence

• Increasing consumption• High barriers to entry• Growing share of value added producers

Macro viewCurrent TNK-BP retail presence

• Growing share of value added producers• Market consolidation

Increasing retail coverage

Growth in existing and adjacent regions, aiming to become a market leader based on COCO sales volumes by leveraging our

t l d t

Existing regions

current supply advantage

Accessing selected new priority regions through inorganic growth, aiming to secure a New

regions competitive position among the existing regional players

regions

Presence along selected high-traffic motorways, aiming to

hi b b ildiSelected

44

achieve synergy by building an integrated retail network across Russia

Selected motorways

Additional informationAdditional information

Corporate governanceCorporate governance

47

Clear strategy

To become a world class oil and gas group, an industry leader in Russia with a clear focus on the sustainability and renewal of its resources and the efficiency of its operations

Maintain internationalConvert resources Maintain international standard corporate governance system

Sustain world class

Monetize our gas portfolioEnhance margins

Convert resources to reserves to

production

Increase contribution Optimize refining Replace min 100% of business practices and systems

Promote Business Ethics and standards

of gas sales

Exploit TNK-BP significant gas and associated gas

Opt e e gcoverage

Enhance marketing coverage

pannual production with new reservesApply technology and innovationS Ethics and standards

Increase transparency

associated gas resources

Develop power generation projects

Optimize product flow

Utilise competitive logistics

Sustain production efficiency at brownfieldsEffectively develop new greenfields

47

new greenfieldsAcquire new subsoil use licenses

48

TNK-BP corporate structure1

50% 50%Alf A /R BP

TNK-BP Ltd (BVI)

Alfa, Access/Renova BP

c.50%

63%RUSIA

Petroleum

Slavneft(JV with

Gazprom Neft) TNK-BP Finance S A (L b )

100%100%

TNK Industrial Holdings Ltd (BVI)

100%

STBP Holdings Ltd.

100%

S.A. (Luxembourg)

LisichanskRefinery(Ukraine)

c.95%

TNK-BP Commerce (Ukraine)

TNK-BP International Ltd (BVI)

100%

95%

( )

TNK-BP Management

100%East Siberia Gas

Company50%

Upstream Refining Marketing

TNK-BP Holding

48

Note: Showing principal holding and operating companies

49

Board of Directors

Mikhail FridmanChairman

Alfa Group

Mikhail FridmanChairman

Alfa Group

L d R b t f P t EllL d R b t f P t EllLord Robertson of Port EllenDeputy Chairman

Lord Robertson of Port EllenDeputy Chairman

Gerhard SchroederChairman of the Shareholders’ Committee of Nord Stream AG

Andy InglisChief Executive of Upstream Business,

BP

Andy InglisChief Executive of Upstream Business,

BP

Len Blavatnik Chairman, Access Industries

Len Blavatnik Chairman, Access Industries

Alexander ShokhinPresident of the Russian Union of Industrialists and Entrepreneurs

J L

Iain MacdonaldCFO, Fairfield Energy Limited

Iain MacdonaldCFO, Fairfield Energy Limited

Alex KnasterChairman of Pamplona Capital

Management, Alfa Group

Alex KnasterChairman of Pamplona Capital

Management, Alfa Group

Viktor VekselbergChairman, Renova GroupViktor VekselbergChairman, Renova Group

James LengEuropean Chairman, AEA (an American

private equity partnership)Board member of a number of other

international companies

David PeattieExecutive Vice President for Russia and

Kazakhstan, BP

David PeattieExecutive Vice President for Russia and

Kazakhstan, BP

49

representatives of AARrepresentatives of BPindependent directors

50

Management structureCEOCEOCEOInterim

M. Fridman

CEOInterim

M. Fridman

Deputy CEOM. Barsky*

CFOJ. MuirCFO

J. MuirExecutive Director

G. KhanExecutive Director

G. KhanСОО

B. SchraderСОО

B. SchraderExecutive Director

V. VekselbergExecutive Director

V. Vekselberg

Deputy Executive Director, EVP

Executive Director, EVP

Executive Director, EVP EVP

EVPSupport

EVPStrategy

& BusinessChief Legal ,

Gas business development

A. Ferguson

Upstream

S. Brezitsky

,Downstream

D. Baudrand

,Downstream

D. Baudrand

Technology

F. Sommer

ppServices

A. Tyomkin

Development

S. Miroshnik

gCounsel

I. Maydannik

50

members of the Management Board *M. Barsky planned to become CEO effective 1 January 2011

5151

Corporate governance

New Shareholder Agreement

• Signed in January 2009• Maintains 50:50 ownership structure of TNK-BP Group• Defines the management and financial framework• Includes dead-lock resolution mechanism

• 11 members – 4 representatives each from BP and AAR plus 3 independent directors• Approves major transactions and key strategic decisions• Key functions: provides strategic directions, reviews strategy and performance of TNK-BP

Board of Directors

• 3 Board Committees: Audit, Compensation and HSE Committee

CEO and Management Board

• BP nominates the CEO, subject to the Board of Directors unanimous approval• CEO heads the Management Board; personal authority of CEO expanded Management Board g ; p y p• Key functions: responsible for TNK-BP’s day-to-day management

Boards of Directors • Boards of Directors at key TNK-BP subsidiaries to have equal number of representatives from BP and AAR and will also have an independent directorat key subsidiaries representatives from BP and AAR and will also have an independent director

• Enhances shareholder governance and prevents deadlock

Financial framework • Target gearing range of 25-35%

51

Financial framework g g g g• Quarterly dividends of not less than 40% of TNK-BP’s net income

52

Prudent financial strategyFocused on supporting the Group’s growth while minimising financial risks and maintaining a

• Maintain gearing within a range of 25% to 35%Narrowed from the previous 25 50% starting from Jan 2009Financial

pp g p g g gstrong balance sheet with adequate liquidity and financial flexibility

Narrowed from the previous 25-50% starting from Jan 2009

• Maintain financial ratios in line with strong investment grade companies

• Maintain investment grade credit ratings

Di id d f 40% i f N t I

framework

• Dividends of 40% min of Net Income

• Maintain average life of debt portfolio at 4-5 yearsDebt strategy Reflecting investment project cash generation profiles

• Maintain the right fixed / floating ratioBy balancing between bonds and bank financing

• Maintain a smooth repayment profileMaintain a smooth repayment profile

• Keep debt portfolio largely unsecured

• Maintain proper currency of debt

• Broaden investor base

52

• Broaden investor base

Operational performanceOperational performance

5454

Extensive resource base

11 7 billion barrels of proved reserves and with 19 years reserves life (PRMS)

258% organic reserve replacement ratio (PRMS)2007-2009 average. 3-year average reserve replacement ratio on SEC-LOF basis 146%

11.7 As at end 2009. SEC-LOF reserves of 8.6 billion barrels and 14 years reserve life

73% exploration success rate2007-2009 average

$3 6 finding & development (F&D) costs per barrel

Reserve Replacement RatioResource base at YE2009 (PRMS)

$3.6 2007-2009 average. $2.2/boe in 2009

25

30

35bn boe Reserve life

50 years

Reserve life30 Possible

297329

250

300

350%

PRMS SEC LOF

10

15

20Reserve life

19 years

> 30 years

Probable Probable

Possible

104125

156 146127

149129

179

82

177

100

150

200

54

0

5

Proved 2P 3P

ProvedProved Proved

0

50

2004 2005 2006 2007 2008 2009

55

Brownfield asset baseSamotlor fieldNyagan fields3P Reserves: 7.6bn boe

1H10 oil production: 546 mbpd

y g3P Reserves: 4.7bn boe

1H10 oil production: 85 mbpd

Other West Siberia fields

Samotlor

3P Reserves: 4.8bn boe


Moscow

Nyagan

Orenburg

Nizhnevartovsk

NovosibirskOrenburg fields3P Reserves: 2 4bn boe3P Reserves: 2.4bn boe


Novosibirsk fields3P Reserves: 0.1bn boe


55

56

BrownfieldsSustaining brownfield production

1,400

1,600• Brownfield production maintained broadly flat

through application of select new technology and processes

Sustaining brownfield productionmboed

800

1,000

1,200• Base production decline rate decreased by 1% in 2009 and 4% since 2007

• Samotlor– Delivers 38% of total liquids production

200

400

600Delivers 38% of total liquids production

– 3P reserves of 7.6bn boe

– will remain a reliable producer going forward

• Orenburg0

2003 2004 2005 2006 2007 2008 2009 1H10

g

– Delivers 27% of total liquids production

– 3P reserves of 2.4bn boe

– outstanding liquids production growth of 9 9%Orenburgneft(Volga-Urals)

Samotlor andother brownfieldsoutstanding liquids production growth of 9.9%

in 1H10 vs 1H09 60-70 years old fields(West Siberia)40 years old fields

56

57

Strong refining presence and ang g pextensive marketing network

NizhnevartovskKrasnoleninskRefinery assets RyazanBuilt in 1998

Capacity: 29 mbpd

Utilisation: 90%

Built in 1998

Capacity: 4 mbpd

Utilisation: 78%

Retail sites

yModernised in 2006

Capacity: 323 mbpd



Utilisation: 91%

YANOS (50%)Modernised in 2006

Capacity: 286 mbpd

Utilisation: 91%



Utilisation: 96%Moscow

Nyagan

1,478 retail sitesOrenburg

Nizhnevartovsk

Novosibirsk

LisichanskModernised in 2008

Capacity: 144 mbpd


SaratovModernised in 2004

Capacity: 132 mbpd


57


Utilisation: 71%


Utilisation: 88%

Refining data as at end 2009, retail sites as at end 1H 2010

58

• Total refining throughput of 675 mbpd in 2009 and

Refining• Operating availability forecast of >97% for 2010

686 mbpd in 1H 2010*• Refining cover of 42% (Russia and Ukraine) for 1H

2010*• Robust refining margins benefiting from fiscal

i

(based on mid-year estimate)

• Scheduled turnarounds at refineries

• Continued modernization of refining portfolio toproduce fuel to meet European quality standardsregime

Stable throughput and high operating availability

produce fuel to meet European quality standards

Refining margins outperform other regions

661701 698 675 686

600

800100%

mbpd$/bbl

TNK-BP

North West Europe

200

40090%Europe Mediterranean

0

200

80%2006 2007 2008 2009 1H10

R fi i th h t O ti il bilit

2008 2009

58

Refining throughput Operating availability

Source: BP Trading Conditions Update, company data 1H 2010 operating availability is full year forecast based on mid-year estimate

* Preliminary actuals, here and on page 6 of this presentation

59

Continued retail expansionThroughput per site

• Inorganic activities in Russia, Belarus, Ukraine

• Launch of new fuels

N f d t d TNK d BP

Throughput per site

50

60

er s

ite, k

lpd Average throughput

per BP site (Russia)

Average throughputper TNK site• New range of products under TNK and BP

brands

• B2B business expansion: jet fuels, bitumen, lubricants and marine fuel

5348

20

30

40

age

thro

ughp

ut p

e p

Indicativethroughput (Europe)

• We support and actively promote exchange trade as the most objective market price indicator for oil products

11 1211 110

10

2008 2009

Ave

ra

Brand # of sites at 30 Jun 10

Company owned and operated sites

TNK-BP retail network in Russia, Ukraine and Belarus

Company owned and operated sitesBP 75TNK 834

Jobber sites 569

59

60

Taxation regime: recent developmentsChanges in taxation regime – already introducedg g y

• Export duty suspended for 22 East Siberian fields (including Verkhnechonskoe,Suzunskoye, Tagulskoye) during 1H 2010, a reduced per barrel rate of 0.45 * (Uralsprice – $50) applies from 1 July 2010

• MET holidays introduced to encourage development of new fields in East Siberia,Yamalo-Nenets Autonomous District

• Accelerated VAT refund effective from 2010 – positive for working capitalp g p• Non taxable threshold for mineral extraction tax (MET) up from $9 to $15 per barrel

from 1 Jan 2009• Corporate income tax rate reduced from 24% to 20% effective 1 Jan 2009p• Export duty calculation methodology changed effective 1 Dec 2008, reducing duty lag

effect

Changes in taxation regime under discussionChanges in taxation regime – under discussion• A working group that includes representatives of Russian oil companies and

government bodies is currently working on a new concept of industry taxation

60

• Downstream sector: proposals of levelling of duties for light and dark products

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