Post on 08-May-2015
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
1H 2010 operational and financial resultsBusiness updateFinancial performance2010 outlook
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
1H 2010 operational and financial resultsBusiness updateFinancial performance2010 outlook
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
1H10 oil production:47 mbpd
Start-up: 2009
1H10 oil production:75 mbpd
*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
1H10 oil production:234 mbpd
Moscow
Nyagan
Orenburg
Nizhnevartovsk
NovosibirskOrenburg fields3P Reserves: 2 4bn boe3P Reserves: 2.4bn boe
1H10 oil production:403 mbpd
Novosibirsk fields3P Reserves: 0.1bn boe
1H10 oil production:27 mbpd
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
Conversion ratio: 63%
Light products output: 55%
Utilisation: 91%
YANOS (50%)Modernised in 2006
Capacity: 286 mbpd
Utilisation: 91%
Conversion ratio: 63%
Light products output: 57%
Utilisation: 96%Moscow
Nyagan
1,478 retail sitesOrenburg
Nizhnevartovsk
Novosibirsk
LisichanskModernised in 2008
Capacity: 144 mbpd
Conversion ratio: 71%
SaratovModernised in 2004
Capacity: 132 mbpd
Conversion ratio: 70%
57
Light products output: 58%
Utilisation: 71%
Light products output: 44%
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