LukOil(OAO) - Final Results (MDA)
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RNS Number:0491S
LukOil (OAO)
10 April 2008
Management's discussion and analysis of financial condition and results of
operations
The following report represents management's discussion and analysis of the
financial condition and results of operations of OAO LUKOIL as of December 31,
2007, and each of the years ended December 31, 2007, 2006 and 2005, and
significant trends that may affect its future performance. It should be read in
conjunction with our US GAAP consolidated financial statements and notes and
supplemental oil and gas disclosure.
References to "LUKOIL", "the Company", "the Group", "we" or "us" are references
to OAO LUKOIL and its subsidiaries and equity affiliates. All dollar amounts are
in millions of US dollars, unless otherwise indicated. Tonnes of crude oil
produced are translated into barrels using conversion rates characterizing the
density of oil from each of our oilfields. Tonnes of crude oil purchased as well
as other operational indicators expressed in barrels were translated into
barrels using an average conversion rate of 7.33 barrels per tonne. Translations
of cubic meters to cubic feet were made at the rate of 35.31 cubic feet per
cubic meter. Translations of barrels of crude oil into barrels of oil equivalent
("BOE") were made at the rate of 1 barrel per BOE and of cubic feet into BOE at
the rate of 6 thousand cubic feet per BOE.
This report includes forward-looking statements - words such as "believes", "
anticipates", "expects", "estimates", "intends", "plans", etc. - that reflect
management's current estimates and beliefs, but are not guarantees of future
results. Please see "Forward-looking statement" on page 41 for a discussion of
some of the factors that could cause actual results to differ materially.
Key financial and operational results
2007 Change to 2006 Change to 2005
2006, % 2005, %
Sales (millions of US dollars) 81,891 21.0 67,684 21.4 55,774
Net income (millions of US dollars) 9,511 27.1 7,484 16.2 6,443
EBITDA (millions of US dollars) 15,388 25.1 12,299 18.2 10,404
Earnings per share of common stock (US
dollars)
Basic earnings (US dollars) 11.48 26.7 9.06 14.5 7.91
Diluted earnings (US dollars) 11.48 27.0 9.04 16.0 7.79
Hydrocarbon production by the Group
including our share in equity affiliates
(thousands of BOE) 795,099 1.5 783,194 12.3 697,429
Crude oil production by the Group
including our share in equity affiliates 96,645 1.5 95,235 5.6 90,158
(thousands of tonnes)
Gas available for sale produced by the
Group including our share in equity
affiliates (millions of cubic meters) 13,955 2.5 13,612 141.6 5,635
Refined products produced by our
subsidiaries (thousands of tonnes) 48,819 6.9 45,670 3.4 44,182
Hydrocarbon proved reserves including our
share in equity affiliates (millions of
BOE) 20,369 - 20,360 0.1 20,330
During 2007, our net income was $9,511 million, which is $2,027 million, or
27.1%, more than in 2006.
The main factor for improvement of our performance in 2007, was an increase in
the international crude oil and refined products prices. On the other side we
were affected by growing operating expenses and transportation tariffs. However,
the negative effect of these factors was partially mitigated by increased
volumes of hydrocarbon production and crude oil refining. These and other
drivers impacting the results of our operations are considered below in detail.
Segment information
Our operations are divided into three main business segments:
- Exploration and Production - which includes our exploration, development
and production operations relating to crude oil and natural gas. These
activities are primarily located within Russia, with additional activities in
Azerbaijan, Kazakhstan, Uzbekistan, the Middle East, Colombia, and Northern and
Western Africa.
- Refining, Marketing and Distribution - which includes refining and
transport operations, marketing and trading of crude oil, natural gas and
refined products.
- Chemicals - which includes processing and trading of petrochemical
products.
Other businesses include banking, finance and other activities. Each of our
three main segments is dependent on the other, with a portion of the revenues of
one segment being a part of the costs of the other. In particular, our Refining,
Marketing and Distribution segment purchases crude oil from our Exploration and
Production segment. As a result of certain factors considered in the "Domestic
crude oil and refined products prices" section on page 11, benchmarking crude
oil market prices in Russia cannot be determined with certainty. Therefore, the
prices set for inter-segment purchases of crude oil reflect a combination of
market factors, primarily international crude oil market prices, transportation
costs, regional market conditions, the cost of refining crude oil and other
factors. Accordingly, an analysis of either of these segments on a stand-alone
basis could give a misleading impression of those segments' underlying financial
position and results of operations. For this reason, we do not analyze either of
our main segments separately in the discussion that follows. However we present
the financial data for each in Note 23 "Segment information" to our consolidated
financial statements.
Executive overview
Recent developments and outlook
The following has been achieved in 2007:
Exploration and production
- 13 new oil and gas fields were brought on line in 2007 (2006: 11 oil
and gas fields).
- In 2007, we prepared the Yuzhnoye Khylchuyu oil field in
Timan-Pechora region for development and we plan to start production in
mid-2008. We estimate that a production volume of 7.5 million tonnes per year
will be reached in 2009.
- In November 2007, we started commercial production on Khauzak gas
field in Uzbekistan. This is a part of Kandym-Khauzak-Shady gas project, which
is jointly implemented with Uzbekneftegaz National Holding Company. Our share of
expenses related to the project is 90%, but our share of revenues is based on
other factors such as the stage of project development, recovery of exploration
and development costs and increases in project profitability. Such factors as
increase in project profitability and recovery of previously incurred expenses
will result in our share in the project revenues decreasing. The field's maximum
annual production capacity of 12 billion cubic meters is expected to be achieved
in 2012.
Refining
- As a result of modernization works performed in 2006, the capacity
of our refinery in Nizhny Novgorod increased to 17.0 million tonnes per year in
2007, or by 12.6%.
- In 2007, we completed the first stage of our upgrade program in the
Odessa refinery, after completion of the second stage of upgrade an annual
capacity will amount 2.8 million tonnes. We plan to put the refinery into
operation in the second quarter of 2008.
Marketing
- During 2007, the Company acquired a network of 376 petrol stations
in 7 European countries from its related party ConocoPhillips.
- In December 2007, we acquired a network of 55 petrol stations and
related infrastructure in Southern region of the Russian Federation.
- The Company aims to respond to changing market conditions on a
timely basis. In 2007, our refined products exports and international sales
increased by 11.7% in terms of volumes, compared to 2006. As a result, in 2007,
we earned additional revenue due to increased refining volumes and continued
high refining margins. The increase in refined product sales in 2007 led to a
decrease of export and international sales of crude oil by 3.9%.
Other achievements in 2007 are described in detail in other parts of this
report.
Changes in the Group structure, acquisition and disposition of assets
In March 2008, a Group company acquired 100% of the share capital of the SNG
Holdings Ltd. Group for $578 million. The purchase agreement provides for an
additional two components of contingent purchase consideration.
- An amount of $100 million payable if an agreed level of proved and
probable hydrocarbon reserves are verified by an independent petroleum engineer
by June 2008.
- An amount of $100 million payable upon approval of the agreed
development program by the Uzbekistan authorities and an agreed minimum
production volume of crude oil is achieved by March 2009.
The SNG Holdings Ltd. Group holds a 100% interest in a production sharing
agreement in oil and gas condensate fields located in the South-Western Gissar
and Ustyurt regions of Uzbekistan. The purpose of the acquisition was to
increase the Group's presence in the Uzbekistan oil and gas sector.
In March 2008, a Group company entered into an agreement with a related party,
whose management and directors include members of the Group's management and
Board of Directors, to acquire a 64.3% interest in OAO "UGK TGK-8" ("TGK-8") for
approximately $2,117 million. The agreement purchase consideration consists of
23.55 million shares of common stock of the Company (at a market value of
approximately $1,620 million) and a cash payment of approximately $497 million.
As of March 31, 2008, a Group company had acquired 29.99% of TGK-8. The
transaction is expected to be finalized in the second quarter of 2008. TGK-8 is
one of the major gas consumers in the Southern Federal District with the annual
consumption reaching 6 billion cubic meters per year. Its power plants are
located in Astrakhan, Volgograd and Rostov regions, Krasnodar and Stavropol
Districts, and the Republic of Dagestan of the Russian Federation. By purchasing
TGK-8 LUKOIL expects significant synergies through natural gas supplies from the
Company's gas fields located in the Northern Caspian and in Astrakhan region,
which will allow the Company to reach efficient gas price. This acquisition is
made in accordance with the Company's plans to develop its electric power
business.
During 2007, the Group acquired 7.65% of the share capital of OAO "LUKOIL-
Nizhegorod-nefteorgsintez" from minority shareholders for $154 million,
increasing the Group's ownership to 96.91%. OAO "LUKOIL-
Nizhegorodnefteorgsintez" is a refinery plant located in European Russia.
In December 2007, a Group company committed to a plan to sell 162 petrol
stations, located in Pennsylvania and the southern New Jersey of USA, previously
acquired from ConocoPhillips in 2004. In February 2008, this company entered
into an agreement to sell these petrol stations to a third party investor for
$138 million, less estimated amounts to extinguish environmental remediation
liabilities of approximately $19 million. The Group will continue to supply
petroleum products to these petrol stations under a 15 year supply contract with
the new owners. The transaction is expected to be finalized in May 2008. As of
December 31, 2007, the Group classified these petrol stations with the carrying
value of $134 million as assets held for sale in the consolidated balance sheet,
additionally the Group had a liability related to assets held for sale with the
carrying value of $14 million included in "Other current liabilities" of the
consolidated balance sheet.
In December 2007, a Group company acquired a distribution network of 55 petrol
stations and storage facilities in the Rostov region, for $56 million. The
acquisition of this distribution network will enable the Company to double
petroleum products marketing output in the region. We expect refined products
output in this region to increase up to 200 thousand tonnes per year, which
represents 12% of the local retail market as a result of this acquisition.
In December 2007, OAO LUKOIL and OAO GAZPROM NEFT established a joint venture,
OOO Oil and Gas Company "Regional Development". The Group owns a 49% stake in
the authorized capital of the joint venture and OAO GAZPROM NEFT has a 51%
stake. The joint venture will be managed on a parity basis and will focus on
acquiring rights for subsurface use, geological survey of subsurface areas,
exploration and production of hydrocarbons, field development, implementation of
infrastructure-related projects, transportation and marketing of produced
hydrocarbon materials.
In June 2007, the Group finalized the acquisition of a 100% interest in
companies owning 376 petrol stations in Europe, including 156 in Belgium and
Luxembourg, 49 in Finland, 44 in the Czech Republic, 30 in Hungary, 83 in Poland
and 14 in Slovakia, for $442 million from ConocoPhillips, its related party. We
intend to re-brand the stations within one year. The stations located in Finland
will be re-branded as Teboil stations. The remaining petrol stations in other
European countries will be re-branded as LUKOIL stations.
In November 2006, a Group company entered into an agreement with Mittal
Investments S.A.R.L. to sell 50% of its interest in Caspian Investment Resources
Ltd. ("Caspian", formerly Nelson Resources Limited), which has exploration and
production operations in western Kazakhstan, for $980 million. This transaction
was completed on April 20, 2007. In addition, Mittal Investments S.A.R.L. paid a
liability in the amount of $175 million, which represented 50% of Caspian's
outstanding debt to Group companies.
In January 2007, a Group company acquired the remaining 34% of the share capital
of OOO Geoilbent for $300 million. The acquisition increased the Group's
ownership in OOO Geoilbent to 100%. Prior to this acquisition the Group
accounted for its investment using the equity method of accounting due to the
fact that the minority shareholder held substantive participating rights. OOO
Geoilbent was an exploration and production company operating in the West
Siberian region of the Russian Federation.
In December 2006, the Group sold its 100% stakes in LUKOIL Shelf Limited and
LUKOIL Overseas Orient Limited, which owned and operated the Astra jack-up rig
for $40 million.
In June 2006, the Group acquired 41.81% of the share capital of OAO
Udmurtnefteproduct for $25 million. OAO Udmurtnefteproduct is a Russian refined
product distribution company, operating more than 100 petrol stations in the
Udmurt Republic of the Russian Federation.
In June 2006, a Group company acquired 100% of the share capital of
Khanty-Mansiysk Oil Corporation ("KMOC") from Marathon Oil Corporation for $847
million (including $249 million repayment of KMOC debt). At the date of
acquisition KMOC owned 95% of the share capital of OAO
Khantymansiyskneftegazgeologia and 100% of the share capital of OAO Paitykh Oil
and OAO Nazymgeodobycha ("KMOC subsidiaries"). By December 31, 2007, a Group
company had acquired the remaining 5% of the share capital of OAO
Khantymansiyskneftegazgeologia for $18 million. This acquisition increased the
Group's ownership in OAO Khantymansiyskneftegazgeologia to 100%. KMOC's
subsidiaries operate oil and gas fields in the West Siberian region of the
Russian Federation.
In May 2006, the Group sold its remaining interest in OAO Bank Petrocommerce for
$33 million.
In December 2005, the Company made a decision to sell ten tankers. A Group
company finalized the sale of eight tankers in May 2006, for a price that
approximated their carrying value of $190 million. The sale of the remaining two
tankers is expected to be finalized in April 2008, for a price that approximates
their carrying value of $70 million. As of December 31, 2007 and 2006, the Group
classified these tankers as assets held for sale in the consolidated balance
sheets.
During the period from November to December 2005, a Group company acquired 51%
of the share capital of OAO Primorieneftegaz for $261 million. Subsequently, in
May 2006, a Group company acquired the remaining 49% of the share capital of OAO
Primorieneftegaz for 4.165 million shares of common stock of the Company (at a
market value of approximately $314 million), thereby increasing the Group's
ownership stake in OAO Primorieneftegaz to 100%. OAO Primorieneftegaz is a
Russian oil and gas exploration company operating in European Russia.
Resource base
Maintaining a stable oil and gas resource base together with providing a high
reserve replacement ratio are key elements of our long-term strategy. Following
our strategy we secured stable hydrocarbon reserves level in 2007. The table
below summarizes the net oil-equivalent proved reserves of consolidated
subsidiaries and our share in equity affiliates:
(millions of BOE) December 31, Changes in 2007 December 31,
2007 2006
Production* Extensions, Revision of
discoveries and previous
changes in estimates
structure
Western Siberia 11,387 (509) 499 163 11,234
Komi Republic 2,293 (95) 90 (16) 2,314
Ural region 2,230 (88) 11 92 2,215
Volga region 1,699 (28) 15 10 1,702
Northern Timan-Pechora 1,172 (15) 9 (122) 1,300
Other in Russia 249 (16) 21 (1) 245
Outside Russia 1,339 (58) (17) 64 1,350
Proved oil and gas 20,369 (809) 628 190 20,360
reserves
Probable oil and gas 12,187 12,340
reserves
Possible oil and gas 6,301 6,022
reserves
* Gas production shown before own consumption.
Increase of proved reserves as a result of the revision of previous estimates
mainly relates to increase in hydrocarbon prices. Nevertheless, in the new
production regions the increase in costs exceeded the rate of crude oil price
increases, which resulted in negative revisions.
Increase of proved hydrocarbon reserves as a result of geological exploration
work amounted to 659 million BOE in 2007.
Acquisitions of licenses for production increased our proved reserves by 26
million BOE.
In 2007, we increased our ownership in Geoilbent up to 100%. This increased our
proved hydrocarbon reserves by 30 million BOE. The sale of our 50% share in
Caspian in 2007 decreased our reserves by 112 million BOE.
Operational highlights
Hydrocarbon production
2007 2006 2005
Daily production of hydrocarbons, including Company's share in 2,178 2,145 1,911
equity affiliates (thousand BOE per day)
- crude oil 1,953 1,926 1,820
- natural and petroleum gas* 225 219 91
Hydrocarbon extraction expenses (US dollar per BOE) 3.58 3.08 2.66
* Gas available for sale (excluding gas produced for our own consumption).
Crude oil production. In 2007, we increased our total daily crude oil production
by 1.4%, compared to 2006 (including the Company's share in equity affiliates)
and produced 713 million barrels, or 96.6 million tonnes.
The following table represents our production in 2007 and 2006 by major regions.
(thousands of tonnes) 2007 Change to 2006 2006
Total, % Change in Organic
structure change
Western Siberia 59,849 2.5 2,520 (1,085) 58,414
Komi Republic 12,432 6.0 - 701 11,731
Ural region 11,183 3.0 - 328 10,855
Volga region 3,017 0.5 - 16 3,001
Northern Timan-Pechora 2,144 14.7 - 274 1,870
Other in Russia 2,110 2.5 - 51 2,059
Crude oil production in Russia 90,735 3.2 2,520 285 87,930
Crude oil produced internationally 3,412 (5.4) (687) 492 3,607
Total crude oil produced by consolidated 94,147 2.9 1,833 777 91,537
subsidiaries
Our share in crude oil production of
equity affiliates:
in Russia 365 (77.6) (1,287) 21 1,631
outside Russia 2,133 3.2 - 66 2,067
Total crude oil production 96,645 1.5 546 864 95,235
The main oil producing region of the Company is Western Siberia. In the oil
fields of Western Siberia the Company produced 63.6% of its crude oil in 2007
(63.8% in 2006).
Delays in putting the Yuzhnoye Khylchuyu oil field in Timan-Pechora region into
production resulted in slower growth in crude oil production in 2007. We expect
to begin production from this field in mid-2008 with approximate planned annual
production of 7.5 million tonnes to be reached from 2009. We are close to
finalizing infrastructure construction works related to this field including
construction of the offshore ice-resistant terminal in Varandey. This oil field
is developed within our strategic partnership with ConocoPhillips.
The organic decline of crude oil production in Western Siberia was compensated
by an increase as a result of structural changes. Structural increase in crude
oil production in Western Siberia was due to acquisition of the remaining
interest in OOO Geoilbent in January 2007, and dismantling by OOO LUKOIL-Western
Siberia and Brazos Petroleum Overseas Limited (a Group affiliated company) their
joint activity at the end of 2006. Before 2007, the crude oil production of
Geoilbent and the joint activity were accounted for using equity method.
Beginning from 2007, all crude oil production of the former joint activity was
transferred to OOO LUKOIL-Western Siberia. In June 2006, we acquired KMOC and
it's subsidiaries, which produced 645 thousand tonnes of crude oil in
January-May 2007. Structural changes in overseas crude oil production reflect
the changes in ownership of Caspian, where the Group reduced its interest from
100% to 50% in the end of April 2007.
In addition to our production, we purchase crude oil in Russia and on
international markets. In Russia we primarily purchase crude oil from affiliated
producing companies and other producers, including vertically integrated oil
companies that lack refining capacity or are unable to export their crude oil.
Then we may either refine or export purchased crude oil. Crude oil purchased on
international markets is used for trading activities, for supplying our overseas
refineries or for processing at third parties refineries. During 2007, we
purchased 1,534 thousand tonnes in order to process at our and at third parties'
refineries, compared to 2,293 thousand tonnes during 2006. The decrease in
external crude oil purchases was due to increased refining of crude oil produced
by the Group to maximize the benefit of high refining margins.
2007 2006 2005
(thousand (thousand (thousand (thousand (thousand (thousand
of of of of of of
barrels) tonnes) barrels) tonnes) barrels) tonnes)
Crude oil purchases in Russia 345 47 13,561 1,850 10,760 1,468
Crude oil purchases 32,802 4,475 37,390 5,101 69,122 9,430
internationally
Total crude oil purchased 33,147 4,522 50,951 6,951 79,882 10,898
In 2007, the volume of crude oil purchased in Russia substantially decreased as
a result of changes in the Group structure. The crude oil purchased in 2006
included transactions with our former 66% equity affiliate OOO Geoilbent. In
January 2007, we acquired the remaining 34% of OOO Geoilbent, thereby increasing
the Group's ownership stake to 100%. The decrease in volume of crude oil
purchased internationally was primarily due to decreased purchases for refining.
Gas production. In 2007, we produced 13,955 million cubic meters of gas
available for sale (including our share in equity affiliates), an increase by
2.5%, compared to 2006.
We reduced production from the Nakhodkinskoe gas field, where we produced 7,719
million cubic meters of natural gas in 2007, compared to 8,348 million cubic
meters in 2006. In June-October 2007, we decreased natural gas supply to OAO
Gazprom from the Nakhodkinskoe gas field due to the warm winter. At the same
time we increased production of petroleum gas in Western Siberia by 395 million
cubic meters, or by 20.2%, compared to 2006 primarily due to a higher level of
petroleum gas utilization. Also in 2007, we began production from the
Shakh-Deniz field in Azerbaijan where our share in gas production totaled 309
million cubic meters, and from the Khauzak gas field in Uzbekistan, where we
produced 136 million cubic meters of natural gas.
In order to ensure continuous supply of natural gas from the Nakhodkinskoe gas
field to market, in October 2003, we signed an agreement with OAO Gazprom. In
accordance with the agreement OAO Gazprom undertakes to purchase the gas at the
Yamburg Compressor Plant and to transport it through the Russian Unified Gas
Supply System. In September 2006, we entered into an additional agreement with
OAO Gazprom, under which OAO Gazprom undertakes to purchase 8 billion cubic
meters of gas annually at a price of 1,059 rubles per 1,000 cubic meters.
Refining, marketing and trading
We operate four refineries located in European Russia and three refineries
located overseas - in Bulgaria, Ukraine and Romania. In August 2005, we closed
the Odessa refinery to commence a wide-scale upgrade. The test run of the Odessa
refinery after the completion of the first stage of the upgrade was held in
October 2007. The second stage is planned to be completed by the end of the
second quarter of 2008. Annual capacity of the Odessa refinery after completion
of the upgrade will be 2.8 million tonnes per year.
Compared to 2006, production at our refineries increased by 6.9%. Russian
refineries increased production by 7.8%. In the first quarter of 2007, our
refinery throughput in Russia was lower than planned by approximately 0.2
million tonnes due to a fire at the Volgograd refinery in March 2007. We
recovered crude oil throughput at the refinery by the end of April 2007, and in
the second quarter of 2007, it reached the same production volume as in the
respective period of 2006. In the first quarter of 2007, we performed a planned
upgrade of our Bulgarian refinery resulting in a slight decrease in output. The
above factor resulted in the production of our overseas refineries increasing
only by 2.8% in 2007, compared to 2006. A significant increase in production
volumes in Russia in 2007, compared to the previous year was primarily due to
the increase in capacity of the Nizhny Novgorod refinery from 15.1 to 17.0
million tonnes per year as a result of our modernization program at this
refinery.
Production of refined products at our refineries in 2006 increased by 3.4%,
compared to 2005. Russian refineries increased production by 6.1%. The
production of overseas refineries decreased by 7.7% as a result of the temporary
shutdown of the Odessa refinery.
The Group is constantly improving the refined products mix at our refineries in
order to produce higher quality and more profitable products. At our Russian
refineries we produced 7,218, 6,542 and 4,671 thousand tonnes of Euro 4 and Euro
5 diesel fuel in 2007, 2006 and 2005, respectively. In 2007 and 2006, our
production of Euro 3 gasoline amounted to 852 and 548 thousand tonnes,
respectively (in 2005 we did not produce Euro 3 gasoline).
Along with our own production of refined products we refined crude oil at third
party refineries. In Russia we refined 3,589 thousand tonnes of crude oil at
third party refineries primarily to supply our network in the Ural region. To
supply our retail networks in Eastern Europe we refined oil at third party
refineries in Belorussia and Serbia. In 2007, we decreased processing of our
crude oil at Belorussian refineries due to a reduction in profitability
resulting from changes in legislation.
Our marketing and trading activities mainly include wholesale and bunkering
operations in Western Europe, South-East Asia, Central America and retail
operations in the USA, Eastern Europe, the Baltic States and other regions. In
2007, we continued to expand these activities in Central Europe. As a result of
this expansion, the total volume of refined products purchased from third
parties for wholesale and to supply retail networks increased to 38,694 thousand
tonnes or $23,883 million in 2007 (compared to 35,928 thousand tonnes or $19,413
million in 2006, and 32,225 thousand tonnes or $15,021 million in 2005).
In Russia we purchase refined products on occasion, primarily to manage supply
chain bottlenecks.
The following table represents volumes of refinery throughput, refined products
produced and purchased.
2007 2006 2005
(thousand barrels per day)
Own refinery throughput 1,044 978 945
Refinery throughput at third parties refineries 93 100 57
Total refinery throughput 1,137 1,078 1,002
(thousand of tonnes)
Refined products produced at the Group refineries in Russia* 40,381 37,459 35,290
Refined products produced at the Group refineries outside Russia 8,438 8,211 8,892
Total refined products produced at the Group refineries 48,819 45,670 44,182
Refined products produced at the third party refineries in Russia 3,270 3,002 1,497
Refined products produced at the third party refineries outside 945 1,586 1,159
Russia
Total refined products produced at the third party refineries 4,215 4,588 2,656
Refined products purchased in Russia 1,543 919 1,394
Refined products purchased internationally 38,745 36,034 32,238
Total refined products purchased 40,288 36,953 33,632
* Excluding production of mini refineries.
Exports of crude oil and refined products from Russia
In 2007, our export of crude oil from Russia was 4.5% less than in 2006. During
2007, we exported 46.5% of our total domestic crude oil production (50.2% in
2006, and 54.4% in 2005). 2.4% of our crude oil produced in Russia was exported
bypassing the trunk oil pipeline system of OAO AK Transneft ("Transneft") (3.0%
in 2006 and 8.7% in 2005). In spite of the overall decrease of our crude oil
export from Russia we continue to increase our export by means of Baltic
Pipeline System ("BPS"). The volume of crude oil, exported using the BPS
(through the Primorsk terminal), increased in 2007 up to 14,022 thousand tonnes
(2006 - 13,662 thousand tonnes, 2005 - 9,713 thousand tonnes).
The volumes of crude oil exported from Russia by our subsidiaries are summarized
as follows:
2007 2006 2005
(thousand of (thousand (thousand of (thousand (thousand of (thousand
barrels) of tonnes) barrels) of tonnes) barrels) of tonnes)
Exports of crude oil using 293,163 39,995 304,034 41,478 282,418 38,529
Transneft export routes
Exports of crude oil bypassing 15,818 2,158 19,461 2,655 53,421 7,288
Transneft
Total crude oil exports 308,981 42,153 323,495 44,133 335,839 45,817
The crude oil exported through our own export infrastructure was 1,857 thousand
tonnes in 2007, 13.6% less than in 2006 due to a decrease in volumes exported
through the Svetly terminal. This reduction was mainly due to optimization of
export routs and a shift of some crude oil volumes from export to refining.
The Group owns and operates the Vysotsk export terminal. In September 2006, we
completed the construction of the Vysotsk terminal and its current capacity can
be expanded up to 15 million tonnes per year. Currently we use the terminal to
export refined products: in 2007, we exported 10,518 thousand tonnes of refined
products through this terminal (in 2006 - 8,423 thousand tonnes, in 2005 - 5,065
thousand tonnes). In the future we expect to use the terminal to export both
crude oil and refined products, depending on market conditions.
In 2007, we exported from Russia 25.1 million tonnes of refined products, an
increase of 22.0%, compared to 2006. We export from Russia primarily diesel
fuel, fuel oil and gasoil. These products account for approximately 85% of our
refined products export volumes.
Main macroeconomic factors affecting our results of operation
Change in the price of crude oil and refined products
The price at which we sell crude oil and refined products is the primary driver
of our revenues. During 2007, the Brent crude oil price fluctuated between $50
and $96 per barrel and reached its peak of $96.03 at the end of December.
In the beginning of the year lower oil prices were caused by warm weather in the
Northern hemisphere and excessive stocks. The oil price has further increased
due to restrictions put on production volumes by OPEC, which led to reduction in
oil stocks, growing oil demand and decline of oil production in some regions,
political instability in the main oil production regions and negative climatic
factors, and weakening of the US dollar.
According to the International Energy Agency (IEA), in 2007, the world demand
for crude oil and, subsequently, refined products increased by 1.4%, compared to
2006, averaging 86.0 million barrels per day. In 2007, based on OPEC data, its
actual daily production amounted to 31.0 million barrels per day, or 1.5% less
than in 2006. This situation can be viewed as an indicator that crude oil prices
may remain relatively high in the medium-term. However due to the speculative
nature of the crude oil price the probability of a price correction remains
high. The depth of the correction would depend on OPEC actions.
Substantially all of the crude oil that we export is Urals blend. The following
table shows the average crude oil and refined product prices for 2007, 2006 and
2005.
2007 Change to 2006 Change to 2005
2006, % 2005, %
(in US dollars per barrel, except for figures in percent)
Brent crude 72.39 11.1 65.16 20.0 54.31
Urals crude (CIF Mediterranean)* 69.38 13.1 61.37 21.1 50.67
Urals crude (CIF Rotterdam)* 69.16 12.9 61.23 22.2 50.12
(in US dollars per metric tonne, except for figures in
percent)
Fuel oil 3.5% (FOB Rotterdam) 339.00 18.2 286.91 24.8 229.92
Diesel fuel (FOB Rotterdam) 634.09 9.7 577.92 14.4 505.01
High-octane gasoline (FOB Rotterdam) 695.97 12.4 619.29 15.9 534.11
Source: Platts.
* The Company sells crude oil on foreign markets on various delivery terms.
Thus, our average realized sale price of oil on international markets differs
from the average prices of Urals blend on Mediterranean and Northern Europe
markets.
Domestic crude oil and refined products prices
Substantially all crude oil produced in Russia is produced by vertically
integrated oil companies such as ours. As a result, most transactions are
between affiliated entities within vertically integrated groups. Thus, there is
no concept of a benchmark domestic market price for crude oil. The price of
crude oil that is produced but not refined or exported by one of the vertically
integrated oil companies is generally determined on a transaction-by-transaction
basis against a background of world market prices, but with no direct reference
or correlation. At any time there may exist significant price differences
between regions for similar quality crude oil as a result of the competition and
economic conditions in those regions. At the same time it should be noted that
in 2006 and 2007 our domestic crude oil sales prices were nearly at the level of
our export net back price.
Domestic prices for refined products are determined to some extent by world
market prices, but they are also directly affected by local demand and
competition.
The table below represents average domestic wholesale prices of refined products
in 2007, 2006 and 2005.
2007 Change from 2006 Change from 2005
2006, % 2005, %
(in US dollars per metric tonne, except for figures in
percent)
Fuel oil 194.19 10.9 175.07 42.9 122.54
Diesel fuel 503.84 6.4 473.44 12.8 419.74
High-octane gasoline (Regular) 631.93 13.0 559.11 14.9 486.71
High-octane gasoline (Premium) 712.81 15.5 617.41 15.9 532.52
Source: Kortes (excluding VAT).
Changes in the US dollar-ruble exchange rate and inflation
A substantial part of our revenues is either denominated in US dollars or is
correlated to some extent with US dollar crude oil prices, while most of our
costs in the Russian Federation are settled in Russian rubles. Therefore, ruble
inflation and movements of exchange rates can significantly affect the results
of our operations. In particular, the real appreciation of the ruble against the
US dollar will generally cause our costs to increase in US dollar terms.
However, an increase of the ruble denominated revenue in Russia in the US dollar
terms reduces this adverse effect.
The following table gives data on inflation in Russia, the change in the
ruble-dollar exchange rate, and the level of real ruble appreciation.
2007 2006 2005
Ruble inflation (CPI), % 11.9 9.1 10.9
Change of the ruble-dollar exchange rate, % 6.8 8.5 (3.7)
Real appreciation of the ruble against the US dollar*,% 20.0 19.3 6.9
Average exchange rate for the period (ruble to US 25.58 27.19 28.29
dollar)
Exchange rate at the end of the period (ruble to US 24.55 26.33 28.78
dollar)
* Devaluation of purchasing power of the US dollar in the Russian Federation is
calculated on the basis of the ruble-dollar exchange rates and the level of
inflation in Russia.
Tax burden
Given the relative size of our activities in Russia, our tax profile is largely
determined by the taxes payable in Russia (based on records maintained under
Russian legislation - not US GAAP). In 2007, 2006 and 2005, the tax charge on
the operations in Russia was approximately 85% of our total tax charge.
In addition to income taxes, we are subject to a number of other taxes in
Russia, many of which are based on revenue or volumetric measures. Other taxes
to which we are subject include:
• mineral extraction tax • social taxes
• excise and export tariffs • VAT
• property tax • other local and regional taxes
The effective rates of total taxes and tariffs (total taxes, including income
taxes, taxes other than on income and excise and export tariffs, divided by
income before taxes and tariffs) for 2007, 2006 and 2005, respectively, were
74%, 77% and 74%. In 2007, tax expenses in Russia were about 52% of the domestic
and export sales revenue of Russian companies of the Group.
The measures that we use for tax planning and management strategies have been
based on our understanding of tax legislation existing at the time of
implementation of these measures. We are subject to tax authority audits on an
ongoing basis, as is normal in the Russian environment, and, at times, the
authorities have attempted to impose significant additional taxes on us. We
believe that we have adequately met and provided for tax liabilities based on
our interpretation of existing tax legislation. However, the relevant
authorities may have differing interpretations and the effects could be
significant.
The following table represents average enacted rates for taxes specific to the
oil industry in Russia for the respective periods.
2007* Change 2006* Change 2005*
to 2006, to 2005,
% %
Export tariffs on crude oil $/tonne 206.70 4.9 197.01 50.8 130.62
Export tariffs on refined products
Light distillates (gasoline), $/tonne 151.59 5.7 143.40 55.4 92.26
middle distillates (jet fuel),
diesel fuel and gasoils
Liquid fuels (fuel oil) $/tonne 81.64 5.7 77.27 46.5 52.73
Excise on refined products
Straight-run gasoline RUR/tonne 2,657.00 - 2,657.00 - -
High-octane gasoline RUR/tonne 3,629.00 - 3,629.00 - 3,629.00
Low-octane gasoline RUR/tonne 2,657.00 - 2,657.00 - 2,657.00
Diesel fuel RUR/tonne 1,080.00 - 1,080.00 - 1,080.00
Motor oils RUR/tonne 2,951.00 - 2,951.00 - 2,951.00
Mineral extraction tax
Crude oil RUR/tonne 2,472.67 9.1 2,265.69 20.8 1,876.26
Natural gas RUR/1,000 m3 147.00 - 147.00 8.9 135.00
* Average values.
Tax rates set in rubles and translated at the average exchange rates for the
respective periods are as follows:
2007* Change to 2006* Change to 2005*
2006, % 2005, %
Excise on refined products
Straight-run gasoline $/tonne 103.88 6.3 97.74 - -
High-octane gasoline $/tonne 141.89 6.3 133.49 4.1 128.29
Low-octane gasoline $/tonne 103.88 6.3 97.74 4.1 93.93
Diesel fuel $/tonne 42.23 6.3 39.73 4.1 38.18
Motor oils $/tonne 115.38 6.3 108.55 4.1 104.33
Mineral extraction tax
Crude oil $/tonne 96.68 16.0 83.34 25.7 66.32
Natural gas $/1,000 m3 5.75 6.3 5.41 13.4 4.77
* Average values.
Changes in the tax rates specific to the oil industry in Russia in 2007,
compared to 2006 were a result of the movements in the Urals crude oil price.
These rates are linked to international crude oil price and change in line with
them. The methods to determine the rates for such taxes are presented below.
Crude oil extraction tax rate. Before December 31, 2006, the crude oil
extraction tax rate was calculated as follows. The base rate is 419 rubles per
metric tonne extracted and it is adjusted depending on the international market
price of Urals blend and the ruble exchange rate. The tax rate is zero when the
average Urals blend international market price for a tax period is less than or
equal to $9.00 per barrel. Each $1.00 per barrel increase in the international
Urals blend price over the threshold ($9.00 per barrel) results in an increase
of the tax rate by $1.61 per tonne extracted (or $0.22 per barrel extracted
using a conversion factor of 7.33).
Effective from January 1, 2007, the crude oil extraction tax rate varies
depending on the development and depletion of a particular oilfield. The tax
rate is zero for extra-heavy crude oil and for crude oil produced in certain
regions of Eastern Siberia, depending on the period and volume of production.
For crude oil produced in other regions the tax rate calculation described above
should be multiplied by a coefficient characterizing the depletion of a
particular oilfield. The coefficient is equal to 1.0 for the oilfields with
depletion below 80%. Each 1% increase of depletion of a particular oilfield
above 80% results in a decrease of the coefficient by 0.035. The minimum value
of the coefficient is 0.3. The depletion level assessment is based on crude oil
production and reserves information reported to the Russian government.
Natural gas extraction tax rate. Mineral extraction tax on natural gas
production is calculated using a flat rate. The current rate of 147 rubles per
thousand of cubic meters of natural gas extracted has been effective since
January 1, 2006.
Crude oil export duty rate is calculated on a progressive scale. The rate is
zero when the average Urals blend international market price is less than or
equal to approximately $15.00 per barrel ($109.50 per metric tonne). If the
Urals blend price is in a layer between $15.00 and $20.00 per barrel ($146.00
per metric tonne), each $1.00 per barrel increase in the Urals blend price over
the layer's lower bound results in an increase of the crude oil export duty rate
by $0.35 per barrel exported. If the Urals blend price is in a layer between
$20.00 and $25.00 per barrel ($182.50 per metric tonne), each $1.00 per barrel
increase in the Urals blend price over the layer's lower bound results in an
increase of the crude oil export duty rate by $0.45 per barrel exported. Each
$1.00 per barrel increase in the Urals blend price over $25.00 per barrel
results in an increase of the crude oil export duty rate by $0.65 per barrel
exported.
The Russian government sets export tariff rates for two-month periods. The
rates in a specific two-month period are based on Urals blend international
market prices in the preceding two months. Thus, the calculation method that
the Russian government employs to determine export tariff rates results in a
two-month gap between movements in crude oil prices and the revision of the
export duty rate based on those crude oil prices.
Export duty rates on refined products are set by the Russian government. The
rate of export duty depends on internal demand for refined products and
international crude oil market conditions.
Crude oil and refined products exported to CIS countries, other than Ukraine,
are not subject to export duties. On January 1, 2007, customs regulations
between Russia and Belorussia were changed. Crude oil exported from Russia to
Belorussia is now subject to export duties. The latest amendments made by
customs authorities set a coefficient of 0.293 to be applied from February 1,
2007 to the regular export duty rate set by the Russian Government for
calculation of export duty on crude oil exports from Russia to Belorussia.
Transportation of crude oil and refined products in Russia
The main Russian crude oil production regions are remote from the main crude oil
and refined products markets. Therefore, access of crude oil production
companies to the markets is dependent on the extent of diversification of
transport infrastructure and access to it. As a result, transportation cost is
an important macroeconomic factor affecting our net income.
Transportation of crude oil produced in Russia to refineries and export
destinations is performed primarily through the trunk oil pipeline system of
state-owned Transneft. Access to the Transneft crude oil export pipeline network
is allocated quarterly, based on recent volumes produced and delivered through
the pipeline and proposed export destinations. The crude oil transported by
Transneft is Urals blend - a mix of crude oils of various qualities, therefore
Russian companies, which produce crude oil of a higher quality, can not obtain
benefits from selling it using Transneft's pipeline. Alternative access to
international markets bypassing Transneft export routes can be obtained through
railroad transport, by tankers, and own export infrastructure of oil producing
companies. Our own export infrastructure includes the Vysotsk terminal in the
Leningrad region, the Varandey terminal in the Nenetsky Autonomous District and
the Svetly terminal in the Kaliningrad region. We use the Varandey terminal to
export crude oil produced by our joint venture with ConocoPhillips located in
Northern Timan-Pechora. The Svetly terminal exports crude oil primarily produced
by OOO LUKOIL-Kaliningradmorneft, our subsidiary operating in the Kaliningrad
region, and refined products.
Transportation of refined products in Russia is performed by railway transport
and pipeline system of OAO AK Transnefteproduct. Russian railway infrastructure
is owned and operated by OAO Russian Railways. Both companies are state-owned.
Besides transportation of refined products OAO Russian Railways provides oil
companies with crude oil transportation services. We transport the major part of
our refined products by railway transport.
As the activities of the above mentioned companies fall under the scope of
natural monopolies, the fundamentals of their tariff policies are defined by the
state authorities to ensure the balance of interests of the state and all
participants in the transportation process. Transportation tariffs of natural
monopolies are set by the Federal Service for Tariffs of the Russian Federation
("FST"). The tariffs are dependent on transport destination, delivery volume,
distance of transportation, and several other factors. Changes in the tariffs
depend on inflation forecasts by the Ministry of Economic Development and Trade
of the Russian Federation, the investment needs of owners of transport
infrastructure, other macroeconomic factors, and compensation of economically
reasonable expenses, incurred by entities of natural monopolies. Tariffs are to
be revised by FST at least annually.
According to the Federal Statistics Service of the Russian Federation, during
2007, transportation tariffs increased as follows: transportation of crude oil
by pipeline - 9.9%, transportation of refined products by pipeline - 17.2%,
transportation by railway - 7.7%. These amounts differ from actual changes in
tariffs for transportation of crude oil and refined products by the Group for
the period considered due to the specifics in the routes and geography of our
supplies from the Russian transportation averages.
Year ended December 31, 2007, compared to years ended December 31, 2006 and
December 31, 2005
Results of operations
The table below details certain income and expense items from our consolidated
statements of income for the periods indicated.
2007 2006 2005
(millions of US dollars)
Revenues
Sales (including excise and export tariffs) 81,891 67,684 55,774
Equity share in income of affiliates 347 425 441
Total revenues 82,238 68,109 56,215
Costs and other deductions
Operating expenses (6,172) (4,652) (3,443)
Cost of purchased crude oil, gas and products (27,982) (22,642) (19,590)
Transportation expenses (4,457) (3,600) (3,371)
Selling, general and administrative expenses (3,207) (2,885) (2,578)
Depreciation, depletion and amortization (2,172) (1,851) (1,315)
Taxes other than income taxes (9,367) (8,075) (6,334)
Excise and export tariffs (15,033) (13,570) (9,931)
Exploration expense (307) (209) (317)
(Loss) gain on disposals and impairments of (123) (148) 52
assets
Income from operating activities 13,418 10,477 9,388
Interest expense (333) (302) (275)
Interest and dividend income 135 111 96
Currency translation gain (loss) 93 169 (134)
Other non-operating expense (240) (118) (44)
Minority interest (55) (80) (121)
Income before income taxes 13,018 10,257 8,910
Current income taxes (3,410) (2,906) (2,301)
Deferred income taxes (97) 133 (166)
Total income tax expense (3,507) (2,773) (2,467)
Net income 9,511 7,484 6,443
Basic earnings per share of common stock (in US 11.48 9.06 7.91
dollars)
Diluted earnings per share of common stock (in US 11.48 9.04 7.79
dollars)
The analysis of the main financial indicators of the financial statements is
provided below.
Sales revenues
Sales breakdown 2007 2006 2005
(millions of US dollars)
Crude oil
Export and sales on international markets other than CIS 18,346 16,859 15,589
Export and sales to CIS 912 790 778
Domestic sales 440 376 120
19,698 18,025 16,487
Refined products
Export and sales on international markets
Wholesale 37,971 30,302 22,923
Retail 9,183 7,157 6,293
Domestic sales
Wholesale 5,862 5,431 4,753
Retail 3,721 2,720 1,972
56,737 45,610 35,941
Petrochemicals
Export and sales on international markets 1,569 1,260 1,134
Domestic sales 733 569 469
2,302 1,829 1,603
Other 3,154 2,220 1,743
Total sales 81,891 67,684 55,774
Sales volumes 2007 2006 2005
Crude oil (thousands of barrels)
Export and sales on international markets other than CIS 268,974 278,972 312,712
Export and sales to CIS 19,879 21,682 23,852
Domestic sales 11,757 13,363 4,926
Crude oil (thousands of tonnes)
Export and sales on international markets other than CIS 36,695 38,059 42,662
Export and sales to CIS 2,712 2,958 3,254
Domestic sales 1,604 1,823 672
41,011 42,840 46,588
Refined products (thousands of tonnes)
Export and sales on international markets
Wholesale 64,394 57,558 49,549
Retail 7,910 7,171 7,117
Domestic sales
Wholesale 13,704 15,155 16,421
Retail 4,853 3,995 3,549
90,861 83,879 76,636
Total sales volume of crude oil and refined products 131,872 126,719 123,224
Realized average sales prices
2007 2006 2005
($/barrel)($/tonne) ($/barrel)($/tonne)($/barrel)($/tonne)
Average realized price
international
Oil (excluding CIS) 68.21 499.96 60.43 442.96 49.85 365.41
Oil (CIS) 45.86 336.15 36.46 267.22 32.63 239.20
Refined products
Wholesale 589.66 526.46 462.61
Retail 1,160.90 998.05 884.30
Average realized price within
Russia
Oil 37.43 274.37 28.16 206.43 24.44 179.15
Refined products
Wholesale 427.74 358.38 289.41
Retail 766.67 680.79 555.80
During 2007, our revenues increased by $14,207 million, or by 21.0%, compared to
2006 (in 2006 by $11,910 million, or by 21.4%, compared to 2005).
The total volume of crude oil and refined products sold was 132 million tonnes,
which represents an increase of 4.1%, compared to 2006. Our revenues from crude
oil sales increased by $1,673 million, or by 9.3%, compared to 2006 (in 2006 by
$1,538 million, or by 9.3%, compared to 2005). Our sales of refined products
increased in 2007 by $11,127 million, or by 24.4%, compared to 2006 (in 2006 by
$9,669 million, or by 26.9%, compared to 2005).
Sales of crude oil and refined products on international markets, including the
CIS, accounted for 84.7% of the total sales volume in 2007 (in 2006 - 83.4%, and
in 2005 - 83.3%).
The increase in sales was principally due to the following:
• increase in hydrocarbon prices
• increase in crude oil refining, resulting from high refining margins
• increase in trading activities
• increase in total volume of crude oil production
Sales of crude oil
2007 vs. 2006
The 9.3% increase in our total crude oil sales from 2006 to 2007 was
attributable primarily to an increase in our international crude oil sales
revenues (excluding CIS). This sales revenue, which accounted for approximately
93.1% of our total crude oil sales revenue in 2007 and 93.5% in 2006, increased
by 8.8% primarily due to an increase in sales prices by 12.9%. At the same time
the total volume of crude oil sales decreased by 3.6%, compared to 2006 as a
result of increased crude oil refining in Russia.
2006 vs. 2005
In 2006, we reduced exports of crude oil from Russia by 1,684 thousand tonnes,
or by 3.7%. However, revenue from crude oil sales on international markets
increased by 7.8%, compared to the previous year. The effect of reduced volumes
of exports from Russia and our crude oil trading activities on international
markets was offset by the growth of crude oil prices.
During 2006, we increased our sales of crude oil on the domestic market,
compared to 2005 by 1,151 thousand tonnes, or by 171.3%, in order to take
advantage of the increased profitability of domestic sales.
Sales of refined products
2007 vs. 2006
In 2007, sales of refined products was 69.3% of our total revenues (68.9% in
terms of volumes sold), compared to 67.3% (66.3% - in terms of volumes) in 2006.
In 2007, the portion of our domestic refined product sales was 14.1% of the
total tonnes sold (in 2006 - 15.2%), and represented 11.7% of our total revenues
(in 2006 - 12.0%). The decrease in our domestic refined products sales as a
percentage of total refined products sales was due to the expansion of our
international activities, including the increase of export from Russia.
The average realized wholesale price of refined products outside Russia
increased by $63.20 per tonne, or by 12.0%, compared to 2006. Wholesale volumes
of refined products sold outside Russia increased by 6,836 thousand tonnes, or
by 11.9%, primarily due to increased volumes of export from Russia. As a result,
our revenue from the wholesale sales of refined products outside Russia
increased by $7,669 million, or by 25.3%.
During 2007, retail sales of refined products outside Russia increased by 739
thousand tonnes, or by 10.3%, compared to 2006. This increase is attributable to
additional sales volumes generated by the 376 petrol stations acquired from
ConocoPhillips in the second quarter of 2007. Refined products sales at those
stations were 769 thousand tonnes in the period June-December 2007. Average
retail prices increased to $1,160.90 per tonne, or by 16.3%. As a result, our
revenue from retail sales increased by $2,026 million, or by 28.3%, compared to
2006. In 2007, revenue from retail sales was 19.5% (in 2006 - 19.1%) of total
refined products sales outside Russia. Our international retail sales include
supplies of refined products to third party retail networks under long-term
contracts with pricing similar to retail pricing.
In 2007, the average domestic wholesale realized price on refined products
increased by $69.36 per tonne, or by 19.4%, compared to 2006. In 2007, the
wholesale of refined products within Russia decreased by 1,451 thousand tonnes,
or by 9.6%, compared to 2006. As a result, our revenue from the wholesale of
refined products on the domestic market increased by 7.9%. Volumes of refined
products, which were not utilized in the domestic wholesale market were directed
to a retail segment or exported from Russia.
In 2007, retail sales within Russia increased by 858 thousand tonnes, or by
21.5%, compared to 2006. Average retail prices increased to $766.67 per tonne,
or by 12.6%. As a result, our revenue from retail sales increased by $1,001
million in 2007, or by 36.8%, compared to 2006. Revenue from retail sales was
38.8% of total refined products sales in Russia in 2007 (in 2006 - 33.4%).
2006 vs. 2005
In 2006, sales of refined products was 67.3% of our total revenues (66.3% in
terms of volumes sold), compared to 64.4% (62.2% - in terms of volumes) in 2005.
In 2006, the portion of our domestic refined product sales was 15.2% of the
total tonnes sold (in 2005 - 16.2%), but represented 12.0% of our total revenues
(in 2005 - 12.0%). The decrease in our domestic refined products sales as a
percentage of total refined products sales was due to the expansion of our
trading activities outside Russia.
In 2006, the average realized wholesale price of refined products outside Russia
increased by $63.85 per tonne, or by 13.8%, compared to 2005. Wholesale volumes
of refined products sold outside Russia increased by 8,009 thousand tonnes, or
by 16.2%, due to increased volumes of refined products trading and exports from
Russia. As a result, our revenue from the wholesale of refined products outside
Russia increased by $7,379 million, or by 32.2%.
In 2006, retail sales of refined products outside Russia were approximately at
the same level as in 2005. Average retail prices increased up to $998.05 per
tonne, or by 12.9% from 2005 to 2006. As a result, our revenue from retail sales
increased by $864 million, or by 13.7% from 2005 to 2006. In 2006, revenue from
retail sales was 19.1% (in 2005 - 21.5%) of total refined products sales outside
Russia.
The wholesale of refined products within Russia in 2006 decreased by 1,266
thousand tonnes, or by 7.7%, compared to 2005. The average domestic realized
price on refined products increased by $68.97 per tonne, or by 23.8%. As a
result, our revenue from the wholesale of refined products on the domestic
market increased by $678 million, or by 14.3%. Volumes of refined products,
which were not utilized in the domestic wholesale market were directed to a
retail segment or exported from Russia.
Retail sales within Russia increased in 2006 by 446 thousand tonnes, or by
12.6%, compared to 2005. Average retail prices increased up to $680.79 per
tonne, or by 22.5%. As a result, our revenue from retail sales increased by
$748 million in 2006, or by 37.9%, compared to 2005. Revenue from retail sales
was 33.4% of total refined products sales in Russia in 2006 (in 2005 - 29.3%).
Sales of petrochemical products
2007 vs. 2006
Revenue from sales of petrochemical products increased in 2007 by $473 million,
or by 25.9%, compared to 2006. This increase in revenue resulted from both price
and volume factors.
2006 vs. 2005
Revenue from sales of petrochemical products increased in 2006 by $226 million,
or by 14.1%, compared to 2005, due to an increase in prices for petrochemical
products.
Sales of other products
Other sales include revenues from sales of gas, gas refined products and other
services provided and goods not related to our primary activities (such as
electricity, heat, transportation, etc.) sold by our production and marketing
companies. Our major purchaser of natural gas produced in the Russian Federation
is OAO Gazprom.
2007 vs. 2006
Other sales increased by $934 million, or by 42.1%, mainly as a result of the
growth in other sales and services provided to third parties, gas and gas
refined products sales both in Russia and abroad. In 2007, sales of natural gas
amounted to $389 million (an increase by 69.1%, compared to 2006). In 2007, we
sold 7.2 billion cubic meters of natural gas to OAO Gazprom at $41.4 per 1,000
cubic meters.
2006 vs. 2005
Other sales increased by $477 million, or by 27.4%, generally as a result of the
growth in gas and gas refined products sales. Sales of natural gas amounted to
$230 million in 2006. In 2006, we sold 7.5 billion cubic meters of natural gas
to OAO Gazprom at $23.6 per 1,000 cubic meters.
Equity share in income of affiliates
The Group has investments in equity method affiliates and corporate joint
ventures. These companies are primarily engaged in crude oil exploration,
production, marketing, refining and distribution operations in the Russian
Federation and crude oil production and marketing in Kazakhstan. Our largest
affiliate is ZAO Turgai-Petroleum, a 50% interest affiliate company developing
the Kumkol oil field in Kazakhstan. In January 2007, we acquired the remaining
interest in OOO Geoilbent, and, at the end of 2006, ceased the joint activity of
OOO LUKOIL-Western Siberia and Brazos Petroleum Overseas Limited (a Group
affiliated company). Before 2007, OOO Geoilbent and the joint activity were
accounted for using equity method.
2007 vs. 2006
Compared to 2006, our share in income of affiliates decreased by $78 million, or
by 18.4%, primarily due to the changes in affiliates' structure.
2006 vs. 2005
Compared to 2005, our share in income of affiliates decreased by $16 million, or
by 3.6%. The Group's share in the net income of ZAO Turgai-Petroleum in 2006 was
$184 million, which represented a decrease of $14 million, compared to 2005.
This decrease in the net income of ZAO Turgai-Petroleum, along with the effect
of changes in our ownership of equity affiliates reduced the overall growth in
the profitability of our Russian oil and gas producing affiliates.
Operating expenses
Operating expenses include the following types of costs:
2007 2006 2005
(millions of US dollars)
Hydrocarbon extraction expenses 2,757 2,312 1,764
Own refining expenses 880 730 644
Refining expenses at third parties refineries 242 230 104
Excise included in processing fee paid to third parties 158 - -
refineries*
Petrochemical expenses 272 247 214
Crude oil transportation to refineries 848 686 448
Other operating expenses 1,271 861 679
6,428 5,066 3,853
Nhange in operating expenses in crude oil and refined (256) (414) (410)
products inventory originated within the Group
Total operating expenses 6,172 4,652 3,443
Cost of purchased crude oil, petroleum and chemical 27,982 22,642 19,590
products
*As a result of recent amendments to the Russian tax legislation, effective
since January 1, 2007, responsibility to pay excises on refined products (except
for straight-run gasoline) was transferred from traders and retailers to
refineries. Before 2007, substantial part of excises on realization of refined
products produced at third parties refineries was paid by the marketing
subsidiaries of the Group and included in "Excise and export tariffs" of our
results of operations. Currently such excises are included into processing fee.
Compared to 2006, operating expenses increased by $1,520 million, or by 32.7%,
which is mainly explained by the growth of hydrocarbon extraction expenses,
other operating expenses and processing and refining costs. Real appreciation of
the ruble against the US dollar is a significant factor affecting our operating
expenses in Russia. In 2007, the real ruble appreciation was 20.0%.
Hydrocarbon extraction expenses
Our extraction expenses include expenditures related to repairs of extraction
equipment, labor costs, expenses on artificial stimulation of reservoirs, fuel
and electricity costs, property insurance of extraction equipment and other
similar costs.
Expenses of the Company's oil and gas production enterprises related to the sale
of services and goods (such as electricity, heat, etc.) that do not relate to
core activities have been excluded from extraction expenses and are included in
other operating costs.
2007 vs. 2006
In 2007, our extraction expenses rose by $445 million, or by 19.2%, compared to
2006. The increase resulted from an increase in hydrocarbon production by our
subsidiaries to 774.6 million BOE, which is an increase of 2.8%, compared to
2006, the effect of the real ruble appreciation, increased expenses for energy
supply, materials and labor. In 2007, extraction expenses included approximately
$45 million of expenses related to changes in the Group structure. Our average
hydrocarbon extraction cost per barrel of oil equivalent increased from $3.08 to
$3.58, or by 16.1%, compared to 2006.
2006 vs. 2005
In 2006, our extraction expenses rose by $548 million, or by 31.1%, compared to
2005. The increase resulted from an increase in hydrocarbon production by our
subsidiaries to 753.8 million BOE, or by 13.3%, compared to 2005, the effect of
the real ruble appreciation, increased expenses of artificial stimulation of
reservoirs and expenses for energy supply and materials. In 2006, extraction
expenses included $95 million of expenses related to crude oil producing
companies acquired in late 2005 and in 2006. Our average hydrocarbon extraction
cost per barrel of oil equivalent increased from $2.66 to $3.08, or by 15.8%,
compared to 2005.
Own refining expenses
2007 vs. 2006
In 2007, refining expenses increased by $150 million, or by 20.5%, compared to
2006.
Refining expenses at our domestic refineries increased by 25.4%, or by $132
million, as a result of increased production volume, the effect of the real
ruble appreciation, and due to large-scale overhauls at the Perm refinery in the
second quarter of 2007.
Refining expenses at our international refineries increased by 8.6%, or by $18
million. This resulted mainly from a general increase in refining costs
including an effect of an appreciation of the exchange rates of Romanian and
Bulgarian currencies, which are tied to Euro, to the US dollar.
2006 vs. 2005
In 2006, refining expenses increased by $86 million, or by 13.4%, compared to
2005.
Refining expenses at our domestic refineries increased by 14.3%, or by $65
million as a result of the effect of the real ruble appreciation and due to
increased production volume.
Refining expenses at our international refineries increased in 2006 by 11.1%, or
by $21 million, compared to 2005. The growth of refining expenses was primarily
due to the growth of high-quality production output at our plant in Bulgaria,
which was partly offset by the reduction of refining expenses at the Odessa
refinery, due to its wide-scale upgrade.
Refining expenses at third parties refineries
Along with our own production of refined products we refined crude oil at third
parties refineries both in Russia and overseas.
2007 vs. 2006
In 2007, refining expenses increased by 5.2%, compared to 2006 as a result of
increased refining costs in Russia, which was partially offset by decreased
refining volumes in Belorussia.
2006 vs. 2005
In 2006, refining expenses at third parties refineries amounted to $230 million,
which is more than twice the prior year, due to an almost doubling of volumes
refined in Russia.
Petrochemical operating expenses
2007 vs. 2006
In 2007, operating expenses of our petrochemical companies increased by $25
million, or by 10.1%, compared to 2006. This was mainly due to increase of
expenses at our Stavrolen petrochemical plant as a result of putting in
operation of polypropylene production facilities.
2006 vs. 2005
Operating expenses of our petrochemical companies increased by $33 million, or
by 15.4%, compared to 2005, mainly as a result of the increased cost of raw
materials and power supply and maintenance activities performed at our Russian
petrochemical plants in the second quarter of 2006.
Crude oil transportation to refineries
2007 vs. 2006
Crude oil transportation to refineries increased in 2007 by $162 million, or by
23.6%, compared to 2006, due to an increase in transportation tariffs and
volumes refined transported.
2006 vs. 2005
Crude oil transportation to refineries increased in 2006 by $238 million, or by
53.1%, compared to 2005, due to an increase in transportation tariffs and
volumes refined transported.
Other operating expenses
Other operating expenses include operating expenses of our gas processing
plants, the costs of other services provided and goods not related to our core
activities (such as electricity, heat, transportation, etc.) sold by our
production and marketing companies, and operating expenses of other non-core
businesses of the Group.
2007 vs. 2006
Other operating expenses increased by $410 million, or by 47.6%, compared to
2006. This was due to a general increase in other sales including growth of
transportation and other services provided by the Group in the international
segment.
2006 vs. 2005
Other operating expenses increased by $182 million, or by 26.8%, compared to
2005. This was due to increase in other services provided.
Change in operating expenses in crude oil and refined products inventory
originated within the Group
This line includes extraction and refining expenses related to crude oil and
refined products produced by the Group during the reporting period, but not sold
to third parties.
Before 2006, such amounts included changes in inventory balances related to
mineral extraction taxes, export tariffs and transportation expenses. Commencing
in the first quarter of 2006, such changes are reflected in the corresponding
income statement lines. Since the Group's management assesses the effect of the
change in this classification on the presentation of the income statement for
the year 2005 as not material, no reclassifications were made to comparatives.
Cost of purchased crude oil, gas and products
2007 vs. 2006
Cost of purchased crude oil, gas and products increased by $5,340 million in
2007, or by 23.6%, compared to 2006, primarily due to an increase in
international refined products trading volumes and prices.
Cost of purchased crude oil, gas and products included the result of hedging of
international crude oil and refined products sales. In 2007, we recognized a
$575 million expense on hedging, compared to an income of $183 million in 2006.
2006 vs. 2005
Cost of purchased crude oil, gas and products increased by $3,052 million in
2006, or by 15.6%, compared to the previous year due to a significant increase
in the volume of refined products trading and increase in market prices for
crude oil and petroleum products. At the same time we saw a decrease in the cost
of purchased crude oil of $1,166 million. The decrease in external crude oil
purchases was due to increased refining of crude oil produced by the Group to
maximize the benefit of high refining margins.
Cost of purchased crude oil, gas and products included the result of hedging of
international crude oil and refined products sales. In 2006, we recognized a
$183 million income on hedging, compared to an expense of $171 million in 2005.
Transportation expenses
2007 vs. 2006
Our transportation expenses increased in 2007 by $857 million, or by 23.8%,
compared to 2006. This was due to an increase in transportation tariffs, the
increased volumes of refined products export from Russia, changes in exports
destinations and an overall increase in sales volumes.
Average transportation tariffs weighted by volumes of the Group's crude oil and
refined products export deliveries to different locations changed in 2007,
compared to the same period of the previous year as follows: crude oil sea
shipping tariffs increased by 11.6%; crude oil pipeline tariffs increased by
13.8%; railway tariffs for refined products transportation increased by 35.1%.
2006 vs. 2005
The increase in the total volume of sales together with the increase in
transportation tariffs led to the increase in our transportation expenses in
2006 by $229 million, or by 6.8%, compared to 2005.
Average transportation tariffs weighted by volumes of the Group's crude oil and
refined products export deliveries to different locations changed in 2006,
compared to the previous year as follows: crude oil sea shipping tariffs
decreased by 15.2%; crude oil pipeline tariffs increased by 21.5%; railway
tariffs for refined products transportation increased by 26.6%.
Selling, general and administrative expenses
Selling, general and administrative expenses include general business expenses,
payroll costs (excluding extraction entities' and refineries' production staff
costs), insurance costs (except for property insurance related to extraction and
refinery equipment), costs of maintenance of social infrastructure, movement in
bad debt provision and other expenses.
2007 vs. 2006
In 2007, our selling, general and administrative expenses increased by $322
million, or by 11.2%, compared to 2006.
The growth was mainly due to real ruble appreciation, expansion of our
activities both in Russia and internationally, indexation of salaries and
increase in information technology expenses.
This was partially offset by the decrease in the cost related to our share-based
management compensation plan. In 2007, such expenses amounted to $125 million,
compared to $280 million in 2006.
Selling, general and administrative expenses in 2007 also included approximately
$69 million of expenses related to the changes in the Group structure.
2006 vs. 2005
In 2006, our selling, general and administrative expenses increased by $307
million, or by 11.9%, compared to 2005.
The increase in selling, general and administrative expenses was a result of the
real ruble appreciation and the general expansion of our operations outside
Russia. These expenses were also affected by an increase in costs related to our
share-based compensation program for management in 2006 ($280 million, compared
to $263 million in 2005).
In 2006, selling, general and administrative expenses also included $87 million
of expenses related to the subsidiaries, that we acquired in late 2005 and in
2006.
Depreciation, depletion and amortization
Depreciation, depletion and amortization expenses include depletion of assets
fundamental to production, depreciation of other productive and non-productive
assets and certain intangible assets.
2007 vs. 2006
Our depreciation, depletion and amortization expenses increased by $321 million,
or by 17.3%, compared to 2006. The increase was a result of the Company's
capital expenditures and the corresponding increase in depreciable assets. This
increase included approximately $36 million related to the changes in the Group
structure.
2006 vs. 2005
Our depreciation, depletion and amortization expenses increased by $536 million,
or by 40.8%, compared to 2005. The increase was a result of the Company's
capital expenditures and the corresponding increase in depreciable assets. The
increase included $198 million of depreciation, depletion and amortization
expenses related to our acquisitions, in late 2005 and in 2006.
Exploration expenses
2007 vs. 2006
During 2007, the amount charged to exploration expense increased by $98 million,
or by 46.9%, compared to 2006. Dry hole costs increased by $52 million up to
$143 million.
In the first half of 2007, we completed assessment of two exploratory wells
drilled in Saudi Arabia. One of the wells was dry, and its cost of $51 million
was charged to expense in 2007. The second well discovered a natural gas
reservoir. Also, in beginning of 2008, we finalized geological evaluation of
another exploratory well drilled in Saudi Arabia, which was found to be dry. Its
cost of $21 million was charged to expense in 2007. Other overseas dry hole
costs amounted to $20 million.
The dry hole costs in Russia amounted to $51 million and primarily related to
Volga, Timan-Pechora and Western Siberia regions.
2006 vs. 2005
During 2006, the amount charged to exploration expense decreased by $108
million, or by 34.1%, compared to 2005. In 2006, dry hole costs amounted to $91
million, primarily related to exploration projects in Egypt ($12 million) and
exploration in Komi and Timan-Pechora in Russia ($53 million). Geological and
geophysical costs, charged to exploration expense in 2006 were incurred
primarily in Russia and Uzbekistan ($78 million and $12 million, respectively).
In 2005, dry hole costs amounted to $170 million. The Group completed drilling
the first exploratory wells of the Yalama (D-222) and Tyub-Karagan exploration
projects (located in Azerbaijan and Kazakhstan, respectively). Both exploratory
wells were dry and the costs of $105 million were charged to expense.
(Loss) gain on disposals and impairments of assets
2007 vs. 2006
Loss on disposals and impairments of assets in 2007 amounted to $123 million,
compared to $148 million in 2006.
The losses include the financial result from disposals of a number of non-core
assets and individually insignificant impairments of non-performing business
units.
2006 vs. 2005
Loss on disposals and impairment of assets in 2006 amounted to $148 million,
compared to a $52 million gain in 2005.
The losses included the financial result from disposals of a number of non-core
assets and individually insignificant impairments of non-performing business
units. In 2006, losses also included the impairment of unproved property in
Azerbaijan of $68 million.
In 2005, we recognized a gain of $152 million on the sale of our 30% interest in
OOO Narianmarneftegaz to ConocoPhillips, a gain of $4 million on the sale of our
38% interest in ZAO Globalstroy-Engineering and a gain of $25 million on the
sale of our interest in ZAO Arktikneft.
Interest expense
2007 vs. 2006
Interest expense increased in 2007 by $31 million, or by 10.3%, compared to 2006
resulting from an overall increase in our indebtedness. At the same time, the
weighted-average interest rate on our long-term indebtedness decreased, compared
to the level of 2006.
2006 vs. 2005
Interest expense in 2006 increased by $27 million, or by 9.8%, compared to 2005.
The growth of interest expense was primarily due to debt service related to a
loan of $1,934 million, which the Group obtained to finance the acquisition of
Caspian and a general increase of our indebtedness. Moreover, in the second
quarter of 2006, the Group and ConocoPhillips reached an agreement to amend the
contractual interest rates related to the financing of our joint venture OOO
Narianmarneftegaz from 0.1% to 6.8-8.2% per annum, which also impacted interest
expense.
Taxes other than income taxes
2007 2006 2005
(millions of US dollars)
In Russia
Mineral extraction taxes 8,482 7,281 5,590
Social security taxes and contributions 385 309 284
Property tax 284 219 210
Other taxes 105 160 162
Total in Russia 9,256 7,969 6,246
International
Social security taxes and contributions 57 47 40
Property tax 29 28 23
Other taxes 25 31 25
Total internationally 111 106 88
Total 9,367 8,075 6,334
2007 vs. 2006
Taxes other than income taxes increased in 2007 by 16.0%, or by $1,292 million,
compared to 2006, due to an increase in mineral extraction tax resulting from an
increase of crude oil extraction tax rate by 16.0%.
2006 vs. 2005
The increase in taxes other than income taxes resulted primarily from a $1,691
million increase in mineral extraction taxes. Other taxes for 2005 included a
$150 million provision accrued in relation to the results of tax audits of the
Group companies for periods prior to 2004 financial year.
Excise and export tariffs
Our excise and export tariffs include taxes on sales of refined products and
export tariffs on the export of crude oil and refined products.
2007 2006 2005
(millions of US dollars)
In Russia
Excise tax and sales taxes on refined products 734 610 654
Export tariffs 10,814 10,114 6,590
Total in Russia 11,548 10,724 7,244
Internationally
Excise tax and sales taxes on refined products 3,468 2,835 2,679
Export tariffs 17 11 8
Total internationally 3,485 2,846 2,687
Total 15,033 13,570 9,931
2007 vs. 2006
Excise and export tariffs increased by $1,463 million, or by 10.8%, compared to
2006. The increase in export tariffs resulted mainly from the increase of tariff
rates. The volume factor of the tariffs' increase due to expansion of refined
products export from Russia was partially offset by reduction of crude oil
export.
The growth in international excises was mainly due to the effect of acquisition
of the European petrol stations from ConocoPhillips, an increase in 2007 of
excise rates in Bulgaria, substantial increase of refined product sales in
Romania, and implementation in May, 2006, of a new sales-tax on export of
refined products in Romania.
2006 vs. 2005
Excise and export tariffs increased by $3,639 million, or by 36.6%, compared to
2005. The increase in export tariff expenses resulted from a growth in export
tariff rates. Because of the two-month lag between the determination of the
crude oil export tariff rate and the period of its application in the fourth
quarter of 2006 we sold crude oil at lower prices while we paid export tariffs
at higher rates. This resulted in approximately $0.4 billion of negative effect
on income before income tax.
Income taxes
2007 vs. 2006
Our total income tax expense increased by $734 million, or by 26.5%, compared to
2006, due to an increase of income before income tax by $2,761 million, or by
26.9%.
Our effective income tax rate in 2007 was 26.9% (in 2006 it was 27.0%), which is
higher than the maximum statutory rate for the Russian Federation (24%). This is
attributable to the fact that some costs incurred during the period are not tax
deductible or only deductible to a certain limit.
2006 vs. 2005
Our total income tax expense increased by $306 million, or by 12.4%, compared to
2005, due to an increase of income before income tax by $1,347 million, or by
15.1%.
Our effective income tax rate in 2006 was 27.0% (in 2005 it was 27.7%).
Reconciliation of net income to EBITDA (earnings before interest, income taxes,
depreciation and amortization)
2007 2006 2005
(millions of US dollars)
Net income 9,511 7,484 6,443
Add back:
Income tax expense 3,507 2,773 2,467
Depreciation and amortization 2,172 1,851 1,315
Interest expense 333 302 275
Interest and dividend income (135) (111) (96)
EBITDA 15,388 12,299 10,404
EBITDA is a non-US GAAP financial measure. EBITDA is defined as net income
before interest, taxes and depreciation and amortization. The Company believes
that EBITDA provides useful information to investors because it is an indicator
of the strength and performance of our business operations, including our
ability to finance capital expenditures, acquisitions and other investments and
our ability to incur and service debt. While depreciation and amortization are
considered as operating costs under US GAAP, these expenses primarily represent
the non-cash current period allocation of costs associated with long-lived
assets acquired or constructed in prior periods. Our EBITDA calculation is
commonly used as a basis for some investors, analysts and credit rating agencies
to evaluate and compare the periodic and future operating performance and value
of companies within the oil and gas industry. EBITDA should not be considered in
isolation as an alternative to net income, operating income or any other measure
of performance under US GAAP. EBITDA does not include our need to replace our
capital equipment over time.
Liquidity and capital resources
2007 2006 2005
(millions of US dollars)
Net cash provided by operating activities 10,881 7,766 6,204
Net cash used in investing activities (9,715) (7,515) (6,225)
Net cash (used in) provided by financing activities (1,098) (1,186) 432
Operating activities
Our primary source of cash flow is funds generated from our operations. During
2007, cash generated by operating activities was $10,881 million, an increase of
40.1%, compared to 2006. In 2007, our operating cash inflows were affected by an
increase of working capital by $1,828 million, compared to January 1, 2007. This
was mainly caused by:
• an increase of $525 million in VAT receivable balances
• a $691 million net increase in trade accounts receivable and payable
• an increase in inventory of $1,148 million, primarily resulting from
increased volumes of refined products held
At the same time, the negative effect from the above mentioned factors was
partly offset by a decrease of $521 million in tax accounts receivable and a $15
million net decrease in other assets and liabilities.
In 2006, our cash flows from operating activities were significantly affected by
an increase in working capital of $1,621 million, as a result of an increase in
inventory, trade and taxes accounts receivable.
Investing activities
An increase in cash used in investing activities resulted from an increase in
capital expenditures by $2,652 million, or by 41.3%, compared to 2006 (for
detailed analysis of the capital expenditures see the next pages). Also, during
2007, the Company paid $255 million for the acquisition of licenses for crude
oil exploration and production for two fields in the Komi Republic.
In 2007, we spent $442 million on acquisition of retail networks in Europe, $154
million on increasing our stake in the Nizhny Novgorod Refinery and $240 million
on numerous acquisitions of medium-sized companies and individually
insignificant increases of our stake in subsidiaries. Acquisitions in 2007 also
included $832 million of advances related to acquisitions of upstream assets in
Uzbekistan (SNG Holdings Ltd.) and future acquisitions of downstream assets in
Russia and abroad.
Cash flows from investing activities include $1,155 million of cash received
from the sale of our 50% interest in Caspian.
In 2006, we spent $1,374 million on acquisitions of interests in other
companies, $1,500 million less, compared to 2005. We paid $847 million for the
acquisition of KMOC, and $300 million as an advance for the acquisition of the
remaining 34% of the share capital of OOO Geoilbent. In 2005, we spent $2,874
million mainly for the acquisitions of Caspian, OAO Primorieneftegaz, Oy Teboil
Ab and Suomen Petrooli Oy, the remaining interest in ZAO SeverTEK, an equity
interest in OOO Geoilbent and increase of our share in LUKOIL Neftochim Bourgas
AD.
Financing activities
In 2007, net movements of short-term and long-term debt generated an inflow of
$616 million. These inflows in 2007 included loans of $672 million received from
ConocoPhillips as its part of financing our joint venture in the Timan-Pechora
region.
In June 2007, a Group company raised $1,000 million by an issue of
non-convertible bonds. $500 million were placed with a maturity of 10 years and
a coupon yield of 6.356% per annum and the remaining bonds were placed with a
maturity of 15 years and a coupon yield of 6.656% per annum. All bonds were
placed at the face value and have a half year coupon period. The amount raised
was used to refinance a significant part of our debt related to the loan of
$1,934 million, which the Group obtained in December 2005 to finance the
acquisition of Caspian. As a result, the peak debt burden, which was to fall in
December 2008, has halved.
In 2006, net movements of short-term and long-term debt generated an inflow of
$715 million, compared to an inflow of $1,132 million in the respective period
of 2005. This inflow included:
• 14 million non-convertible rouble bonds with a face value of 1,000 Russian
rubles each issued in December 2006 ($532 million)
• $530 million of borrowings related to our KMOC acquisition
• $381 million of loans received from ConocoPhillips as its part of
financing our joint venture in the Timan-Pechora region (previously this
loan was accounted for as equity contribution).
During 2007, as a result of settlement of a stock-based compensation plan
employees purchased approximately 8.8 million shares held by the Group as a
treasury stock at the grant price for $129 million and resold approximately 1.5
million shares back to the Group for $134 million.
Also, during 2007, a Group company paid $578 million for the purchase of the
Company's common stock under our capital management program. In 2006, we paid
$782 million for the purchase of the Company's stock under this program.
In 2007, the Company paid $1,230 million in dividends ($1,015 and $800 million
in 2006 and 2005, respectively).
These factors resulted in a net cash outflow from financing activities of $1,098
million in 2007, compared to an outflow of $1,186 million in 2006.
The Group has sufficient borrowing capacity to meet unanticipated cash
requirements. As of December 31, 2007, the Company had available unutilized
short-term credit facilities with a number of banks of $1,916 million.
The Group systematically works at decreasing the level of secured debt, mainly
represented by the pledge of export receivables and fixed assets. As of December
31, 2007, the level of secured debt was approximately 6% of total debt, while as
of December 31, 2006, it was 14%, and as of December 31, 2005, it was 35%.
Credit rating
Standard & Poor's Ratings Services raised in 2007 its long-term corporate credit
rating and all debt ratings on the Company to BBB- from BB+ following review of
the Company's 2006 results, financial policies, and strategic plan.
In 2007, Moody's affirmed the Company's long-term corporate family rating and
long-term issuer rating of Baa2.
In 2007, Fitch Ratings affirmed the Company's long-term issuer default rating of
BBB- and short-term issuer default rating of F3. In the beginning of 2008, Fitch
Ratings changed our outlook from stable to positive.
A rating is not a recommendation to buy, sell or hold securities and may be
subject to revision, suspension or withdrawal at any time by the assigning
rating organization. Similar ratings on the Company and/or on different types
of securities do not necessarily mean the same thing. The ratings do not address
the marketability of any of our securities or their market price. Any change in
the credit ratings of the Company or our securities could adversely affect the
price that a subsequent purchaser will be willing to pay for our securities. We
recommend that you analyze the significance of each rating independently from
any other rating.
Analysis of capital expenditures
2007 2006 2005
(millions of US dollars)
Exploration and production 6,391 4,334 2,487
Russia 871 786 431
International
Total exploration and production 7,262 5,120 2,918
Refining, marketing and distribution 1,177 916 654
Russia 645 559 475
International
Total refining, marketing and distribution 1,822 1,475 1,129
Chemicals 73 121 59
Russia 98 51 18
International
Total chemicals 171 172 77
Other 117 119 53
Total capital expenditures* 9,372 6,886 4,177
Acquisitions of subsidiaries**
Exploration and production 77 1,469 778
Russia 357 91 1,959
International
Total exploration and production 434 1,560 2,737
Refining, marketing and distribution 685 122 27
Russia 511 - 229
International
Total refining, marketing and distribution 1,196 122 256
Other 38 32 -
Less cash acquired (102) (26) (119)
Total acquisitions of subsidiaries 1,566 1,688 2,874
* Including non-cash transactions.
**Including prepayments related to acquisitions of subsidiaries and minority
shareholding interest and non-cash transactions.
During 2007, capital expenditures, including non-cash transactions, amounted to
$9,372 million, $2,486 million more than in the previous year. The growth was
mainly resulted from expenditures in our exploration and production segment,
which increased by $2,142 million, or by 41.8%, compared to 2006. The growth in
exploration and production capital expenditures in new regions amounted to
$1,000 million, due to construction of facilities and development of
infrastructure on our new oil fields. The capital expenditures in traditional
exploration regions of Western Siberia increased by $830 million, substantially,
as a result of an increase in exploratory drilling and investment in pipelines
and machinery. Capital expenditures in European Russia increased by $209
million. In 2007, an increase in the capital expenditures in our overseas
exploration projects (excluding Caspian region) amounted to $103 million and
primarily related to our projects in Kazakhstan, Saudi Arabia and Uzbekistan.
The Company estimates its 2008 capital expenditures in our exploration and
production segment at approximately $7.1 billion, with $1.0 billion of that
outside Russia. Refining, marketing and distribution capital spending is
estimated to be $1.9 billion, with $0.6 billion of that outside Russia.
The table below shows our exploration and production capital expenditures in new
promising oil regions.
2007 2006 2005
(millions of US dollars)
Northern Timan-Pechora 2,357 1,526 673
Yamal 75 135 216
Caspian region* 441 212 259
Total 2,873 1,873 1,148
* Russian and international projects.
Contractual obligations, other contingencies and off balance sheet arrangements
Capital commitments and contractual obligations
The Group owns and operates refineries in Bulgaria (LUKOIL Neftochim Bourgas AD)
and Romania (Petrotel-LUKOIL). As a result of Bulgaria and Romania joined the
European Union in 2007, LUKOIL Neftochim Bourgas AD and Petrotel-LUKOIL are
required to upgrade their refining plants to comply with the requirements of
European Union legislation in relation to the quality of produced petroleum
products and environmental protection. These requirements are stricter than
existed Bulgarian and Romanian legislation. The Group estimates the amount of
future capital commitment required to upgrade LUKOIL Neftochim Bourgas AD and
Petrotel-LUKOIL to be approximately $878 million and $59 million, respectively.
Group companies have commitments under the terms of existing license agreements
in the Russian Federation of $1,561 million over the next 5 years and of $46
million thereafter. Management believes that a significant portion of these
commitments will be fulfilled by the services to be provided by Eurasia Drilling
Company and ZAO Globalstroy-Engineering as discussed below.
In connection with the sale of LUKOIL-Burenie in 2004 the Group signed a five
year contract for drilling services. Under the terms of the contract, drilling
services of $1,211 million and $753 million will be provided by LUKOIL-Burenie
(now Eurasia Drilling Company) during 2008 and 2009, respectively.
The Company has signed a four-year agreement for the provision of construction,
engineering and technical services with ZAO Globalstroy-Engineering. The volume
of these services is based on the Group's capital construction program, which is
re-evaluated on an annual basis. The Group estimates the amount of capital
commitment under this agreement for 2008 to be approximately $706 million.
A Group company has commitment to purchase equipment for modernization of the
petrochemical refinery in Ukraine over the next 2 years. As of December 31,
2007, this commitment was approximately $160 million.
Group companies have commitments for capital expenditure contributions in the
amount of $357 million related to various production sharing agreements over the
next 30 years.
Group companies have investment commitments relating to oil deposits in Iraq of
$495 million to be spent within 3 years from when exploitation becomes possible.
Due to significant changes in the political and economic situation in Iraq the
future of this contract is not clear, however, the Group is actively pursuing
its legal right to this contract in Iraq in alliance with ConocoPhillips.
The following table displays our total contractual obligations and other
commitments:
Millions of dollars Total 2008 2009 2010 2011 2012 After
On balance sheet
Short term debt 2,214 2,214 - - - - -
Long-term bank loans and borrowings 2,391 1,218 204 364 182 138 285
Long-term non-bank loans and 48 11 19 6 7 1 4
borrowings
Long-term loans and borrowings from 1,745 - - - - - 1,745
related parties
6,356% Non-convertible US dollar 500 - - - - - 500
bonds, maturing 2017
6,656% Non-convertible US dollar 500 - - - - - 500
bonds, maturing 2022
7.25% Russian ruble bonds, maturing 244 - 244 - - - -
2009
7.10% Russian ruble bonds, maturing 326 - - - 326 - -
2011
7.40% Russian ruble bonds, maturing 244 - - - - - 244
2013
Capital lease obligations 107 47 35 14 1 5 5
TOTAL 8,319 3,490 502 384 516 144 3,283
Off balance sheet
Capital commitments under oil and gas 1,607 575 473 162 164 187 46
license agreements in Russia*
Operating lease obligations 1,782 500 426 235 155 133 333
Capital commitment in LUKOIL-Neftochim 878 213 297 143 225 - -
Bourgas AD
Capital commitment in LUKOIL-Petrotel 59 32 20 7 - - -
Commitment for modernization of the 160 152 8 - - - -
petrochemical refinery in Ukraine
Capital commitments in PSAs 357 282 27 7 2 1 38
Obligation under contract with Eurasia 1,964 1,211 753 - - - -
Drilling Company
Obligation under contract with ZAO 706 706 - - - - -
Globalstroy-Engineering
* Management believes that a significant portion of these commitments will be
fulfilled by the services to be performed by Eurasia Drilling Company and ZAO
Globalstroy-Engineering.
Off balance sheet arrangements
LUKARCO, an investee recorded under the equity method of accounting has a loan
facility on which $610 million was drawn as of December 31, 2007. Borrowings
under this loan bear interest at LIBOR plus 2.5% per annum, maturing by May 1,
2012. To enhance the credit standing of LUKARCO, the Company guarantees 54% of
the interest payment as well as the repayment of 54% of the loan at maturity. As
of December 31, 2007, the total amount of the Company's guarantee was $348
million, which includes $19 million related to accrued interest on the
outstanding amount. Payments are due if the Company is notified that LUKARCO is
not able to fulfill its obligations at maturity date. The Company's guarantee is
secured by its 54% interest in LUKARCO with the carrying value of $462 million
and $358 million as of December 31, 2007 and 2006, respectively. There are no
material amounts being carried as liabilities for the Group's obligations under
this guarantee.
Commitment Expiration by Period
Millions of dollars Total 2008 2009 2010 2011 2012 After
Guarantees of equity affiliate's 361 131 167 63 - - -
debt
Litigation and claims
On November 27, 2001, Archangel Diamond Corporation ("ADC"), a Canadian diamond
development company, filed a lawsuit in the District Court of Denver, Colorado
against OAO "Arkhangelskgeoldobycha" ("AGD"), a Group company, and the Company
(together the "Defendants"). ADC alleged that the Defendants interfered with the
transfer of a diamond exploration license to Almazny Bereg, a joint venture
between ADC and AGD. ADC claimed total damages of approximately $4.8 billion,
including compensatory damages of $1.2 billion and punitive damages of $3.6
billion. On October 15, 2002, the District Court dismissed the lawsuit for lack
of personal jurisdiction. This ruling was upheld by the Colorado Court of
Appeals on March 25, 2004. On November 21, 2005, the Colorado Supreme Court
affirmed the lower courts' ruling that no specific jurisdiction exists over the
Defendants. By virtue of this finding, AGD (the holder of the diamond
exploration license) was dismissed from the lawsuit. The Supreme Court found,
however, that the trial court made a procedural error by not holding an
evidentiary hearing before making its ruling concerning general jurisdiction
regarding the Company, which is whether the Company had systematic and
continuous contacts in the State of Colorado at the time the lawsuit was filed.
In a modified opinion dated December 19, 2005, the Colorado Supreme Court
remanded the case to the Colorado Court of Appeals (instead of the District
Court) to consider whether the lawsuit should have been dismissed on alternative
grounds (i.e., forum non conveniens). On June 29, 2006, the Colorado Court of
Appeals declined to dismiss the case based on forum non conveniens. The Company
filed a petition for certiorari on August 28, 2006, asking the Colorado Supreme
Court to review this decision. This petition has been rejected. On March 5,
2007, the Colorado Supreme Court remanded the case to the District Court. On
June 11, 2007, the District Court ruled it would conduct an evidentiary hearing
on the issue of whether the Company is subject to general personal jurisdiction
in the State of Colorado. A status conference with the Court is scheduled for
June 13, 2008. Management does not believe that the ultimate resolution of this
matter will have a material adverse effect on the Group's financial condition.
On February 20, 2004, the Stockholm District Court overturned the decision of
the Arbitral Tribunal of the Arbitration Institute of the Stockholm Chamber of
Commerce ("Arbitration Tribunal"), made on June 25, 2001, dismissing ADC's
action against AGD based on lack of jurisdiction. ADC's lawsuit against AGD was
initially filed with the Arbitral Tribunal claiming alleged non-performance
under an agreement between the parties and its obligation to transfer the
diamond exploration license to Almazny Bereg. This lawsuit claimed compensation
of damages amounting to $492 million. In March 2004, AGD filed an appeal against
the Stockholm District Court decision with the Swedish Court of Appeals. On
November 15, 2005, the Swedish Court of Appeals denied AGD's appeal and affirmed
the Stockholm District Court decision. On December 13, 2005, AGD filed an appeal
against the Swedish Court of Appeals decision with the Swedish Supreme Court. On
April 13, 2006, the Swedish Supreme Court denied the application of AGD for
appeal against the Swedish Court of Appeal's decision dated November 15, 2005.
On May 6, 2006, a Notice of Arbitration was received on behalf of ADC. On
December 20, 2006, the first session of the Arbitration Tribunal with
participation of both parties took place in order to define procedural issues
related to the tribunal. As a result of the hearing the Arbitration Tribunal
issued a detailed procedural order setting out the rules and timetable for the
conduct of the arbitration. In May 2007, ADC filed a statement of claim that
requested the Tribunal to require AGD to transfer the diamond exploration
license to Almazny Bereg. On October 22, 2007, AGD submitted a statement of
defense. On December 21, 2007, the Arbitration Tribunal issued a procedural
order on suspension of the arbitration for four months. Management does not
believe that the ultimate resolution of this matter will have a material adverse
effect on the Group's financial condition.
The Group is involved in various other claims and legal proceedings arising in
the normal course of business. While these claims may seek substantial damages
against the Group and are subject to uncertainty inherent in any litigation,
management does not believe that the ultimate resolution of such matters will
have a material adverse impact on the Group's operating results or financial
condition.
Quantitative and qualitative disclosures about market risks
Interest rate risk
We are exposed to changes in interest rates, primarily associated with our
variable rate short-term and long-term borrowings. We do not utilize any
interest rate swaps or other derivatives to hedge against the risk of changes in
interest rates on our variable rate debt. As of December 31, 2007, our
borrowings that are sensitive to changes in interest rates totaled $3,096
million (for details on long-term borrowings please refer to Note 12 "Long-term
debt" of the consolidated financial statement). Utilizing the actual interest
rates in effect and the balance of our variable rate debt as of December 31,
2007, and assuming a 10% change in interest rates and no change in the balance
of debt outstanding, the potential effect on our annual interest expense would
not be material to our results of operations.
The following tables represent principal cash flows and related weighted-average
interest rates by expected maturity times.
Fixed rate borrowings Floating rate borrowings
2007 (millions of US % (millions of US %
dollars) dollars)
2008 132 5.27 2,035 5.28
2009 297 6.65 169 5.91
2010 41 2.87 329 5.60
2011 373 6.59 142 6.25
2012 2 5.00 137 6.40
After 1,250 6.67 284 6.96
Total* 2,095 6.49 3,096 5.60
2006 (millions of US % (millions of US %
dollars) dollars)
2007 91 3.07 1,202 5.94
2008 47 3.54 2,224 6.15
2009 283 6.49 79 7.29
2010 35 2.94 242 6.61
2011 341 6.68 56 7.87
After 233 4.70 157 9.40
Total* 1,030 5.59 3,960 6.29
* Excluding napital lease obligations and loans and borrowings from related
parties.
Foreign currency risk
The countries in which our principal operations are located have been subject to
hyperinflation and during the last 10 years the local currency has been subject
to large devaluations. As a result we are subject to the risk that the local
currency may suffer future devaluation that may subject us to losses, depending
on our net monetary asset position. We currently do not use any formal hedging
arrangements to minimize the effect of these potential losses. Additionally,
because we have operations in a number of other countries we are required to
conduct business in a variety of foreign currencies and, as a result, we are
subject to foreign exchange rate risk on cash flows related to sales, expenses,
financing and investment transactions. The impacts of fluctuations in foreign
currency exchange rates on our geographically diverse operations are varied. We
recognized a net foreign currency translation gain of $93 million in 2007, a
gain of $169 million in 2006 and a loss of $134 million in 2005.
Appreciation of the ruble against the US dollar in 2005-2007 had a negative
impact on our operating profit and cash flows since it lead to an increase of
our ruble costs in US-dollar terms and a decrease in the amount of our export
cash revenue in ruble terms. As mentioned above, a substantial part of our
revenue is denominated in US dollars or, to some extent, linked to oil prices
quoted in US dollars, while a significant part of our costs is ruble
denominated. Should the ruble appreciation against US dollars in 2008 be at a
level of 10% our free cash flows will be significantly affected (taking into
account that other macroeconomic factors will remain constant).
Commodity derivative instruments
The Group participates in certain petroleum products marketing and trading
activity outside of its physical crude oil and petroleum products businesses.
The Group's derivative activity is limited to these marketing and trading
activities and hedging of commodity price risks. Currently this activity
involves the use of futures and swap contracts together with purchase and sale
contracts that qualify as derivative instruments. The Company maintains a system
of controls over these marketing and trading activities that includes policies
covering the authorization, reporting and monitoring of derivative activity.
The Group recognized an expense of $575 million in 2007, an income of $183
million in 2006 and an expense of $171 million in 2005 from the use of
derivative instruments. The fair value of derivative contracts outstanding and
recorded on the consolidated balance sheets was a net liability of $50 million
and a net asset of $43 million as of December 31, 2007 and 2006, respectively (a
net liability of $26 million in 2005).
Critical accounting policies
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to select
appropriate accounting policies and to make estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses. See
Note 2 "Summary of significant accounting policies" to our consolidated
financial statements for descriptions of the Company's major accounting
policies. Certain of these accounting policies involve judgments and
uncertainties to such an extent that there is a reasonable likelihood that
materially different amounts would have been reported under different
conditions, or if different assumptions had been used.
Business combinations
Purchase price allocation
Accounting for the acquisition of a business requires the allocation of the
purchase price to the various assets and liabilities of the acquired business.
For most assets and liabilities, purchase price allocation is accomplished by
recording the asset or liability at its estimated fair value. The most difficult
estimations of individual fair values are those involving property, plant and
equipment and identifiable intangible assets. We use all available information
to make these fair value determinations and, for major business acquisitions,
typically engage an outside appraisal firm to assist in the fair value
determination of the acquired long-lived assets. We have, if necessary, up to
one year after the acquisition closing date to finish these fair value
determinations and finalize the purchase price allocation.
Principles of consolidation
Our consolidated financial statements include the financial position and results
of the Company, controlled subsidiaries of which the Company directly or
indirectly owns more than 50% of the voting interest, unless minority interest
shareholders have substantive participating rights, and variable interest
entities where the Group is determined to be the primary beneficiary. Other
significant investments in companies of which the Company directly or indirectly
owns between 20% and 50% of the voting interest and over which it exercises
significant influence but not control, are accounted for using the equity method
of accounting. Investments in companies of which the Company directly or
indirectly owns more than 50% of the voting interest but where minority interest
shareholders have substantive participating rights are accounted for using the
equity method of accounting. Undivided interests in oil and gas joint ventures
are accounted for using the proportionate consolidation method. Investments in
other companies are recorded at cost.
Revenue recognition
Revenues from sales of crude oil and petroleum products are recognized when
title passes to customers. Revenues include excise on petroleum products sales
and duties on export sales of crude oil and petroleum products.
Revenues from non-cash sales are recognized at the fair market value of the
crude oil and petroleum products sold.
Successful efforts accounting for oil and gas activities
Accounting for oil and gas activities is subject to special accounting rules
that are unique to the oil and gas industry. Property acquisitions, successful
exploratory wells, all development costs and support equipment and facilities
are capitalized. Artificial stimulation and well work-over costs are included
in operating expenses as incurred.
Property acquisition costs
For individually significant undeveloped properties, management periodically
performs impairment test based on exploration and drilling efforts to date. For
undeveloped properties that individually are relatively small, management
exercises judgment and determines a periodic property impairment charge as
required that is reported in loss on disposals and impairments of assets.
Exploratory costs
For exploratory wells, drilling costs are temporarily capitalized, or "suspended
", on the balance sheet, pending a judgmental determination of whether
potentially economic oil and gas reserves have been discovered by the drilling
effort. If a judgment is made that the well did not encounter potentially
economic oil and gas quantities, the well costs are expensed as a dry hole and
are reported in exploration expense. Exploratory wells that are judged to have
discovered potentially economic quantities of oil and gas and that are in areas
where a major capital expenditure would be required before production could
begin, remain capitalized on the balance sheet as long as additional exploratory
appraisal work is under way or firmly planned. There is no periodic impairment
assessment of suspended exploratory well costs. Management continuously monitors
the results of the additional appraisal drilling and seismic work and expenses
the suspended well costs as dry holes when it judges that the potential field
does not warrant further exploratory efforts in the near term.
Other exploratory expenditures, including geological and geophysical costs are
expensed as incurred.
Proved oil and gas reserves
Reserves are estimated using the definitions of reserves prescribed by the US
Society of Petroleum Engineers and the World Petroleum Congress requirements.
Due to the inherent uncertainties and the necessarily limited nature of
reservoir data, estimates of reserves are inherently imprecise, require the
application of judgment and are subject to change as additional information
becomes available. The estimates are made using all available geological and
reservoir data as well as historical production data. Estimates are reviewed
and revised as appropriate. Revisions occur as a result of changes in prices,
costs, fiscal regimes, reservoir performance or a change in the Company's plans.
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas liquids including condensate and natural gas that geological and engineering
data demonstrate with reasonable certainty can be recovered in future years from
known reservoirs under existing economic and operating conditions. Reserves are
considered proved if they can be produced economically as demonstrated by either
actual production or conclusive formation tests. Proved reserves do not include
additional quantities of oil and gas reserves that may result from applying
secondary or tertiary recovery techniques not yet tested and determined to be
economic. The proved reserves include volumes which are recoverable up to and
after license expiry dates. Proved developed reserves are the quantities of
proved reserves expected to be recovered through existing wells with existing
equipment and operating methods.
Management has included within proved reserves significant quantities which the
Group expects to produce after the expiry dates of certain of its current
production licenses in the Russian Federation. These licenses expire between
2011 and 2026, with the most significant expiring between 2011 and 2014.
Management believes the licenses will be extended to produce subsequent to their
current expiry dates. The Group is in the process of extending all of its
production licenses in the Russian Federation. The Group has already extended a
portion of these licenses and expects to extend the remaining licenses for
indefinite periods. To date there have been no unsuccessful license renewal
applications.
Impairment of long-lived assets
Long lived assets, such as oil and gas properties, other property, plant, and
equipment, and purchased intangibles subject to amortization, are assessed for
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset group may not be recoverable. Recoverability of
assets to be held and used is measured by a comparison of the carrying amount of
an asset group to the estimated undiscounted future cash flows expected to be
generated by that group. If the carrying amount of an asset group exceeds its
estimated undiscounted future cash flows, an impairment charge is recognized by
writing down the carrying amount to the estimated fair value of the asset group,
generally determined as discounted future net cash flows. Assets to be disposed
of are separately presented in the balance sheet and reported at the lower of
the carrying amount or fair value less costs to sell, and are no longer
depreciated. The assets and liabilities of a disposed group classified as held
for sale are presented separately in the appropriate asset and liability
sections of the balance sheet.
Deferred income taxes
Deferred income tax assets and liabilities are recognized in respect of future
tax consequences attributable to temporary differences between the carrying
amounts of existing assets and liabilities for the purposes of the consolidated
financial statements and their respective tax bases and in respect of operating
loss and tax credit carryforwards. Deferred income tax assets and liabilities
are measured using enacted tax rates expected to apply to taxable income in the
years in which those temporary differences are expected to reverse and the
assets be recovered and liabilities settled. The effect on deferred income tax
assets and liabilities of a change in tax rates is recognized in the
consolidated statement of income in the reporting period which includes the
enactment date.
The ultimate realization of deferred income tax assets is dependent upon the
generation of future taxable income in the reporting periods in which the
originating expenditure becomes deductible. In assessing the realizability of
deferred income tax assets, management considers whether it is more likely than
not that the deferred income tax assets will be realized. In making this
assessment, management considers the scheduled reversal of deferred income tax
liabilities, projected future taxable income, and tax planning strategies.
Asset retirement obligations
Under various laws, contracts, permits and regulations, the Group has legal
obligations to remove tangible equipment and restore the land or seabed at the
end of operations at production sites. The largest asset retirement obligations
of the Group relate to wells and oil and gas production facilities and
pipelines. In accordance with SFAS No. 143, "Accounting for Asset Retirement
Obligations," the Group records the fair value of liabilities associated with
such obligations when incurred. Estimating the future asset retirement
obligations costs necessary for this accounting calculation involves significant
estimates and judgments by management. Most of these obligations are many years
in the future and the contracts and regulations often have vague descriptions of
what removal practices and criteria will have to be met when the removal event
actually occurs. Asset removal technologies and costs are constantly changing,
as well as political, environmental, safety and public relations considerations.
Contingencies
Certain conditions may exist as of balance sheet dates that may result in
losses, but the impact of which will only be resolved when one or more future
events occur or fail to occur. The Group is required to both determine whether
a loss is probable based on judgment and interpretation of laws and regulations
and determine whether the loss can be reasonably estimated. If our assessment
of a contingency indicates that it is probable that a material loss will arise,
and the amount of the liability can be estimated, then the estimated liability
is accrued and charged to the consolidated statement of income. If our
assessment indicates that a potentially material loss is not probable, but is
only reasonably possible, or is probable but cannot be estimated, then the
nature of the contingent liability is disclosed in the notes to our consolidated
financial statements. Loss contingencies considered remote are generally not
disclosed unless they involve guarantees, in which case the nature of the
guarantee is disclosed. The Company's management continually monitor known and
potential contingent matters and make appropriate charges to the consolidated
statement of income when warranted by circumstance.
Use of derivative instruments
The Group's derivative activity is limited to certain petroleum products
marketing and trading outside of its physical crude oil and petroleum products
businesses and hedging of commodity price risks. Currently this activity
involves the use of futures and swaps contracts together with purchase and sale
contracts that qualify as derivative instruments. The Group accounts for these
activities under the mark-to-market methodology in which the derivatives are
revalued each accounting period. Resulting realized and unrealized gains or
losses are presented in the consolidated statement of income on a net basis.
Unrealized gains and losses are carried as assets or liabilities on the
consolidated balance sheet.
Recent accounting pronouncements
In March 2008, the FASB issued SFAS No. 161, "Disclosures about Derivative
Instruments and Hedging Activities." This Statement improves financial reporting
about derivative instruments and hedging activities by enhanced disclosures of
their effects on entity's financial position, financial performance and cash
flows. SFAS No. 161 is effective for financial statements for fiscal years and
interim periods beginning after November 15, 2008, early application is
encouraged. The Group is required to adopt the provisions of SFAS No. 161 in the
first quarter 2009 and does not expect any material impact on its results of
operations, financial position or cash flows upon adoption.
In December 2007, the FASB issued SFAS No. 141 (Revised), "Business
combinations." This Statement will apply to all transactions in which an entity
obtains control of one or more businesses. SFAS No. 141 (Revised) requires an
entity to recognize the fair value of assets acquired and liabilities assumed in
a business combination; to recognize and measure the goodwill acquired in the
business combination or gain from a bargain purchase and modifies the disclosure
requirements. The Group is required to prospectively adopt the provisions of
SFAS No. 141 (Revised) for business combinations for which the acquisition date
is on or after January 1, 2009. Early adoption of SFAS No. 141 (Revised) is
prohibited.
In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in
Consolidated Financial Statements - an amendment of ARB No. 51." This Statement
will apply to all entities that prepare consolidated financial statements
(except not-for-profit organizations) and will affect those which have an
outstanding noncontrolling interest (or minority interest) in their subsidiaries
or which have to deconsolidate a subsidiary. This Statement changes the
classification of a non-controlling interest; establishing a single method of
accounting for changes in the parent company's ownership interest that does not
result in deconsolidation and requires a parent company to recognize a gain or
loss when a subsidiary is deconsolidated. The Group is required to prospectively
adopt the provisions of SFAS No. 160 in the first quarter 2009, except for the
presentation and disclosure requirements which shall be applied retrospectively.
Early adoption of SFAS No. 160 is prohibited.
In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for
Financial Assets and Financial Liabilities." This Statement expands the
possibility of using fair value measurements and permits enterprises to choose
to measure certain financial assets and financial liabilities at fair value.
Enterprises shall report unrealized gains and losses on items for which the fair
value option has been elected in earnings in each subsequent period. The Group
is required to adopt the provisions of SFAS No. 159 in the first quarter 2008
and does not expect any material impact on its financial statements upon
adoption.
In September 2006, the FASB issued SFAS No. 158, "Employers' Accounting for
Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB
Statements No. 87, 88, 106 and 132(R)." This Statement requires an employer that
sponsors one or more single-employer defined benefit plans to: (a) Recognize the
funded status of a benefit plan in its statement of financial position; (b)
Recognize as a component of other comprehensive income, net of tax, the gains or
losses and prior service costs or credits that arise during the period but are
not recognized as components of net periodic benefit cost; (c) Measure defined
benefit plan assets and obligations as of the date of the employer's fiscal
year-end statement of financial position (with limited exceptions); (d) Disclose
in the notes to financial statements additional information about certain
effects on net periodic benefit cost for the next fiscal year that arise from
delayed recognition of the gains or losses, prior service costs or credits, and
transition asset or obligation. The provisions of this Statement were effective
December 31, 2006, except for the requirement to measure plan assets and benefit
obligations as of the date of the employer's fiscal year-end, which is effective
December 31, 2008. The adoption of the provisions of SFAS No. 158 did not have a
material impact on the Group's results of operations, financial position or cash
flows.
In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements,"
which establishes a single authoritative definition of fair value, sets out a
framework for measuring fair value and requires additional disclosures about
fair value measurements. This Statement does not require any new fair value
measurements but is expected to increase the consistency of those measurements.
The Group is required to adopt the provisions of SFAS No. 157 in the first
quarter 2008 and does not expect any material impact on its financial statements
upon adoption.
In June 2006, the FASB issued FASB Interpretation No. 48, "Accounting for
Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109" (FIN
48). This Interpretation clarifies the accounting for uncertainty in income
taxes recognized in an enterprise's financial statements in accordance with FASB
Statement No. 109, "Accounting for Income Taxes." The Group adopted the
provisions of FIN 48 in the first quarter 2007. The adoption of the provisions
of Interpretation No. 48 did not have a material impact on the Group's results
of operations, financial position or cash flows.
In June 2006, the FASB ratified the consensus reached by the EITF on Issue No.
06-3, "How Taxes Collected from Customers and Remitted to Governmental
Authorities Should Be Presented in the Income Statement (That Is, Gross versus
Net Presentation)." The consensus requires disclosure of either the gross or net
presentation, and any such taxes reported on a gross basis should be disclosed
in the interim and annual financial statements. The Group adopted the provisions
of EITF Issue No. 06-3 in 2006. The adoption of the Issue did not have a
material impact on the Group's financial statements.
In December 2004, the FASB issued SFAS No. 123(R), "Share-Based Payment," which
revises SFAS No. 123 and supersedes Accounting Principles Board (APB) Opinion
No. 25 regarding stock-based employee compensation plans. SFAS No.123(R)
requires liability classified share-based payment awards to employees to be
valued at fair value on the date of grant and as of each reporting date and
expensed over the vesting period. Equity classified share-based payment awards
to employees should be valued at fair value on the date of grant and expensed
over the vesting period. The adoption of the provisions of SFAS No. 123(R)
during 2006 did not have a material impact on the Group's results of operations,
financial position or cash flows.
Forward-looking statements
Certain statements in this document are not historical facts and are "
forward-looking." We may from time to time make written or oral forward-looking
statements in reports to shareholders and in other communications. Examples of
such forward-looking statements include, but are not limited to:
• statements of our plans, objectives or goals, including those related to
products or services;
• statements of future economic performance; and
• statements of assumptions underlying such statements.
Forward looking statements that may be made by us from time to time (but that
are not included in this document) may also include projections or expectations
of revenues, income (or loss), earnings (or loss) per share, dividends, capital
structure or other financial items or ratios. Words such as "believes," "
anticipates," "expects," "estimates," "intends" and "plans" and similar
expressions are intended to identify forward-looking statements but are not the
exclusive means of identifying such statements. By their very nature,
forward-looking statements involve inherent risks and uncertainties, both
general and specific, and risks exist that the predictions, forecasts,
projections and other forward-looking statements will not be achieved. You
should be aware that a number of important factors could cause actual results to
differ materially from the plans, objectives, expectations, estimates and
intentions expressed in such forward-looking statements.
These factors include:
• inflation, interest rate and exchange rate fluctuations;
• the price of oil;
• the effects of, and changes in, Russian government policy;
• the effects of competition in the geographic and business areas in which we
conduct operations;
• the effects of changes in laws, regulations, taxation or accounting standards
or practices;
• our ability to increase market share for our products and control expenses;
• acquisitions or divestitures;
• technological changes; and
• our success at managing the risks of the aforementioned factors.
This list of important factors is not exhaustive. When relying on
forward-looking statements, you should carefully consider the foregoing factors
and other uncertainties and events, especially in light of the political,
economic, social and legal environment in which we operate. Such forward-looking
statements speak only as of the date on which they are made, and, subject to any
continuing obligations under the Listing Rules of the U.K. Listing Authority, we
do not undertake any obligation to update or revise any of them, whether as a
result of new information, future events or otherwise. We do not make any
representation, warranty or prediction that the results anticipated by such
forward-looking statements will be achieved, and such forward-looking statements
represent, in each case, only one of many possible scenarios and should not be
viewed as the most likely or standard scenario.
This information is provided by RNS
The company news service from the London Stock Exchange
END
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