ANNUAL REPORT

GROWTH EFFICIENCY INNOVATION

NATURAL GAS PRODUCER

RUSSIA'S LARGEST INDEPENDENT

OAO NOVATEK ANNUAL REPORT 2012

RUSSIA'S LARGEST INDEPENDENT NATURAL GAS PRODUCER

	Letter to Shareholders 6
	Strategy 11
	Growth. Efficiency. Innovation 12
	Key events 19
	Key indicators 20

01	REVIEW OF OPERATING RESULTS 23
	Licenses and Reserves 23
	Geological Exploration 25
	Field Development 26
	Hydrocarbon Production 27
	Processing 37
	Marketing 39

02	ENVIRONMENTAL AND SOCIAL RESPONSIBILITY 47
	Environmental Protection 47
	Health and Safety 49
	Human Resources 50
	Social Policy and Charity 53

03	MANAGEMENT AND CORPORATE GOVERNANCE 57
	Corporate Governance System 57
	General Meeting of Shareholders 58
	Board of Directors 58
	Board Committees 62
	Management Committee 64
	Remuneration to Members of the Board of Directors and Management Committee 65
	Internal Control and Audit 65
	Share Capital 67
	Dividends 68
	Information Transparency 69

	ADDITIONAL INFORMATION 70
	Major Risk Factors 70
	Information on Members of the Board of Directors and Management Committee 74
	Major Transactions and Interested Party Transactions 82
	IFRS Consolidated Financial Statements 85
	Management's Discussion and Analysis of Financial Condition and Results of Operations 160

	Contact information 202

NOVATEK IS RUSSIA'S LARGEST INDEPENDENT NATURAL GAS PRODUCER AND THE SECOND-LARGEST NATURAL GAS PRODUCER IN RUSSIA

NOVATEK'S MAIN BUSINESSES ARE EXPLORATION AND PRODUCTION, PROCESSING, TRANSPORTATION AND MARKETING OF NATURAL GAS AND LIQUID HYDROCARBONS. THE COMPANY'S PRIMARY PRODUCTION AND PROCESSING ASSETS ARE LOCATED IN THE YAMAL-NENETS AUTONOMOUS REGION (YNAO), ONE OF THE LARGEST GAS PRODUCING REGIONS IN THE WORLD.

BLN BOE OF PROVED HYDROCARBON RESERVES UNDER SEC

57.3 16% 9%

BCM OF NATURAL GAS PRODUCED IN 2012

GLOBALLY AMONG PUBLICLY TRADED COMPANIES BY PROVED NATURAL GAS RESERVES UNDER SEC

OF TOTAL RUSSIAN NATURAL GAS PRODUCTION

GLOBALLY AMONG PUBLICLY TRADED COMPANIES BY NATURAL GAS PRODUCTION VOLUMES

OF TOTAL NATURAL GAS DELIVERIES TO THE DOMESTIC MARKET VIA THE UGSS

FIELDS AND LICENSE AREAS

1. Yurkharovskoye field
1. East-Tarkosalinskoye field 3. Khancheyskoye field
1. Olimpiyskiy license area (Sterkhovoye field)
1. South-Tambeyskoye field
1. Termokarstovoye field
1. West-Yurkharovskoye field
1. North-Khancheyskoye field
1. Yarudeyskoye field
1. Raduzhnoye field
1. New-Yurkharovskiy license area
1. Yumantilskiy license area
1. West-Urengoyskiy license area
1. North-Yubileynoye field
1. North-Russkiy license area 16. North-Russkoye field
1. West-Tazovskiy license area
1. North-Yamsoveyskiy license area
1. Ukrainsko-Yubileynoye field
1. Pilyalkinskiy license area
1. Malo-Yamalskoye field
1. West-Chaselskoye field
1. Beregovoy license area
1. Pyreinoye field
1. Khadyryakhinskiy license area
1. Samburgskiy license area
1. Yevo-Yakhinskoye field
1. Yaro-Yakhinskiy license area
1. North-Chaselskiy license area
1. Salmanovskoye (Utrenneye) field
1. Geofizicheskoye field
1. North-Obskiy license area 33. East-Tambeyskiy license area
1. North-Tasiyskiy license area
1. North-Urengoyskoye field

LETTER TO SHAREHOLDERS

Dear Shareholders,

OUR Core Business continued to develop successfully throughout 2012 in full conformity with the Company's strategic objectives and priorities, with a focus toward a balanced growth on all key performance indicators and the strengthening of our competitive advantages. Achievements in the reporting year, combined with our flexible and innovative approach to business, offer an excellent foundation for the efficient increase of production volumes, enabling us to look into the future with confidence.

Our main competitive advantages are an extensive resource base, which guarantees a steady increase in hydrocarbon production at industry-leading low costs, and our integrated production chain, which helps to maximize risk-adjusted margins and improve the sustainability of our business operations.

During 2012, we increased our proven hydrocarbon reserves under the SEC reserve standards by one-third to approximately 12.4 billion boe and, as at the end of the current reporting year, we ranked among the top four public companies worldwide in terms of proven natural gas reserves. Equally impressive, NOVATEK achieved a record 842% reserve replacement rate in 2012 (three-year reserve replacement rate – 623%) demonstrating the efficacy of our exploration and development program as well as completing another value accretive acquisition in close proximity to our existing operations and infrastructure.

Our hydrocarbon reserve base is concentrated in the resource rich Yamal Nenets Autonomous Region of Russia, which is the world's largest natural gas region with well-developed infrastructure, enabling us to consistently report one of the lowest cost levels in the oil and gas industry. Our reserve replacement costs in 2012 were RR 33.1 (\$1.07) per boe and lifting costs were RR 17.8 (\$0.57) per boe.

A key strategic priority for the Company is the steady and efficient growth of production volumes commensurate with our sustainable field development activities and resource base. At the end of 2012 more than 60% of our proved reserves under the SEC reserve standards were classified as "undeveloped", and our reserve life increased from 25 years to 31 years, providing an excellent base for sustainable production growth in the future. During the year, we increased our gas production by 7% and the production of crude oil and unstable gas condensate by 4%, which is consistent with our operational guidance for the year.

The increase in our proven reserves and production levels was supported by the acquisition in November 2012 of a 49% equity stake in ZAO Nortgas, which holds a production license to develop the North-Urengoyskoye field. The field is located in close proximity to existing NOVATEK production and transportation capacity and has considerable potential for production growth with the planned development of the field's Eastern

OAO NOVATEK 2012

A KEY STRATEGIC PRIORITY FOR THE COMPANY IS THE STEADY AND EFFICIENT GROWTH OF PRODUCTION VOLUMES COMMENSURATE WITH OUR SUSTAINABLE FIELD DEVELOPMENT ACTIVITIES AND RESOURCE BASE. AT THE END OF 2012 MORE THAN 60% OF OUR PROVED RESERVES UNDER THE SEC RESERVE STANDARDS WERE CLASSIFIED AS "UNDEVELOPED", AND OUR RESERVE LIFE INCREASED FROM 25 YEARS TO 31 YEARS, PROVIDING AN EXCELLENT BASE FOR SUSTAINABLE PRODUCTION GROWTH IN THE FUTURE

dome. The Nortgas acquisition complements NOVATEK's existing asset portfolio and will enable us to achieve more ambitious targets for production growth in the medium term.

We continued to invest capital to further develop our existing asset portfolio in 2012 and commissioned new production capacities as scheduled. A fourth complex was launched in the second development phase at the Yurkharovskoye field bringing total production output at the field to its targeted plateau levels, as well as launching the first stage of a booster station to keep production at field's maximum levels. Production of natural gas and gas condensate began at the Samburgskoye field of Sever-Energia during 2012, where the first and second stages of a gas treatment facility were commissioned and transport infrastructure was installed. We also launched a central oil gathering facility at the East Tarkosalinskoye field as part of our development plans to exploit the oil layers on this important field.

We have already worked diligently and constructively in previous years to create an integrated production value chain, with our own processing facilities and diversified distribution channels. Preparations were made in

2012 for the start of construction work to expand processing capacity at the Purovsky gas condensate plant in conjunction with planned increases of unstable gas condensate output from our fields, including purchases from our joint venture partners. We also signed an agreement on strategic cooperation with OAO Russian Railways, ensuring that the expansion of transport infrastructure will keep pace with planned output increases from the Purovsky processing plant.

Construction of main facilities was almost completed in the first phase of the new complex for transshipment and fractionation of gas condensate at the port of Ust-Luga on the Baltic Sea. The complex will allow the Company to enter new markets, expand its customer base and increase sales of higher value added products.

We took a number of important strategic steps in our commercial marketing of natural gas in Russia during 2012. At year-end, we acquired an 82% participation interest in OOO Gazprom mezhregiongaz Kostroma, significantly increasing the volume of our supplies to end-users in the Kostroma region. A number of new long-term contracts were also signed with major end-users, guaranteeing continued growth in the sales volumes of our marketable natural gas. For the first time in our history, we executed delivery contracts for periods of up to 15 years, confirming a high level of confidence in NOVATEK's commercial capabilities among end customers. We also managed to

increase the proportional share of end-users in our total gas volumes sales mix from 55% in 2011 to 69% in 2012, which represents another important marketing achievement as well as providing sales stability in our customer relationships.

We remain bullish on the natural gas markets over the long-term and expect further growth in the share of natural gas in the global energy mix despite sluggish demand growth over the past several years. Our longerterm outlook for natural gas also envisages a greater role for liquefied natural gas, or LNG, in the global supply balance. Development of LNG production and transportation will, to a large extent, be decisive for the future of the global gas market.

The delivery of natural gas to the international market in the form of LNG has a key role in NOVATEK's long-term strategy, allowing us to diversify our markets and efficiently monetize our conventional natural gas reserves on the Yamal Peninsula. In 2012, we continued implementing the Yamal LNG project, which provides for construction of an LNG plant at our South-Tambeyskoye gas condensate field. Progress in the reporting year included the completion of front end engineering design for the field development, LNG plant and port of Sabetta, as well as finalizing of technical specifications and completion of basic design of a new ARC-7 ice-class LNG tanker. Tenders were initiated for engineering, procurement and construction of the LNG plant and for the transportation of LNG.

GROWTH EFFICIENCY INNOVATION

THE DELIVERY OF NATURAL GAS TO THE INTERNATIONAL MARKET IN THE FORM OF LNG HAS A KEY ROLE IN NOVATEK'S LONG-TERM STRATEGY, ALLOWING US TO DIVERSIFY OUR MARKETS AND EFFICIENTLY MONETIZE OUR CONVENTIONAL NATURAL GAS RESERVES ON THE YAMAL PENINSULA. IN 2012, WE CONTINUED IMPLEMENTING THE YAMAL LNG PROJECT, WHICH PROVIDES FOR CONSTRUCTION OF AN LNG PLANT AT OUR SOUTH-TAMBEYSKOYE GAS CONDENSATE FIELD

We also commenced gas trading operations on the international markets.

We continued to report strong financial results in 2012 underpinned by our commitment and focus on cost controls, prudent investment decisions, and commensurate with the growth profile of our operations. Our consolidated IFRS earnings per share increased to RR 22.9, or by 23% compared to the normalized level of 2011, excluding the effects of gains on disposals, and, as a result, the Board of Directors recommended the General Meeting of Shareholders to approve dividends for the reporting year at RR 6.86 per share, which is 14% more than dividends for 2011.

We recognize that the sustainable development of the Company depends on the high standards of social responsibility and our commitment to these principles. We have always been cognizant of our operational footprint to the regional development in the Far North of Russia, where our core production and processing assets are located, and we remain committed to ensure environmental integrity and industrial safety, and caring for our staff and the indigenous peoples of the region. These are fundamental principles, which we will not compromise.

We could not achieve the success we have accomplished without the contribution of every member of our

GROWTH EFFICIENCY INNOVATION

highly professional and well-organized team of employees formed over the years since NOVATEK's foundation. Human capital underscores our solid foundation for the successful implementation of the Company's strategic plans.

On behalf of the Board of Directors and Management, we are pleased to present the Annual Report of NOVATEK for the year 2012, and we would like to thank our shareholders for their unfailing confidence in the Company and our long-term strategic plans. We endeavor to continue investing capital efficiently in the development of our facilities for extraction, processing and transportation of natural gas and liquid hydrocarbons, making best use of the experiences we have gained in the past and using our competitive advantages to create shareholder value in a sustainable manner.

ALEXANDER E. NATALENKO Chairman of the Board of Directors

LEONID V. MIKHELSON Chairman of the Management Committee

MARK A. GYETVAY Chief Financial Officer

STRATEGY

Future development of Company business is associated with further work on expansion of a vertically integrated value chain: from exploration and production of hydrocarbons to the processing of liquid hydrocarbons and sale of products to end-users.

Main strategic priorities of NOVATEK are:

Growth of the resource base and efficient reserve management;
Maintaining sustainable rates of growth of hydrocarbon production;
Maintaining a low-cost structure;
Expansion of processing capacity to maximize vertical integration and develop the hydrocarbon value chain; and
Optimization and expansion of existing marketing channels, and creation of new marketing channels.

The Company has a number of competitive advantages to implement its strategy successfully. These competitive advantages include: size and structure of the resource base; existing infrastructure close to core producing fields; a well-developed customer base for natural gas sales; own facilities for gas condensate processing and exports; and developed marketing channels for liquefied petroleum gases (LPG) and stable gas condensate. NOVATEK's competitiveness is also supported by its high level of operating flexibility and consistent use of the latest technologies in production and business management.

Our commitment to social responsibility and to observing the latest environmental, health and safety standards are integral parts of NOVATEK's development strategy.

* Number of legal entities.

GROWTH EFFICIENCY INNOVATION

GROSS PRODUCTION

Revenues are net of VAT, export duties, excise and fuel taxes. EBITDA and profit are adjusted for gain (loss) on disposal of interests in subsidiaries and joint ventures.

EFFICIENCY

1.1 RESERVE REPLACEMENT COSTS \$/BOE

HIGH QUALITY RESOURCE BASE AND USE OF STATE-OF-THE-ART TECHNOLOGIES

YURKHAROVSKOYE FIELD

RESERVE RECOVERY PER WELL

More than 7 bcm

of gas on average

FLOW RATE

Up to 4.5 mmcm per day

THE DRILLING OF LARGE DIAMETER HORIZONTAL WELLS RESULTS IN HIGHER FLOW RATES AND LOWER LIFTING COSTS

HIGHER RESERVE RECOVERY PER WELL RAISES EFFICIENCY OF THE

DEVELOPMENT COSTS

0.57

\$/BOE LIFTING COSTS 83

TH. BOE PRODUCTION PER EMPLOYEE 0.7

kWh ELECTRICITY CONSUMPTION PER BOE OF PRODUCTION

RR MLN EBITDA PER EMPLOYEE ROACE

EBITDA MARGIN

INNOVATION

1 DRILLING 2

The use of special hydrocarbon-based drilling mud allows to increase drilling speed and results in the high-precision penetration of production horizons. Geosteering technology enables to maximize the length of productive horizontal sections of our wells. Application of these technologies allows to materially increase flow rates.

DRILLING CUTTINGS PROCESSING PLANT

A unique drilling cuttings processing plant at the Yurkharovskoye field enables us to efficiently resolve the drilling cuttings utilization problem, while drilling at the coast of the Gulf of Ob, resulting in material environmental benefits and cost savings due to efficient recycling of hydrocarbon-based drilling mud.

3 4 PRODUCTION WELLS

A typical well casing at the Yurkharovskoye field is up to 245 mm in diameter with the length of horizontal part of the borehole exceeding 1,000 meters, which results in flow rate of up to 4.5 mmcm of gas per day. The use of large diameter and multilateral horizontal wells reduces the total number of wells required to develop the field, thereby minimizing the field's overall capital expenditures.

TURBO-EXPANDERS

Turbo-expanders operating at our Yurkharovskoye field allow to materially increase the efficiency of gas treatment operations due to much lower electricity consumption and full compliance with quality requirements to marketable gas.

5 6 METHANOL PRODUCTION FACILITY

Methanol is an integral element of natural gas and gas condensate production process allowing to avoid hydrate formation. A unique methanol production facility at our Yurkharovskoye field eliminated the need to purchase and transport methanol to the field, thus decreasing our lifting costs and minimizing potential environmental risks.

ALTERNATIVE ENERGY SOURCES

Solar panels and wind generators provide the necessary electricity to operate the telemechanic system and valves of the condensate pipeline connecting our Yurkharovskoye field with the Purovsky Plant therefore eliminating the need to build a costly high voltage power transmission line along the entire pipeline route and reducing pipeline construction time.

The LPG dehydration unit at our Purovsky Plant is the first of its kind to be constructed and utilized in Russia, which allows us to produce LPG to the highest quality requirements, including international standards for export purposes.

NOVATEK was the first in Russia to introduce "On Spot" loading system at its Purovsky Plant to load stable gas condensate into rail tank cars. This loading system ensures the fastest loading possible (compared with gallery-type loading systems) while minimizing environmental risks.

OF STABLE GAS CONDENSATE DELIVERED MT

RUSSIA'S LARGEST INDEPENDENT NATURAL GAS PRODUCER

KEY EVENTS

01

Launch of the fourth stage of Phase Two development at the Yurkharovskoye field, bringing total production at the field to its target plateau. Commissioning of the first stage booster compressor station at the field.

02

Start of the first and second phases of commercial production at the Samburgskoye field, which is being developed by the joint venture, OOO SeverEnergia.

03

Acquisition of a 49% equity stake in ZAO Nortgas, which owns a hydrocarbon production license for the North-Urengoyskoye field.

04

Acquisition of an 82% interest in OOO Gazprom mezhregiongas Kostroma, which supplies gas to a broad range of customers in Kostroma region.

GROWTH EFFICIENCY INNOVATION

05

Start of construction work on the port of Sabetta, which will be the key transport infrastructure link in the Yamal LNG project.

06

Signing of gas supply agreements with end-users, including 15-year agreements with the Russian subsidiaries of E.ON and Fortum, a 10.5-year agreement with MMK, contracts with Mechel Group companies for 10 years and longer, a 5-year contract with OAO Severstal and a 3-year contract with OAO Mosenergo.

07

Successful placement of Eurobonds with total nominal value of \$1 billion and 10-year maturity. Issue of Russian rouble bonds with total nominal value of RR 20 million and 3-year maturity.

08

Agreement on strategic partnership up to 2020 with OAO Russian Railways, providing for expansion of railway infrastructure to ensure guaranteed transportation of products from the Purovsky Plant.

09

Launch of the central oil treatment facility at the East Tarkosalinskoye field.

GROWTH EFFICIENCY INNOVATION

KEY INDICATORS

	UNITS	2011	2012	CHANGE
FINANCIAL INDICATORS
Total revenues(1)	RR mln	175,273	210,973	20.4%
Normalized profit from operations(2)	RR mln	78,660	85,394	8.6%
Normalized EBITDA(2)	RR mln	85,401	95,166	11.4%
Normalized profit attributable to shareholders of OAO NOVATEK(2)	RR mln	56,707	69,518	22.6%
Normalized earnings per share(2)	RR	18.69	22.91	22.6%
Net cash provided by operating activities	RR mln	71,907	75,825	5.4%
Capital expenditures	RR mln	31,161	43,554	39.8%
Free cash flow	RR mln	40,746	32,271	(20.8)%
Net debt	RR mln	71,647	114,067	59.2%
Total debt to equity	Х	0.40	0.45	-

OPERATING INDICATORS
Proved natural gas reserves (SEC)	bcm	1,321	1,758	33.1%
Proved liquid hydrocarbon reserves (SEC)	mmt	91	106	16.5%
Total hydrocarbon reserves (SEC)	mmboe	9,393	12,394	31.9%
Gross production of natural gas	bcm	53.54	57.32	7.1%
Gross production of liquid hydrocarbons	mt	4,124	4,287	4.0%

POSITIONS IN THE RUSSIAN GAS INDUSTRY
Share in natural gas production	%	8.0%	8.8%	0.8 p.p.
Share in gas deliveries to the domestic market via the UGSS	%	14.8%	16.3%	1.5 p.p.

(1) Net of VAT, export duties, excise and fuel taxes.

(2) Adjusted for gain (loss) on disposal of interests in subsidiaries.

Financial data is in accordance with the consolidated IFRS financial statements. Data on reserves and production include subsidiaries and share in joint ventures.

PROVED NATURAL GAS RESERVES (SEC), BCM

GROSS NATURAL GAS PRODUCTION, BCM

EBITDA*, RR BLN

* EBITDA is adjusted for the gain (loss) on disposal of interests in subsidiaries.

TOTAL PROVED HYDROCARBON RESERVES (SEC), MMBOE

GROSS LIQUIDS PRODUCTION, MMT

PROFIT ATTRIBUTABLE TO SHAREHOLDERS OF OAO NOVATEK*, RR BLN

* Profit is adjusted for the gain (loss) on disposal of interests in subsidiaries.

REPLACEMENT RATIO IN 2012 %

RUSSIA'S LARGEST INDEPENDENT NATURAL GAS PRODUCER

01 REVIEW OF OPERATING RESULTS

THE FOURTH STAGE OF PHASE TWO DEVELOPMENT AT THE YURKHAROVSKOYE FIELD, OUR LARGEST PRODUCING FIELD, WAS COMMISSIONED IN OCTOBER 2012, BRINGING THE FIELD TO ITS PLANNED ANNUAL PRODUCTION PLATEAU OF 36.5 BCM OF NATURAL GAS

LICENSES AND RESERVES

NOVATEK's fields and license areas are located in the YNAO of the Russian Federation, which is the world's largest natural gas producing region and accounts for approximately 17% of global natural gas production and 84% of Russian natural gas production. The concentration of the Company's producing and prospective fields, license areas and processing facilities in this region combined with the Region's overall oil and gas infrastructure have allowed NOVATEK to minimize the risks associated with developing its assets and expanding its resource base. The Company has many years of experience working in the YNAO, which has enabled it to effectively capitalize on the growth opportunities resident there to increase shareholder value.

Exploration and production of hydrocarbons in Russia is subject to licensing. As of 31 December 2012, our subsidiaries and joint ventures held 35 licenses for fields and license areas, of which 30 are classified as either production or combined exploration

and production licenses and five are classified as exploration licenses. The duration of licenses for our core fields exceeds 20 years: the license for the Yurkharovskoye field is valid until 2034, the East-Tarkosalinskoye field expires in 2043, and the South-Tambeyskoye field in 2045. NO-VATEK is strictly observing all of its license obligations pursuant to current Russian legislation, and carries out continuous monitoring of license tenders in order to expand its resource base in strategically important regions.

The Company's reserves are appraised on an annual basis by independent petroleum engineers, "DeGolyer and MacNaughton" ("D&M") under the SEC and PRMS reserves reporting standards. Most of the Company's reserves are located onshore or can be developed from onshore locations and are attributed to the conventional categories (capable of being exploited using conventional technologies, in contrast to unconventional gas deposits such as shale gas).

As of 31 December 2012, NOVATEK's SEC proved reserves totaled 12,394 mmboe, based on our equity ownership interest in

OF PROVED HYDROCARBON RESERVES ADDED IN 2012 (INCLUDING PRODUCTION) BLN BOE 3.4

the respective fields, representing a 32% increase compared to proved reserve volumes as of the end of 2011. In 2012, we added 3,405 mmboe of proved reserves under the SEC reserves reporting standards, inclusive of 2012 production, and recorded a more than eight-fold (842%) reserve replacement rate (874% for natural gas). Total proved reserves of natural gas increased to 1,758 bcm or by 493 bcm, inclusive of 2012 production. At year-end 2012, the Company's reserve to production ratio (or R/P ratio) increased from 25 years in 2011 to 31 years.

Under the PRMS reserves reporting methodology, the Company's total proved reserves increased by 4,665 mmboe, inclusive of 2012 production, and aggregated 15,597 mmboe. Total proved plus probable reserves (2P reserves) increased by 45% to 22,355 mmboe, including an increase of natural gas reserves by 1,054 bcm, inclusive of 2012 production, to 3,106 bcm.

The increase in all of our reserve categories under international reserve reporting standards was due to successful exploration at the Company's fields, ongoing production drilling, the inclusion of Salmanovskoye (Utrennee) and Geofizicheskoye fields acquired in 2011 into the reserve appraisal (the reserves of these two fields increased substantially in 2012 due do exploration

works conducted during the year), as well as the acquisition of an equity stake in ZAO Nortgas, which holds the license for the North-Urengoyskoye field.

As of 31 December 2012, NOVATEK's total recoverable reserves under the Russian reserve classification ABC1 + C2 totaled 4,398 bcm of natural gas and 523 mmt of liquid hydrocarbons, based on our equity ownership interest in the respective fields. In 2012, these reserves increased by 400 bcm of gas and 28 mmt of liquid hydrocarbons, inclusive of 2012 production. The growth was due to successful exploration works, which among other results allowed us to substantially increase reserves at the Salmanovskoye (Utrenneye) and Geofizicheskoye fields, as well as our acquisition of the equity stake in ZAO Nortgas.

NOVATEK continued to deliver low cost reserve growth in 2012 through strategically investing capital in development and exploration activities as well as strategic acquisitions, which enabled the Company to maintain its position as one of the lowest cost producers in the global oil and gas industry. The Company's total 2012 reserve replacement costs were RR 33.1 per boe (\$1.07 per boe)(1) while our three-year and five-year reserve replacement costs amounted to RR 41.5 per boe (\$1.36 per boe) and RR 34.2 per boe (\$1.14 per boe), respectively.

ANNUAL REPORT OAO NOVATEK 2012

⁽¹⁾ At an average exchange rate of RR 31.09 per USD.

Exploration work

	UNITS	2011	2012	CHANGE, %
2D seismic	linear km	376	7,001	1,762%
Subsidiaries	linear km	91	7,001	7,593%
Joint Ventures	linear km	285	0	(100)%
3D seismic	sq. km	1,689	2,799	66%
Subsidiaries	sq. km	899	2,258	151%
Joint Ventures	sq. km	790	541	(32)%
Exploration drilling	th. m	41.3	36.2	(12)%
Subsidiaries	th. m	20.8	26.8	29%
Joint Ventures	th. m	20.5	9.4	(54)%

GEOLOGICAL EXPLORATION

Exploration drilling totaled 36.2 thousand meters in 2012, eight prospecting and exploration wells were completed leading to discovery of five new deposits and a better understanding of the geology of previously discovered deposits.

NOVATEK aims to expand its resource base through geological exploration at fields and license areas not only in close proximity to existing transportation and production infrastructure, but also in new potentially prospective hydrocarbon areas. The Company ensures the efficiency of geological exploration work by deploying state-of-the-art technologies and relying on the experience and expertise of the specialists in its geology department, and the Company's Scientific and Technical Center located in Tyumen.

The Company uses a systematic approach to exploration and development of its fields and license areas, beginning with the collection and interpretation of seismic data to the creation of dynamic field models for the placement of exploration and production wells. We employ modern geological and hydrodynamic modeling as well as new well drilling and completion techniques to maximize the ultimate recovery of hydrocarbons in a cost effective manner.

In 2012, full-scale exploration work began at our fields located on the Gydan Peninsula and offshore license areas in the Gulf of Ob, which were acquired in 2011. Exploration work activities also continued at fields and license areas in the Nadym-Pur-Taz region, including the Yurkharovskoye, West-Yurkharovskoye, North-Khancheyskoye and Yarudeyskoe fields and the Khancheyskiy, Olimpiyskiy, New-Yurkharovskiy and North-Russkiy license areas. The exploration activities at these fields targeted gas condensate and crude oil bearing Lower Cretaceous (including Achimov) and Jurassic deposits at subsurface depths of between 2,000 to 4,400 meters. We also continued exploration work at the South-Tambeyskoye field on the Yamal Peninsula.

In 2012, NOVATEK completed approximately 7,000 linear kilometers of two-dimensional (2D) seismic and 2,799 square km of three-dimensional (3D) seismic, including seismic activities run at our joint ventures. The major growth in seismic activities as compared to 2011 was due primarily to 2D seismic work activities in the Gulf of Ob and 3D work activities on the Gydan Peninsula. Exploration drilling totaled 36.2 thousand meters in 2012, eight prospecting and exploration wells were completed leading to discovery of five new deposits and a better understanding of the geology of previously discovered deposits.

As a result of exploration works, production drilling and the re-appraisal of reserves (excluding the effect from the acquisition of a stake in ZAO Nortgas), our recoverable natural gas reserves under the Russian reserve classification ABC1 + C2 increased by 218 bcm. Most of the recoverable reserve growth was at the Geofizicheskoye, Khancheyskoye, North-Khancheyskoye, Yarudeyskoe, Pyreinoye, Beregovoye, Samburgskoye, Urengoyskoye and Yaro-Yakhinskoye fields.

26 GROWTH ANNUAL REPORT OAO NOVATEK 2012

EFFICIENCY INNOVATION

FIELD DEVELOPMENT

Two phases of the Samburgskoye field with total annual capacity of 4.6 bcm of gas and more than 600 thousand tons of gas condensate were launched in 2012, being the first field to start commercial production at our SeverEnergia joint venture.

During 2012, NOVATEK's subsidiaries invested RR 32.0 billion in the development and construction at our producing and prospective fields as part of our capital investment program in order to achieve sustainable hydrocarbon production growth.

The fourth stage of Phase Two development at the Yurkharovskoye field, our largest producing field, was commissioned in October 2012, bringing the field to its planned annual production plateau of 36.5 bcm of natural gas. The first stage of a booster compressor station was also brought into operation and will enable maximum levels of gas production to be maintained at the field.

Two phases of the Samburgskoye field with total annual capacity of 4.6 bcm of gas and more than 600 thousand tons of gas condensate were launched in 2012, being the

first field to start commercial production at our SeverEnergia joint venture.

We also finalized the construction of a central oil treatment facility at the East-Tarkosalinskoye field, where we began to successfully exploit the field's oil deposits. The new facility will allow us to substantially increase crude oil production at the field.

Production drilling in 2012, including joint ventures, amounted to 245.2 thousand meters, which is 133% more than the meters drilled in 2011. A total of 18 natural gas and 24 oil wells were completed, including six wells at the Yurkharovskoye field with average initial flow rate of 2.2 mmcm of natural gas per day. A new record was set for the wellbore length at the Yurkharovskoye field following the completion of a 7,100-meter well with a horizontal section of 1,200 meters.

Gross hydrocarbon production*

	UNITS	2011	2012	CHANGE
Gas	bcm	53.54	57.32	7.1%
	mmboe	350.1	374.9
Liquid hydrocarbons	mt	4,124	4,287	4.0%
	mmboe	34.6	35.9
Total production	mmboe	384.7	410.8	6.8%

* Including share in production by joint ventures.

HYDROCARBON PRODUCTION

Gross natural gas production increased mainly due to organic growth at the Yurkharovskoye and East-Tarkosalinskoye fields, production start-up at the Samburgskoye field, and the acquisition in November 2012 of an equity stake in ZAO Nortgas, which is developing the North-Urengoyskoye field.

NOVATEK's 2012 gross production from all fields (including the Company's share in production of joint ventures) amounted to 411 mmboe (405 mmboe of sales production), representing an increase of 6.8% over the prior year.

In 2012, total gross production of natural gas amounted to 57.3 bcm (sales production – 56.5 bcm), representing 91% of our total hydrocarbon output. The share of gas produced from the Valanginian layers (or "wet gas") in proportion to total gas production was 72%. Gross natural gas production increased by 7.1% or by 3.8 bcm, as compared to 2011 volumes, mainly due to organic growth at the Yurkharovskoye and East-Tarkosalinskoye fields, production start-up at the Samburgskoye field, and the acquisition in November 2012 of an equity stake in ZAO Nortgas, which is developing the North-Urengoyskoye field.

The Yurkharovskoye field accounted for 55% of total gas production growth due to drilling of new wells and the expansion of field infrastructure. The East-Tarkosalinskoye field contributed about 19% of production growth due to side-tracking activities and an increase in production of associated gas, while the Samburgskoye field, launched in April 2012, contributed approximately 12%. The Nortgas acquisition contributed 5% of growth in our production profile from the date of acquisition to year-end.

Gross production of liquid hydrocarbons totaled 4.29 mmt (sales production – 4.27 mmt), of which 88% was unstable de-ethanized gas condensate and 12% of crude oil. Gross production of liquids increased by 4.0% or 163 thousand tons as compared with 2011 mainly due to increased volumes of crude oil production at the East-Tarkosalinskoye field, where the central oil treatment facility was launched in 2012. Our total crude oil production increased by 85.3% year-on-year.

We continued to achieve some of the lowest lifting costs in the industry (expenses directly related to the extraction and processing of natural gas, gas condensate and crude oil from the reservoir). Company lifting costs were RR 17.8 (\$0.57) per boe in 2012.

Main Producing Fields

In 2012, sales production of hydrocarbons was carried out at nine fields and license areas of which, our three core fields – Yurkharovskoye, East-Tarkosalinskoye and Khancheyskoye – accounted for approximately 90% of total sales production. All of the fields are located in close proximity to the Unified Gas Supply System (UGSS), the world's largest gas transporting infrastructure. 28 GROWTH ANNUAL REPORT OAO NOVATEK 2012

EFFICIENCY INNOVATION

PRODUCTION DRILLING AT THE YURKHAROVSKOYE FIELD

Yurkharovskoye field

The Yurkharovskoye oil and gas condensate field is the main producing asset of NOVATEK, and, as of the end of 2012, the field accounted for approximately 25% of the Company's proved natural gas reserves to SEC standards and 54% of proved developed SEC reserves. In 2012, the field contributed more than 60% of our sales natural gas production and 63% of liquids production. The license for the field is valid until 2034.

The field was discovered in 1970 and is located within the polar circle on the southeast shore of the Tazov peninsula. The field's western part lies on the Tazov peninsula, while the central and eastern parts are situated offshore in the Tazov Gulf. The offshore part of the field is being developed from onshore locations using horizontal wells.

Proved SEC reserves as at the end of 2012 were 436.5 bcm of natural gas and 23.2 mmt of liquid hydrocarbons. Most of the gas reserves are contained in Valanginian layers and the productive layers are located over a small geographical area, which we believe enhances the efficiency of reserves development and exploitation in terms of both capital expenditures and operating costs.

SALES PRODUCTION OF NATURAL GAS AT THE YURKHAROVSKOYE FIELD, BCM

Marketable production of gas and gas condensate at the Yurkharovskoye field began in 2003, and, in 2012, reached 34.1 bcm of natural gas and 2,672 thousand tons of liquid hydrocarbons. The field development model provides for the drilling of large-diameter and multilateral horizontal wells, which reduces the total number of wells needed to develop the field, thereby minimizing capital expenditures. Wells at the field are up to 245 mm in diameter and the length of horizontal parts of the borehole exceeds 1,000 meters, with initial flow rates at some producing wells average up to 4.5 mmcm of gas per day. In 2012, a total of 6 new gas and gas condensate wells were launched and the total well stock (producing wells) increased to 72 by the year end.

The launch of the fourth stage of Phase Two development in October 2012 has brought the field to its target production plateau of 36.5 bcm per annum of natural gas. The fourth stage consists of two low-temperature separation lines, each with annual capacity of 3.5 bcm of natural gas.

The first stage booster compressor station consisting of three units with total capacity of 75 MW was also launched in 2012, which enables gas production at the field to be maintained at the maximum plateau level.

In 2012, one test well was drilled to prepare for the future development of oil deposits at the field, and achieved an initial flow rate of 83 tons per day.

East-Tarkosalinskoye field

The East-Tarkosalinskoye oil and gas condensate field was discovered in 1971 and the license for its development is valid until 2043. The field began producing crude oil

29 GROWTH EFFICIENCY INNOVATION

SALES PRODUCTION OF NATURAL GAS AT THE EAST-TARKOSALINSKOYE FIELD, BCM

in 1994 and natural gas and gas condensate in 1998 and 2001, respectively.

At the end of 2012, proved SEC reserves of the field were 198.2 bcm of natural gas and 21.1 mmt of liquid hydrocarbons. The East-Tarkosalinskoye field is our most mature field and further field development is focused on exploiting the field's crude oil layers and increasing crude oil production. Accordingly, we launched the central oil treatment facility in 2012 and 18 crude oil wells were drilled as part of the field's development activities. From the central treatment facility the crude oil is transported via our pipeline to the metering station of Transneft's oil pumping station and injected into the pipeline system operated by Transneft.

There were 117 natural gas and 73 crude oil wells at the field at the end of 2012. Production at the field during 2012 totalled 12.7 bcm of natural gas and 984 thousand tons of liquid hydrocarbons.

Khancheyskoye field (Khancheyskiy license area)

The Khancheyskoye field was discovered in 1990 and is located 65 kilometers to the east of the East-Tarkosalinksoye field. The license for the Khancheyskoye field is valid until 2044. The field began producing natural gas and gas condensate in 2001 and crude oil in 2007.

At the end of 2012, proved SEC reserves totaled 32.6 bcm of natural gas and 3.3 mmt of liquid hydrocarbons. Drilling of a pilot hole at a production well during the year led to discovery of a new gas condensate deposit. Two production wells were successfully drilled in 2012 and field's pro-

25 NUMBER OF

ANNUAL REPORT OAO NOVATEK 2012

PRODUCTION WELLS AT THE SAMBURGSKOYE FIELD AS OF 31 DECEMBER 2012

duction totalled 3.6 bcm of natural gas and 518 thousand tons of liquid hydrocarbons. Gas and condensate production at the field peaked in 2010–2011, and future potential is associated with the development of field's crude oil reserves.

Other producing fields

The Company's three core fields accounted for approximately 90% of marketable production of hydrocarbons in 2012. The remaining volumes were produced at the following six fields and license areas: the Beregovoy license area, the Pyreinoye field, the Samburgskiy license area, the Sterkhovoye field (at the Olimpiyskiy license area), the Yumantilskiy license area and the North-Urengoyskoye field.

Beregovoy license area and Pyreinoye field

The Beregovoy license area and the Pyreinoye field, which are being developed by our joint venture, OAO Sibneftegas (NO-VATEK's share – 51%), accounted for 9% of NOVATEK's marketable production of hydrocarbons in 2012.

The Beregovoy license area, valid until 2023, is the largest asset of Sibneftegas in terms of reserves. Total proved gross reserves of the Beregovoy area as at 31 December 2012 under the SEC reserves methodology are estimated at 148.6 bcm of natural gas, of which our share is 75.8 bcm. Commercial production of natural gas at the field began in 2007 and, in 2012 the field produced 9.5 bcm of natural gas (NOVATEK's share – 4.9 bcm). Interpretation of 3D seismic data was completed in 2012, the geological field model was adjusted, and reserves were re-estimated in order to optimize the field development plan.

The Pyreinoye gas condensate field, valid until 2021, has proved gross gas reserves of 19.3 bcm, as estimated under the SEC reserves methodology as at 31 December 2012, with our proportional share in the proved reserves apprised at 9.8 bcm of natural gas. Commercial gas production began at the field in 2009, and in 2012, the field produced 0.95 bcm of natural gas (NOVATEK's share – 0.48 bcm). Interpretation of 3D seismic data was completed in 2012, the geological field model was adjusted, and reserves were re-estimated in order to optimize the field development plan. One gas producing well was also drilled.

Samburgskoye field (Samburgskiy license area)

The Samburgskoye field is located within the Samburgskiy license area, which also encompasses four other fields (North-Yesetinskoye, East-Urengoyskoye and North-Purovskoye fields, as well as a part of the Urengoyskoye field). The exploration and production license for the Samburgskoye field is valid until 2018 and is owned by OAO Arcticgas, a wholly owned subsidiary of SeverEnergia, in which we have a 25.5% economic interest (51% in SeverEnergia is owned by Yamal Development, a 50/50 joint venture between NOVATEK and Gazprom neft). The Samburgskoye field has proved gross gas reserves of 97.8 bcm (NOVATEK's share – 24.9 bcm) and reserves of liquid hydrocarbons of 15.7 mmt (NOVATEK's share – 4.0 mmt), as estimated under SEC reserves methodology at 31 December 2012.

Commercial production of natural gas and unstable gas condensate began in April 2012 with various facilities commissioned into operation at the field during the year: the first and second phases of gas treatment unit, a 46-km gas pipeline connecting the gas treatment unit to the UGSS and a 20-km gas condensate pipeline connecting the field to the pipeline that links the Yurkharovskoye field to the Purovsky processing Plant. There were 25 production wells at the end of 2012, and all of the unstable gas condensate produced at the field is delivered to the Purovsky Plant for further processing.

North-Urengoyskoye field

The North-Urengoyskoye gas condensate field, discovered in 1966, is located 25 km south of the Yurkharovskoye field. The development license for the field is held by ZAO Nortgas. In November 2012, NOVATEK acquired a 49% equity stake in ZAO Nortgas.

The North-Urengoyskoye field has proved gross gas reserves of 157.3 bcm of natural gas and 21.1 mmt of liquid hydrocarbons, as estimated under SEC reserves methodology at 31 December 2012. Our share in the proved reserves is 77.1 bcm of natural gas and 10.4 mmt of liquid hydrocarbons. Field reserves are concentrated in two domes – western and eastern. Commercial production started at the western dome in 2001, and at the end of 2012, the field infrastructure included 54 production wells, a gas treatment facility with a 5.3 bcm annual capacity and a booster compressor station with a 20 MW capacity.

During 2012, the field produced 4.2 bcm of natural gas and 426 thousand tons of unstable gas condensate (NOVATEK's share since acquisition of its equity interest was 0.2 bcm of natural gas and 19 thousand tons of gas condensate). Preparatory work was carried out to start production at the eastern dome of the field, including construction of well pads, drilling of production wells, construction of gas gathering networks and a gas treatment unit. Production launch at the eastern dome will more than double production of natural gas and triple production of gas condensate at the field.

Sterkhovoye field (Olimpiyskiy license area)

The Sterkhovoye field located within the Olimpiyskiy license area, the development license for which is valid until 2026, consists of two gas condensate layers and has proved gas reserves of 1.4 bcm and liquid hydrocarbons reserves of 0.36 mmt under the SEC reserves methodology at 31 December 2012. The field is connected to the UGSS by a 14 kilometer natural gas pipeline with transportation capacity of 3.1 bcm per annum, which will also be used to transport gas produced at the Dobrovolskoye field, also located within the Olimpiyskiy license area. Hydrocarbon production at the Sterkhovoye field began in 2009 and in 2012, amounted to 0.1 bcm of gas and 19 thousand tons of gas condensate.

Yumantilskoye field (Yumantilskiy license area)

The Yumantilskoe field is located within the Yumantilskiy license area, the development license for which is valid until 2024. Total recoverable reserves of the field under the Russian reserve classification ABC1 + C2 amounted to 3.8 bcm of gas and 0.5 mmt of liquids at the end of 2012 (reserve amounts to SEC and PRMS standards have not been estimated). Commercial production at the field began in 2001, but has been occasionally suspended due to maintenance works at the wells. Gas production at the field totaled 0.1 mmcm in 2012.

32 GROWTH ANNUAL REPORT OAO NOVATEK 2012

EFFICIENCY INNOVATION

KHANCHEYSKOYE FIELD

Prospective fields and license area

In 2012, full-scale exploration work began at our fields located on the Gydan Peninsula and offshore license areas in the Gulf of Ob, which were acquired in 2011. We carried out 6,260 linear km of 2D and 759 square km of 3D seismic work at these fields and license areas.

Our asset base includes a number of prospective fields and license areas at various stages of exploration and development, which provide a basis for future sustainable hydrocarbon production growth. Fields in the Nadym-Pur-Taz Region are located in close proximity to existing transportation and processing infrastructure, which will enable their cost-effective development. The South-Tambeyskoye field, which is an integral part of the Yamal LNG project, is located on the coast of the Gulf of Ob, enabling efficient shipment of LNG to the international markets through the Port of Sabetta. The Salmanovskoye (Utrenneye)

REVIEW OF OPERATING RESULTS

33 GROWTH EFFICIENCY INNOVATION

421BCM PROVED NATURAL GAS RESERVES OF SEVERENERGIA FIELDS

field on the Gydan Peninsula is in close proximity of the South-Tambeyskoye field, across the Gulf of Ob.

SeverEnergia fields

OAO Arcticgas, a subsidiary of SeverEnergia (51% in SeverEnergia is owned by Yamal Development, a 50/50 joint venture between NOVATEK and Gazprom neft; economic interest of NOVATEK in SeverEnergia is 25.5%), holds the exploration and production license for the Samburgskiy license area (which includes the Samburgskoye, North-Yesetinskoye, East-Urengoyskoye and North-Purovskoye fields, as well as a part of the Urengoyskoye field) and for the Yaro-Yakhinskoye, North-Chaselskoye and Yevo-Yakhinskoye fields.

As at 31 December 2012, the proved gross reserves of the non-producing fields of SeverEnergia under the SEC reserves methodology were estimated at 322.9 bcm of natural gas and 54.4 mmt of liquid hydrocarbons (with our share of 82.3 bcm of natural gas and 13.9 mmt of liquid hydrocarbons), and the largest non-producing fields in terms of reserves are the Urengoyskoye, Yaro-Yakhinskoye and North-Chaselskoye fields.

In 2012, SeverEnergia began preparatory works for the construction of key infrastructure at the Urengoyskoye field, including a gas treatment facility, gas pipeline to link the field to the UGSS and a gas condensate pipeline to link the field to the Yurkharov – Purovsky Plant pipeline. Geological exploration and development planning for other fields of SeverEnergia continued in 2012. The revision of the geological model for the fields at the Samburgskiy license area and re-estimation of their reserves carried

out in 2012 led to major upward revision of resource potential of the license area. The results from testing an appraisal well at the Yaro-Yakhinskoye field resulted in a significant increase in its hydrocarbon reserves. Testing of an exploration well at the North-Chaselskoye field led to discovery of a new gas condensate deposit.

Termokarstovoye field

The development license for the Termokarstovoye field is valid until 2021 and is held by Terneftegaz, in which NOVATEK holds a 51% equity stake.

The Termokarstovoye field was discovered in 1988 and consists of five gas condensate deposits at depths of 2,550 to 3,000 meters. Proved reserves under the SEC reserve reporting standards at the year-end 2012 amounted to 22.3 bcm of natural gas and 6.9 mmt of liquid hydrocarbons (with NOVATEK's share of 11.4 bcm of natural gas and 3.5 mmt of liquid hydrocarbons).

A decision was made to proceed with field development following successful geological exploration work carried out in 2011 and 2012. In 2012, we undertook work activities relating to field development and infrastructure, and on the project documentation for the field's transport infrastructure. Preparations for construction works such as hydraulic earth filling, construction of well pads, and construction of river transport facilities for offloading of construction materials were also made.

North-Khancheyskoye field

The license for the North-Khancheyskoye field is valid until 2029, and has been apprised to hold estimated proved reserves

34 GROWTH ANNUAL REPORT OAO NOVATEK 2012

EFFICIENCY INNOVATION

481BCM PROVED NATURAL GAS RESERVES OF THE SOUTH-TAMBEYSKOYE FIELD

as of 31 December 2012 in accordance with SEC reserves standards of 2.5 bcm of natural gas.

One exploration well was drilled in 2012, leading to the discovery of one gas and one gas condensate reservoir. The field's geological model was finalized, allowing us to proceed with field development planning and design work relating to surface facilities.

Yarudeyskoye field

The license for the Yarudeyskoye field is valid until 2029 and is held by Yargeo, in which NOVATEK has a 51% equity stake. Most of the recoverable reserves at the field are located in crude oil deposits. Proved reserves of the field to SEC reserves standards as of 31 December 2012 totaled 4.5 mmt of liquid hydrocarbons and 7.4 bcm of natural gas (our share in proved reserves is 2.3 mmt of liquid hydrocarbons and 3.8 bcm of natural gas). Reserves according to C1+C2 Russian classification amounted to 46 mmt of liquids and 28 bcm of natural gas (NOVATEK's share is 23 mmt of liquids and 14 bcm of natural gas). In 2012, an appraisal well was drilled at the field, which confirmed the field's geological model and led to an increase of estimated reserves. Work on a development plan for the field was underway.

North-Russkoye field

The license for the North-Russkoye field is valid until 2031. Proved reserves of the field under SEC standards as of 31 December 2012 were 22.5 bcm of gas and 1.9 mmt of liquid hydrocarbons. A development plan for the field was completed in 2011, and site preparation and hydraulic earth filling were carried out in 2012.

Olimpiyskiy license area

The license for the Olimpiyskiy area is valid until 2026. The area includes the Sterkhovoye field, which is already in production (see "Other producing fields"), as well as the Dobrovolskoye field, Dremuchee field and part of the Urengoyskoye field. As of 31 December 2012, proved SEC reserves at Dobrovolskoye field and part of the Urengoyskoye field were estimated at 26.1 bcm of natural gas and 2.2 mmt of liquid hydrocarbons.

The results of seismic work and drilling of wells at adjacent license areas helped to clarify the geological model for the part of the Urengoyskoye field located within the Olimpiyskiy license area. The field's drilling program was decided in 2012 and the project document for the field development was approved, and works were carried out on the documentation for the transport infrastructure. Production drilling at the field is planned to start in 2013.

South-Tambeyskoye field (Yamal LNG project)

OAO Yamal LNG, in which NOVATEK holds an 80% equity stake, holds the license for exploration and production at the South-Tambeyskoye field valid until 2045.

The South-Tambeyskoye field was discovered in 1974 and is located in the north-eastern portion of the Yamal Peninsula. The field has five shallow gas horizons and 37 deeper gas condensate horizons. The depth of the horizons varies from between 900 to 2,850 meters.

As of 31 December 2012, the field was estimated to contain 481.4 bcm of proved

35 GROWTH EFFICIENCY INNOVATION

235 BCM

PROVED NATURAL GAS RESERVES OF THE SALMANOVSKOYE FIELD

natural gas reserves and 13.4 mmt of proved liquid hydrocarbon reserves, under SEC reserves methodology. Our share in the reserves of the field is 385.1 bcm of gas and 10.7 mmt of liquid hydrocarbons. Based on total proved reserves, the South-Tambeyskoye field is the largest field in our reserves portfolio.

The field has already been thoroughly studied with 2D and 3D seismic and exploration wells drilled, a detailed geological model and reserve appraisal have been completed, which allowed us to optimize the field development plan. As a result of exploration works carried out in 2012 one new gas condensate deposit was discovered. Production potential of the field exceeds 27 bcm of natural gas per annum, and natural gas produced at the field is planned to be delivered to the international markets in a form of liquefied natural gas, or LNG.

The field development plan provides for the drilling of approximately 200 wells at 19 well pads, construction of a gas gathering pipeline system, gas treatment facilities and a liquefaction plant. The liquefaction plant will include three trains of 5 to 5.5 mmt annual capacity each as well as LNG storage facilities. The shipment infrastructure will include a jetty with two tanker loading berths at the port of Sabetta equipped with ice protection facilities. LNG carriers of special design ARC-7 will be used to transport the LNG to international markets.

Front-end engineering design work of the project was completed in 2012, a contractor was selected for drilling of the first production wells, two rigs were dispatched to the field, and work was carried out on preparing the well pads. Construction of cargo berths began at the port of Sabetta for receipt of building materials

and LNG plant modules. Work was underway on construction of roads, fuel depot, power station and boiler house, housing facilities and canteens. A consultant was selected for issues of corporate and social responsibility, and preparations began for certification of the Yamal LNG integrated management system to ISO 14001:2004 and OHSAS 18001:2007 international standards. Tenders for LNG shipping, construction of LNG carriers and engineering, procurement and construction of the LNG plant were announced, and initial proposals were received from the participants. We were also working on marketing the expected LNG production and arranging the necessary project financing.

Fields and license areas on the Gydan Peninsula and the offshore Gulf of Ob

Licenses for the Geofizicheskoye and Salmanovskoye (Utrenneye) fields on the Gydan Peninsula and the East-Tambeyskiy and North-Obskiy areas in the Gulf of Ob were acquired in September 2011 and are valid through 2031 and 2041, respectively.

The Salmanovskoye (formerly Utrenneye) field, located in the northern part of the Gydan peninsula on the shores of the Gulf of Ob in close proximity to the South-Tambeyskoye field, was discovered in 1980. It is the largest field by recoverable reserves that has been found to date on the Gydan Peninsula. The field contains 34 hydrocarbon deposits, including 16 gas deposits, 15 gas condensate deposits, two oil and gas condensate deposits and one crude oil deposit. Proved reserves to SEC standards were estimated for the first time in 2012 and as of 31 December 2012 amounted to 235.2 bcm of natural gas and 8.6 mmt of liquid hydrocarbons.

36 GROWTH ANNUAL REPORT OAO NOVATEK 2012

EFFICIENCY INNOVATION

COMPRESSOR BOOSTER STATION AT THE EAST-TARKOSALINSKOYE FIELD

The Geofizicheskoye oil and gas condensate field, located in the middle part of the Gydan peninsula on the shores of the Gulf of Ob, was discovered in 1975 and contains 35 hydrocarbon deposits, including 19 gas deposits, 12 gas condensate deposits, three crude oil deposits and one crude oil and gas condensate deposit. Proved reserves under SEC standards were estimated for the first time in 2012, and as of 31 December 2012 amounted to 124.9 bcm of natural gas and 0.4 mmt of liquid hydrocarbons.

In 2012, we carried out 351 linear km of 2D and 759 square km of 3D seismic work

at the fields, and based on the geological and geophysical work performed, the reserves of the fields were re-estimated and additional work was performed on their geological models.

The East-Tambeyskiy and North-Obskiy licence areas, located offshore in the Gulf of Ob, have a geographical acreage area of approximately 9,800 square km. Their resources are estimated at 1.8 tcm of natural gas of D1+D1L categories under the Russian reserve classification system. In 2012, we conducted 5,909 linear km of 2D seismic work at these licence areas.

4.03 MMT

OF GAS CONDENSATE PROCESSED AT THE PUROVSKY PLANT IN 2012

PROCESSING

Gas condensate is produced from our fields in an unstable form and requires further processing before it can be delivered to our customers. Our primary gas condensate processing asset is the Purovsky Plant, which has total processing capacity of five mmt of de-ethanized gas condensate per annum, which allows us to produce approximately 3.7 mmt of stable gas condensate and approximately 1.3 mmt of liquefied petroleum gas, or LPG per annum. The Purovsky Plant is located in the YNAO and is in close proximity to the East-Tarkosalinskoye field. We also own a system of condensate pipelines, enabling delivery of gas condensate from our fields to the Purovsky Plant.

The Purovsky Plant is an important link in our midstream value chain that provides us complete operational control over our processing needs and access to higher yielding marketing channels for our stable gas condensate.

In 2012, the Purovsky Plant received feedstock from the Yurkharovskoye, East-Tarkosalinskoye, Khancheyskoye, Sterkhovoye and Samburgskoye fields, supplied via the Company's own condensate pipelines, as well as from the North-Urengoyskoye field operated by ZAO Nortgas.

In 2012, the Purovsky Plant processed 4.03 mmt of de-ethanized unstable gas condensate, or 4.3% more than in 2011, resulting

in the commercial production of 3,081 mt of stable gas condensate and 903 thousand tons of LPG as well as approximately 17 thousand tons of methanol produced during the LPG scrubbing process. The growth in processing volumes mainly reflects the start of deliveries to the Purovsky Plant of de-ethanized gas condensate from the Samburgskoye field in April and the North-Urengoyskoye field in November.

During the year, the Purovsky Plant operated at approximately 81% of full capacity. We continued working on a project to expand annual capacity of the Plant to 11 mmt ahead of a scheduled increase of gas condensate production: design documentation was completed, orders were placed for the main equipment and preparations to start construction and assembly work were carried out.

The expansion of the processing capacity of the Purovsky Plant does not involve the construction of any additional capacity for LPG production. Under our longterm agreements with OAO Sibur Holding ("Sibur"), a related party, approved by the EGM in January 2013, 100% of the light hydrocarbons produced during the gas condensate stabilization process at the Company's Purovsky Plant will be delivered to Sibur's Tobolsk Petrochemical Complex. Sibur will process up to 1.2 mmt of light hydrocarbons on tolling terms and will redeliver the produced LPG to us for

38 GROWTH ANNUAL REPORT OAO NOVATEK 2012

GAS CONDENSATE PROCESSING VOLUMES

AT THE PUROVSKY PLANT, MT

distribution via our existing marketing network, while the remaining volumes of light hydrocarbons will be sold to Sibur on an "ex-plant" basis. These agreements will allow us to minimize capital expenditures on the expansion of the Purovsky Plant and optimize logistics of LPG through NO-VATEK's marketing network.

The Purovsky Plant is connected to the Russian rail network at the Limbey rail station. Substantially all of the stabilized gas condensate produced at the Purovsky Plant is delivered by rail to the Port of Vitino where it is loaded onto ocean tankers for further transportation to international markets. Rail transport is also used to supply LPG to the domestic market and export.

In March 2012, we signed a Strategic Partnership Agreement for the period up to 2020 with OAO Russian Railways. The agreement calls for expansion of railway capacity on the "Limbey – Surgut – Tobolsk" route and guarantees the transport of 100% of the volumes produced at the Purovsky Plant taking into consideration the expected growth in its production capacity.

Ust-Luga Stable Gas Condensate Transshipment and Fractionation Complex

As part of our strategy to maximize margins through value added projects, we continued construction of a new terminal facility at Ust-Luga, located on the Baltic Sea, for the transshipment and fractionation of stable gas condensate produced at the Purovsky Plant. The estimated fractionation capacity of the Ust-Luga complex is up to six mmt per annum. After the launch of the complex the stable gas condensate processed at the Purovsky Plant will be redirected from

EFFICIENCY INNOVATION

PUROVSKY PLANT OUTPUT IN 2012, %

the port of Vitino to our new complex at Ust-Luga. Main portion of the stable gas condensate will be used as feedstock to the fractionation unit for further processing into light and heavy naphtha, jet fuel, diesel fraction and heating oil, which will be sold to international export markets while the remaining volumes supplied to the facility by rail transport will be loaded onto tankers for delivery to export markets.

Upon completion, the complex will include two 3-mmt per annum fractionation trains, reservoir tank farms for feedstock and processed products, rail facilities for loading and receiving finished and raw materials and two deep-water tanker berths. Work on main facilities of the first stage of the project including the first fractionation train neared completion in 2012.

The complex will allow us to expand our vertically integrated chain and our customer base, as well as to increase sales of higher value added products and diversification across markets. Since the distance from the Purovsky Plant to Ust-Luga is nearly 400 km less than to Vitino we also expect savings on railroad transport costs.

58.9 BCM

OF NATURAL GAS SOLD IN 2012

MARKETING

We continued to increase the number of end-customers buying our natural gas and for the first time in our history, we executed long-term delivery contracts for periods of up to 15 years. The share of sales to the end-customer segment in our total sales volumes mix rose to 69%.

Natural gas sales

During 2012, we supplied natural gas to 35 regions of the Russian Federation and accounted for 16.3% of the total natural gas deliveries to the domestic market via the UGSS.

NOVATEK's 2012 natural gas sales volumes totaled 58.9 bcm, representating an increase of 9.7% compared to 2011 sales volumes of 53.7 bcm. The share of sales to the end-customer segment in our total sales volumes mix rose to 69.3% from 54.7% in 2011.

The growth in sales volumes was due to an increase in natural gas supplies to the Chelyabinsk region, the Perm region and the Komi Republic by approximately 10.4 bcm in comparison with 2011. In 2012, our customers were located primarily in the Perm Territory, the Chelyabinsk, Orenburg, Sverdlovsk, Moscow, Kostroma, Kirov and Tyumen regions, the Komi Republic, the city of St-Petersburg, as well as the YNAO and Khanty-Mansyisk Autonomous Region.

During 2012, our total revenues from natural gas sales increased to RR 142.6 billion or by 28.6%, as compared to 2011, due to the combination of higher volumes sold and an increase in the regulated gas tariff effective from 1 July.

We continued to increase the number of end-customers buying our natural gas and for the first time in our history, we executed

long-term delivery contracts for periods of up to 15 years. Contracts were signed with MMK (10.5 years), the Russian subsidiaries of E.ON and Fortum (15 years), as well as with subsidiaries of Mechel Group (10 years and longer). Annual delivery volumes under these contracts are expected to represent up to 30% of our total sales in the coming years.

A five-year contract was also signed with OAO Severstal, providing for total supplies of approximately 12 bcm of natural gas, as well as a three-year contract with OAO Mosenergo to supply 27 bcm of natural gas.

In December 2012, we acquired an 82% stake in OOO Gazprom mezhregiongas Kostroma, which supplies natural gas to a wide range of consumers in the Kostroma region. This newly acquired company supplied approximately 3.8 bcm of natural gas to customers in the Kostroma region during 2012, as compared with 0.8 bcm supplied directly by NOVATEK.

In order to maintain production levels during periods of seasonal demand NOVATEK has entered into an agreement with OAO Gazprom for the use of their underground storage facilities on a space available basis. Historically, natural gas is injected into underground storage facilities during warmer periods when demand is lower and later withdrawn during periods of colder weather and increased demand.

REVIEW OF OPERATING

RESULTS

Regions with sales volumes

above 1 bcm

EFFICIENCY INNOVATION

Regions with sales volumes between 0.5 to 1.0 bcm

Regions with sales volumes

below 0.5 bcm

NATURAL GAS SALES VOLUMES, BCM

NATURAL GAS SALES VOLUMES TO END-CUSTOMERS, BCM

BREAKDOWN OF 2012 NATURAL GAS SALES VOLUMES, %

NATURAL GAS SALES REVENUES, RR BLN*

AVERAGE NATURAL GAS PRICE, RR PER MCM*

REGIONAL BREAKDOWN OF 2012 NATURAL GAS SALES VOLUMES TO END-CUSTOMERS, %

Natural gas and liquids sales volumes

	UNITS	2011	2012	CHANGE
Total gas sales volumes, including:	mmcm	53,667	58,880	9.7%
End customers	mmcm	29,332	40,806	39.1%
Traders	mmcm	24,335	18,074	(25.7)%
Share of end-customers in total gas sales volumes	%	54.7%	69.3%	14.6 p.p.

Stable gas condensate sales volumes	mt	2,984	2,847	(4.6)%
LPG sales volumes	mt	880	905	2.8%
Crude oil sales volumes	mt	242	442	82.6%

In 2012, NOVATEK withdrew 945 mmcm of natural gas from underground storage facilities during periods of high demand and injected 1,309 mmcm when space was available. At the end of 2012, the Company had 1,096 mmcm of natural gas in storage and available for withdrawal in future periods.

We also began work during the year to establish a gas trading business on the international markets, and accordingly, agreements were signed in July 2012 for the annual supply of two bcm of natural gas to the German energy company EnBW. The supplies under these commercial trading activities began in October 2012.

Liquid Hydrocarbon Sales

In 2012, NOVATEK continued to use the Northern Sea Route for supplies of stable gas condensate to the fast growing markets in the Asian-Pacific region. During the seasonal navigational period, we sent eight tankers through the Northern Sea Route, which delivered 487 thousand tons of stable gas condensate to consumers in China and South Korea.

The Company's primary liquid hydrocarbon sales volumes are comprised of stable gas condensate and liquefied petroleum gases. We are also producing and selling relatively small quantities of crude oil. The stable gas condensate is primarily used in the petrochemical and oil refining industries as an alternative to naphtha and light crude oil, respectively. Our LPG is sold to both the chemical processing industry, as a feedstock, and the retail and wholesale fuel markets where its high energy content, environmental safety and ease of transportation and storage make it an attractive fuel source for automobiles and residential usage.

We strive to respond quickly to changing market conditions by optimizing the customer base and supply geography, as well as developing and maintaining logistics infrastructure. Total sales volumes of liquid hydrocarbons in 2012 amounted to 4,203 thousand tons, a 2.2% increase over 2011 volumes. The growth was due

to higher crude oil production and an increase of volumes of unstable gas condensate processed at the Purovsky Plant. The growth in our liquids sales volumes was constrained by a significant increase in stable gas condensate inventories due to redirection of sales to Asian-Pacific region, which essentially reserves itself in the next quarter and is affected by the loading schedule at each quarter end and the destination of the cargos.

Total revenues from liquids sales increased to RR 67.6 billion, or by 5.9%, in 2012 as compared to 2011, due to the increase in sales volumes and higher realized prices.

Liquid hydrocarbons produced at the Purovsky Plant are transported by rail. At the end of 2012 we owned and leased 6,700 rail cisterns, of which 2,700 were used for the transport of LPG and 4,000 for the transport of stable gas condensate. Our crude oil is transported through

LIQUID HYDROCARBON SALES VOLUMES, MT

the trunk pipelines owned and operated by OAO Transneft.

During 2012, we sold 2,847 thousand tons of stable gas condensate, a 4.6% decrease as compared to the volumes sold in 2011. The lower sales volumes reflected an increase in the stable gas condensate inventories to 461 thousand tons as at the end of the year mainly due to an increased volume of sales to the Asian-Pacific region that were in seaborne transit and not recognized as revenues in the current reporting period. More than 99% of all stable gas condensate sales volumes, or 2,821 thousand tons, were exported via the all season port of Vitino on the White Sea. Fifty-six percent of export volumes were sold to countries in the Asian-Pacific region, 29% to markets in Europe, 11% to the USA and 4% to markets in South America.

In 2012, NOVATEK continued to use the Northern Sea Route (NSR) for supplies of stable gas condensate to the fast growing markets in the Asian-Pacific region. During the seasonal navigational period, we sent eight tankers through the NSR, which delivered 487 thousand tons of stable gas condensate to consumers in China and South Korea.

The Company sells its LPG volumes to both the export and domestic markets. In 2012, total LPG sales volumes amounted to 905 thousand tons, of which 53% were exported. Novatek Polska, our wholly owned LPG trading company in Poland, was responsible for 55% of our total LPG export sales. Other export markets for LPG were Finland, Hungary, Lithuania, Latvia, Slovakia, Romania and Turkey.

43 GROWTH EFFICIENCY INNOVATION

LIQUID HYDROCARBON SALES REVENUES, RR BLN*

* Net of VAT, excise tax and export duties.

On the domestic market, our LPG is sold through large wholesale channels, as well as our network of retail and small wholesale stations. In 2012, large wholesale supplies to the domestic market were 323 thousand tons, representing 36% of total LPG sales volumes. The total amount of LPG sold through our domestic network of retail and small wholesale stations increased to 103 thousand tons or by 14% as compared to 2011 volumes. At the end of 2012, NOVATEK owned 66 stations in Chelyabinsk, Volgograd, Rostov and Astrakhan regions.

Sales of crude oil in 2012 were 442 thousand tons, an 83% increase over 2011 volumes. Sixty six percent of our crude oil volumes were sold on the domestic market with the remaining volumes supplied to export markets.

EFFICIENCY INNOVATION

LIQUID HYDROCARBON SALES

REVIEW OF OPERATING

RESULTS

TANKERS WITH CONDENSATE SENT VIA THE NOTHERN SEA 8 ROUTE IN 2012

242 GRANTS

AWARDED TO SCHOOLCHILDREN IN 2012

RUSSIA'S LARGEST INDEPENDENT NATURAL GAS PRODUCER

02 ENVIRONMENTAL AND SOCIAL RESPONSIBILITY

NOVATEK HAS IMPLEMENTED AN INTEGRATED MANAGEMENT SYSTEM FOR ENVIRONMENTAL PROTECTION, OCCUPATIONAL HEALTH AND SAFETY IN COMPLIANCE WITH REQUIREMENTS OF INTERNATIONAL STANDARDS

NOVATEK adheres to the principles of effective and responsible business conduct and considers the welfare of its employees and their families, environmental and industrial safety, the creation of a stable and beneficial social environment as well as contributing to Russia's overall economic development as priorities and responsibilities of the Company.

ENVIRONMENTAL PROTECTION

NOVATEK's core producing assets are located in the Far North, a harsh Arctic region with vast mineral resources and a fragile environment. The Company is committed to environmental protection in its operations.

NOVATEK has implemented an Environmental, Health and Safety Policy, while at the same time an Integrated Management System for Environmental Protection, Occupational Health and Safety (IMS) in compliance with requirements of international standards has been implemented at all of our main subsidiaries. In 2012, as part of our ongoing commitment to IMS, our joint venture, Sibneftegas, was certified in accordance with ISO 14001:2004 international standards.

In 2012, to prevent air pollution and reduce greenhouse gas emissions from flared associated petroleum gas (APG) we completed the construction and launch of a central oil treatment facility at our East-Tarkosalinskoye field. The facility's capacity allows rational use of up to 700 mcm of APG per day and reduces greenhouse gas emissions by 640 mt of СО2 equivalent per annum.

In 2012, NOVATEK continued its participation in the Carbon Disclosure Project (CDP), which discloses information on greenhouse gas emissions and the energy efficiency of production, and CDP Water Disclosure Project, which discloses information on the use of water resources. The Company provides access to information regarding the effect of its operations on the environment to all our stakeholders in a wide range of federal and regional media and on the Company's website.

The protection and preservation of the marine environment and natural resources is a key principle of our Environmental Policy. At the end of 2011, we acquired the licenses for the East-Tambeyskiy and North-Obskiy license areas and the Salmanovskoye (Utrenneye) and Geofizicheskoye fields, which are wholly or partially located in the Gulf of Ob. Following this acquisition we held public hearings on the environmental

48 GROWTH ANNUAL REPORT OAO NOVATEK 2012

WATER CONSUMPTION OF NOVATEK E&P COMPANIES

impact assessment of our planned operations before the commencement of geological exploration in these license areas. We received environmental approval for our offshore geophysical program and a baseline study of environmental components was carried out within the license areas along with the development of the environmental monitoring and subsurface protection programs.

In 2012, innovative closed flare systems that reduce the amount of harmful emissions were designed and installed during the first phase of construction of the stable gas condensate transshipment and fractionation facility at the port of Ust-Luga, located

EFFICIENCY INNOVATION

ATMOSPHERE EMMISSIONS OF NOVATEK E&P COMPANIES

on the Baltic Sea. State-of-the-art engineering solutions and design have been employed in the automatic closed flare systems, including automatic interlock circuits, liquid valves, ultraviolet flame scanners, fault-tolerant startup and shutdown system, warning lights, multi-burner heads with built-in flame arresters, devices to prevent detonation, and pilot burners with remote spark generators and UV scanners.

One of the Company's priorities is the rational usage of resources, including energy resources. The table below sets out the physical volumes and the Russian rouble equivalent of energy resources consumed by the Company in 2012.

Energy resource consumption by the subsidiaries of NOVATEK in 2012

	VOLUME	RR MLN, NET OF VAT
Natural gas, mmcm	665	320.1
Electricity, MW*h	269,351	766.4
Heating energy, Gcal	202,804	197.7
Oil, tons	543	12.5
Motor gasoline, tons	819	25.5
Diesel fuel, tons	4,481	131.3
Other, tons	42,860	103.5

HEALTH AND SAFETY

Our strategic goal is to achieve a leading position amongst oil and gas companies on all key indicators in terms of Occupational Health and Safety. In order to accomplish this goal, the Company continually updates its IMS, improves employees' qualification and applies advanced technologies.

In accordance with the requirements of the federal law "On Industrial Safety of Hazardous Production Facilities" and "Rules on the Organization and Implementation of Industrial Control for Compliance with Requirements of Industrial Safety at Hazardous Production Facilities" all of our subsidiaries have developed their own rules for the organization and implementation of industrial control for compliance with these requirements. We have

also established industrial control compliance commissions, which carry out periodic audits of departments and production facilities to comply with the EHS requirements.

In 2012, 2,772 employees, including workers and middle management, underwent HSE training courses.

The Company started providing its employees with the new protective clothing manufactured according to the technical specifications developed in 2011 in order to standardize the requirements for protective clothing at our subsidiaries.

Due to the IMS effectiveness no accidents or fires were recorded at the Company's hazardous production facilities in 2012.

41 %

OF OUR SPECIALISTS AND LINE WORKERS UPGRADED THEIR RESPECTIVE QUALIFICATIONS IN 2012

HUMAN RESOURCES

In 2012, we developed and approved the Successor program, which aims to provide executives with the ability to participate in training activities aimed at developing a common understanding of the goals and the strategy of the Company for preparation for higher level positions within the Company.

Employees are NOVATEK's most valuable resource, allowing the Company to grow rapidly and effectively. The Company's human resource management system is based on the principles of fairness, respect, equal opportunities for professional development, dialogue between management and employees, as well as continuous, comprehensive training and development opportunities for the Company's employees at all levels.

As of the end of 2012, NOVATEK and its subsidiaries had 5,440 employees, 40% of whom work in exploration and production and 50% in processing, transportation and marketing.

Personnel Training and Development

In an environment of rapidly developing technologies and management systems, our multilevel training and professional development program enables our employees to contribute to raising the Company's competitiveness. In 2012, the primary goals of training and professional development included:

• developing and implementing the "Successor" program aimed at providing the Company with a talent pool of senior managers;

developing and implementing the "Steps in Discovering Talents" program for young specialists targeted at training highly qualified personnel whose competence level fully meets business needs;
developing and implementing the "Technical Training" program based on the results of tests in the Corporate Technical Competency Assessment System for various lines of business; and
involvement of young specialists in NO-VATEK's "Research-to-Practice Conferences" and the "Fuel and Energy Complex (FEC) Competitions".

During the past year, NOVATEK continued its efforts to increase employee training, improve working conditions and ensure a safe environment at its production facilities. In 2012, 41% of our specialists and line workers upgraded their respective qualifications, and 52% of the Company's engineers and technicians completed employee certification and industrial safety courses.

51 GROWTH EFFICIENCY INNOVATION

BREAKDOWN OF PERSONNEL AS AT 31 DECEMBER 2012

Specialized training courses for employees of production divisions started in September 2012 under the Technical Training program at Gubkin Russian State University Training and Research Center, the Petroleum Learning Center at Tomsk Polytechnic University and other centers, and 81 employees underwent training through the program. An on-site training program has been developed and implemented at OOO NOVATEK-Purovsky ZPK, in which 45 employees took part during the year.

A total of 103 people were tested under the Corporate Technical Competency Assessment System during the year, including 10 people during the hiring process to fill vacant positions and 41 employees promoted to more senior positions. Six people have been included in the Technical Training program for 2013 as a result of testing newly hired employees.

In 2012, we completed the first phase of the "Steps in Discovering Talents" program, whereby 47 young specialists participated in training courses (Effective Training and Development, Presentation Skills and Self-Organization) for personal skills development. Mentors – employees with high professional competencies able and willing to share their experience – were assigned to young specialists to help them adapt quickly and effectively and develop successfully as professionals. A Mentorship Practicum in which 31 mentors took part was organized and held in order to build knowledge and skills of working with young specialists. During the year, young specialists met with experts from various lines of the Company's business.

The 7th Interregional Research-to-Practice Conference for the Company's young specialists attended by 47 employees was held in Moscow in September 2012. Based on the results of the competition, 12 winners were awarded a trip to a petroleum training center in Norway, and the second- and third-place winners received cash prizes. The winner nominated in the category "Best Implemented Project 2012" was awarded a cash prize, and the top seven projects advanced to the FEC 2012 Competition for Youth Projects, held by the Russian Federation's Ministry of Energy.

In 2012, two of NOVATEK's young specialists who were winners of the FEC-2011 Competition received commendations from the Ministry of Energy.

Social Programs

The focus in employee relations is on implementing social programs. According to the Core Concept of the Company's social policy which was adopted in 2006, the social benefits package for employees includes the following programs:

voluntary medical insurance for employees;
therapeutic resort treatment for employees and members of their families;
provision of special-purpose short-term loans;
special-purpose compensation and social support payments;
provision of special-purpose interest-free loans to purchase housing, and
pension program.

Along with providing an optimum social benefits package, the Company is also committed to creating opportunities for employees to play sports and get involved in sports and cultural events. In 2012, our employees and their family members visited

52 GROWTH ANNUAL REPORT OAO NOVATEK 2012

EFFICIENCY INNOVATION

EMPLOYEES OF THE PUROVSKY PLANT

exhibitions at Russia's national museums, classical music concerts, and attended sporting events like hockey, basketball and football (soccer) games in their free time with the Company's assistance.

The Company publishes its corporate newsletter "NOVATEK", including the "NOVATEK Family" feature, to inform

employees about the Company's activities and get employees, specialists and managers actively involved in business, cultural, sports, charitable and corporate activities. In 2012, we began to publish a new corporate magazine "NOVATEK Plus" in conjunction with developing the overall corporate media within the Company.

SOCIAL POLICY AND CHARITY

NOVATEK continued to finance programs targeting education and youth development, support for low-income families, repair and modernization of socially important facilities and preservation of the culture heritage of the indigenous peoples of the Far North and Russia as a whole.

During 2012, NOVATEK continued to contribute to an improvement in the living standards of local populations in the YNAO as well as the Samara, Chelyabinsk and Tyumen regions. Special priority was given to the performance of our long-term agreements with the municipalities of these regions for financing programs targeting education and youth development, support for low-income families, repair and modernization of socially important facilities and preservation of the culture heritage of the indigenous peoples of the Far North and Russia as a whole. In 2012, NOVATEK invested more than RR 1.0 billion on projects and activities related to the support of indigenous peoples, charitable contributions and educational programs.

Cooperation with Indigenous Peoples of the Far North

During 2012, NOVATEK provided financial support to the "Yamal for Descendants" association and its district branches. We achieved our statutory goals, including the support of the youth branch of the Association, air delivery of the nomadic population and food in remote areas, purchase and delivery of fuel to name a few items.

Throughout the year, the Company also provided sponsorship assistance to the following organizations:

• The Association of Minority Populations of Indigenous Peoples of the Far North,

Siberia, and Far East of the Russian Federation – for legal services, training courses and seminars, and publishing;

The Administration of the YNAO for purchasing rehabilitation equipment for the disabled and for arranging diagnosis and treatment assistance for seriously ill and disabled children;
The Yamal District to fund measures on behalf of the Ilebts Territorial Community of Indigenous Peoples of the North and organize expeditions to discover sacred and ceremonial sites of Yamal's indigenous population;
The Tazov District for construction of a cold storage facility in the village of Gyda and purchasing snowmobiles and motor boats for residents; and
The Nadym District for the construction of a helipad in the Kutopyugan village.

Educational Programs

NOVATEK continued to develop the Company's continuing education program, which provides opportunities to gifted students, from the regions where we operate, to further their education at top rated universities, participate in NOVATEK internships and, upon completion of their studies, possible employment with the Company.

Recruitment and career guidance for promising employees start with the "Gifted Children" program implemented at School No. 8 in Novokuybyshevsk and School No. 2 in

EFFICIENCY INNOVATION

52 GRANTS AWARDED

TO SCHOOL TEACHERS FROM THE START OF THE "GRANTS" PROGRAM

Tarko-Sale. Special classes are formed on a competitive basis from the most talented grade 10 and 11 students with above-average test scores.

The Company has also implemented two "Grants" programs for schoolchildren and teachers living in the Purovsky District of the YNAO.

The "Grants" program for schoolchildren is an educational support program, which we have been administering since 2004. Under the program, students in grades 5 through 11 living in the districts are awarded grants from the Company to support their academic and creative development and to encourage a responsible attitude towards their studies. In 2012, the Company awarded 242 grants.

The "Grants" program for the teachers is intended to raise the prestige of the teaching profession and create favorable conditions for developing new and talented teachers. Since the program was launched, 52 teachers have received grants, including nine in 2012.

In an effort to create conditions for more effective use of university and college resources in preparing students for future professional activities, the Company has developed and successfully implemented the NOVATEK-VUZ program. The program is an action plan for focused, high-quality training for specialists with higher education in key areas of expertise in order to grow the Company's business and meet its needs for young specialists. The program is based at the St. Petersburg State Mining University, Gubkin Russian State University of Oil and Gas in Moscow and the Tyumen Oil and Gas University.

Students who have passed their exams with good and excellent results receive additional monthly payments. During their studies, the students are offered paid field, engineering and directed internships. This experience allows them to apply the knowledge obtained at lectures and seminars to real-life situations and gain experience in the professions they've chosen, while the Company receives an opportunity to meet potential employees.

Support of Cultural Traditions

The strengthening of partnership relations between the Company and Russia's leading cultural and educational institutions, creative groups and charity funds continued during the 2012 period, namely the Russian State Museum (St.Petersburg), the Moscow Kremlin Museum, the State Tretyakov Gallery, the Multimedia Art Museum (the Moscow House of Photography Museum and Exhibition Complex), the Moscow Museum of Modern Art and the Samara Regional Art Museum.

One of the most outstanding cultural events in Russia became an exhibition of one of the most famous artists of the 20th century, Boris Grigoriev. The project was jointly sponsored by the Russian State Museum, the State Tretyakov Gallery and NOVATEK. The Company was also a sponsor of the exhibition "Mastership of the Russian Armorer", which was organized by the Moscow Kremlin Museum and the Samara Regional Art Museum. We also continued to support the annual International Festival "Imperial Gardens of Russia", sponsored and staged by the Russian State Museum.

In 2012, special priority was given to projects and exhibitions of modern art and

NOVATEK supported the exhibition "Arte Povera", which was organized for the first time in Russia by the Multimedia Art Museum and presented works of art from the most important Italian modern artists of the second half of the 20th century. NOVATEK also became a partner of the Moscow Museum of Modern Art in 2011 and supported the large-scale exhibition project "Impossible Community", which brought together 35 Russian and foreign painters, many of whom displayed their works in Moscow for the first time.

NOVATEK also remained a General Partner of the Moscow Soloists Chamber Ensemble under the direction of Yuri Bashmet.

Sports Projects

NOVATEK has continued its support for semi-professional and high-level amateur sports programs. The Company and its subsidiaries organize regular tournaments in the most popular sports, including soccer, volleyball, swimming, et cetera. A team made up of Company's employees also takes part in the annual Moscow Mini-Soccer Championship. The Company is the General Partner of the Dynamo Hockey Club (Moscow), the Spartak Basketball Club (St. Petersburg) and the NOVA Volleyball Team (Novokuybyshevsk).

Charity

The Company continued its cooperation with Chulpan Khamatova's Gift of Life charitable foundation in 2012. Funds raised from events are directed to children's hospitals to buy modern medical equipment.

In 2012, the Company held two blood donor sessions for children from the Russian Children's Clinical Hospital at its Moscow office in collaboration with the foundation.

We continued our charitable activities of the Company's All Together volunteer movement founded in 2008. As in previous years, the volunteers' participated in a number of causes including support for orphans and children with various illnesses, veterans, orphaned animals as well as support for the blood donor movement and the organization of other charitable programs.

10 MEETINGS OF THE BOARD OF DIRECTORS WERE HELD IN 2012

RUSSIA'S LARGEST INDEPENDENT NATURAL GAS PRODUCER

03 MANAGEMENT AND CORPORATE GOVERNANCE

NOVATEK STRIVES TO COMMIT TO THE HIGHEST STANDARDS OF CORPORATE GOVERNANCE. WE BELIEVE THAT SUCH STANDARDS ARE AN ESSENTIAL PREREQUISITE TO BUSINESS INTEGRITY AND PERFORMANCE AND PROVIDE A FRAMEWORK FOR SOCIALLY RESPONSIBLE MANAGEMENT OF THE COMPANY'S OPERATIONS

CORPORATE GOVERNANCE SYSTEM

NOVATEK strives to commit to the highest standards of corporate governance. We believe that such standards are an essential prerequisite to business integrity and performance and provide a framework for socially responsible management of the Company's operations.

The Company has established an effective and transparent system of corporate governance complying with both Russian and international standards. NOVATEK's supreme governing body is the General Meeting of Shareholders. The corporate governance system also includes the Board of Directors, the Board Committees, and the Management Committee, as well as the system of internal control and audit bodies. The activity of all these bodies is governed by the applicable laws of the Russian Federation, NOVATEK's Charter and internal documents available on our website (www.novatek.ru/en).

NOVATEK strives to consider the principles of corporate governance outlined in the Corporate Governance Code recommended by the Russian Federation's Federal Commission for Securities Market dated 4 April 2002 №421/r. The Company follows the recommendations of the Code, as well as offering to our shareholders and investors other solutions that are intended to protect their rights and legitimate interests.

Since the Company's shares are listed on the London Stock Exchange in the form of depositary receipts, NOVATEK places great emphasis on the UK Financial Reporting Council's Combined Code on Corporate Governance and follows its recommendations as far as practicable.

The Company adheres to the internal Corporate Governance Code approved by the Board of Directors in 2005 (Minutes No. 60 of 15 December 2005). This Code has been elaborated on in accordance with best Russian and international practices in corporate governance, ethical norms and specific conditions of the Company's operations and in accordance with Russian legislation and the Company's Charter.

The Company also adheres to the internal Code of Business Ethics approved by the Board of Directors in 2011 (Minutes No. 133 of 24 March 2011). The Code establishes general norms and principles governing the conduct of members of the Board of Directors, Management Committee and Revision Commission, as well as NOVATEK's management and employees, which were elaborated on the basis of moral and ethical values and professional standards. The Code also determines the rules which govern mutual relationships inside the Company and NOVATEK's relationships with its subsidiaries and joint ventures, shareholders, investors, the government and public, consumers, suppliers, and other stakeholders.

NOVATEK's corporate governance practices make it possible for its executive bodies to effectively manage ongoing operations in a reasonable and good faith manner and solely to the benefit of the Company and its shareholders.

GENERAL MEETING OF SHAREHOLDERS

The General Meeting of Shareholders is NOVATEK's supreme governing body. The activity of the General Meeting of Shareholders is governed by the laws of the Russian Federation, the Company's Charter, and the Regulations on the General Meetings approved by NOVATEK's General Meeting of Shareholders in 2005 (Minutes No. 95 of 28 March 2005) with amendments. The Guidelines were elaborated in accordance with Russian legislation, the Company's Charter and the recommendations of the Russian Corporate Code of Conduct.

The General Meeting of Shareholders is responsible for the approval of annual reports, annual financial statements, the distribution of profit, including dividends payout, the election of Board of Directors and Revision Commission, approval of the Company's Auditor and other corporate and business matters.

On 27 April 2012, the Annual General Meeting of Shareholders approved the annual report, annual financial statements (in accordance with Russian Accounting Standards), distribution of profit and the size of dividends based on the results of FY2011. The meeting also elected the Board of Directors, Chairman of the Management Committee and the Revision Commission, as well as approved remuneration to members of the Board of Directors, Revision Commission and the Company's auditor for 2012.

On 16 October 2012, the Extraordinary General Meeting of Shareholders approved the amount of interim dividend for the first six months of 2012 and a long-term contract for natural gas purchase from OAO SIBUR Holding.

BOARD OF DIRECTORS

The Board of Directors (the Board) activity is governed by the laws of the Russian Federation, the Company's Charter and the Regulations on the Board of Directors approved by NOVATEK's General Meeting of Shareholders in 2005 (Minutes No. 96 of 17 June 2005) with amendments.

The Board carries out the overall strategic management of the Company's activity on behalf of and in the interests of all its

Board and Committee meetings attendance in 2012

MEMBER	INDEPENDENCE	BOARD OF DIRECTORS	AUDIT COMMITTEE	CORPORATE GOVERNANCE AND REMUNERATION COMMITTEE	STRATEGY AND INVESTMENTS COMMITTEE
Alexander Natalenko	independent*	10/10	3/3	4/4
Leonid Mikhelson	executive	10/10
Andrei Akimov	independent **	9/10	3/3
Burckhard Bergmann	independent **	10/10		4/4	4/4
Mark Gyetvay	executive	10/10			4/4
Yves-Louis Darricarrere	independent**	9/10			4/4
Kirill Seleznev	independent **	6/10			2/4
Ruben Vardanian	independent , *	10/10	3/3	4/4
Gennady Timchenko	independent **	10/10			3/4

* Independent Director in accordance with the UKLA Combined Code.

** Independent Director in accordance with the Corporate Governance Code recommended by the RF Federal Commission for Securities Market.

shareholders, and ensures the Company's efficient performance in order to increase its shareholder value.

The Board determines the Company's strategy and priority lines of business, endorses long-term and annual business plans, reviews financial performance, internal control, risk management and other matters within its competence, including optimization of corporate and capital structure, approval of major transactions, making decisions on investment projects and recommendations on the size of dividend per share and its payment procedure, and convening General Meeting of Shareholders. The members of the Board are elected by the General Meeting of Shareholders.

The current members of the Board were elected at the Annual General Meeting of Shareholders on 27 April 2012. The Board of Directors is comprised of nine members, of which seven are non-executive directors. Six directors are considered to be independent in accordance with the Corporate Governance Code recommended by the Russian Federation's Federal Commission for Securities Market, and two in accordance with requirements of the UK Financial Reporting Council's Combined Code on Corporate Governance. The Board Chairman is Alexander Egorovich Natalenko. The Chairman is responsible for leading the Board and ensuring its effectiveness.

The members of NOVATEK's Board have a wide range of expertise as well as significant experience in strategic, financial, commercial and oil and gas activities. The Board members hold regular meetings with NOVATEK's senior management

to enable them to acquire a detailed understanding of NOVATEK's business activities and strategy and the key risks. In addition to these formal processes, Directors have access to the Company's medium-level managers for both formal and informal discussions to ensure regular exchange of information they need to participate in the Board meetings and make balanced decisions in a timely manner.

Board activities during the year

To ensure the Company's efficient performance, the Board meetings shall be convened on a regular basis at least once every two months. In 2012, the Board met 10 times, of which 6 meetings were held in absentia. During the year, the following key issues were discussed and respective decision made:

reviewed and approved the Company's 2011 full year operating and financial results;
approved the acquisition as well as the applicable financing of a 49% equity stake in ZAO Nortgas;
recommended a full year dividend for 2011, based on full year financial results, and an interim dividend for first half 2012, based on interim financial results for that period;
approved Russian rouble bond registration with the total nominal value of RR 45 billion;
approved the acquisition of an 82% interest in OOO Gazprom mezhregiongas Kostroma; and
reviewed and approved NOVATEK's business plan for 2013.

60 GROWTH ANNUAL REPORT OAO NOVATEK 2012

EFFICIENCY INNOVATION

MR. ALEXANDER Y. NATALENKO

Born in 1946

Chairman of NOVATEK's Board of Directors

Member of the Audit Committee

Member of the Corporate Governance and Remuneration Committee

Member of the Board of Directors of OAO Rosgeologia

MR. ANDREI I. AKIMOV

Born in 1953

Member of NOVATEK's Board of Directors

Chairman of the Audit Committee

Chairman of the Management Board of "Gazprombank" (OAO)

MR. LEONID V. MIKHELSON

Born in 1955

Member of NOVATEK's Board of Directors

Chairman of the Management Committee

DR. BURCKHARD BERGMANN

Born in 1943

Member of NOVATEK's Board of Directors

Member of the Corporate Governance and Remuneration Committee

Member of the Strategy and Investments Committee

Board Member of the Presidium of the German-Russian Chamber of Commerce

MR. YVES LOUIS CHARLE JUSTIN DARRICARRERE

Born in 1951

Member of NOVATEK's Board of Directors

Member of the Corporate Governance and Remuneration Committee

Executive Vice President of Total S.A.

President of Total Exploration & Production

MR. KIRILL G. SELEZNEV

Born in 1974

Member of NOVATEK's Board of Directors

Member of the Strategy and Investments Committee

Member of the Management Board, Director of Gas and Liquid Hydrocarbons Marketing and Processing Department of OAO "Gazprom"

General Director of OOO "Gazprom Mezhregiongaz"

MR. GENNADY N. TIMCHENKO

Born in 1952

Member of NOVATEK's Board of Directors

Member of the Strategy and Investments Committee

MR. MARK A. GYETVAY

Born in 1957

Member of NOVATEK's Board of Directors

Chairman of the Strategy and Investments Committee

Member and Deputy Chairman of the Management Committee

Chief Financial Officer

MR. RUBEN K. VARDANIAN

Born in 1968

Member of NOVATEK's Board of Directors

Chairman of the Corporate Governance and Remuneration Committee

Member of the Audit Committee

Co-head of Sberbank CIB

Committees membership as of 31 December 2012:

	AUDIT COMMITTEE	STRATEGY AND INVESTMENTS COMMITTEE	CORPORATE GOVERNANCE AND REMUNERATION COMMITTEE
Chairman	Andrei Akimov	Mark Gyetvay	Ruben Vardanian
Members	Ruben Vardanian	Burckhard Bergmann	Alexander Natalenko
	Alexander Natalenko	Yves-Louis Darricarrere	Burckhard Bergmann
		Gennady Timchenko
		Kirill Seleznev

BOARD COMMITTEES

The Company has three Board Committees: the Audit Committee, the Strategy and Investments Committee and the Corporate Governance and Remuneration Committee.

The Committees' activities are governed by the Committees Charters approved by the Board of Directors. The specific terms of reference for each of the Board Committees are available on our website.

The Committees play a vital role in ensuring that the high standards for corporate governance are maintained throughout the Company and that specific decisions are analyzed and the necessary recommendations are issued prior to general Board discussions. The minutes of the Committees meetings are circulated to the Board members and are accompanied by any necessary materials and explanatory notes.

In order to carry out their duties, the Committees may request information or documents from members of the Company's executive bodies or heads of the Company's relevant departments. For the purpose of considering any issues being within their competence, the Committees may engage experts and advisers having necessary professional knowledge and skills.

Strategy and Investments Committee

The primary function of the Strategy and Investments Committee is to develop and give recommendations to the Board for determining of priorities of the Company's operations and assessing the effectiveness of investment projects and their impact on NOVATEK's shareholder value.

In carrying out its responsibilities and assisting the members of the Board in discharging their duties, the Strategy and Investment Committee is responsible for but not limited to:

analyzing concepts, programs, and plans of the Company's strategic development and giving recommendations to the Board;
developing recommendations to the Board with respect to any transactions with assets the value of which exceeds 5% of the Company's assets book value, as calculated in accordance with the accounting data as of the last reporting date;
developing recommendations to the Board following the consideration of investment projects proposed by the Company's executive bodies for implementation; and
developing recommendations to the Board for utilization of the Company's reserves and provisions.

In 2012, the Strategy and Investments Committee met four times.

63 GROWTH EFFICIENCY INNOVATION

Corporate Governance and Remuneration Committee

The primary function of the Corporate Governance and Remuneration Committee is to improve the corporate governance system and to review the Company's practices and policies to ensure compliance of the Company's business practices and internal regulatory documents with applicable standards of corporate governance and Russian and international best practice standards. The Corporate Governance and Remuneration Committee is also responsible for determining the policy for executive remuneration and for the remuneration and benefits of individual executive directors and senior executives as well.

In order to assist the Board, the Committee performs the following functions:

develop and regularly review our corporate governance documents and documents regulating corporate conflicts;
develop recommendations with respect to our dividend policy and distribution;
evaluate the Company's Investor Relations and Shareholder communications polices;
develop procedures for and perform an annual evaluation of the work performed by the Board; and
determine the annual compensation for the Board and the Revision Commission members.

In 2012, the Corporate Governance and Remuneration Committee met four times.

Audit Committee

The primary function of the Audit Committee is the control over financial and business operations of the Company and assistance to the Board in exercising effective control by assessing:

the accuracy, transparency, and completeness of the Company's financial statements prepared in accordance with Russian and International accounting standards;
the candidature of the Company's external auditor;
the independent auditor's report with respect to the Company's annual financial statements;
the efficiency of the Company's internal control procedures and proposals for their improvement.

The Audit Committee works actively with the Revision Commission, external auditor and Company's executive bodies, inviting NOVATEK's managers responsible for the preparation of the financial statements to attend the Committee meetings.

In 2012, the Audit Committee met three times.

MANAGEMENT AND

CORPORATE GOVERNANCE

64 GROWTH ANNUAL REPORT OAO NOVATEK 2012

EFFICIENCY INNOVATION

MANAGEMENT COMMITTEE

NOVATEK's Management Committee is a collegial executive body responsible for the day-to-day management of the Company's operations. The Management Committee is governed by the laws of the Russian Federation, NOVATEK's Charter, decisions of the General Meetings of Shareholders and the Board of Directors and by other internal documents. More information regarding the Management Committee's competence is provided in the Management Committee Regulations approved by NOVATEK's General Meeting of Shareholders in 2005 (Minutes No. 95 of 28 March 2005).

Members of the Management Committee are elected by the Board of Directors from among the Company's key employees. The Management Committee is subordinated to the Board of Directors and the General Meeting of Shareholders. Chairman of the Management Committee is responsible for leading the Committee and ensuring its effectiveness as well as organizing the Management Committee meetings and implementing decisions of the General Meeting of Shareholders and the Board. The Management Committee is currently comprised of eight members elected by the Board of Directors (Minutes No. 118 of 3 December 2009 and Minutes No. 113 of 24 March 2011). The Chairman of the Management Committee is Leonid Viktorovich Mikhelson.

Leonid Mikhelson	Chairman
Mikhail Popov	First Deputy Chairman, Commercial Director
Vladimir Baskov	Deputy Chairman
Alexander Fridman	Deputy Chairman
Mark Gyetvay	Deputy Chairman, Chief Financial Officer
Tatyana Kuznetsova	Deputy Chairman, Director of the Legal Department
Iosif Levinzon	Deputy Chairman
Kirill Yanovskiy	Director for Finance and Strategy

Management Committee of NOVATEK as at 31.12.2012

Remuneration paid to members of the Board of Directors and Management Committee

	BOARD OF DIRECTORS(1)	MANAGEMENT COMMITTEE
Total paid, including:	105.5	1,297.5
Salaries	-	495.8
Bonuses	-	786.5
Fees	105.0	-
Other property advancements	0.5	15.2

(1) Some members of NOVATEK's Board of Directors are simultaneously members of the Management Committee. Payments to such members in relation to their activities as members of the Management Committee are included in the total payments to members of the Management Committee.

REMUNERATION TO MEMBERS OF THE BOARD OF DIRECTORS AND MANAGEMENT COMMITTEE

The procedure for and criteria of calculating remuneration to members of NOVATEK's Board of Directors, as well as the compensation of their expenses, are prescribed in the Company's Charter and Regulations on NOVATEK's Board of Directors.

The procedure for and criteria of calculating remuneration to the Chairman and members of NOVATEK's Management Committee, as well as the compensation of their expenses, are prescribed in the Regulations for the Management Committee and the employment contracts they sign with the Company.

INTERNAL CONTROL AND AUDIT

The Company has a system of internal control over financial and business operations with the respect to modern international best practices. The system of internal control consists of the Audit Committee, the Revision Commission, the Chairman of the Management Committee, the Management Committee, the Company's management and the Internal Audit Division.

The objects of internal control are OAO NOVATEK, its subsidiaries and joint ventures, and their subdivisions, as well as their activities.

The goals, objectives and internal control procedures are established by the Regulations on NOVATEK's Internal Control, approved by the Board of Directors (Minutes No. 114 of 31 August 2009).

Revision Commission

Revision Commission consisting of four members is elected at the Annual General Meeting of Shareholders for a period of one year. The competence of the Revision Commission is governed by the Russian Federation Law On Joint Stock Companies No. 208-FZ as well as the Company's Charter and the Regulations on the Revision Commission Procedures approved by the General Meeting of Shareholders (Minutes No. 95 of 28 March 2005).

The Revision Commission is an internal control body responsible for oversight of the Company's financial and business activities, management bodies, officers, divisions, departments, branches, and representative offices. The Revision Commission audits the Company's financial and business performance for the year, as well as for any other period as may be decided by its members or other persons authorized in accordance with Russian Federation law and the Regulations for NOVATEK's Revision Commission. The results are presented in the form of revisions Auditing Commission.

In 2012, the Revision Commission held one documentary revision of financial and business activity of the Company for the year 2011. As a result the conclusions about the reliability of the data contained in the Company's 2012 Financial Statements and 2012 Annual Report were prepared and submitted to the Annual General Meeting of Shareholders.

Internal Audit Division

NOVATEK's Internal Audit Division is working on raising assurances to achieve the strategic goals of the Company and effectiveness of its corporate governance. The Internal Audit Division is guided by the Code of Ethics of the Institute of Internal Auditors and International internal audit standards.

The Division reports directly to the Chairman of the Management Committee and the Audit Committee. The Internal Audit Division operates on the basis of the annual strategic schedule of revisions based on risk assessment and the approval of the Chairman of the Management Committee and annually provides to the Chairman of the Management Committee and the Audit Committee the results of its activities.

In performing its functions, the Internal Audit Division is guided by the principles of independence and objectiveness. NO-VATEK's internal standards envisage full access of the Internal Audit Division employees to all functions, records, property and personnel of the Company in implementing their audit tasks.

According to the results of audits, the Division develops plan-actions to eliminate identified risks and to implement proposals for optimization of the financial and business activity.

External Auditor

The Annual General Meeting of Shareholders appoints an external auditor to conduct independent review of NO-VATEK's financial statements. The Audit Committee gives recommendations to

the Company's Board of Directors regarding the candidatures of external auditors and the price of their services. Based on the Committee's recommendations, the Board proposes the auditor's candidature for the consideration and for approval by the Annual General Meeting of Shareholders.

ZAO PricewaterhouseCoopers Audit was approved as the Company's external auditor to conduct independent audit of the Company's financial statements for 2012.

In selecting the auditor's candidature, attention shall paid to level of their professional qualifications, independence, possible risk of any conflict of interest, terms of the contract, and an amount of remuneration requested by the candidates. The Audit Committee oversees the external auditor's independence and objectivity as well as the quality of the audit conducted. The Committee annually provides to the Board of Directors the results of review and evaluation of the audit opinion regarding the Company's financial statements. The Audit Committee meets with the auditor's representatives at least once per year.

NOVATEK's management is aware of and accepts recommendations on independence of the external auditor by placing certain restrictions on such auditor's involvement in providing non-audit services. Remuneration paid to the principle auditors for auditing and other services is specified in the Note 22 to the consolidated financial statements prepared in accordance with IFRS standards for 2012.

SHARE CAPITAL

Our share capital is RR 303,630,600 and consists of 3,036,306,000 ordinary shares, each with a nominal value of RR 0.1. As of 31 December 2012, NOVATEK did not have privileged shares.

Our shares are traded in US dollars and Russian roubles on the MICEX-RTS Stock Exchange and have an A1 listing (symbol: NVTK).

The Federal Financial Market Service issued to NOVATEK a permit for circulation beyond Russian Federation of 910,589,000 ordinary shares comprising 29.99% of the Company's share capital.

Our Global Depositary Receipts (GDR) are listed on the London Stock Exchange (symbol: NVTK). Each GDR represents 10 ordinary shares. As of 31 December 2012, NO-VATEK's GDRs were issued on 910,588,780 ordinary shares comprising 29.99% of the Company's share capital.

Equity stakes in NOVATEK's share capital and the number of shares owned by members of the Board of Directors and Management Committee

	EQUITY STAKE AS OF 31 DECEMBER 2012(1), %	NUMBER OF SHARES
Board of Directors
Alexander Natalenko	-	-
Andrei Akimov	-	-
Burckhard Bergmann	-	-
Ruben Vardanian	-	-
Mark Gyetvay	-	-
Yves-Louis Darricarrere	-	-
Leonid Mikhelson	0.6754	20,506,542
Kirill Seleznev	-	-
Gennady Timchenko	-	-
Management Committee
Vladimir Baskov	0.0288	874,408
Alexander Fridman	0.0817	2,481,049
Tatyana Kuznetsova	0.1944	5,903,035
Iosif Levinzon	-	-
Mikhail Popov	0.1440	4,372,038
Kirill Yanovskiy	0.1051	3,192,530

(1) The equity stakes are given based on the records in the register of NOVATEK's shareholders in accordance with the Russian Federation laws.

68 GROWTH ANNUAL REPORT OAO NOVATEK 2012

EFFICIENCY INNOVATION

6.86 RR PER SHARE

RECOMMENDED DIVIDEND FOR 2012

DIVIDENDS

NOVATEK's dividend policy is based on keeping the balance between the Company's business goals and shareholder's interests. A decision to pay dividends as well as the size, payout time and form of the dividend is passed by the Annual General Meeting of Shareholders according to the recommendation of the Board of Directors. Dividends are paid twice a year; their size depends on market conditions, cash flow and the Company's capital structure and investment program. NOVATEK is strongly committed to its dividend policy.

On 19 March 2013, the Board of Directors of OAO NOVATEK recommended to the Annual General Meeting of Shareholders to pay dividends for FY 2012 in the amount of RR 3.86 per ordinary share or RR 38.6 per one Global Depositary Receipt (GDR), exclusive of RR 3.0 of interim dividends per ordinary share or RR 30.0 per one GDR for the first six months of 2012.

Thus, should the General Meeting of Shareholders approve the above recommended dividend, the dividends for 2012 will total RR 6.86 per ordinary share (RR 68.6 per one GDR), and the total amount of dividends payable for 2012 will be RR 20,829,059,160.

The amount of paid dividends accrued for the years 2007 to 2011, and for the first six months of 2012 is reported as of 31 December 2012 in the table below. Partial payment of the accrued dividends was made due to provision by shareholders (nominee holders) of incorrect postal and/or banking details and insufficient information regarding banking or postal details of shareholders.

Accrued and paid dividends on NOVATEK shares for the period from 2007 to 2012

DIVIDEND ACCRUAL PERIOD	AMOUNT OF DIVIDENDS, RR PER SHARE	TOTAL AMOUNT OF DIVIDENDS ACCRUED, RR	TOTAL AMOUNT OF DIVIDENDS PAID, RR
2007	2.35	7,135,319,100	7,135,293,833
2008	2.52	7,651,491,120	7,651,310,957
2009	2.75	8,349,841,500	8,349,681,894
2010	4.00	12,145,224,000	12,144,967,156
2011	6.00	18,217,836,000	18,217,663,073
First 6 months of 2012	3.00	9,108,918,000	9,108,864,267

INFORMATION TRANSPARENCY

NOVATEK is committed to providing objective, reliable, and consistent information about the Company and its activities to all stakeholders and also complies with modern standards for information disclosure while adhering to a maximum level of transparency. The Regulations on Information Policy approved by the Board of Directors (Minutes No. 45 of 10 May 2005), define main principles for disclosing information and increasing information transparency.

Material information about the Company is disclosed in a timely manner in the form of press releases through authorized disclosure in accordance with the applicable laws of Russian Federation and United Kingdom. The Company discloses quarterly financial statements in accordance with the International Financial Reporting Standards ("IFRS"), Management's Discussion and Analysis of Financial Condition and Results of Operations as well as various presentations for investors.

In addition to press releases and material facts, the Company's website provides detailed information on all aspects of its activities, including our Sustainability Report. We regularly participate in information disclosure on greenhouse gas emissions and energy efficiency of production – the Carbon Disclosure Project (CDP), and on the use of water resources – the CDP Water Disclosure Project, as well as other industry's publications and studies.

The Company maintains an ongoing dialogue with shareholders and investors in

order to ensure full awareness of investment community about its activities.

The main channels of communication with the investment community are through the Chairman of the Management Committee, Deputy Chairman (the Chief Financial Officer) and the Investor Relations department. The Company's representatives meet on a regular basis with key financial audiences to discuss issues of interest to them.

In accordance with principles of its unified information policy, NOVATEK conducts an active, ongoing dialog with representatives of media outlets. The information disclosed to mass media comprises all aspects of the Company's activities, including financial and operating results and projects under development, as well as socially or environmentally important aspects.

NOVATEK actively involves in a variety of outside Exhibitions and Conferences.

During 2012, representatives of the Company participate in more than 15 exhibitions, conferences and round tables and gave seven presentations on key industry issues. One of the most important events was the Second International Conference – Yamal LNG starts marine transportation LNG in Arctic, which was organized by NOVATEK. According to the conference participants, among which were heads of the relevant Russian ministries and institutions as well as scientists and businessmen from Russia, Europe and the Asian-Pacific Region, the conference was highly organized.

ADDITIONAL INFORMATION

MAJOR RISK FACTORS

The risks provided herein are by no means exhaustive and only reflect the Company's own opinions and estimates.

Industry Risks

The major risks associated with the Russian domestic gas market are largely attributable to the extensive government regulation of prices for natural gas sold on the domestic market as well as Gazprom's dominant position in the industry.

The following factors may adversely affect the Company's operations, or its financial and economic performance:

Government regulation of natural gas sales prices on the domestic market for Gazprom companies;
Dependence on throughput capacity of trunk pipelines;
Potential increases in government-regulated tariffs for pipeline transportation of natural gas and crude oil as well as railway transportation;
Decline in world prices for liquid hydrocarbons;
The Company's dependence on OAO AK Transneft and OAO Russian Railways for the use of liquid hydrocarbons' distribution networks; and
Increasing competition in the Russian natural gas industry from independent natural gas producers and vertically integrated companies.

NOVATEK implements specific measures to minimize the potential impact of industry risks. In particular, the Company is actively building productive partnerships with key service suppliers, expanding its customer base, actively searching for purchasers of natural gas at agreed prices and entering into long-term contracts with them.

In addition, NOVATEK strives to diversify its marketed product line to include gas condensate, crude oil and petroleum derivatives, along with the marketing of natural gas.

Country and Regional Risks

NOVATEK is a Russian company operating in a number of Russian regions.

Country risk is defined by the fact that Russia is still an emerging economy. Despite the positive trend in the Russian economy; strong GDP growth, political stability, improving living standards, etc., the country's economy is still developing.

The Russian economy is commodity-based and oriented towards export of raw materials, which explains the dependence of the country's industrial output on the demand for raw materials in world markets.

The Company produces and processes hydrocarbons on the territory of Western Siberia, a region with a challenging climate. The Company's vulnerability to region-specific impacts is insignificant and is completely accounted for through the management of the Company's financial and economic operations. The Company has built an efficient system of interaction between its production and marketing units and its principal production facilities are concentrated in close proximity to the transportation networks in use.

Risks related to possible military conflicts, state of emergency announcements, or strikes, are non-existent, as the Company operates in economically and socially stable regions.

Financial Risks

NOVATEK's financial performance is subject to financial risks associated with the fluctuation of foreign currency exchange rates, as the Company borrows funds in foreign denominated currencies and markets a portion of its products internationally.

With respect to the fluctuation of the Russian rouble in relation to other currencies, the marketing of products internationally substantially extensively reduces this risk and balances out the adverse effects of the national currency's exchange value fluctuations. The inflow of export profits will secure mainly payment of outstanding amounts due therefore, currency risks will not substantially impact the Company's operations.

In the case of an interest rate decline, repayment of outstanding amounts on existing loans and credits may become less attractive in comparison with current offers in the loan market. In this event, the Company will undertake to replace existing debt facilities with current market offers on better terms and conditions, including borrowing costs.

Overall interest rate growth may affect the Company's borrower liabilities, subject to change under specific conditions. The resulting dynamic behavior in the borrowed funds value restricts their use as a source of funds throughout "expensive loan" periods.

Interest rate shifts in specific sectors of the debt market will result in the Company diversifying its funding sources and switching to market sectors with more attractive financial resources.

Commodity Price Risks

Commercial trading strategy for natural gas, stable gas condensate, LPG, crude oil and related oil products is centrally managed in the Company. Changes in commodity prices could negatively or positively affect the Company's results of operations.

As an independent natural gas producer, NO-VATEK is not subject to the government's regulation of natural gas prices. Nevertheless, the Company's prices are strongly influenced by the prices regulated by the Federal Tariffs Service (FTS), a governmental agency.

The Company sells all of its crude oil and gas condensate under spot contracts. Gas condensate volumes sold to the US, European, South America and Asian Pacific markets are based on benchmark reference prices of light oil WTI and Brent or naphtha. Crude oil sold internationally is priced based on benchmark reference crude oil prices of Brent, plus a margin or a discount and on a transaction-by-transaction basis for volumes sold domestically. As a result, NOVATEK's revenues from the sales of liquid hydrocarbons are subject to commodity price volatility based on fluctuations or changes in benchmark reference prices. Presently, the Company does not use commodity derivative instruments for trading purposes to mitigate price volatility.

Credit Risk

Credit risk refers to the risk exposure of the Company to a potential financial loss due to the default of counterparties on their contractual obligations. NOVATEK mitigates credit risk through the management of its cash and cash equivalents, including short-term deposits with banks, as well as credit exposure to customers, including outstanding trade receivables and committed transactions. Cash and cash equivalents are deposited only with banks that are considered by the Company at the time of deposit to have minimal risk of default.

The Company's trade and other receivables consist of a large number of customers, spread across diverse industries and geographical areas. Most of NOVATEK's international liquid sales are made to customers with independent

external ratings. Almost all domestic sales of liquid hydrocarbons are made on a 100 percent prepayment basis. Although the Company does not require collateral in respect of trade and other receivables, it has developed standard credit payment terms and constantly monitors the status of trade receivables and the creditworthiness of the customers.

Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company's approach to managing liquidity risk is to ensure that it will always have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Company's reputation. In managing its liquidity risk, NOVATEK maintains adequate cash reserves and debt facilities, continuously monitors forecasted and actual cash flows and matches the maturity profiles of financial assets and liabilities. The Company prepares various financial plans (monthly, quarterly and annually), which ensures that the Company has sufficient cash on demand to meet expected operational expenses, financial obligations and investing activities for a period of 30 days or more. The Company has also entered into a number of short-term credit facilities, such as credit lines and overdraft facilities, which can be drawn down to meet short-term financing needs. To fund cash requirements of a more permanent nature, the Company will normally raise long-term debt in international and domestic markets.

Inflation Risks

The change in the consumer price index has an impact on NOVATEK's profitability and as a consequence, its financial standing and ability to pay on liabilities and securities.

This factor is not considered a major risk to our business due to the fact that the tariff policy of the Russian Federation contemplates a gradual increase in the domestic gas prices commensurate with the growth in inflation rates.

NOVATEK may not be able to predict the inflation level, since apart from the consumer price level, it is necessary to take into account the change in real purchasing power of the Russian rouble, the pricing conditions in liquid hydrocarbon export markets and the government policy in relation to tariffs for natural gas.

NOVATEK monitors the consumer price index and takes this factor into account when determining its selling prices.

Risks Related to the Impact of the Global Financial Crisis

The main risks relating to the impact of global financial crisis are Russian rouble devaluation and a decrease in demand for natural gas as a result of a decline in Russian industrial output.

A staged increase of the regulated domestic price for natural gas planned by the Russian government, combined with foreign currency denominated revenue received from export sales of liquids and cost reduction due to the decrease of domestic prices for materials and services, mitigate the consequences of potential Russian rouble devaluation for NOVATEK.

The search for new customers along with provision of more flexible terms and conditions to existing contracts and stable demand from our main end-customer segment, public utilities, enable the Company to compensate for the slump in the domestic demand for natural gas from industrial consumers.

Legal Risks

The Company's operations are susceptible to risks resulting from changes in the statutory regulation of the following spheres:

Currency laws (in areas concerning export/import and borrowings operations);
Tax laws (in areas regulating taxation systems and rates applicable to companies in general, and to companies marketing natural gas and liquid hydrocarbons, specifically);
Customs laws (in areas concerning the export of liquid hydrocarbons and their derivatives);
Licensing requirements for natural resource extraction.

Operational Risks

The Company is not involved in any significant litigation and the risks pertaining to such litigation are minor.

The Company and its affiliates hold long-term field development licenses.

Certain risks exist for the Company's operations associated with field exploration and development. Exploration drilling incorporates multiple risks, including the risk of non-availability of commercial reserves. Information on the Company's fields' reserves is provided as estimated, subject to certain factors and assumptions. Actual production volumes across fields, along with the cost-effectiveness of reserve exploitation, may deviate from estimated figures.

The Company's operations require substantial investment into field exploration and development, followed by the production, transportation, and processing of natural gas, oil, and gas condensate. Insufficient funding for these and other expenditures may affect the Company's financial standing and performance results.

Risk Insurance

Risk insurance is an integral part of NOVATEK's risk management system. In 2012, the insurance coverage guaranteed adequate protection against the risks of damage to our business. Insurance is provided by reputable domestic insurance companies that have the highest insurance ratings in Russia (Standard & Poor`s BBB-/ Stable on National Scale: ruAA +) with risk reinsurance by major international insurance companies.

The Company fully complies with the applicable legal requirements in terms of mandatory insurance, such as third-party liability insurance of owners of hazardous facilities and vehicles.

To reduce the risks of financial losses the Company utilizes the following voluntary insurance products:

Insurance of the risk of damage/loss of property;
Management liability insurance.

The risks of damage/loss of property resulting from accidents are fully insured. Full cost recovery with a franchise is in place. Following the assessments made in 2011 we insured our production equipment on new terms providing for better coverage of risks. Since 1 January 2012 the property insurance is applied at replacement cost, which results in better compensation of potential damages. For more than 7 years NOVATEK has procured its top management liability insurance against possible claims by third parties for any losses incurred through wrong actions or decisions. The overall limit on such insurance coverage is 150 million U.S. dollars.

In 2012, the Company began developing a comprehensive program for business interruption insurance. The new program is estimated to cover all of our main producing entities.

GROWTH EFFICIENCY INNOVATION

INFORMATION ON MEMBERS OF NOVATEK'S BOARD OF DIRECTORS AND MANAGEMENT COMMITTEE

MR. ALEXANDER Y. NATALENKO Born in 1946

Chairman of NOVATEK's Board of Directors and member of its Audit Committee and its Corporate Governance and Remuneration Committee

Mr. Natalenko completed his studies at the Irkutsk State University in 1969 with a primary focus in Geological Engineering. Subsequently, he worked with the Yagodinskaya, Bagdarinskaya, Berelekhskaya, Anadirskaya and East-Chukotskaya geological expeditions. In 1986, Mr. Natalenko headed the North-East Industrial and Geological Association and, in 1992, he was elected president of АО "Magadan Gold & Silver Company". He subsequently held various executive positions in Russian and foreign geological organizations. From 1996 to 2001, Mr. Natalelnko held the position of Deputy Minister of Natural Resources of the Russian Federation. He is a member of the Board of Directors of ZAO GC VERTEX. In 2012, Mr. Natalenko was elected member of the Board of Directors of OAO Rosgeologia.

Currently, Mr. Natalenko is Chairman of NOVATEK's Board of Directors. He is also a member of the Audit Committee and Corporate Governance and Remuneration Committee of NOVATEK's Board of Directors.

Mr. Natalenko is the recipient of the State Prize of the Russian Federation and an Honored Geologist of Russia.

MR. LEONID V. MIKHELSON Born in 1955

Member of NOVATEK's Board of Directors, Chairman of NOVATEK's Management Committee

Mr. Mikhelson received his primary degree from the Samara Institute of Civil Engineering in 1977, where he specialized in Industrial Civil Engineering. That same year, Mr. Mikhelson began his career as foreman of a construction and assembling company in Surgut, Tyumen region, where he worked on the construction of the first section of Urengoi-Chelyabinsk gas pipeline. In 1985, Mr. Mikhelson was appointed Chief Engineer of Ryazantruboprovodstroy. In 1987, he became General Director of Kuibishevtruboprovodstroy, which in 1991, was the first company in the region to sell its shares and became a private company, AO SNP NOVA. Mr. Mikhelson remained SNP NOVA's Managing Director from 1987 through 1994. Subsequently, he became a General Director of the management company "Novafininvest".

Since 2002, Mr. Mikhelson has served as a member of the Board of Directors and Chairman of the Management Committeeof NOVATEK. From March 2008 to December 2010, he has been a member of the Board of Directors of OAO Stroytransgas. From 2009 to 2010 he was the Chairman of the Board of Directors of ОАО Yamal LNG and from 2008 to 2011 he was a member of the Board of Directors of OOO Art Finance. He is the Chairman of the Board of Directors of ZAO SIBUR Holding and a member of the Supervisory Board of the OAO Russian Regional Development Bank. Mr. Mikhelson is the recipient of the Russian Federation's Order of the Badge of Honor.

MR. ANDREI I. AKIMOV Born in 1953

Chairman of the Management Board of "Gazprombank" (OAO), Member of NOVATEK's Board of Directors and Chairman of its Audit Committee

Mr. Akimov graduated from the Moscow Financial Institute in 1975 where he specialized in international economics. Between 1974 and 1987, Mr. Akimov held various executive positions in the Bank of Foreign Trade ("Vneshtorgbank") of the USSR. From 1985 to 1987 he served as Deputy General Director of Vneshtorgbank's branch in Zurich (Switzerland) and between 1987 and 1990, Mr. Akimov headed Donau Bank in Vienna (Austria). From January 1991 to November 2002 he was Managing Director of financial company, IMAG GmbH Vienna (Austria) and, at the same time, served as an Advisor to the Chairman of Vneshtorgbank. Since 2003, Mr. Akimov has been the Chairman of the Management Committee of Gazprombank (OAO). He is a member of the Board of Directors of ZAO Gerosgaz, Carbon Trade & Finance SICAR S.А. and Chairman of the Supervisory Board of Gazprombank (Switzerland) Ltd. Since June 2011, Mr. Akimov has been a member of the Board of Directors of OAO Gazprom and since October 2011, he has been the Chairman of the Board of Directors of ОAO Rosneftegaz. Currently, he is a Chairman of the Audit Committee of OAO NOVATEK.

DR. BURCKHARD BERGMANN Born in 1943

Member of NOVATEK's Board of Directors, its Corporate Governance and Remuneration Committee and its Strategy and Investments Committee, Board Member of the Presidium of the German-Russian Chamber of Commerce, Member of the Advisory Board of the Union of German Science Funds

Dr. Bergmann studied physics at the Freiburg and Aachen Universities from 1962 to 1968 and was awarded a Doctorate in Engineering by Aachen University of Technology in 1970. From 1968 to 1969, Dr. Bergmann worked at the German Federal Ministry for Research and Technology and from 1969 to 1972 – at the J lich Nuclear Research Center. In 1972, Dr. Bergmann joined Ruhrgas AG (from 1 July 2004 – E.ON Ruhrgas AG), heading the LNG Purchasing Department. In 1978, he became Head of the Gas Purchasing Division responsible for gas purchasing, commercial aspects of gas transmission and storage. In 1980, he was elected as a member of the Management Board of E.ON Ruhrgas AG, serving from June 1996 as its Vice-Chairman and from June 2001 to February 2008 as its Chairman. From March 2003 to February 2008 he was also a member of the Management Board of E.ON AG.

Dr. Bergmann is also a member of the Board of Directors (Supervisory Board) of: Allianz Lebensversicherungs-AG, Commerzbank AG, Contilia GmbH, Telenor ASA. In addition, he is a member of the Advisory Boards for Dana Gas International, IVG Immobilien AG. He has been elected as Chairman of the Advisory Board of Jaeger Grund und Dienste GmbH& Co KG and

member of the Board of Trustees of RAG Foundation since 2012.

Dr. Bergmann holds the following distinctions: Commander of the Royal Norwegian Order of Merit (1997); Honorary Consul of the Russian Federation in the State of North Rhine-Westphalia a Foreign Member of the Academy of Technological Sciences of the Russian Federation (2003); Order of Merit of the State of North Rhine-Westphalia (2004) as well as a winner of Director of the Year, Moscow (2007). In June 2011, by means of presidential Decree he became a recipient of the Order of the Friendship of Peoples award for significant contribution in development of the Russian-German relations.

MR. RUBEN K. VARDANIAN Born in 1968

Member of NOVATEK's Board of Directors, Chairman of its Corporate Governance and Remuneration Committee and member of its Audit Committee

Ruben Vardanian is Co-head of Sberbank CIB. Prior to closing the deal to merge Sberbank of Russia and Troika Dialog in January 2012 he was Chairman of the Board of Directors of Troika Dialog, where he was working since its foundation.

Mr. Vardanian is a Board member of several companies: OAO AvtoVAZ, OAO KAMAZ, OAO NOVATEK, OAO SIBUR Holding, Joule Unlimited, Inc (a pioneer in production of renewable fuel based on solar energy) and others. He is also Board Chairman of several companies: OAO Rosgosstrakh, ZAO AmeriaBank

Mr. Vardanian is Co-founder of the Moscow-based Skolkovo School of Management and is represented on its Coordinating Council. The school was established on the initiative of Mr. Vardanian and several Russian businessmen. Between 2006 and 2011, Mr. Vardanian was President of the Skolkovo School of Management.

Mr. Vardanian is also a member of the President's Council on Implementation of National Projects and Demographic Policy, President's International Advisory Committee on Establishment of International Financial Center in the Russian Federation. He is a member of the RF Government's Competition and Entrepreneurship Council.

The World Economic Forum (Davos) included Mr. Vardanian in a list of "100 future world leaders". He was also included in the Top-22 Business Leaders of Russia for three consecutive years (rating by the "Kommersant" newspaper and Managers Association).

Mr. Vardanian, graduated with honors from Moscow State University with a degree in Economics. In 2000, he also completed executive management courses at INSEAD (Fontainebleau, France) and, in 2001 and 2005, he completed the courses at Harvard Business School (USA).

MR. MARK A. GYETVAY Born in 1957

Member of NOVATEK's Board of Directors and Chairman of its Strategy and Investments Committee, Member and Deputy Chairman of NOVATEK's Management Committee Chief Financial Officer

Mr. Gyetvay studied at Arizona State University (Bachelor of Science, Accounting, 1981) and later at Pace University, New York (Graduate Studies in Strategic Management, 1995). After graduation, Mr. Gyetvay worked in various capacities at a number of independent oil and gas companies (Champlin Petroleum Co., Texas, Ensource Inc. and MAG Enterprises, Colorado, and Amerada Hess Corporation, New Jersey) where he specialized in financial and economic analysis for both upstream and downstream segments of the petroleum industry.

In 1994, Mr. Gyetvay began his work at Coopers and Lybrand, as Director, Strategic Energy Advisory Services. He subsequently moved to Moscow in 1995 with Coopers & Lybrand to lead the oil and gas practice. He was admitted as a partner of PricewaterhouseCoopers Global Energy where he assumed the role of client service engagement partner, Utilities and Mining practice, based in Russia (Moscow office). Mr. Gyetvay was an engagement partner on various energy and mining clients providing overall project management, financial and operational expertise, maintaining and supporting client service relationships as well as serving as concurring partner on transaction services to the petroleum sector.

Mr. Gyetvay is a Certified Public Accountant, a member of the American Institute of Certified Public Accountants and an associate member of the Society of Petroleum Engineers.

In 2003, Mr. Gyetvay became a member of NOVATEK's Board of Directors and is also a Chairman of the Strategy and Investments Committee of NOVATEK's Board of Directors. Since 2004–2008, he has been Chief Financial Officer and, in August 2007, Mr. Gyetvay was elected to NOVATEK's Management Committee and, in July 2010, he became Deputy Director of NOVATEK's Management Committee.

MR. YVES LOUIS CHARLE JUSTIN DARRICARRERE Born in 1951

Executive Vice President, Total S.A., President, Total Exploration & Production, Member of NOVATEK's Board of Directors and its Corporate Governance and Remuneration Committee

After two years lecturing at the Ecole Nationale Superieure des Mines de Paris, Yves-Louis Darricarrere began his career in Elf Aquitaine in 1978, first in the Mining Division in Australia and later in the Exploration & Production Branch, where he was appointed successively Country Representative for Australia and Egypt at head office; Managing Director of the subsidiaries in Egypt and Colombia; Director Business development and new ventures, then Finance Director of the Exploration & Production Branch and of the Oil and Gas directorate. In 1998, he was appointed Deputy Director-General of Elf Exploration-Production responsible

for Europe and the United States and was nominated a member of the Management Committee of Elf-Aquitaine.

In 2000, he was appointed Senior Vice-President for Exploration & Production Northern Europe and became a member of the Total Group Management Committee.

On 1 September 2003, Yves-Louis Darricarrere was nominated to the Group's Executive Committee and was appointed President of Total Gas & Power, and on 14 February 2007, he became President of Total Exploration & Production.

Yves-Louis Darricarrere is a graduate of the Ecole Nationale Superieure des Mines and the Institut d'Etudes Politiques in Paris and holds a master's degree in economic science. He is Chevalier de la Legion d'Honneur (Knight of the French Legion of Honour).

MR. KIRILL G. SELEZNEV Born in 1974

Member of the Management Board, Director of Gas and Liquid Hydrocarbons Marketing and Processing Department of OAO "Gazprom", General Director of OOO Gazprom Mezhregiongaz, Member of NOVATEK's Board of Directors and its Strategy and Investments Committee

Mr. Seleznev graduated from the D.F. Ustinov Baltic State Institute of Technology in 1997 and, in 2002, received a degree in Finance and Credit from the St. Petersburg State University. Upon completion of his university studies, Mr. Seleznev managed OOO "Baltic Finance Company", OAO Investment and Financial Group "Management Investments Development" and OAO "St. Petersburg Sea Port", all of which are located in St. Petersburg, Russia. In 2000, Mr. Seleznev was appointed as Chief of the Tax Group at ОАО "Baltic Pipeline System", St. Petersburg, Russia. Between 2001 and 2002, Mr. Seleznev held the position of Deputy Chief of Staff of the Management Board and Assistant to Chief Executive Officer of OAO Gazprom, in Moscow, Russia. Since 2002, he has been the head of the Gas and Liquid Hydrocarbons Marketing and Processing Department of OAO Gazprom and a Member of the OAO Gazprom Management Board. Since 2003, Mr. Seleznev has been the General Director of OOO Gazprom Mezhregiongaz.

Mr. Seleznev is also a member of the Board of Directors and Supervisory Board of several other entities. Since 2006, Mr. Seleznev has been a member of NOVATEK's Board of Directors.

MR. GENNADY N. TIMCHENKO Born in 1952

Member of NOVATEK's Board of Directors and its Strategy and Investments Committee

In 1976, Mr. Timchenko graduated with a Masters of Science from the Mechanical University in Leningrad. He began his career at the Izjorskii Factory in Leningrad, an industrial plant which made components for the energy industry. Between 1982 and 1988, he was a Senior Engineer at the Ministry of Foreign Trade. Mr. Timchenko has more than 20 years of experience in Russian and International

energy sectors and he has built interests in trading, logistics and transportation related companies.

In 1988, Mr. Timchenko became a vice president of Kirishineftekhimexport, the export and trading arm of the Kirishi refinery in the Leningrad region. In 1991, he worked for Urals Finland which specialized in oil and petrochemical trading. Between 1994 and 2001, Mr. Timchenko was managing Director of IPP OY Finland and IPP AB Sweden. In 1997, he co-founded Gunvor, a leading independent oil-trading company. Mr. Timchenko was a member of the Board of Directors of OOO Transoil and OOO BalttransService. Since 2009, he has been a member of NOVATEK's Board of Directors. Mr. Timchenko is also the Chairman of the Board of Directors and President of the Ice Hockey Club SKA St-Petersburg, as well as the Chairman of the Board of Directors of OOO Kontinental Hockey League.

MR. VLADIMIR A. BASKOV Born in: 1960

Deputy Chairman of NOVATEK's Management Committee

In 1986, Mr. Baskov graduated from the Moscow Higher Police School of the USSR. In 2000, he completed courses at the Management Academy at the Russian Ministry for Internal Affairs. From 1981 to 2003, he served in various departments within the Russian Ministry for Internal Affairs. From 1991 to 2003, Mr. Baskov held managerial positions within the aforementioned Ministry's organizational structures. In 2003 he was appointed Director of the Business Support

Department for NOVATEK. In 2005 he was appointed Deputy Chairman of NO-VATEK's Management Committee and in August 2007 he became a member of NOVATEK's Management Committee. Candidate of Legal Sciences. He was awarded the Order For Personal Courage, the Russian Federation's Order of the Badge of Honor and other state and departmental awards: Honorary Diplomas of the President of the Russian Federation, the Ministry of Internal Affairs, the Governor of the Moscow Region. He also has the awards of the Russian Orthodox Church (Order of Holy Prince Daniel of Moscow and a medal of St. Sergius).

MRS. TATYANA S. KUZNETSOVA Born in: 1960

Deputy Chairman of NOVATEK's Management Committee, Director of NO-VATEK's Legal Department

Ms. Kuznetsova graduated from the Far East State University with a degree in Law. From 1986, she was Senior Legal Advisor for a legal bureau. In 1993, Ms. Kuznetsova became Deputy General Director for Legal Issues and from 1996, Marketing Director for OAO Purneftegasgeologiya. In 1998, she was appointed Deputy General Director of OAO Nordpipes. Since 2002, she has been Director of the Legal Department for NOVATEK. Since 2005, she has been the Deputy Chairman of NOVATEK's Management Committee – Director of NOVATEK's Legal Department and in August 2007, she became a member of NOVATEK's Management Committee.

MR. IOSIF L. LEVINZON Born in: 1956

Deputy Chairman of NOVATEK's Management Committee

Mr. Levinzon graduated from the Tyumen Industrial Institute specializing in geology and is a Candidate of Geological and Mineralogical Science. He continued postgraduate studies in Perm State Technical University. From 1978 to 1987, he was the Head of the Urengoy oil expedition and from 1987 to 1996 he was the General Director of Purneftegasgeologiya. From 1996 to 2005, Mr. Levinzon was the Deputy Governor, 1st Deputy Governor and Vice-Governor of the Yamal-Nenets Autonomous Region. From 2005 to 2006, Mr. Levinzon was an Advisor to the Chairman of the Federation Council of the Federal Assembly of the Russian Federation. From 2006 to 2009, Mr. Levinzon was an Advisor on Corporate and Strategic Development at ZAO OSTER and also at ZAO Investgeoservis. Since August 2009, Mr. Levinzon held the position of Deputy Chairman of NOVATEK's Management Committee and in December 2009 he was elected a member of NOVATEK's Management Committee. Mr. Levinzon is a recipient of the Honored Geologist of Russia, the Order of the Badge of Honor and the Order of the Friendship of Peoples awards and has been awarded the Certificate of Merit from the Governor of the Yamal-Nenets Autonomous Region.

MR. MIKHAIL V. POPOV Born in: 1969

First Deputy Chairman of NOVATEK's Management Committee, Commercial Director

Mr. Popov studied at the Gubkin State Academy of Oil and Gas until 1992 and in 1994, graduated from the Kiev Institute of National Economy. In 1992, he held the position of Deputy Chairman of AO Bankomsvyaz's Managing Committee (Kiev). In 2002, he was appointed Director of the Capital Construction Department and Deputy General Director of OAO Novafininvest. From 2003, Mr. Popov served as Director of Crude Oil and Oil Products Department of OAO NOVATEK. In 2004, Mr. Popov was elected First Deputy Chairman of NOVATEK's Management Committee. Since August 2007, he has been a member of the Management Committee and since May 2011, he has been NOVATEK's First Deputy Chairman-Commercial Director.

MR. ALEXANDER M. FRIDMAN Born in: 1951

Deputy Chairman of NOVATEK's Management Committee

In 1973, Mr. Fridman graduated from the Gubkin Institute of Oil and Gas in Moscow, with a degree in Oil and Gas Fields Development and Exploitation. Since 1984, he was employed by various Gazprom companies: as Chief Engineer of Nadymgazprom, Head of the Production and Technical Department of the Industrial Association, and Chief Engineer of Mostransgaz's Kaluga Department for Gas Transportation and Underground Storage. From 1992 to 2003, he was First Deputy General Director of a joint venture established by OAO Gazprom and DKG-EAST (Hungary). Since 2003 Mr. Fridman was the Deputy General Director of Novafininvest. In 2004, Mr. Fridman was elected Deputy Chairman of the Management Committee of OAO NOVATEK. In August 2007, became a member of NOVATEK's Management Committee.

MR. KIRILL N. YANOVSKIY Born in: 1967

Member of NOVATEK's Management Committee, Director for Finance and Strategy

In 1991, Mr. Yanovskiy graduated from the Gubkin Institute of Oil and Gas in Moscow. From 1992, he headed a department of the Yugorsky Joint-Stock Bank. From 1995, he headed the Securities Department at the Neftek Joint-Stock Commercial Bank. Since 2002, he has been Director of NOVATEK's Financial Planning, Analysis and Control Department. In August 2007, Mr. Yanovskiy was elected to NOVATEK's Management Committee and in 2007 was appointed Deputy Director for Finance and Strategy. Since May 2011 he has been Director for Finance and Strategy .

MAJOR TRANSACTIONS AND INTERESTED PARTY TRANSACTIONS

In 2012, the Company consummated several major interested party transactions:

Loan Agreement; Subscription Agreement; Paying Agency Agreement; Trustee and Agents Fee Side Letter; and Fee Side Letter (the "Transaction");

Scope of the Transaction:

The Loan Agreement between Novatek Finance Limited (the "Lender") and OAO NOVATEK (the "Borrower") whereby OAO NOVATEK borrows an amount of funds equal to those received from the placement of relevant Eurobond tranche and the loan participation notes and undertakes to repay the principal amount and accrued interest pursuant to the terms and conditions of the Loan Agreement, as well as pay a specified fee, reimburse expenses in relation to loan provision and make other payments, including indemnity, and assume other obligations provided for by the Loan Agreement;

Subscription Agreement between Novatek Finance Limited (the "Issuer"), OAO NO-VATEK (the "Borrower") and Barclays Bank plc and Goldman Sachs International, and/or their affiliates, and/or other entities designated in addition to or instead of these entities, and/or other entities specified in the Subscription Agreement (collectively referred to as the "Joint Lead Managers"), whereby:

(a) Novatek Finance Limited acting as an issuer undertakes to issue and sell Eurobonds, with proceeds channeled to finance one or more loans, and the Joint Lead Managers acting as initial buyers undertake to subscribe to and pay for Eurobonds (or procure such subscription and payment) subject always to meeting conditions precedent set forth in the Subscription Agreement, and

(b) OAO NOVATEK provides representations and warranties regarding inter alia its business activity, as well as completeness and reliability of information about such business activity contained in the Prospectus prepared in accordance with international practices for the Transaction purposes, and assumes unlimited liability to pay indemnity and reimburse specific expenses as expressly provided, and other obligations envisaged by the Subscription Agreement;

Paying Agency Agreement between Novatek Finance Limited (the "Issuer"), OAO NOVATEK (the "Borrower") and other parties specified therein, whereby paying and other agencies are appointed and the procedure of Eurobonds servicing and redemption is defined, and OAO NOVATEK undertakes to make certain payments and assumes obligations provided for by the Paying Agency Agreement;

The Trustee and Agents Fee Side Letter and the Fees Side Letter between Novatek Finance Limited, OAO NOVATEK and other parties to these Letters providing for the payment of fees and other amounts in relation to raising funds in accordance with the Loan Agreement in the amount and manner specified in such Letters;

Deadline for obligations performance under the transaction: until the parties fully discharge their obligations.

Parties and beneficiaries to the transaction: OAO NOVATEK (the "Borrower"); Novatek Finance Limited (the "Lender"); Barclays Bank plc and Goldman Sachs International; The price (money value) of asset being the scope of the Transaction equals to the total amount, which includes the aggregate amount of the principle debt on the loans of 1,000,000,000 (one billion) US dollars, interest on the loan / each of the loans raised, calculated based on an annual interest rate of up to 4.4220% per annum, provided that the loan / each loan is granted for up to 10 years, as well as the fees of the trustee, agents and other persons comprising less than 50% of the Company's assets' book value as of the last accounting date.

The asset value as of the end of the accounting period (quarter, year) preceding the transactions date (agreement date) for which financial statements are prepared in accordance with the Russian Federation laws: RR 265,835,437,000. The transaction is considered to be a major transaction.

Transaction date (agreement date) – 10.12.2012.

The transaction was approved by NO-VATEK's Board of Directors (Minutes No. 153 of 19.11.2012).

In 2012, the Company consummated the following related party transactions the amount of which exceeds 2 percent of the Company's assets' book value as of the last accounting date:

Gas supply contract entered into by and between OAO SIBUR Holding (the "Supplier") and OAO NOVATEK (the "Buyer").

The transaction's material terms and conditions:

• Between January 1, 2013 and December 31, 2022, inclusively, the Supplier undertakes to deliver Natural Gas to the Gas Delivery Points specified in the Gas Supply Contract, and the Buyer undertakes to accept and timely pay for the Gas;

Gas supply volume: up to 69,700,000,000 cm.
Deadline for obligations performance under the transaction and information on obligations performance: The gas supply contract is valid with respect to gas deliveries until 31 December 2012 inclusively; and with respect to other obligations until they are fully discharged;
The transaction amount in Russian roubles is calculated for the period from 2013 through 2022, including the effective VAT (18%), and shall not exceed RR 360,000,000,000;

Interested parties: NOVATEK's Board Member Ruben Karlenovich Vardanian; Chairman of NOVATEK'S Management Committee and NOVATEK's Board Member Leonid Viktorovich Mikhelson; NOVATEK's Board Member Gennady Nikolaevich Timchenko.

The transaction was approved by resolution of OAO NOVATEK's Extraordinary General Meeting of Shareholders (Minutes No. 116 of 17.10.2012).

Deed of Indemnity governed by the English law (the "Deed");

The transaction's material terms and conditions:

Parties: OAO NOVATEK, GPB-Financial Services LTD, SIB (Cyprus) Limited and/ or their affiliates.
Subject of the transaction: In view of raising by OAO NOVATEK of one or several loans from Novatek Finance Limited funded through the issue

and placement of Novatek Finance Limited loan participation notes (Eurobonds) in one or several tranches in the international capital markets for the total amount of USD 1,500,000,000 (One billion five hundred million) (or its equivalent in any other currency) with an annual interest rate of up to 9% and for the period of up to 10 years for each of the loans, OAO NOVATEK assumes obligations to reimburse and compensate certain expenses under the Deed as provided therein within the below stated liability cap to GPB-Financial Services LTD, SIB (Cyprus) Limited and/or their affiliates and other parties to which there will be applicable the Deed provisions relating to reimbursement or compensation of possible expenses, and OAO NOVATEK assumes other liabilities envisaged by the Deed.

Beneficiaries: GPB-Financial Services LTD, SIB (Cyprus) Limited and/or their affiliates and other parties to which there will be applicable the Deed provisions relating to reimbursement or compensation of possible expenses.
Price of the transaction: The Deed price shall be commensurate with the market level and shall be determined based on the scope of aggregate liabilities of OAO NOVATEK assumed under the Deed, in the amount of RR 5.2 billion which is less than 2% of OAO NOVATEK's asset book value as of 30 September 2012, the last accounting date before the date of transaction.

The Deed terms not defined in this item as the Deed material terms may be amended as agreed by the relevant Parties to the Deed.

Interested parties: NOVATEK's Board Member Andrei Igorevich Akimov; NOVATEK's Board Member Ruben Karlenovich Vardanian;

The transaction was approved by NO-VATEK's Board of Directors (Minutes No. 154 of 06.12.2012).

IFRS CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED 31 DECEMBER 2012 AND 2011 AND INDEPENDENT AUDITOR'S REPORT

	Independent Auditor's Report 3
	Consolidated Statement of Financial Position 4
	Consolidated Statement of Income 5
	Consolidated Statement of Comprehensive Income 6
	Consolidated Statement of Cash Flows 7
	Consolidated Statement of Changes in Equity 9
	Notes to the Consolidated Financial Statements:
Note 1.	Organization and principal activities 11
Note 2.	Basis of presentation 11
Note 3.	Summary of significant accounting policies 12
Note 4.	Critical accounting estimates and judgments 21
Note 5.	Acquisitions and disposals 24
Note 6.	Property, plant and equipment 29
Note 7.	Investments in joint ventures 30
Note 8.	Long-term loans and receivables 33
Note 9.	Inventories 34
	Note 10. Trade and other receivables 34
	Note 11. Prepayments and other current assets 35
	Note 12. Cash and cash equivalents 36
	Note 13. Long-term debt 36
	Note 14. Pension obligations 38
	Note 15. Short-term debt and current portion of long-term debt 40
	Note 16. Trade payables and accrued liabilities 40
	Note 17. Shareholders' equity 41
	Note 18. Share-based compensation program 42
	Note 19. Oil and gas sales 43
	Note 20. Transportation expenses 43
	Note 21. Taxes other than income tax 44
	Note 22. General and administrative expenses 44
	Note 23. Materials, services and other 45
	Note 24. Purchases of natural gas and liquid hydrocarbons 45
	Note 25. Finance income (expense) 46
	Note 26. Income tax 47
	Note 27. Financial instruments and financial risk factors 49
	Note 28. Contingencies and commitments 57
	Note 29. Principal subsidiaries and joint ventures 59
	Note 30. Related party transactions 60
	Note 31. Segment information 62
	Note 32. Exploration for and evaluation of mineral resources 65
	Note 33. Subsequent events 65
	Note 34. New accounting pronouncements 66
	Unaudited supplemental oil and gas disclosures 69
	Contact Information 74

	Notes	At 31 December 2012	At 31 December 2011
ASSIBILS
Non-current assets
Property, plant and equipment	6	197,376	166,784
Investments in joint ventures	7	189,136	123,029
Long-term loans and receivables	8	13,150	32,130
Other non-current assets		5,228	3,173
Total non-current assets		404,890	325,116
Current assets
Inventories	9	3,091	1,683
Current income tax prepayments		1,756	1,153
Trade and other receivables	10	16,409	16,699
Prepayments and other current assets	11	18,567	14,950
Cash and cash equivalents	12	18,420	23,831
Total current assets		58,243	58,316
Total assets		463,133	383,432
LIABILITIES AND EQUITY
Non-current liabilities
Long-term debt	13	97,805	75,180
Deferred income tax liabilities	26	13,969	12,805
Asset retirement obligations		2,879	2,734
Other non-current liabilities		2,049	917
Total non-current liabilities		116,702	91,636
Current liabilities
Short-term debt and current portion of long-term debt	ા ર	34,682	20,298
Trade payables and accrued liabilities	16	15,925	24,922
Current income tax payable		198	611
Other taxes payable		4,325	4,283
Total current liabilities		55,130	50,114
Total liabilities		171,832	141,750

Equity attributable to OAO NOVATEK shareholders Ordinary share capital		393	393
Treasury shares		(584)	(281)
Additional paid-in capital		31,220	31,220
Currency translation differences		(202)	193
Asset revaluation surplus on acquisitions		5,617	5,617
Retained earnings		253,606	203,871
Total equity attributable to OAO NOVATEK shareholders	17	290,050	241,013
Non-controlling interest		1,251	669
Total equity		291,301	241,682
Total liabilities and equity		463,133	383,432

OAO NOVATEK Consolidated Statement of Income

(in millions of Russian roubles, except for share and per share amounts)

		Year ended 31 December:
	Notes	2012	2011

Revenues
Oil and gas sales	19	210,246	174,811
Other revenues		727	462
Total revenues		210,973	175,273
Operating expenses
Transportation expenses	20	(60,848)	(48,329)
Taxes other than income tax	21	(16,846)	(16,559)
Purchases of natural gas and liquid hydrocarbons	24	(17,483)	(5,994)
Depreciation, depletion and amortization	6	(11,185)	(9,277)
General and administrative expenses	22	(10,936)	(8,218)
Materials, services and other	23	(7,216)	(5,947)
Exploration expenses		(2,022)	(1,819)
Net impairment expenses		(325)	(782)
Change in natural gas, liquid hydrocarbons
and work-in-progress		1,086	105
Total operating expenses		(125,775)	(96,820)

Net gain (loss) on disposal of interest in subsidiaries		(60)	62,948
Other operating income (loss)		196	207
Profit from operations		85,334	141,608

Finance income (expense)
Interest expense	25	(3,236)	(2,150)
Interest income	25	1,731	3,392
Foreign exchange gain (loss)		4,491	(3,945)
Total finance income (expense)		2,986	(2,703)
Share of profit (loss) of joint ventures,
net of income tax	7	(2,105)	(3,880)
Profit before income tax		86,215	135,025

Income tax expense
Current income tax expense		(16,142)	(12,467)
Net deferred income tax expense		(632)	(3,267)
Total income tax expense	26	(16,774)	(15,734)
Profit (loss)		69,441	119,291
Profit (loss) attributable to:
Non-controlling interest		(17)	(364)
Shareholders of OAO NOVATEK		69,458	119,655
Basic and diluted earnings per share (in Russian roubles)		22.89	39.45
Weighted average number of shares outstanding (in thousands)		3,034,245	3,033,302

OAO NOVATEK Consolidated Statement of Comprehensive Income

(in millions of Russian roubles)

	Year ended 31 December:
	2012	2011
Profit (loss)	69,441	119,291
Other comprehensive income (loss) after income tax:
Currency translation differences	(395)	313
Other comprehensive income (loss)	(395)	313
Total comprehensive income (loss)	69,046	119,604
Total comprehensive income (loss) attributable to:
Non-controlling interest Shareholders of OAO NOVATEK	(17) 69,063	(364) 119,968

OAO NOVATEK

Consolidated Statement of Cash Flows

(in millions of Russian roubles)

		Year ended 31 December:
	Notes	2012	2011
Profit before income tax		86,215	135,025
Adjustments to profit before income tax:
Depreciation, depletion and amortization		11,499	9,475
Net impairment expenses		325	782
Net foreign exchange loss (gain)		(4,491)	3,945
Net loss (gain) on disposal of assets		101	(62,811)
Interest expense		3,236	2,150
Interest income		(1,731)	(3,392)
Share of loss (profit) in joint ventures, net of income tax	7	2,105	3,880
Net change in other non-current assets and long-term receivables		780	1,132
Change in pension obligations		709	120
Other adjustments		(195)	82
Working capital changes
Decrease (increase) in trade and other receivables, prepayments
and other current assets		(8,086)	(6,103)
Decrease (increase) in inventories		(1,425)	(132)
Increase (decrease) in trade payables and accrued liabilities,
excluding interest and dividends payable		5,014	567
Increase (decrease) in other taxes payable		(624)	1,120

Total effect of working capital changes		(5,121)	(4,548)
Income taxes paid		(17,607)	(13,933)
Net cash provided by operating activities		75,825	71,907
Cash flows from investing activities
Purchases of property, plant and equipment		(37,378)	(25,335)
Prepayments for participation in tender for mineral licenses	6	-	(6,870)
Purchases of inventories intended for construction		(1,938)	(773)
Acquisition of subsidiaries net of cash acquired		184	(4,188)
Acquisition of joint ventures	5, 7	(42,697)	(21,176)
Additional capital contributions to joint ventures	8	(5,213)	(3,955)
Proceeds from disposals of subsidiaries net of cash disposed	5	302	11,796
Interest paid and capitalized		(2,698)	(3,508)
Loans provided		(4,818)	(6,729)
Repayments of loans provided		8,102	13,166
Interest received		2,030	929
Net cash (used for) provided by investing activities		(84,124)	(46,643)
Cash flows from financing activities
Proceeds from long-term debt		81,149	44,885
Proceeds from short-term debt		-	3,700
Repayments of long-term debt		(40,412)	(8,552)
Repayments of short-term debt		-	(21,321)
Interest paid		(2,320)	(818)
Dividends paid	17	(19,718)	(15,166)
Acquisition of non-controlling interest	5	(16,290)	(14,817)
Capital contributions to the Group's subsidiaries
by non-controlling shareholders		497	-
Sales of treasury shares	17	-	354
Purchases of treasury shares	17	(303)	-
Net cash (used for) provided by financing activities		2,603	(11,735)

OAO NOVATEK Consolidated Statement of Cash Flows (in millions of Russian roubles)

		Year ended 31 December:
	Notes	2012	2011
Net effect of exchange rate changes on
cash, cash equivalents		285	64
Net increase (decrease) in cash, cash equivalents		(5,411)	13,593
Cash and cash equivalents at beginning of the period		23,831	10,238
Cash, cash equivalents at end of the period		18,420	23,831

OAO NOVATEK	Consolidated Statement of Changes in Equity	(in millions of Russian roubles, except for number of shares)

	Number of ordinary shares (in thousands)	capital Ordinary share	shares Treasury	capital Additional paid-in	revaluation acquisitions Asset surplus on	Currency translation differences	earnings Retained	attributable to OAO NOVATEK shareholders Equity	interest Non controlling	Total equity
For the year ended 31 December 2011
1 January 2011	3,033,184	393	(446)	30,865	5,617	(120)	110,810	147,119	20,667	167,786
Currency translation differences	-	-	-	-	-	313	-	313	-	313
Profit (loss)	-	-	-	-	-	-	119,655	119,655	(364)	119,291
Total comprehensive income (loss)	-	-	-	-	-	313	119,655	119,968	(364)	119,604
Dividends (Note 17)	-	-	-	-	-	-	(15,166)	(15,166)	-	(15,166)
Equity call option reclassification	-	-	-	-	-	-	322	322	-	322
subscription in subsidiaries on Impact of additional shares non-controlling interest	-	-	-	-	-	-	-	-	286	286
Acquisition of non-controlling interest (Note 5)	-	-	-	-	-	-	(11,750)	(11,750)	(19,920)	(31,670)
Sales of treasury shares (Note 17)	1,154	-	165	355	-	-	-	520	-	520
31 December 2011	3,034,338	393	(281)	31,220	5,617	193	203,871	241,013	669	241,682

(in millions of Russian roubles, except for number of shares) Consolidated Statement of Changes in Equity OAO NOVATEK
-----------------------------------------------------------------------------------------------------------------------------

- 3,034,338 - - - - For the year ended 31 December 2012 Total comprehensive income (loss) subscription in subsidiaries on Currency translation differences Impact of additional shares Dividends (Note 17) 1 January 2012 Profit (loss)		shares Treasury	capital Additional paid-in	revaluation surplus on acquisitions Asset	Currency translation differences	earnings Retained	attributable to OAO NOVATEK shareholders	interest Non controlling	Total equity

	393	(281)	31,220	5,617	193	203,871	241,013	669	241,682
	-	-	-	-	(395)	-	(395)	-	(395)
	-	-	-	-	-	69,458	69,458	(17)	69,441
		-	-	-	(395)	69,458	69,063	(17)	69,046
	-	-	-	-	-	(19,723)	(19,723)	-	(19,723)
- non-controlling interest	-	-	-	-	-	-	-	497	497
(925) Purchase of treasury shares (Note 17)	-	(303)	-	-	-	-	(303)	-	(303)
- Acquisition of subsidiaries (Note 5)	-	-	-	-	-	-	-	102	102
3,033,413 31 December 2012	393	(584)	31,220	5,617	(202)	253,606	290,050	1,251	291,301

1 ORGANIZATION AND PRINCIPAL ACTIVITIES

OAO NOVATEK (hereinafter referred to as "NOVATEK") and its subsidiaries (hereinafter jointly referred to as the "Group") is an independent oil and gas company engaged in the acquisition, exploration, development, production and processing of hydrocarbons with its core oil and gas operations located and incorporated in the Yamal-Nenets Autonomous Region ("YNAO") of the Russian Federation.

The Group sells its natural gas on the Russian domestic market at unregulated market prices (except for deliveries to residential customers); however, the majority of natural gas sold on the domestic market is sold at prices regulated by the Federal Tariffs Service, a governmental agency. The Group's stable gas condensate and crude oil sales volumes are sold on both the Russian domestic and international markets, and are subject to fluctuations in benchmark crude oil prices. Additionally, the Group's natural gas sales fluctuate on a seasonal basis due mostly to Russian weather conditions, with sales peaking in the winter months of December and January and troughing in the summer months of July and August. The Group's liquids sales volumes comprising stable gas condensate, crude oil and oil and gas products remain relatively stable from period to period.

In December 2012, the Group acquired an 82 percent participation interest in OOO Gazprom mezhregiongas Kostroma, a Russian regional natural gas trader, to support and expand natural gas sales opportunities in the Kostroma Region of the Russian Federation (see Note 5).

In December 2012, the Group established a wholly owned subsidiary, OOO NOVATEK Moscow region, to support the Group's current natural gas deliveries as well as to expand potential sales opportunities in the Moscow region of the Russian Federation.

In December 2012, the Group disposed of its wholly owned non-core subsidiary, OOO Purovsky Terminal (see Note 5).

In November 2012, the Group acquired a 49 percent ownership interest in ZAO Nortgas, an oil and gas producing company, which holds the license for the North-Urengoyskoye field located in the YNAO (see Note 5).

During 2012, the Group signed long-term natural gas purchase and sales contracts with third parties to commence commercial trading activities in the European market. The contracts were signed for a period of ten years starting from 1 October 2012 with the expected total volume of natural gas traded over this period of approximately 20 billion cubic meters (see Notes 27, 31).

In January and June 2012, the Group merged its wholly owned subsidiaries OOO Yamalenergogas and OOO Gazprom mezhregiongas Chelyabinsk into its wholly owned subsidiaries OOO NOVATEK-Perm and OOO NOVATEK-Chelyabinsk, respectively. The mergers did not affect the Group's consolidated financial and operational results.

2 BASIS OF PRESENTATION

The accompanying consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") under the historical cost convention. In the absence of specific IFRS guidance for oil and gas producing companies, the Group has developed accounting policies in accordance with other generally accepted accounting principles for oil and gas producing companies, mainly US GAAP, insofar as they do not conflict with IFRS principles. The preparation of financial statements in conformity with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise judgment in the process of applying the Group's accounting policies. The areas involving a higher degree of judgment or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements are disclosed in Note 4.

Most of the Group entities prepare their statutory financial statements in accordance with the Regulations on Accounting and Reporting of the Russian Federation. The Group's consolidated financial statements are based on the statutory records with adjustments and reclassifications recorded in the consolidated financial statements for the fair presentation in accordance with IFRS. The principal adjustments primarily relate to (a) depreciation, depletion and amortization, and valuation of property, plant and equipment, (b) consolidation of subsidiaries, (c) business combinations, (d) accounting for income taxes, and (e) valuation of unrecoverable assets, expense recognition and other provisions.

2 BASIS OF PRESENTATION (CONTINUED)

Functional and presentation currency. The consolidated financial statements are presented in Russian roubles, the Group's reporting (presentation) currency and the functional currency for the majority of Group's entities. The assets and liabilities (both monetary and non-monetary) of the Group entities whose functional currency is not the Russian rouble are translated into Russian roubles at the closing exchange rate at each balance sheet date. All items included in the shareholders' equity, other than profit or loss, are translated at historical exchange rates. The financial results of these entities are translated into Russian roubles using average exchange rates for each reporting period. Exchange adjustments arising on the opening net assets and the profits for the reporting period are taken to a separate component of equity until the disposal of the foreign operation and reported as currency translation differences in the consolidated statement of changes in equity and the consolidated statement of comprehensive income.

Exchange rates used in preparation of this consolidated financial statements for the entities whose functional currency is not the Russian rouble were as follows:

			Average rate for the year ended 31 December:
Russian roubles to one currency unit	At 31 December 2012	At 31 December 2011	2012	2011
US dollar ("USD") Polish Zloty ("PLN")	30.37 9.87	32.20 9.47	31.09 9.56	29.39 9.94

Exchange rates, restrictions and controls. Any re-measurement of Russian rouble amounts to US dollars or any other currency should not be construed as a representation that such Russian rouble amounts have been, could be, or will in the future be converted into other currencies at these exchange rates.

Reclassifications. Certain reclassifications have been made to the comparative figures to conform to the current period presentation with no effect on profit for the period or shareholder's equity. The export sales of liquefied petroleum gas for the year ended 31 December 2012 are presented net of excise and fuel tax. Accordingly, liquefied petroleum gas sales and excise and fuel tax expenses for the year ended 31 December 2011 were decreased by RR 998 million.

3 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of consolidation. Subsidiaries are those companies and other entities (including special purpose entities) in which the Group, directly or indirectly, has an interest of more than one half of the voting rights or otherwise has power to govern the financial and operating policies so as to obtain benefits. The existence and effect of potential voting rights that are presently exercisable or presently convertible are considered when assessing whether the Group controls another entity. Subsidiaries are consolidated from the date on which control is transferred to the Group (acquisition date) and are deconsolidated from the date that control ceases.

The acquisition method of accounting is used to account for the acquisition of subsidiaries. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured at their fair values at the acquisition date, irrespective of the extent of any non-controlling interest.

The Group measures non-controlling interest on a transaction by transaction basis, either at: (a) fair value, or (b) the non-controlling interest's proportionate share of net assets of the acquiree.

Goodwill is measured by deducting the net assets of the acquiree from the aggregate of the consideration transferred for the acquiree, the amount of non-controlling interest in the acquiree and fair value of an interest in the acquiree held immediately before the acquisition date. Any negative amount ("negative goodwill") is recognized in profit or loss, after management reassesses whether it identified all the assets acquired and all liabilities and contingent liabilities assumed and reviews appropriateness of their measurement. Acquisition-related costs are recognized as expenses rather than included in goodwill.

3 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

The consideration transferred for the acquiree is measured at the fair value of the assets given up, equity instruments issued and liabilities incurred or assumed, including fair value of assets or liabilities from contingent consideration arrangements but excludes acquisition related costs such as advisory, legal, valuation and similar professional services. Transaction costs incurred for issuing equity instruments are deducted from equity; transaction costs incurred for issuing debt are deducted from its carrying amount and all other transaction costs associated with the acquisition are expensed.

Intercompany transactions, balances and unrealized gains on transactions between group companies are eliminated; unrealized losses are also eliminated unless the cost cannot be recovered. The Group and all of its subsidiaries use uniform accounting policies consistent with the Group's policies.

Non-controlling interest is that part of the net results and of the equity of a subsidiary attributable to interests which are not owned, directly or indirectly, by the Group. Non-controlling interest forms a separate component of the Group's equity. Changes in the Group's ownership interest in a subsidiary that do not result in the loss of control are accounted for as equity transactions.

Disposals of subsidiaries, associates or joint ventures. When the Group ceases to have control or significant influence, any retained interest in the entity is re-measured to its fair value, with the change in carrying amount recognized in profit or loss. The fair value is the initial carrying amount for the purposes of subsequently accounting for the retained interest as an associate, joint venture or financial asset. In addition, any amounts previously recognized in other comprehensive income in respect of that entity are accounted for as if the Group had directly disposed of the related assets or liabilities. This may mean that amounts previously recognized in other comprehensive income are recycled to profit or loss.

If the ownership interest in an associate is reduced but significant influence is retained, only a proportionate share of the amounts previously recognized in other comprehensive income are reclassified to profit or loss where appropriate.

Acquisition of non-controlling interests. The difference between the purchase consideration and the carrying amount of non-controlling interests acquired is recognized within equity to account for acquisitions of noncontrolling minority stakes.

Investments in associates and joint ventures. Associated companies and joint ventures are entities over which the Group has significant influence or joint control, respectively, but which it does not control. Generally, significant influence exists when the Group has between 20 and 50 percent of voting rights. Associated companies and joint ventures are accounted for using the equity method and are initially recognized at cost. The difference between the cost of an acquisition and the share of the fair value of the associate's identifiable net assets represents goodwill upon acquiring the associated company. Dividends received from associates and joint ventures reduce the carrying value of the investment in associates and joint ventures. The carrying amount of associates and joint ventures includes goodwill identified on acquisition less accumulated impairment losses, if any. Other post-acquisition changes in the Group's share of net assets of an associate or joint venture are recognized as follows: (a) the Group's share of profits or losses is recorded in the consolidated profit or loss for the year as share of result of associates or joint ventures; (b) the Group's share of other comprehensive income is recognized in other comprehensive income and presented separately; and (c) all other changes in the Group's share of the carrying value of net assets of associates or joint ventures are recognized in profit or loss within the share of result of associates or joint ventures. When the Group's share of losses in an associate or joint ventures equals or exceeds its interest in the associate, including any other unsecured receivables, the Group does not recognize further losses, unless it has incurred obligations or made payments on behalf of the associate.

Unrealized gains on transactions between the Group and its associates and joint ventures are eliminated to the extent of the Group's interest in the associates and joint ventures; unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred.

Accounting policies of associates and joint ventures have been changed where necessary to ensure consistency with the policies adopted by the Group.

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Non-current assets held for sale. Non-current assets classified as held for sale are measured at the lower of carrying amount and fair value less selling costs. Non-current assets are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset is available for immediate sale in its present condition. Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification.

Property, plant and equipment are not depreciated once classified as held for sale.

Property, plant and equipment. Property, plant and equipment are carried at historical cost of acquisition or construction and adjusted for accumulated depreciation, depletion, amortization and impairment.

The Group follows the successful efforts method of accounting for its oil and gas properties and equipment whereby property acquisitions, successful exploratory wells, all development costs and support equipment and facilities are capitalized. Unsuccessful exploratory wells are charged to expense at the time the wells are determined to be non-productive. Production costs, overheads and all exploration costs other than exploratory drilling and license acquisition costs are charged to expense as incurred. Acquisition costs of unproved properties are evaluated periodically and any impairment assessed is charged to expense.

The Group's principal oil and gas reserves have been independently estimated by internationally recognized petroleum engineers whereas other oil and gas reserves of the Group have been determined based on estimates of mineral reserves prepared by management in accordance with internationally recognized definitions. The present value of the estimated costs of dismantling oil and gas production facilities, including abandonment and site restoration costs, are recognized when the obligation is incurred and are included within the carrying value of property, plant and equipment, subject to depletion using the unit-of-production method.

Costs of minor repairs and maintenance are expensed when incurred. Cost of replacing major parts or components that extend the life of property, plant and equipment items are capitalized and depreciated over the estimated remaining life of the major part or component. All components that are replaced are written off.

The cost of self-constructed assets includes the cost of direct materials, direct employee related costs, a pro-rata portion of depreciation of assets used for construction and an allocation of the Group's overhead costs.

At each reporting date management assesses whether there is any indication of impairment in respect of property, plant and equipment. If any such indication exists, management estimates the recoverable amount, which is determined as the higher of an asset's fair value less selling costs and its value in use. The carrying amount is reduced to the recoverable amount and the impairment loss is recognized in the consolidated statement of income. An impairment loss recognized for an asset in prior years is reversed if there has been a change in the estimates used to determine the asset's recoverable amount.

Gains and losses on disposals of property, plant and equipment are determined by comparing proceeds with the carrying amount. Gains and losses are recognized in the consolidated statement of income.

Exploration costs. Exploration costs (geological and geophysical expenditures, expenditures associated with the maintenance of non-proven reserves and other expenditures relating to exploration activity), excluding exploratory drilling expenditures and license acquisition costs, are charged to the consolidated statement of income as incurred. License acquisition costs and exploratory drilling costs are recognized as assets until it is determined whether proved reserves justifying their commercial development have been found. If no proved reserves are found, the capitalized drilling costs are charged to the consolidated statement of income. License acquisition costs and exploratory drilling costs recognized as assets are reviewed for impairment on an annual basis.

The cost of 3-D seismic surveys used to assist production, increase total recoverability and determine the desirability of drilling additional development wells within proved reservoirs are capitalized as development costs. All other seismic costs are expensed as incurred.

Depreciation. Depreciation, depletion and amortization of oil and gas properties and equipment (except for processing facilities) is calculated using the unit-of-production method for each field based upon proved developed reserves for development costs, and total proved reserves for costs associated with acquisitions of proved properties. A portion of the reserves used for depreciation, depletion and amortization calculations include reserves expected to be produced beyond license expiry dates. Management believes that there is requisite legislation and past results (or experience) to extend mineral licenses at the initiative of the Group and, as such, intends to extend its licenses for properties expected to produce beyond the current license expiry dates.

Property, plant and equipment, other than oil and gas properties and equipment, are depreciated on a straight-line basis over their estimated useful lives. Land and assets under construction are not depreciated.

The estimated useful lives of the Group's property, plant and equipment, other than oil and gas properties and equipment, are as follows:

	Years
Machinery and equipment	5-15
Processing facilities	20-30
Buildings	25-50

Intangible assets. Intangible assets that have a finite useful life are amortized using the straight-line method over the period of their useful life. There were no intangible assets with indefinite useful lives held by the Group at the reporting dates.

Effective interest method. The effective interest method is a method of calculating the carrying value of a financial asset or a financial liability held at amortized costs and of allocating the interest income or interest expense over the relevant period.

The effective interest rate is the rate that exactly discounts future cash payments and receipts through the expected life of the financial instrument or, when appropriate, a shorter period to the net carrying value of the financial asset or financial liability.

Financial assets. The Group classifies its financial assets in the following categories: financial assets at fair value through profit or loss, held-to-maturity, loans and receivables, and available-for-sale. The classification depends on the purpose for which the financial assets were acquired. Management determines the classification of its financial assets at initial recognition. Subsequent reclassification of financial assets is made only as a result of a change in intention or ability of management to hold the financial assets. Financial assets are recognized initially at fair value, normally being the transaction price plus, in the case of financial assets not at fair value through profit or loss, directly attributable transaction costs. The subsequent measurement of financial assets depends on their classification.

(a) Financial assets at fair value through profit or loss

Financial assets at fair value through profit or loss are financial assets held for trading. A financial asset is classified in this category if acquired principally for the purpose of selling in the short-term. Derivative instruments are also categorized as held for trading unless they are designated as hedges. Financial assets carried at fair value through profit or loss are initially recognized at fair value and transaction costs are expensed in the consolidated statement of income. Gains or losses arising from changes in the fair value of the "financial assets at fair value through profit or loss" category are presented in the consolidated statement of income within other operating income (loss) in the period in which they arise. Dividend income from financial assets at fair value through profit or loss is recognized in the consolidated statement of income as part of other operating income (loss) when the Group's right to receive payments is established.

(b) Held-to-maturity investments

Held-to-maturity investments include quoted non-derivative financial assets with fixed or determinable payments and fixed maturities that the Group has both the intention and ability to hold to maturity. After initial measurement, the held-to-maturity investments are measured at amortized cost using the effective interest method. Gains and losses are recognized in the consolidated statement of income when the investments are derecognized or impaired, as well as through the amortization process.

Held-to-maturity investments are included in current assets, except for maturities greater than 12 months after the balance sheet date. These are classified as non-current assets. There were no such investments held by the Group at the reporting dates.

(c) Loans and receivables

Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. Financial assets classified as loans and receivables are carried at amortized cost using the effective interest method. Gains and losses are recognized in the consolidated statement of income when the loans and receivables are derecognized or impaired, as well as through the amortization process.

Loans and receivables are included in current assets, except for maturities greater than 12 months after the balance sheet date which are classified as non-current assets.

(d) Available-for-sale financial assets

Financial assets classified as available-for-sale are non-derivatives financial assets that are either designated in this category or are not classified in any of the other categories. After initial recognition, financial assets classified as available-for-sale are measured at fair value, with gains and losses recognized in other comprehensive income and accumulated in revaluation reserve in equity until the investment is derecognized or determined to be impaired, at which time the cumulative gain or loss previously recorded in equity is recognized in consolidated statement of income as a reclassification adjustment from other comprehensive income.

Changes in the fair value of monetary securities denominated in a foreign currency and classified as available-forsale financial assets are analyzed between translation differences resulting from changes in amortized cost of the security and other changes in the carrying amount of the security. The translation differences on monetary securities are recognized in consolidated statement of income, while translation differences on non-monetary securities are recognized in other comprehensive income. Changes in the fair value of monetary and non-monetary securities classified as available-for-sale are recognized in other comprehensive income. When securities classified as available-for-sale are sold or impaired, the accumulated fair value adjustments recognized in equity are included in the consolidated statement of income as a reclassification adjustment from other comprehensive income.

The Group assesses at each balance sheet date whether there is objective evidence that a financial asset or a group of financial assets is impaired. A prolonged decline in the fair value of the security below its cost is considered as an indicator that the securities are impaired. If any such evidence exists for available-for-sale financial assets, the cumulative loss (measured as the difference between the acquisition cost and the current fair value, less any impairment loss on that financial asset previously recognized in consolidated statement of income) is recognized in the consolidated statement of income as a reclassification adjustment from other comprehensive income. Impairment losses recognized in the consolidated statement of income on equity instruments are not reversed. There were no available-for-sale investments held by the Group at the reporting dates.

Financial liabilities. Financial liabilities are classified at initial recognition as either financial liabilities at fair value through profit or loss, derivative instruments designated as hedging instruments in an effective hedge or as financial liabilities measured at amortized cost. There were no derivative instruments designated as hedging instruments by the Group at the reporting dates. The measurement of financial liabilities depends on their classification, as follows:

(a) Financial liabilities at fair value through profit or loss

Derivative instruments, other than those designated as effective hedging instruments, are classified as held for trading and are included in this category. These financial liabilities are carried on the consolidated statement of financial position at fair value with gains or losses recognized in the consolidated statement of income.

(b) Financial liabilities measured at amortized cost

All other financial liabilities are included in this category and initially recognized at fair value. For interest-bearing debt, the fair value of the liability is the fair value of the proceeds received net of associated issue costs. After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. This category of financial liabilities includes trade and other payables and debt in the consolidated statement of financial position.

Derivative instruments. Derivative financial instruments are contracts: (a) whose value changes in response to the change in one or more observable variables; (b) that do not require any material initial net investment; and (c) that are settled at a future date. Accordingly, contracts to buy or sell a non-financial item that can be settled net in cash or another financial instrument, or by exchanging financial instruments with the exception of contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the Group's expected purchase, sale or usage requirements, are accounted for as financial instruments. Gains or losses arising from changes in the fair value of derivatives are recognized in the consolidated income statement within other operating profit (loss).

Derivative instruments are carried as assets when the fair value is positive and as liabilities when the fair value is negative. Derivative assets or liabilities expected to be recovered, or with the legal right to be settled more than twelve months after the reporting date are classified as non-current, with the exception of derivative financial instruments held for the purpose of being traded. The amounts of assets and liabilities associated with derivatives are presented without netting assets and liabilities with the same counterparty except where the right of offset and intent to net exist.

The estimated fair values of derivative financial instruments are determined with reference to various market information and other valuation methodologies as considered appropriate, however considerable judgment is required in interpreting market data to develop these estimates. Accordingly, the estimates are not necessarily indicative of the amounts that the Group could realize in a current market situation.

Derivatives embedded in other non-derivative financial instruments or in non-financial host contracts are recognized as separate derivatives when their risks and economic characteristics are not closely related to those of the host contracts, and the host contracts are not carried at fair value. Where there is an active market for a commodity or other non-financial item subject of a purchase or sale contract, a pricing formula will, for instance, be considered to be closely related to the host purchase or sales contract if the price formula is based on the active market in question. A price formula with indexation to other markets or products will however result in the recognition of a separate derivative. Where there is no active market for the commodity or other non-financial item in question, the Group assesses the characteristics of such a price related embedded derivative to be closely related to the host contract if the price formula is based on relevant indexations commonly used by other market participants. This applies to the Group's liquid hydrocarbons and domestic natural gas sales and purchases agreements. Contracts are assessed for embedded derivatives when the Group becomes a party to them, including at the date of a business combination. Such embedded derivatives are measured at fair value at each period end, and the changes in fair value are recognized in profit or loss for the period.

Income taxes. Effective 1 January 2012, Russian tax legislation introduced an option to prepare and file a single, consolidated income tax declaration. According to the new legislation, the taxpayers' group should be comprised of a holding company and any number of entities with at least 90 percent ownership in each (direct or indirect). To be eligible for registration, the taxpayers' group must be registered with tax authorities and meet certain conditions and criteria. The tax declaration can be submitted then by any member of the group. Management has chosen to adopt this option, as discussed in Note 26.

In prior periods, Russian legislation did not contain the concept of a "consolidated tax payer" and, accordingly, the Group's entities were subject to Russian taxation on an individual company basis.

Income taxes have been provided for in the consolidated financial statements in accordance with Russian legislation enacted or substantively enacted as of end of the reporting period. The income tax charge or benefit comprises current tax and deferred tax and is recognized in the consolidated statement of income unless it relates to transactions that are recognized, in the same or a different period, in other comprehensive income or directly in equity. Current tax is the amount expected to be paid to or recovered from the tax authorities in respect of taxable profits or losses for the current and prior periods.

Deferred tax assets and liabilities are recognized in full for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax base. In accordance with the initial recognition exemption, deferred taxes are not recorded for temporary differences on initial recognition of an asset or a liability in a transaction other than a business combination if the transaction, when initially recorded, affects neither accounting nor taxable profit. Deferred tax balances are measured at tax rates enacted or substantively enacted at the balance sheet date which are expected to apply to the period when the temporary differences will reverse or when the tax loss carry forwards will be utilized. Deferred tax assets and liabilities are netted only with respect to individual companies of the Group. Deferred tax assets for deductible temporary differences and tax loss carry forwards are recorded only to the extent that it is probable that future taxable profit will be available against which the deductions can be utilized.

Deferred income tax is provided on post acquisition retained earnings of subsidiaries or joint ventures, except where the Group controls the subsidiary's dividend policy and it is probable that the difference will not reverse through dividends or otherwise in the foreseeable future. Any resultant deferred income tax is measured at the expected tax rate.

Inventories. Natural gas, gas condensate, crude oil and related products inventories are valued at the lower of cost or net realizable value. The cost of inventories includes applicable purchase costs of raw materials, direct operating costs, and related production overhead expenses and is recorded on a first-in-first-out (FIFO) basis. Net realizable value is the estimate of the selling price in the ordinary course of business, less selling expenses.

Materials and supplies inventories are carried at amounts which do not exceed their respective recoverable amounts in the normal course of business.

Trade and other receivables. Trade receivables are represented by amounts due from regular customers in the ordinary course of business (production and marketing of natural gas, gas condensate, crude oil and related products). Trade and other receivables are recognized initially at fair value and subsequently measured at amortized cost using the effective interest method and include value-added taxes. Trade receivables are analyzed for impairment on a debtor by debtor basis. A provision for impairment of receivables is established when there is objective evidence that the Group will not be able to collect all amounts due according to the original terms of receivables. The amount of the provision is the difference between the asset's carrying amount and the present value of estimated future cash flows, discounted at the original effective interest rate. The amount of the provision is recognized in the consolidated statement of income within operating expenses. Subsequent recoveries of amounts previously written off are credited against the amount of the provision in the consolidated statement of income.

Cash and cash equivalents. Cash and cash equivalents comprises cash on hand, cash deposits held with banks, investments which are readily convertible to known amounts of cash and which are not subject to significant risk of change in value and have an original maturity of three months or less. For purposes of the presentation of the statement of cash flows bank overdrafts are deducted from cash and cash equivalents. Bank overdrafts are shown within short-term debt in current liabilities on the consolidated statement of financial position.

Treasury shares. Where any Group company purchases NOVATEK's equity share capital (treasury shares), the consideration paid, including any directly attributable incremental costs (net of income taxes) is deducted from equity attributable to OAO NOVATEK shareholders until the shares are cancelled or reissued. Where such shares are subsequently reissued, any consideration received, net of any directly attributable incremental transaction costs and the related income tax effects, is included in equity attributable to OAO NOVATEK shareholders. Treasury shares are recorded at weighted average cost. Gains or losses resulting from subsequent sales of shares are recorded in the consolidated statement of changes in equity, net of associated costs including taxation.

Dividends. Dividends are recognized as a liability and deducted from shareholders' equity at the balance sheet date only if they are declared before or on the balance sheet date. Dividends are disclosed when they are proposed before the balance sheet date or proposed or declared after the balance sheet date but before the consolidated financial statements are authorized for issue.

Value added tax (VAT). Output VAT related to sales is payable to the tax authorities on the earlier of (a) collection of the receivables from customers or (b) delivery of the goods or services to customers. Input VAT related to purchases is generally recoverable against output VAT upon receipt of the VAT invoice. The tax authorities permit the settlement of VAT on a net basis. VAT related to sales and purchases which is not settled or recovered at the balance sheet date (VAT payable and VAT recoverable) is recognized on a gross basis and disclosed separately within current assets and current liabilities. Where a provision has been made for the impairment of receivables, the impairment loss is recorded for the gross amount of the debtor, including VAT.

Borrowings. Borrowings are recognized initially at fair value, net of transaction costs incurred. Borrowings are subsequently stated at amortized cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognized in the consolidated statement of income over the period of the borrowings using the effective interest method.

Interest costs on borrowings and exchange differences arising from foreign currency borrowings (to the extent that they are regarded as an adjustment to interest costs) used to finance the construction of property, plant and equipment are capitalized during the period of time that is required to complete and prepare the asset for its intended use. All other borrowing costs are expensed.

Trade and other payables. Trade payables are accrued when the counterparty performed its obligations under the contract. Trade payables are recognized initially at fair value and subsequently measured at amortized cost using the effective interest method.

Provisions for liabilities and charges. Provisions are recognized when the Group has a present legal or constructive obligation as a result of past events; when it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation; and a reliable estimate of the amount of the obligation can be made.

Where there are a number of similar obligations, the likelihood that an outflow will be required in settlement is determined by considering the class of obligations as a whole. A provision is recognized even if the likelihood of an outflow with respect to any one item included in the same class of obligations may be low.

Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the obligation. Provisions are reassessed at each reporting date and changes in the provisions resulting from the passage of time are recognized in the consolidated statement of income as interest expense. Where the Group expects a provision to be reimbursed, the reimbursement is recognized as a separate asset but only when the reimbursement is virtually certain.

Asset retirement obligations. An asset retirement obligation is recognized when the Group has a present legal or constructive obligation to dismantle, remove and restore items of property, plant and equipment whose construction is substantially completed. The amount of the obligation is the present value of the estimated expenditures expected to be required to settle the obligation, determined using discount rates reflecting adjustments for risks specific to the obligation. Changes in the obligation resulting from the passage of time are recognized in the consolidated statement of income as interest expense. Changes in the obligation, reassessed at each balance sheet date, related to a change in the expected pattern of settlement of the obligation, or in the estimated amount of the obligation or in the discount rates, are treated as a change in an accounting estimate in the period. Such changes are reflected as adjustments to the carrying value of property, plant and equipment and the corresponding liability.

The Group's exploration, development and production activities involve the use of wells, related equipment and operating sites, oil and gas gathering and treatment facilities and in-field pipelines. Generally, licenses and other regulatory acts require that such assets be decommissioned upon the completion of production, i.e. the Group is obliged to decommission wells, dismantle equipment, restore the sites and perform other related activities. The Group's estimates of these obligations are based on current regulatory or license requirements, as well as actual dismantling and related costs.

The Group's management believes that due to the limited history of gas condensate processing plants activities, the useful lives of these assets are indeterminable (while certain of the operating components and equipment have definite useful lives). Because of these reasons, and the lack of clear legal requirements as to the recognition of obligations, the fair value of an asset retirement obligation for such processing facilities cannot be reasonably estimated and, therefore, legal or contractual asset retirement obligations related to these assets are not recognized.

Due to continuous changes in the Russian regulatory and legal environment, there could be future changes to the requirements and contingencies associated with the retirement of long-lived assets.

Foreign currency transactions. Transactions denominated in foreign currencies are converted into the functional currency of each entity of the Group at the exchange rates prevailing on the date of transactions. Exchange gains and losses resulting from foreign currency re-measurement into the functional currencies are included in the determination of profit (loss) for the reporting period.

Monetary assets and liabilities denominated in foreign currencies are converted into the functional currency of each entity of the Group by applying the year end exchange rate and the effect is stated in the consolidated statement of income. Non-monetary assets and liabilities denominated in foreign currencies valued at cost are converted into the functional currency of each entity of the Group at the initial exchange rate. Non-monetary assets that are remeasured to fair value, recoverable amount or realizable value, are translated at the exchange rate applicable to the date of re-measurement.

Revenue recognition. Revenues represent the fair value of consideration received or receivable for the sale of goods and services in the normal course of business, net of discounts, value-added tax and export duties.

Revenues from oil and gas sales are recognized when such products are shipped or delivered to customers in accordance with the contract terms, the price is fixed or determinable, and the title has transferred. Services are recognized in the period in which the services are rendered.

Interest income is recognized as the interest accrues as related to the net carrying amount of the financial asset.

General and administrative expenses. General and administrative expenses represent overall corporate management and other expenses related to the general management and administration of the business unit as a whole. They include management and administrative compensation, legal and other advisory expenses, insurance of properties, social expenses and compensatory payments of general nature not directly linked to the Group's oil and gas activities, charity and other expenses necessary for the administration of the Group.

Employee benefits. Wages and salaries, bonuses, voluntary medical insurance, paid annual and sick leaves are accrued in the period in which the associated services are rendered by the employees of the Group. Compensation at dismissals, vocational support payments, and other allowances are expensed when incurred.

The Group contributes to the Russian Federation State social insurance fund and State pension plan on behalf of its employees based on gross salary payments. Mandatory contributions to the State social insurance fund and the State pension plan, which is a defined contribution plan, are expensed when incurred and are included in payroll expenses in the consolidated statement of income.

The Group also incurs employee costs related to the provision of benefits such as health and social infrastructure and services, employees meals, transportation, and other services. These amounts principally represent an implicit cost of employing production workers and, accordingly, are charged to payroll expenses in the consolidated statement of income.

Share based compensation. The Group accounts for share-based compensation in accordance with IFRS 2, Sharebased Payment. The fair value of the employee services received in exchange for the grant of the equity instruments is recognized as an expense. The total amount to be expensed over the vesting period is determined by reference to the fair value of the instruments granted measured at the grant date.

Pension obligations. The Group operates a non-contributory post-employment defined benefit plan based on employees' years of service and average salary (see Note 14).

The liability recognized in the consolidated statement of financial position in respect of the defined benefit pension plan is the present value of the defined benefit obligations at the balance sheet date, together with adjustments for unrecognized past service costs. The present value of the pension obligations are determined by discounting the estimated future cash outflows and then attributing such present value to years of service of the respective employees. The defined benefit obligations are calculated annually by independent actuaries using the projected unit credit method. The discount rate was determined by reference to Russian rouble denominated bonds issued by the Government of the Russian Federation chosen to match the duration of the post-employment benefit obligations.

Actuarial gains and losses arising from experience adjustments and changes in actuarial assumptions are recorded to the consolidated statement of income in the period in which they arise. Past service costs are amortized on a straight-line basis over the vesting period.

Earnings per share. Earnings per share are determined by dividing the profit or loss attributable to OAO NOVATEK shareholders by the weighted average number of shares outstanding during the reporting period.

Segment reporting. Operating segments are defined as components of the Group where separate financial information is available and reported regularly to the Group's chief operating decision maker (hereinafter referred to as "CODM", represented by the Management Committee of NOVATEK). Segments whose revenues, results or assets are ten percent or more of the total segments are reported separately.

4 CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS

Consolidated financial statements prepared in accordance with IFRS requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period.

Management reviews these estimates and assumptions on a continuous basis, by reference to past experiences and other factors considered as reasonable which form the basis for assessing the book values of assets and liabilities. Adjustments to accounting estimates are recognized in the period in which the estimate is revised if the change affects only that period or in the period of the revision and subsequent periods, if both periods are affected. Management also makes certain judgments, apart from those involving estimations, in the process of applying the Group's accounting policies. Actual results may differ from such estimates if different assumptions or circumstances apply.

Judgments and estimates that have the most significant effect on the amounts reported in these consolidated financial statements and have a risk of causing a material adjustment to the carrying amount of assets and liabilities within the next financial year are described below.

Useful lives of property, plant and equipment. Management assesses the useful life of an asset by considering the expected usage, estimated technical obsolescence, residual value, physical wear and tear and the operating environment in which the asset is located. Differences between such estimates and actual results may have a material impact on the amount of the carrying values of the property, plant and equipment and may result in adjustments to future depreciation rates and expenses for the period.

4 CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS (CONTINUED)

Fair values of financial assets and liabilities. The fair value of financial assets and liabilities, other than financial instruments that are traded in an active market, is determined by applying various valuation methodologies. Management uses its judgment to make assumptions based on market conditions existing at each balance sheet date. Discounted cash flow analysis is used for various loans and receivables as well as debt instruments that are not traded in active markets. The effective interest rate is determined by reference to the interest rates of instruments available to the Group in active markets. In the absence of such instruments, the effective interest rate is determined by reference to the interest rates of active market instruments available adjusted for the Group's specific risk premium estimated by management. For derivative contracts where observable information is not available, fair value estimations are determined using mark-to-market models and other acceptable valuation methods, for which the key inputs include future prices, volatility, price correlation, counterparty credit risk and market liquidity. Fair values of the Group's derivative commodity contracts and sensitivities to price assumptions are presented in Note 27.

Deferred income tax asset recognition. Management assesses deferred income tax assets at each balance sheet date and determines the amount recorded to the extent that realization of the related tax benefit is probable. In determining future taxable profits and the amount of tax benefits that are probable in the future management makes judgments and applies estimations based on prior years taxable profits and expectations of future income that are believed to be reasonable under the circumstances.

Estimation of oil and gas reserves. Engineering estimates of oil and gas reserves are inherently uncertain and are subject to future revisions. The Group estimates its oil and gas reserves in accordance with rules promulgated by the Securities and Exchange Commission (SEC) for proved reserves. Accounting measures such as depreciation, depletion and amortization charges, impairment assessments and asset retirement obligations that are based on the estimates of proved reserves are subject to change based on future changes to estimates of oil and gas reserves.

Proved reserves are estimated by reference to available reservoir and well information, including production and pressure trends for producing reservoirs. Furthermore, estimates of proved reserves only include volumes for which access to market is assured with reasonable certainty. All proved reserves estimates are subject to revision, either upward or downward, based on new information, such as from development drilling and production activities or from changes in economic factors, including product prices, contract terms or development plans.

Proved reserves are defined as the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions. In some cases, substantial new investment in additional wells and related support facilities and equipment will be required to recover such proved reserves. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change over time as additional information becomes available.

In general, estimates of reserves for undeveloped or partially developed fields are subject to greater uncertainty over their future life than estimates of reserves for fields that are substantially developed and depleted. As those fields are further developed, new information may lead to further revisions in reserve estimates.

Oil and gas reserves have a direct impact on certain amounts reported in the consolidated financial statements, most notably depreciation, depletion and amortization as well as impairment expenses. Depreciation rates on oil and gas assets using the units-of-production method for each field are based on proved developed reserves for development costs, and total proved reserves for costs associated with the acquisition of proved properties. Assuming all variables are held constant, an increase in proved developed reserves for each field decreases depreciation, depletion and amortization expenses. Conversely, a decrease in the estimated proved developed reserves increases depreciation, depletion and amortization expenses. Moreover, estimated proved reserves are used to calculate future cash flows from oil and gas properties, which serve as an indicator in determining whether or not property impairment is present.

Although the possibility exists for changes or revisions in estimated reserves to have a critical effect on depreciation, depletion and amortization charges and, therefore, reported net profit for the year, it is expected that in the normal course of business the diversity of the Group's asset portfolio will mitigate the likelihood of this occurring.

4 CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS (CONTINUED)

Impairment of non-financial assets. Management assesses whether there are any indicators of possible impairment of all non-financial assets at each reporting date based on events or circumstances that indicate the carrying value of assets may not be recoverable. Such indicators include changes in the Group's business plans, changes in commodity prices leading to unprofitable performances, changes in product mixes, and for oil and gas properties, significant downward revisions of estimated proved reserves. Other non-financial assets are tested for impairment when there are indicators that the carrying amounts may not be recoverable.

When value in use calculations are undertaken, management estimates the expected future cash flows from the asset or cash generating unit and chooses a suitable discount rate in order to calculate the present value of those cash flows.

Information about the carrying amounts of major classes of non-financial assets – property, plant and equipment and long-term investments is presented in Notes 6 and 7.

Impairment provision for trade receivables. The impairment provision for trade receivables is based on management's assessment of the probability of collection of individual customer accounts receivable. Significant financial difficulties of the customer, probability that the customer will enter bankruptcy or financial reorganization, and default or delinquency in payments are considered indicators that the receivable is potentially impaired. Actual results could differ from these estimates if there is deterioration in a major customer's creditworthiness or actual defaults are higher than the estimates.

When there is no expectation of recovering additional cash for an amount receivable, it is written off against the associated provision.

Future cash flows of trade receivables that are evaluated for impairment are estimated on the basis of the contractual cash flows of the assets and the experience of management in respect of the extent to which amounts will become overdue as a result of past loss events and the success of recovery of overdue amounts. Past experience is adjusted on the basis of current observable data to reflect the effects of current conditions that did not affect past periods and to remove the effects of past conditions that do not exist currently.

Pension obligations. The cost of defined benefit pension plans and related current service costs are determined using actuarial valuations. The actuarial valuations involve making demographic assumptions (mortality rates, age of retirement, employee turnover and disability) as well as financial assumptions (discount rates, expected rates of return on assets, inflation forecasts, future salary and pension increases). Due to the long term nature of these plans, such estimates are subject to significant uncertainty.

Asset retirement obligations. Management makes provision for the future costs of decommissioning oil and gas production facilities, pipelines and related support equipment based on the best estimates of future cost and economic lives of those assets. Estimating future asset retirement obligations is complex and requires management to make estimates and judgments with respect to removal obligations that will occur many years in the future.

Changes in the measurement of existing obligations can result from changes in estimated timing, future costs or discount rates used in valuation.

The Group also assesses its liabilities for site restoration at each consolidated statement of financial position date in accordance with the guidelines of IFRIC 1, Changes in Existing Decommissioning, Restoration and Similar Liabilities. The amount recognized as a provision is the best estimate of the expenditures required to settle the present obligation at the consolidated statement of financial position date based on current legislation where the Group's respective operating assets are located, and is also subject to change because of modifications, revisions and changes in laws and regulations and their interpretation thereof. As a result of the subjectivity of these provisions there is uncertainty regarding both the amount and estimated timing of incurring such costs.

Fair value assessment of OAO Yamal LNG. As further discussed in Note 5, the Group ceased control of Yamal LNG effective 6 October 2011, but retained joint control and, consequently, was required to fair value the remaining interest in Yamal LNG in accordance with IFRS. The fair value of the investment in Yamal LNG was calculated based on a discounted cash flow model for the Yamal LNG project. The discounted cash flow model included a number of key assumptions, the sensitivities of which are included in Note 5.

5 ACQUISITIONS AND DISPOSALS

Acquisition of OOO Gazprom mezhregiongas Kostroma

On 28 December 2012, the Group acquired an 82 percent participation interest in OOO Gazprom mezhregiongas Kostroma, a Russian regional natural gas trader, to support and expand natural gas sales opportunities in the Kostroma region in the Russian Federation, for total cash consideration of RR 554 million, which was subsequently paid in 2013. At the date of acquisition, the company held three percent of its participation interest in the form of treasury shares, which were eliminated upon consolidation and, accordingly, the Group's effective participation interest in Gazprom mezhregiongas Kostroma was 84.54 percent.

Management has assessed the fair value of identifiable assets and liabilities and calculated that no goodwill arose on the acquisition. The following table represents the net fair values comprising 100 percent of the assets and liabilities of Gazprom mezhregiongas Kostroma:

OOO Gazprom mezhregiongas Kostroma	Fair values at the acquisition date

Non-current assets	735
Trade receivables	895
Other current assets	12
Cash and cash equivalents	296
Non-current liabilities	(129)
Trade payables	(1,096)
Other current liabilities	(58)
Total identifiable net assets	655
Purchase consideration	554
Fair value of the Group's interest in net assets (RR 655 million at 84.54% ownership)	(554)
Goodwill	-

The financial and operational activities of Gazprom mezhregiongas Kostroma would have had an effect of an additional RR 6.7 billion in the Group's revenues and immaterial effect on the Group's profit before tax, if the acquisition occurred on 1 January 2012.

Disposal of OOO Purovsky Terminal

In December 2012, the Group disposed of its 100 percent participation interest in OOO Purovsky Terminal, its noncore subsidiary, to a third party for RR 97 million, which was fully paid in December 2012. The Group recognized a loss on the sale before income tax of RR 60 million.

Prior to the disposal, the Group included balances and results of the operations of the disposed subsidiary within "exploration, production and marketing" in the Group's segment information.

Acquisition of ZAO Nortgas

On 27 November 2012, the Group acquired 49 percent of the outstanding ordinary shares of ZAO Nortgas, an oil and gas company located in the YNAO, for total cash consideration of RR 42,697 million (USD 1,375 million), which was fully paid in November 2012. Nortgas holds a production license for the North-Urengoyskoye field, which expires in 2018. Estimated proved reserves of the field appraised by DeGolyer and MacNaughton under the PRMS and SEC reserve methodologies at 31 December 2012 totalled approximately 186 billion and 157 billion cubic meters of natural gas and 25 million and 21 million tons of hydrocarbon liquids, respectively.

As described above, the Group acquired 49 percent of the ownership interest in Nortgas; however, the Charter stipulates that key financial and operating decisions regarding its business activities are subject to unanimous approval by the Board of Directors. Consequently, the voting mechanism effectively establishes joint control over Nortgas and the Group accounts for the investment under the equity method.

At 31 December 2012, in accordance with IAS 31, Interest in Joint Ventures, the Group assessed preliminary fair values of the identified assets and liabilities of Nortgas. In the consolidated financial statements for the year ended 31 December 2012, the fair value of purchase consideration and the fair value of the identifiable acquired assets and liabilities are preliminary as the Group is in the process of finalizing the fair value estimates for certain assets and liabilities, primarily for property, plant and equipment. Management is required to finalize the fair value determination within 12 months of the date of acquisition. Any revisions to the provisional values will be reflected as of the acquisition date.

ZAO Nortgas	Preliminary fair values at the acquisition date

Property, plant and equipment	130,135
Other non-current assets	1,623
Trade receivables	2,312
Other current assets	2,246
Cash and cash equivalents	966
Long-term debt	(14,378)
Other non-current liabilities	(22,055)
Short-term debt	(1,341)
Dividends payable	(9,700)
Other current liabilities	(2,671)
Total identifiable net assets	87,137
Purchase consideration	42,697
Preliminary fair value of the Group's interest in net assets
(RR 87,137 million at 49% ownership)	(42,697)
Preliminary goodwill	-

The following table represents the preliminary fair values comprising 100 percent of the assets and liabilities of Nortgas:

Subsequent to the acquisition, the Group signed a purchase contract to buy 50 percent of total natural gas produced by Nortgas starting from 1 January 2013 at a predetermined price reflecting current ex-field market price for the region subject to indexation based on the relevant Federal Tariffs Service (FTS) prices. In addition, the Group signed the contract until 31 December 2015 to purchase 100 percent of the unstable gas condensate produced by Nortgas at ex-field prices based on benchmark crude oil and oil products market quotes adjusted for quality and respective tariffs for transportation and processing.

Acquisition of OOO Gazprom mezhregiongas Chelyabinsk

In November 2011, the Group acquired a 100 percent participation interest in OOO Gazprom mezhregiongas Chelyabinsk to expand and market natural gas sales in the Chelyabinsk Region of the Russian Federation for cash consideration of RR 1,550 million, which was fully paid in December 2011. Gazprom mezhregiongas Chelyabinsk is responsible for the sale of natural gas to industrial and residential customers in the Chelyabinsk region, one of the top ten Russian regions in terms of natural gas consumption.

Management has assessed the fair value of identifiable assets and liabilities and calculated that no goodwill arose on the acquisition. The following table represents the net fair values of the assets and liabilities of Gazprom mezhregiongas Chelyabinsk:

OOO Gazprom mezhregiongas Chelyabinsk	Fair values at the acquisition date
Property, plant and equipment	321
Other non-current assets	1,230
Trade receivables	2,112
Other current assets	205
Cash and cash equivalents	654
Non-current liabilities	(232)
Trade payables	(2,364)
Other current liabilities	(376)
Total identifiable net assets	1,550
Purchase consideration	1,550
Goodwill	-

Acquisition of additional equity stake in OAO Yamal LNG

On 26 May 2009, the Group entered into the contract to acquire 51 percent of the outstanding ordinary shares of OAO Yamal LNG, an exploration stage oil and gas company located in the north-eastern part of the Yamal peninsula, YNAO. In September 2011, the Group exercised two call options, acquired in 2009 and 2011, and, as a result, increased its equity stake in Yamal LNG to 100 percent through a purchase of additional 49 percent shares of the company for the total consideration of RR 31,670 million (USD 986 million), of which RR 15,101 million (USD 482 million) was paid in 2009-2011 and RR 16,290 million (USD 504 million) was paid in 2012. As a result of these transactions, the Group reduced non-controlling interest by RR 19,920 million and recorded a difference of RR 11,750 million directly to retained earnings.

Disposal of ownership interest in OAO Yamal LNG

On 5 October 2011, the Board of Directors of OAO NOVATEK approved the sale of a 20 percent stake in Yamal LNG, the Group's wholly owned subsidiary, to TOTAL S.A., the strategic partner in the Yamal LNG project (the "Project"). Prior to that date, the proposed sale received the necessary approvals from the Russian Federation's Strategic Investment Committee and Federal Anti-Monopoly Service.

On 6 October 2011, the Group entered into a Sales contract and signed a new shareholder's agreement (the "Shareholders' agreement") with TOTAL E&P YAMAL SAS, an affiliate of TOTAL S.A., establishing the framework for joint cooperation in exploring and developing the South-Tambeyskoye field (held by Yamal LNG) located in the YNAO.

Total consideration for the 20 percent stake in Yamal LNG to be paid by TOTAL E&P YAMAL comprises of three tranches:

i. first tranche a cash payment of USD 425 million to NOVATEK upon the contract conclusion (payment received in October 2011);
ii. second tranche a cash payment of USD 375 million through additional capital contributions to the ordinary share capital of Yamal LNG, of which USD 170 million was received in 2011 and the remainder USD 205 was received in 2012; and
iii. third tranche an additional cash payment ranging from USD nil to USD 500 million depending on the amount of the Project's capital expenditure through additional capital contribution to the ordinary share capital of Yamal LNG; the final amount of the additional payment will be determined based on the result of the Final Investment Decision. Management has assessed that it is most likely that the full USD 500 million will need to be paid. If the actual amount is less than the amount assessed then the associated consideration and gain recognized for the disposal of the 20 percent stake would need to be adjusted.

In addition, TOTAL E&P YAMAL agreed to compensate past costs of USD 11 million, incurred by NOVATEK in respect of the Project prior to finalization of contractual terms and conditions, through an additional capital contribution to the ordinary share capital of Yamal LNG, which was paid in December 2011.

The Shareholders' agreement further stipulates that additional financing for the Project, if needed, will be partly exercised in a form of disproportional loans from shareholders. Management is unable to quantify at this time the likelihood, amount, timing or interest rate for these loans and, based on this assessment, has determined that their fair value cannot be measured reliably at this moment.

The Shareholders' agreement also permits the Group to subsequently reduce its shareholding in Yamal LNG to 51 percent based on certain pre-specified terms and governance structure.

Presently, the Group has retained an 80 percent interest in Yamal LNG after the transaction; however, the Shareholders' agreement stipulates that key strategic, operational and financial decisions are subject to approval by eight out of nine members of the Board of Directors. As a result of these changes, the Group's effective control over Yamal LNG ceased on 6 October 2011. The Group has determined Yamal LNG to be a joint venture and will account for this investment under the equity method.

Based on the Shareholders' agreement and the provisions of the Sales contract, the Group recorded the disposal of a 20 percent interest in Yamal LNG for total consideration of RR 36,893 million realizing a gain of RR 62,831 million, net of associated income tax of RR 117 million.

The following table summarizes the consideration details and shows the components of the gain from the sale of the ownership interest in Yamal LNG:

	RR million
First tranche (USD 425 million at exchange rate of 32.64 to USD 1.00)	13,871
Compensation of past costs (80 percent of USD 11 million at exchange rate of 32.64 to USD 1.00)	294
Second tranche (80 percent of USD 375 million at exchange rate of 32.64 to USD 1.00)	9,790
Third tranche (80 percent of USD 500 million at exchange rate of 32.64 to USD 1.00 discounted at 0.884 percent per annum)	12,938
Total consideration	36,893
Less: carrying amount of the Group's 20 interest in the net assets	(8,208)
Add: fair value adjustment relating to the retained investment in joint venture	34,263
Gain on the sale of ownership interest	62,948

In accordance with IAS 27, Consolidated and Separate Financial Statements, the Group re-measured its retained investment in Yamal LNG at fair value at the date of ceasing control, with the change in value of RR 34,263 million recognized as an additional gain from disposal as reflected in net gain on disposal of interest in subsidiaries in the consolidated statement of income. The fair value of the investment in Yamal LNG was based on a discounted cash flow model for the Yamal LNG project. The significant assumptions in the discounted cash flow model are: forecasted prices for liquefied natural gas ("LNG"); anticipated production volumes; future capital expenditures required to build necessary infrastructure and drill production wells; and the discount factor used in the fair value calculation. The key sensitivities in relation to the discounted cash flows are:

future LNG prices were based on estimated Brent prices using growth rates as forecasted by the World Bank. If these estimated future prices were to decrease by one percent for each year in the cash flow projection then, assuming that other parameters remain unchanged, the fair value of the retained interest in Yamal LNG and the associated gain on the revaluation would be reduced by RR 6,903 million;
future production was based on estimates of proved and probable reserves. If production volumes were to be one percent lower in the cash flow projection then, assuming that other parameters remain unchanged, the fair value of the retained interest in Yamal LNG and the associated gain on the revaluation would be reduced by RR 4,903 million;
future capital expenditure over the life of the project has been estimated based on preliminary engineering and costing estimates. If the level of capital expenditure were to be one percent higher in the cash flow projection then, assuming that other parameters remain unchanged, the fair value of the retained interest in Yamal LNG and the associated gain on the revaluation would be reduced by RR 3,904 million; and
the discount rate was assumed to be 11.9% (in US dollar terms). If the discount rate was increased by half of one percent (to 12.4%) then, assuming that other parameters remain unchanged, the fair value adjustment and the associated gain on the revaluation would be reduced by RR 21,139 million.

Below is a breakdown of major classes of assets and liabilities at the date of disposal:

OAO Yamal LNG	RR million

Property, plant and equipment	45,867
Other non-current assets	1,404
Cash and cash equivalents	1,846
Other current assets	1,135
Other non-current liabilities	(810)
Short-term debt	(8,100)
Other current liabilities	(300)
Total identifiable net assets at disposal	41,042

The aforementioned property, plant and equipment in the amount of RR 45,867 million (including the costs of mineral rights aggregating RR 39,714 million) was included in the line "Disposal of subsidiaries, net" as disclosed in Note 6. Short-term debt in the amount of RR 8,100 million, which was owed to the Group was settled in December 2011 ahead of its maturity schedule.

The following table reconciles the carrying value of Yamal LNG prior to disposal and the carrying value of the retained investment in the entity recorded under the equity method of accounting in these consolidated financial statements:

OAO Yamal LNG	RR million
Carrying value of the net assets at disposal Add: Group's proportion of proceeds from additional shares emissions Less: carrying amount of the Group's 20 interest in the net assets Add: fair value adjustment relating to the retained investment in joint venture	41,042 23,022 (8,208) 34,263
The carrying value of equity investment	90,119

Prior to the disposal, the Group included balances and results of the operations of the disposed subsidiary within "exploration, production and marketing" in the Group's segment information.

6 PROPERTY, PLANT AND EQUIPMENT

Movements in property, plant and equipment, for the years ended 31 December 2012 and 2011 are as follows:

	Oil and gas properties and equipment	Assets under construction and advances for construction	Other	Total
Cost	193,411	16,022	4,236	213,669
Accumulated depreciation, depletion
and amortization	(26,926)	-	(1,170)	(28,096)
Net book value at 1 January 2011	166,485	16,022	3,066	185,573
Acquisition of subsidiaries	108	183	30	321
Additions	10,140	27,869	22	38,031
Transfers	15,455	(20,216)	4,761	-
Depreciation, depletion and amortization	(9,026)	-	(424)	(9,450)
Disposal of subsidiaries, net	(40,136)	(5,665)	(66)	(45,867)
Impairment	(513)	(107)	-	(620)
Disposals, net	(549)	(439)	(216)	(1,204)
Cost Accumulated depreciation, depletion	177,788	17,647	8,603	204,038
and amortization	(35,824)	-	(1,430)	(37,254)
Net book value at 31 December 2011	141,964	17,647	7,173	166,784
Acquisition of subsidiaries	24	33	23	80
Additions	1,564	41,522	468	43,554
Transfers	21,608	(22,414)	806	-
Depreciation, depletion and amortization	(10,882)	-	(503)	(11,385)
Disposal of subsidiaries, net	(14)	-	(32)	(46)
Disposals, net	(69)	(1,493)	(49)	(1,611)
Reclassifications	1,415	-	(1,415)	-
Cost	202,420	35,295	8,031	245,746
Accumulated depreciation, depletion and amortization	(46,810)	-	(1,560)	(48,370)
Net book value at 31 December 2012	155,610	35,295	6,471	197,376

Included within the oil and gas properties and equipment balance at 31 December 2012 and 2011 are proved properties of RR 28,205 million and RR 22,355 million, net of accumulated depreciation, depletion and amortization of RR 11,744 million and RR 10,300 million, respectively.

Included within the oil and gas properties and equipment balance at 31 December 2012 and 2011 are unproved properties of RR 7,753 million and RR 14,061 million, respectively. The Group's management believes these costs are recoverable and has plans to explore and develop the respective unproved properties.

Included within assets under construction and advances for construction are advances to suppliers of equipment of RR 3,836 million and RR 3,781 million at 31 December 2012 and 2011, respectively.

6 PROPERTY, PLANT AND EQUIPMENT (CONTINUED)

Included in additions to property, plant and equipment for the years ending 31 December 2012 and 2011 are capitalized interest and foreign exchange differences of RR 2,839 million and RR 4,145 million, respectively. The interest capitalization rates for 2012 and 2011 used for additions were 6.8 percent and 7.1 percent, respectively.

In September 2011, the Group purchased, through participation in a tender process, exploration and production licenses for the Salmanovskoye (Utrenneye) and Geofizicheskoye fields and geological studies, exploration and production licenses for the North-Obskiy and East-Tambeyskiy license areas for a total payment of RR 6,870 million, which were included in additions to oil and gas properties.

In October 2011, the Group ceased control of OAO Yamal LNG as described in Note 5 and has recorded a disposal aggregating RR 45,867 million as "Disposal of subsidiaries, net" in property, plant and equipment. The Group retained 80 percent of Yamal LNG and has recorded its proportional share in investments in joint ventures (see Note 7).

Reconciliation of depreciation, depletion and amortization (DDA):

	Year ended 31 December:
	2012	2011
Depreciation, depletion and amortization of property,
plant and equipment	11,385	9,450
Add: DDA of intangible assets	244	111
Less: DDA included in general and administrative expenses (see Note 22)	(314)	(198)
Less: DDA capitalized in the course of intra-group construction services	(130)	(86)
DDA as presented in the consolidated statement of income	11,185	9,277

At 31 December 2012 and 2011, no property, plant and equipment was pledged as security for the Group's borrowings. Impairment of RR nil million and RR 620 million was recognized in respect of oil and gas properties and equipment for the years ended 31 December 2012 and 2011, respectively.

Capital commitments are disclosed in Note 28.

7 INVESTMENTS IN JOINT VENTURES

	At 31 December 2012	At 31 December 2011
Joint ventures:
OAO Yamal LNG	96,736	89,549
ZAO Nortgas	42,586	-
OOO Yamal Development (consolidated)	24,430	8,100
OAO Sibneftegas	24,160	24,187
ZAO Terneftegas	1,224	1,193
Total investments in joint ventures	189,136	123,029

OAO Yamal LNG. As discussed in Note 5, on 6 October 2011, the Group sold a 20 percent stake in OAO Yamal LNG and signed a new Shareholder's agreement with TOTAL E&P YAMAL, establishing the framework for joint cooperation in exploring and developing the South-Tambeyskoye field (held by Yamal LNG) located in the YNAO.

The Group retained an 80 percent interest in Yamal LNG after the transaction; however, the Shareholders' agreement stipulates that key strategic, operational and financial decisions are subject to approval by eight out of nine members of the Board of Directors. As a result of these changes, the Group's effective control over Yamal LNG ceased on 6 October 2011, following which the Group has determined Yamal LNG to be a joint venture and accounts for it under the equity method.

7 INVESTMENTS IN JOINT VENTURES (CONTINUED)

ZAO Nortgas. As discussed in Note 5, on 27 November 2012, the Group acquired 49 percent of the outstanding ordinary shares of ZAO Nortgas, an oil and gas company holding the production license for the North-Urengoyskoye field located in the YNAO for RR 42,697 million. The Charter of Nortgas stipulates that key financial and operating decisions regarding its business activities are subject to unanimous approval by the Board of Directors. Consequently, the voting mechanism effectively establishes joint control over Nortgas. The Group accounts for it under the equity method.

OOO Yamal Development. The Group holds a 50 percent participation interest in OOO Yamal Development, its joint venture with OAO Gazprom Neft, a subsidiary of OAO Gazprom, and accounts for its share of the joint venture using the equity method.

Yamal Development holds a 51 percent participation interest in OOO SeverEnergia, which through its wholly owned subsidiary OAO Arkticheskaya gazovaya kompaniya holds a number of exploration and production licenses, located in YNAO (see Note 28).

The Charter of SeverEnergia stipulates that key financial and operational decisions regarding its business activities are subject to approval by six out of the seven members of the Board of Directors, i.e. none of the participants have a preferential voting right. As a result, the Group has determined SeverEnergia as a joint venture of Yamal Development; the assets and liabilities of SeverEnergia and its financial results are included in the assets, liabilities and financial results of Yamal Development under the equity method in the disclosure of summarized financial information about the Group's investments in joint ventures.

OAO Sibneftegas. The Group holds 51 percent ownership in OAO Sibneftegas, an oil and gas company, which holds a number of exploration and production licenses, located in the YNAO (see Note 28). The Charter of Sibneftegas stipulates that key financial and operational decisions regarding its business activities are subject to approval by nine out of the eleven members of the Board of Directors, that means effectively the unanimous approval by both shareholders. Consequently the voting mechanism effectively establishes joint control over Sibneftegas. The Group accounts for it under the equity method.

ZAO Terneftegas. The Group holds 51 percent ownership in ZAO Terneftegas, its joint venture with TOTAL E&P ACTIVITIES PETROLIERES, established for joint cooperation in exploring and developing the Termokarstovoye gas condensate field (held by Terneftegas) located in the YNAO.

The Shareholders' agreement stipulates that key financial and operational decisions shall be subject to unanimous approval by both shareholders and none of the participants have a preferential voting right. Consequently, the Group's interest in Terneftegas is accounted for using the equity method.

The table below summarizes the movement in the carrying amounts of the Group's joint ventures:

	Year ended 31 December
	2012	2011
At 1 January	123,029	27,026
Share of profit (loss) of joint ventures before income tax	(2,221)	(4,725)
Share of income tax (expense) benefit	116	845
Share of profit (loss) of joint ventures, net of income tax	(2,105)	(3,880)
Acquisitions of joint ventures (see Note 5)	42,697	-
Contributions to equity	25,515	10,000
Disposals of subsidiaries resulting in recognition of joint ventures	-	90,121
Losses (reversals) recognized in excess of investments in joint ventures, reclassified to long-term loans receivable for these companies	-	(238)
At 31 December	189,136	123,029

7 INVESTMENTS IN JOINT VENTURES (CONTINUED)

In 2012, the equity of Yamal LNG was increased through disproportional contribution by its participants totalling RR 23,811 million in accordance with the Shareholders' agreement, of which RR 9,167 million was attributable to NOVATEK (see Note 8). As a result of disproportional contributions, the Group's shareholding did not change notably.

In February 2012, the charter capital of Yamal Development was increased by converting RR 32,697 million of loans provided to the company by its participants, of which RR 16,348 million was attributable to NOVATEK (see Note 8). In June 2011, the charter capital of Yamal Development was increased by RR 20 billion through the conversion of loans, provided to the company by its participants, of which RR 10 billion was attributable to NOVATEK. As a result of each transaction, the participants' pro-rata share in the joint venture increased.

As discussed in Note 5, in October 2011, the Group's effective control over Yamal LNG ceased and subsequent to that event, the Group classified Yamal LNG as a joint venture and recognized its carrying value in line 'Disposals of subsidiaries resulting in recognition of joint ventures'.

At 31 December 2012 and 2011, the Group's interests in its joint ventures and their summarized financial information, relating to the Group's interest, were as follows:

As at and for the year ended 31 December 2012	Non current assets	Current assets	Non current liabilities	Current liabilities	Net assets	Revenues	Profit (loss)	Interest held
Yamal LNG	96,586	3,378	15,326	708	83,930	51	(1,811)	80%
Nortgas	64,904	1,899	22,838	1,379	42,586	365	(110)	49%
Yamal Development
(consolidated)	24,421	9	-	-	24,430	-	(19)	50%
SeverEnergia	42,493	1,322	16,799	2,993	24,023	1,297	11	25.5%
Less: investment and
share of profit of
Yamal
Development in
SeverEnergia	(24,023)	-	-	-	(24,023)	(1,297)	(11)	-
Sibneftegas	37,931	1,056	13,984	843	24,160	5,272	(27)	51%
Terneftegas	3,479	1,053	3,220	88	1,224	1	30	51%
Total	245,791	8,717	72,167	6,011	176,330	5,689	(1,937)
As at and for the year ended 31 December 2011	Non current assets	Current assets	Non current liabilities	Current liabilities	Net assets	Revenues	Profit (loss)	Interest held
Yamal LNG	85,529	1,946	20,542	240	66,693	32	(707)	80%
Yamal Development
(consolidated)	24,340	109	-	16,349	8,100	-	(1,662)	50%
SeverEnergia	37,068	1,264	5,933	8,376	24,023	-	(224)	25.5%
Less: investment and
share of loss of
Yamal
Development in
SeverEnergia	(24,023)	-	-	-	(24,023)	-	224	-
Sibneftegas	40,046	640	15,469	1,030	24,187	3,661	(1,571)	51%
Terneftegas	1,713	164	668	16	1,193	-	(74)	51%
Total	164,673	4,123	42,612	26,011	100,173	3,693	(4,014)

7 INVESTMENTS IN JOINT VENTURES (CONTINUED)

At 31 December 2012 and 2011, the Group's investment in Yamal LNG totaled RR 96,736 million and RR 89,549 million, which differed from its share in the net assets of RR 83,930 million and RR 66,693 million, respectively, as noted above. These differences of RR 12,806 million and RR 22,856 million, respectively, relate to the Group's share in the second and third tranches recognized as part of the consideration for the disposal of the 20 percent interest in Yamal LNG (see Note 5).

All of the joint ventures listed above are registered in the Russian Federation.

8 LONG-TERM LOANS AND RECEIVABLES

	At 31 December 2012	At 31 December 2011
Russian rouble denominated loans	8,564	9,737
US dollar denominated loans	4,366	220
Total	12,930	9,957
Less: current portion of long-term loans	(428)	(634)
Total long-term loans	12,502	9,323
Long-term receivables	394	22,027
Long-term interest receivable	254	780
Total long-term loans and receivables	13,150	32,130

Russian rouble denominated loans. At 31 December 2012 and 2011, the Russian rouble denominated loans included loans to OAO Sibneftegas, the Group's joint venture, in the amount of RR 8,564 million and RR 9,737 million, respectively (see Note 30). The loans had interest rates ranging from 9.5 percent to 10 percent per annum (weighted average interest rate of 9.93 percent and 9.88 percent at 31 December 2012 and 2011, respectively) and are repayable until November 2014.

US dollar denominated loans. At 31 December 2012 and 2011, the US dollar denominated loans included loans to ZAO Terneftegas, the Group's joint venture, in the amount of USD 48 million and USD 7 million, respectively. The loans bear an interest rate of 3.88 percent per annum, which can be adjusted in the subsequent years subject to certain conditions. The loans and interest are repayable after the commencement of commercial production.

In November 2012, the Group provided a shareholder loan to OAO Yamal LNG, the Group's joint venture, in the amount of USD 96 million at an interest rate of 5.09 percent per annum, which can be adjusted in subsequent years subject to certain conditions. The loans and interest are repayable after the commencement of commercial production.

Long-term receivables. In November 2011, the shareholders of OAO Yamal LNG made a decision to increase its equity through a disproportional subscription to the entity's additional shares emissions in the aggregated amount of RR 17,046 million. The legal procedures to register the new charter were not completed at 31 December 2011 and, accordingly, the Group's share of RR 3,955 million paid in 2011 was recognized as long-term receivables. In January 2012, the Group paid the remaining RR 2,507 million. In April 2012, the new charter was formally registered (see Note 7).

In November 2011, the participants of ɈɈɈ Yamal Development, the Group's joint venture, made a decision to pro-ratably increase its equity by converting the part of the loan provided to the company in the amount of RR 32,697 million to equity. The legal procedures to register the new charter were not completed at 31 December 2011 and, accordingly, the Group's share of RR 16,348 million was recognized as long-term receivables. In February 2012, the new charter was formally registered (see Note 7).

No provisions for impairment of long-term loans and receivables were recognized in the consolidated statement of financial position at 31 December 2012 and 2011.

9 INVENTORIES

	At 31 December 2012	At 31 December 2011
Natural gas and hydrocarbon liquids at cost Materials and supplies at cost	2,239 583	1,146 400
Materials and supplies at net realizable value (net of provisions of RR 29 million and RR 31 million at 31 December 2012 and 2011, respectively) Other inventories	256 13	133 4
Total inventories	3,091	1,683

No impairment expenses were recorded during the years ended 31 December 2012 and 2011. No inventories were pledged as security for the Group's borrowings or payables at both dates.

10 TRADE AND OTHER RECEIVABLES

	At 31 December 2012	At 31 December 2011
Trade receivables (net of provision of RR 406 million and RR 133 million at 31 December 2012 and 2011, respectively)	14,250	14,900
Other receivables (net of provision of RR 4 million and RR 14 million at 31 December 2012 and 2011, respectively)	2,158	1,703
Interest on loans receivable	1	96
Total trade and other receivables	16,409	16,699

The carrying values of trade and other receivables approximate their respective fair values. The related exposure to credit risk at the consolidated statement of financial position date is the carrying value of each class of receivables mentioned above.

The Group holds letters of credit in banks with investment grade rating as security for trade receivables in amount RR 1,610 million and RR 1,706 million at 31 December 2012 and 2011, respectively. Also the Group holds as a collateral 100 percent participation interest in OOO BIAXPLEN NK (formerly OOO NOVATEK-Polymer) for other receivables from OAO SIBUR Holding. The Group does not hold any other collateral as security for trade and other receivables (see Note 27 for credit risk disclosures).

Trade and other receivables that are less than three months past due are generally not considered for impairment unless other indicators of impairment exist. Trade and other receivables of RR 277 million and RR 478 million at 31 December 2012 and 2011, respectively, were past due but not impaired. The Group has expanded its natural gas sales to a larger number of mid- to small-sized customers as a result of the recent acquisitions of regional gas traders.

The Group has assessed the payment history of these accounts and recognized impairment where deemed necessary.

The ageing analysis of these past due but not impaired trade and other receivables are as follows:

	At 31 December 2012	At 31 December 2011
Up to 90 days past-due 91 to 360 days past-due Over 360 days past-due	185 85 7	343 135 -
Total past due but not impaired	277	478
Not past due and not impaired	16,132	16,221
Total trade and other receivables	16,409	16,699

10 TRADE AND OTHER RECEIVABLES (CONTINUED)

Movements on the Group provision for impairment of trade and other receivables are as follows:

	Year ended 31 December:
	2012	2011
At 1 January	147	-
Additional provision recorded	272	92
Acquisition of subsidiaries	124	76
Disposal of subsidiaries Receivables written off as uncollectible	(3) (130)	-
		(1)
Provision reversed	-	(20)
At 31 December	410	147

The provision for impaired trade and other receivables has been included in the consolidated statement of income in net impairment expense.

11 PREPAYMENTS AND OTHER CURRENT ASSETS

	At 31 December 2012	At 31 December 2011
Financial assets
Russian rouble denominated loans	428	6,859
Cash restricted in the form of guarantee	1,959	-
Commodity derivatives	451	-
Short-term bank deposits (with original maturity over three months)	10	17
Non-financial assets
Deferred export duties for stable gas condensate and liquefied
petroleum gas	2,718	922
Recoverable value-added tax	1,992	1,550
Deferred transportation expenses for natural gas	1,902	1,139
Prepayments and advances to suppliers (net of provision of RR 13 million
and RR 12 million at 31 December 2012 and 2011, respectively)	6,479	3,322
Prepaid taxes other than income tax	1,523	668
Deferred transportation expenses for stable gas condensate
and liquefied petroleum gas	1,067	413
Other current assets	38	60
Total prepayments and other current assets	18,567	14,950

At 31 December 2011, the Russian rouble denominated loans included a loan provided by NOVATEK proportionally with other participants to OOO SeverEnergia, the Group's related party, in the amount of RR 6,225 million (see Note 30). The loan bore an annual interest rate of MosPrime plus three percent and was fully repaid in March 2012.

12 CASH AND CASH EQUIVALENTS

	At 31 December 2012	At 31 December 2011
Cash at current bank accounts	8,206	7,958
Russian rouble denominated deposits (average interest rate 4.7% p.a. and 4.5% p.a. for 2012 and 2011, respectively)	4,223	4,986
US dollar denominated deposits (average interest rate 0.6% p.a. and 0.8% p.a. for 2012 and 2011, respectively)	5,686	10,822
Other currency denominated deposits	305	65
Total cash and cash equivalents	18,420	23,831

All deposits have original maturities of less than three months (see Note 27 for credit risk disclosures).

13 LONG-TERM DEBT

	At 31 December 2012	At 31 December 2011
US dollar denominated bonds Russian rouble denominated bonds Russian rouble denominated loans US dollar denominated loans	67,998	39,982 9,971 24,966 20,559
	29,960 24,821

	Total
Less: current portion of long-term debt	(34,682)	(20,298)
Total long-term debt	97,805	75,180

At 31 December 2012 and 2011 the Group's long-term debt by facility is as follows:

	At 31 December 2012	At 31 December 2011
Eurobonds – Ten-Year Tenor (repayable in 2022) Russian rouble denominated bonds (repayable in 2015)	30,232 19,969	- -
Eurobonds – Ten-Year Tenor (repayable in 2021) Eurobonds – Five-Year Tenor (repayable in 2016)	19,620 18,146	20,776 19,206
Sberbank three-year loan (repayable in 2013)	14,984	14,966
Russian rouble denominated bonds (repayable in 2013) Sberbank credit line facility	9,991 9,837	9,971 -
Nordea Bank	6,075	6,439
Sumitomo Mitsui Banking Corporation Europe Limited UniCredit Bank	3,633 -	7,685 6,435
Gazprombank	-	10,000
Total	132,487	95,478

Eurobonds. In December 2012, the Group issued Eurobonds in the amount of USD 1 billion. The Eurobonds were issued with an annual coupon rate of 4.422 percent, payable semi-annually. The bonds have a ten-year tenure and are repayable in December 2022.

In February 2011, the Group issued Eurobonds in an aggregate amount of USD 1,250 million. The Eurobonds were issued at par in two tranches, a five-year USD 600 million bond with a coupon rate of 5.326 percent and a ten-year USD 650 million bond with a coupon rate of 6.604 percent. The coupons are payable semi-annually. The bonds are repayable in February 2016 and February 2021, respectively.

13 LONG-TERM DEBT (CONTINUED)

Sberbank. In December 2011, the Group obtained a RR 40 billion credit line facility from OAO Sberbank available to withdraw until March 2012 which was subsequently extended until June 2012. In June 2012, the Group withdrew RR 10 billion under the facility until December 2014 at an interest rate of 8.9 percent per annum. The remaining part of the credit line was not utilized. The facility includes the maintenance of certain restrictive financial covenants.

In December 2010, the Group received a three-year Russian rouble denominated loan from OAO Sberbank in the amount of RR 15 billion at an interest rate of 7.5 percent per annum. The loan is repayable in December 2013 and includes the maintenance of certain restrictive financial covenants.

Gazprombank. In November 2009, the Group obtained a three-year Russian rouble denominated loan from OAO Gazprombank in the amount of RR 10 billion at an interest rate of eight percent per annum. The loan was fully repaid in January 2012 ahead of its maturity schedule.

Sumitomo Mitsui Banking Corporation Europe Limited. In April 2011, the Group obtained a US dollar denominated loan from Sumitomo Mitsui Banking Corporation Europe Limited in the amount of USD 300 million at an interest rate of LIBOR plus 1.45 percent per annum (1.76 percent and 2.03 percent at 31 December 2012 and 2011, respectively). The loan is payable until December 2013 and includes the maintenance of certain restrictive financial covenants.

Nordea Bank. In November 2010, the Group obtained a US dollar denominated loan from OAO Nordea Bank in the amount of USD 200 million at an interest rate of LIBOR plus 1.9 percent per annum (2.11 percent and 2.18 percent at 31 December 2012 and 2011, respectively). The loan is repayable until November 2013 and includes the maintenance of certain restrictive financial covenants.

UniCredit Bank. In October 2009, the Group obtained a US dollar denominated loan from ZAO UniCredit Bank in the amount of USD 200 million at an interest rate of LIBOR plus 3.25 percent per annum. In October 2012, the loan was fully repaid in accordance with its maturity schedule.

Syndicated term loan facility. In November 2012, the Group obtained an unsecured syndicated term loan facility in the amount of USD 667 million. The facility bore an interest rate of LIBOR plus one percent for the first six months and was repayable in May 2014. In December 2012, the loan was repaid ahead of its maturity schedule.

Russian rouble denominated bonds. In October 2012, the Group issued three-year non-convertible Russian rouble denominated bonds in the amount of RR 20 billion with a coupon rate of 8.35 percent per annum, payable semiannually. The bonds are repayable in October 2015.

In June 2010, the Group issued three-year non-convertible Russian rouble denominated bonds in the amount of RR 10 billion with a coupon rate of 7.5 percent per annum, payable semi-annually. The bonds are repayable in June 2013.

The fair values of long-term debt at 31 December 2012 and 2011 were as follows:

	At 31 December 2012	At 31 December 2011
Eurobonds – Ten-Year Tenor (repayable in 2022) Eurobonds – Ten-Year Tenor (repayable in 2021)	30,543	-
	23,201	21,150
Russian rouble denominated bonds (repayable in 2015)	20,198	-
Eurobonds – Five-Year Tenor (repayable in 2016)	19,567	19,414
Sberbank three-year loan (repayable in 2013)	14,745	14,539
Russian rouble denominated bonds (repayable in 2013) Sberbank credit line facility	10,005 9,928	10,000 -

Sumitomo Mitsui Banking Corporation Europe Limited	3,617	7,561
UniCredit Bank	-	6,439
Gazprombank	-	9,928
Total	137,845	95,287

13 LONG-TERM DEBT (CONTINUED)

The fair value of the long-term loans was determined based on future cash flows discounted at the estimated riskadjusted discount rate. The fair value of the corporate bonds was determined based on market quote prices (Level 1 in the fair value measurement hierarchy described in Note 27).

Scheduled maturities of long-term debt at 31 December 2012 were as follows:

Maturity period:	RR million
1 January to 31 December 2014	9,837
1 January to 31 December 2015	19,970
1 January to 31 December 2016	18,146
1 January to 31 December 2017	-
After 31 December 2017	49,852
Total long-term debt	97,805

14 PENSION OBLIGATIONS

In February 2007, the Group announced the implementation of a post-employment benefit program for its retired employees. Under the pension program, employees who are employed by the Group for more than three years (extended to five years effective 1 February 2011) and retire from the Group on or after the statutory retirement age will receive lump sum retirement benefit and monthly payments from NOVATEK for life unless they are actively employed. The amounts of payments to be disbursed depend on the average salary, duration and location of employment. The program is effective from 1 January 2007 and applies to employees who retire after that date.

The program represents an unfunded defined benefit plan and is accounted for as such under provisions of IAS 19, Employee Benefits. The impact of the program on the consolidated financial statements is disclosed below.

The amounts recognized in the consolidated statement of financial position and included in other non-current liabilities are determined as follows:

	At 31 December 2012	At 31 December 2011
Present value of the defined benefit obligations Unrecognized past service cost	1,532 (132)	810 (146)
Defined benefit plan liability recognized in the consolidated statement of financial position	1,400	664

The movements in the present value of the defined benefit obligations are as follows:

	Year ended 31 December:
	2012	2011
At 1 January	810	758
Interest cost	54	48
Benefits paid Current service cost Past service cost Actuarial (gain) loss Lump sum retirement benefit	(18) 91 - 256 339	(13)
		88
		-
		(71)
		-
At 31 December	1,532	810

14 PENSION OBLIGATIONS (CONTINUED)

The amounts recognized in the consolidated statement of income are as follows:

	Year ended 31 December:
	2012	2011
Current service cost Interest cost Actuarial (gain) loss Amortization of past service cost Lump sum retirement benefit	91 54 256 13	88
		48
		(71)
		55
	339	-
Defined benefit plan (benefits) costs recognized
in operating expenses	753	120
of which the following amounts were included as employee compensation in:
Materials, services and other	278	46
General and administrative expenses	475	74

The Group recognized a loss of RR 32 million and RR 9 million as a result of experience adjustments on plan liabilities during the years ended 31 December 2012 and 2011, respectively, included in actuarial (gain) loss.

The principal actuarial assumptions used at 31 December 2012 and 2011 are as follows:

	At 31 December 2012	At 31 December 2011
Weighted average discount rate	6.4%	7.4%
Projected annual increase in employee compensation	5.2%	5.8%
Expected increases to pension benefits	5.2%	5.8%

The assumed average salary and pension payment increases for Group employees have been calculated on the basis of inflation forecasts, analysis of increases of past salaries and the general salary policy of the Group. Inflation forecasts have been estimated to reduce from 6.5 percent for 2013 to 4.9 percent in 2017 and subsequent years.

Mortality assumptions are based on the Russian mortality tables published by the State Statistics Committee from the years 1986 to 1987, which management believes are the most conservative and prudent Russian whole-population mortality tables available.

Management has assessed that reasonable changes in the most significant actuarial assumptions will not have a significant impact on the consolidated statement of income or the liability recognized in the consolidated statement of financial position.

15 SHORT-TERM DEBT AND CURRENT PORTION OF LONG-TERM DEBT

Short-term debt and current portion of long-term debt. At 31 December 2012 and 2011, short-term debt and current portion of long-term debt consisted only of the current portion of long-term debt in the amount of RR 34,682 million and RR 20,298 million, respectively.

Available credit facilities. The Group's available credit facilities at 31 December 2012 were as follows:

		Expiring
	Par value	Within one year	Between 1 and 3 years
BNP PARIBAS Bank (a)	USD 100 million	3,037	-
Credit Agricole Corporate and Investment Bank (a)	USD 100 million	3,037	-
UniCredit Bank (a)	USD 350 million	-	10,630
Sberbank (a)	RR 30 billion	30,000	-
Total available credit facilities		36,074	10,630

(a) – interest rates are predetermined or negotiated at time of each withdrawal.

The Group also maintained available funds under short-term credit lines in the form of bank overdrafts with various international banks for RR 7,327 million (USD 175 million and EUR 50 million) and RR 6,278 million (USD 195 million) at 31 December 2012 and 2011, respectively, on variable interest rates subject to the specific type of credit facility.

16 TRADE PAYABLES AND ACCRUED LIABILITIES

	At 31 December 2012	At 31 December 2011
Financial liabilities
Trade payables	9,959	5,187
Interest payable	1,464	1,009
Other payables	718	16,615
Commodity derivatives	43	-
Non-financial liabilities
Advances from customers	1,227	743
Salary payables	251	210
Other liabilities	2,263	1,158
Trade payables and accrued liabilities	15,925	24,922

At 31 December 2011, other payables included RR 16,244 million, relating to the acquisition of a 49 percent equity stake in ɈȺɈ Yamal LNG, which was fully repaid in June 2012.

17 SHAREHOLDERS' EQUITY

Ordinary share capital. Share capital issued and paid in consisted of 3,036,306,000 ordinary shares at 31 December 2012 and 2011 with a par value of RR 0.1 each. The total authorized number of ordinary shares was 10,593,682,000 shares at both dates.

Treasury shares. In accordance with the Share Buyback Programs authorized by the Board of Directors, the Group's wholly-owned subsidiary, Novatek Equity (Cyprus) Limited, during 2012 and earlier has purchased ordinary shares of OAO NOVATEK in the form of Global Depository Receipts (GDRs) on the London Stock Exchange ("LSE") and ordinary shares on Moscow Interbank Currency Exchange (MICEX) through the use of independent brokers. At 31 December 2012 and 2011, the Group held in total (both shares and GDRs) 2,894 and 1,969 thousand ordinary shares at a total cost of RR 584 million and RR 281 million, respectively. The Group has decided that these shares do not vote.

During the year ended 31 December 2012, the Group purchased in total 925 thousand ordinary shares (both shares and GDRs) at a total cost of RR 303 million. During the year ended 31 December 2011, the Group sold 115,424 GDRs (1,154 thousand ordinary shares) for RR 520 million, recognizing gain of RR 355 million, which were recorded within additional paid-in capital in the consolidated statement of changes in equity.

Dividends. Dividends (including tax on dividends) declared and paid were as follows:

	Year ended 31 December:
	2012	2011
Dividends payable at 1 January	-	-
Dividends declared (*)	19,723	15,166
Dividends paid (*)	(19,718)	(15,166)
Dividends payable at 31 December	5	-
Dividends per share declared during the year (in Russian roubles)	6.50	5.00
Dividends per GDR declared during the year (in Russian roubles)	65.0	50.0

(*) – excluding treasury shares.

The Group declares and pays dividends in Russian roubles. Dividends declared in 2012 and 2011 were as follows:

Final for 2011: RR 3.50 per share or RR 35.0 per GDR declared in April 2012	10,627
Interim for 2012: RR 3.00 per share or RR 30.0 per GDR declared in October 2012	9,109
Total dividends declared in 2012	19,736
Final for 2010: RR 2.50 per share or RR 25.0 per GDR declared in April 2011	7,591
Interim for 2011: RR 2.50 per share or RR 25.0 per GDR declared in October 2011	7,591
Total dividends declared in 2011	15,182

Distributable retained earnings. In accordance with Russian legislation, NOVATEK distributes profits as dividends or transfers them to reserves (fund accounts) on the basis of financial statements prepared in accordance with Russian Accounting Rules. Russian legislation identifies the net profit as basis of distribution. For 2012 and 2011, the net statutory profits of NOVATEK as reported in the published annual statutory reporting forms were RR 28,830 million and RR 39,714 million, respectively. The closing balances of the accumulated profit including the respective years net statutory profit totalled RR 149,719 million and RR 120,889 million at 31 December 2012 and 2011, respectively.

Accumulated profits legally distributable are based on the amounts available for distribution in accordance with the applicable legislation and as reflected in the statutory financial statements of the individual entities of the Group. These amounts may differ significantly from the amounts calculated on the basis of IFRS.

18 SHARE-BASED COMPENSATION PROGRAM

On 12 February 2010, Management Committee of NOVATEK approved a share-based compensation program (the "Program") for a limited number of the Group's senior and key management, as well as high-potential managers, but excluding the members of the Management Committee, which aims to encourage participants to take an active interest in the future development of the Group and to provide material incentive to create shareholders value in OAO NOVATEK. The Program was established in accordance with the Concept of the Long-Term Incentive of Senior Employees approved by the Board of Directors on 25 September 2006 and the Share Buyback Program for three one-year vesting periods ending 31 January 2011, 2012, and 2013.

The Program is established as a cash-settled payment program and references the Group's GDRs, which are publicly traded on the LSE under the ticker symbol "NVTK". At 31 December 2012 and 2011, the Program covered 134 and 146 employees, respectively. Each participant is assigned a pre-determined number of GDRs in accordance with their respective job classification grade and the entitlement for the cash-settled share-based payment cannot be transferred to another person. The cash-settled payments will only be awarded if the participant is employed with the Group at the date of payment.

Each participant is granted share appreciation rights, as part of their remuneration package, and may elect to get paid in cash at the end of each vesting period or to defer payment to the subsequent vesting periods during the Program life. Each payment is based on the sale of the allocated GDRs and is calculated as the difference between the GDRs market price at time of sale and the Program's pre-defined price set at USD 48.62 relating to the onethird of the total number of GDRs assigned to each participant during the vesting period, including any deferrals from prior vesting periods. The grant date is defined as 31 March 2010 and represents the date when all participants agreed to a share-based payment arrangement.

In November 2012, the Group extended the Program's tenor for an additional one-year vesting period ending 31 January 2014 with no change to other terms and conditions.

Total amount of GDRs granted at 31 December 2010	Number of GDRs	Weighted average or closing price (LSE), USD per GDR 119.5
	382,368
Granted	-	-
Exercised	(104,728)	105.0
Forfeited	(36,984)	-
Total amount of GDRs granted at 31 December 2011	240,656	125.2
Granted	-	-
Exercised	(112,305)	144.2
Forfeited	(11,140)	-
Total amount of GDRs granted at 31 December 2012	117,211	119.3

In accordance with IFRS 2, Share-based payment, the Group re-measures the employees' services rendered and the liability incurred at the fair value of the liability. Until the liability is settled, the Group re-measures the fair value of the liability at the end of each reporting period and at the date of settlement, with any changes in fair value recognized in profit or loss for the period. The liability is measured, initially and at the end of each reporting period until settled, at the fair value of the share appreciation rights, by applying an option pricing model based on Monte-Carlo simulations, and to the extent to which the employees have rendered service to date.

18 SHARE-BASED COMPENSATION PROGRAM (CONTINUED)

The fair value of the Program is determined based on the following assumptions:

	2012	2013
Expected volatility	43.04%	43.04%
Risk-free interest rate	-	0.22%
Expected option life (years)	0.96	0.96
Exercise price per GDR (USD)	48.62	48.62

Expected volatility is calculated based on the historical volatility of the price per GDR for the historical period equal to the expected life of the Program (1.1 years). Risk-free interest rate is based on a benchmark USD curve including Deposit Rates (DEPO), Forward Rate Agreements (FRA) and Interest Rate Swaps (IRS).

The fair value of the share-based payments is recognized as a payable to the employees over the vesting period and any changes in the fair value of the liability recognized in the consolidated statement of income.

The amounts recognized by the Group in respect of the Program are as follows:

	Year ended 31 December:
Expenses included in	2012	2011
General and administrative expenses	121	235
Liabilities included in	At 31 December 2012	At 31 December 2011
Other non-current liabilities	57	226
Trade payables and accrued liabilities	181	244
Total share-based compensation program liabilities	238	470

19 OIL AND GAS SALES

	Year ended 31 December:
	2012	2011
Natural gas	142,613	110,932
Stable gas condensate	46,684	46,778
Liquefied petroleum gas	15,599	14,436
Crude oil	5,000	2,479
Oil and gas products	350	186
Total oil and gas sales	210,246	174,811

20 TRANSPORTATION EXPENSES

	Year ended 31 December:
	2012	2011
Natural gas transportation to customers Liquid hydrocarbons transportation by rail Liquid hydrocarbons transportation by tankers Crude oil transportation to customers Other	45,925 10,537 3,742 527 117	34,441 9,791 3,647 281 169
			Total transportation expenses	60,848	48,329

21 TAXES OTHER THAN INCOME TAX

The Group is subject to a number of taxes other than income tax, which are detailed as follows:

	Year ended 31 December:
	2012	2011
Unified natural resources production tax (UPT)	14,833	14,523
Property tax	1,754	1,742
Other taxes	259	294
Total taxes other than income tax	16,846	16,559

The unified natural resources production tax for natural gas production was set at a rate of RR 251 and RR 237 per thousand cubic meters for 2012 and 2011, respectively.

The unified natural resources production tax rate for gas condensate was set for 2011 at the level of 17.5 percent of gas condensate revenues recognized by the producing entities. Effective 1 January 2012, the approach set by the Tax Code of the Russian Federation was changed and a tax rate of RR 556 per ton of gas condensate produced was set.

Under the Tax Code, the tax rate for the unified natural resources production tax for crude oil is calculated by reference to an average price for Urals blend and an average exchange rate over the relevant tax period.

According to the amendments to the Tax Code, effective from 1 January 2012, a zero UPT rate is set for crude oil produced at fields located in the YNAO to the north of the 65th degree of the northern latitude. The Group's East-Tarkosalinskoye and Khancheyskoye fields are located within the applicable geographical area; therefore, the zero UPT rate was applied for the crude oil produced at these fields effective from 1 January 2012.

22 GENERAL AND ADMINISTRATIVE EXPENSES

	Year ended 31 December:
	2012	2011
Employee compensation	6,869	4,650
Legal, audit, and consulting services	1,274	774
Social expenses and compensatory payments	1,001	1,212
Depreciation – administrative buildings	314	198
Business trips expense	292	218
Fire safety and security expenses	199	178
Repair and maintenance expenses	168	115
Rent expense	113	140
Board remuneration	105	103
Insurance expense	86	58
Bank charges	82	58
Other	433	514
Total general and administrative expenses	10,936	8,218

22 GENERAL AND ADMINISTRATIVE EXPENSES (CONTINUED)

Auditors' fees and services. ZAO PricewaterhouseCoopers Audit has served as the Group's independent external auditor for each of the reported financial years. The independent external auditor is subject to re-appointment at the Annual General Meeting of shareholders based on the recommendations from the Board of Directors. The following table presents the aggregate fees for professional services and other services rendered by ZAO PricewaterhouseCoopers Audit to the Group included within legal, audit, and consulting services:

	Year ended 31 December:
	2012	2011
Audit services fee (audit of the Group's consolidated financial statements and the statutory audit of the parent company)	40	39
Non-audit services	4	1
Total auditors' fees and services	44	40

23 MATERIALS, SERVICES AND OTHER

	Year ended 31 December:
	2012	2011
Employee compensation	3,808	2,953
Repair and maintenance services	1,598	1,435
Electricity and fuel	457	405
Materials and supplies	412	309
Security expenses	271	237
Transportation expenses	186	184
Processing fees	99	99
Other	385	325
Total materials, services and other	7,216	5,947

24 PURCHASES OF NATURAL GAS AND LIQUID HYDROCARBONS

	Year ended 31 December:
	2012	2011
Natural gas	14,706	5,854
Unstable gas condensate	2,498	-
Other liquid hydrocarbons	279	140
Total purchases of natural gas and liquid hydrocarbons	17,483	5,994

Natural gas purchases included volumes procured from OAO Sibneftegas, the Group's joint venture, pro-rata to its total production (see Note 30). From January 2012, the Group began purchasing natural gas from its related party OAO SIBUR Holding at prices based on the market prices in the region of purchases (see Note 30).

In November 2012, the Group began purchasing unstable gas condensate from ZAO Nortgas, the Group's joint venture from November 2012, at ex-field prices based on benchmark crude oil and oil products market quotes adjusted for quality and respective tariffs for transportation and processing (see Note 30).

In April 2012, the Group began purchasing unstable gas condensate from OOO SeverEnergia, a related party, at exfield prices based on benchmark crude oil and oil products market quotes adjusted for quality and respective tariffs for transportation and processing (see Note 30).

25 FINANCE INCOME (EXPENSE)

	Year ended 31 December:
Interest expense (including transaction costs)	2012	2011
6.604% USD 650 million Eurobonds February 2021	1,355	1,165
7.5% RR 15 billion Sberbank December 2013	1,143	1,144
5.326% USD 600 million Eurobonds February 2016	1,022	879
7.5% RR 10 billion Bonds June 2013	772	772
8.9% RR 10 billion Sberbank December 2014	520	-
8.35% RR 20 billion Bonds October 2015	355	-
LIBOR+1.45% USD 300 million Sumitomo Mitsui
Banking Corporation Europe Limited December 2013	148	148
LIBOR+1.9% USD 200 million Nordea Bank
November 2013	133	125
LIBOR+3.25% USD 200 million UniCredit Bank October 2012 (1)	71	215
4.42% USD 1 billion Eurobonds December 2022	69	-
8% RR 10 billion Gazprombank November 2012 (1)	42	805
Other interest expenses(2)	72	169
Subtotal	5,702	5,422
Less: capitalized interest	(2,698)	(3,709)
Interest expense (on historical cost basis)	3,004	1,713
Effects of discounting of long-term financial liabilities	-	212
Provisions for asset retirement obligations:
effect of the present value discount unwinding	232	225
Total interest expense	3,236	2,150

(1) – interest rates were reduced during the periods.

(2) – including credit facility with interest rates negotiated at time of each withdrawal.

	Year ended 31 December:
Interest income	2012	2011
Interest income on loans issued Interest income on cash and cash equivalents	1,051 444	2,828 355
Interest income (on historical cost basis)	1,495	3,183
Long-term financial assets: effect of the present value discount unwinding	236	209
Total interest income	1,731	3,392

26 INCOME TAX

Reconciliation of income tax. The table below reconciles actual income tax expense and theoretical income tax, determined by applying the statutory tax rate to profit before income tax.

	Year ended 31 December:
	2012	2011
Profit before income tax	86,215	135,025
Theoretical income tax expense at statutory rate of 20 percent	17,243	27,005
Increase (decrease) due to:
Non-temporary differences in respect of
share of losses of joint ventures	421	776
Non-deductible expenses	546	686
Russian entities' taxation at lower income tax rate	(117)	(118)
Foreign entities' taxation at lower income tax rate	(107)	(226)
Deferred taxes write-off	(21)	342
Tax benefit relating to priority investment projects in the YNAO	(1,709)	-
Disposal of 20 percent interest in Yamal LNG	-	(12,473)
Other non-temporary differences	518	(258)
Total income tax expense	16,774	15,734

In 2012, one of Group's investment projects in the YNAO was included by the YNAO authorities in the list of priority projects, which allows the Group's subsidiary, that carried out the project, to apply a reduced income tax rate of 15.5 percent.

Domestic and foreign components of current income tax expense were:

	Year ended 31 December:
	2012	2011
Russian Federation income tax Foreign income tax	16,011 131	12,364 103
Total current income tax expense	16,142	12,467

Effective income tax rate. The Group's Russian statutory income tax rate for 2012 and 2011 was 20 percent. For the years ended 31 December 2012 and 2011, the consolidated Group's effective income tax rate was 19.5 percent and 11.7 percent, respectively. Excluding the effect of 20 percent disposal of Yamal LNG, the Group's effective income tax rate for the year ended 31 December 2011 was 21.7 percent.

The Group did not file a consolidated tax return for 2011. Instead, each legal entity filed separate tax returns with various tax authorities, primarily in the Russian Federation. Effective 1 January 2012, Russian tax legislation introduced an option to submit a single consolidated income tax return, and, accordingly, in April 2012, the Group's management registered NOVATEK and its core Russian producing subsidiaries as a consolidated group of taxpayers for 2012 and thereafter.

The Group has recorded a deferred tax liability in respect of the temporary difference associated with the investment in Yamal LNG at a zero tax rate as management expects that the carrying value of the investment in Yamal LNG would be recovered primarily through dividends taxable at zero tax rate and also potentially partially through a sale of an additional equity stake in the entity. The Group did not recognize deferred taxes related to a future sale as the tax base in respect of potential interest in Yamal LNG to be sold is assessed to be equal to its carrying amount.

Deferred income tax. Differences between IFRS and Russian statutory tax regulations give rise to certain temporary differences between the carrying value of certain assets and liabilities for financial reporting purposes and for income tax purposes.

26 INCOME TAX (CONTINUED)

Deferred income tax balances are presented in the consolidated statement of financial position as follows:

	At 31 December 2012	At 31 December 2011
Long-term deferred income tax asset (other non-current assets) Long-term deferred income tax liability	1,062 (13,969)	660 (12,805)
Net deferred income tax liability	(12,907)	(12,145)

Deferred income tax assets expected to be realized within twelve months of 31 December 2012 and 2011 were RR 983 million and RR 462 million, respectively. Deferred tax liabilities expected to be reversed within twelve months of 31 December 2012 and 2011 were RR 629 million and RR 199 million, respectively.

Movements in deferred income tax assets and liabilities during the years ended 31 December 2012 and 2011 are as follows:

	At 31 December 2012	Statement of Income effect	Acquisitions	Disposals	At 31 December 2011
Property, plant and equipment	(15,902)	(1,124)	-	11	(14,789)
Intangible assets	(398)	51	(125)	-	(324)
Other	(714)	(496)	(5)	-	(213)
Total deferred income tax liabilities	(17,014)	(1,569)	(130)	11	(15,326)
Tax losses carried forward	1,474	95	4	-	1,375
Inventories	1,077	438	-	(15)	654
Asset retirement obligation	577	30	-	-	547
Trade payables and accrued liabilities	809	327	-	-	482
Other	170	47	-	-	123
Total deferred income tax assets	4,107	937	4	(15)	3,181
Net deferred income tax liabilities	(12,907)	(632)	(126)	(4)	(12,145)

	At 31 December 2011	Statement of Income effect	Acquisitions	Disposals	At 31 December 2010
Property, plant and equipment	(14,789)	(3,827)	-	138	(11,100)
Intangible assets	(324)	23	(265)	-	(82)
Other	(213)	(53)	(13)	-	(147)
Total deferred income tax liabilities	(15,326)	(3,857)	(278)	138	(11,329)
Tax losses carried forward	1,375	603	16	(519)	1,275
Inventories	654	(167)	-	(83)	904
Asset retirement obligation	547	131	-	(80)	496
Trade payables and accrued liabilities	482	27	3	-	452
Other	123	(4)	8	(2)	121
Total deferred income tax assets	3,181	590	27	(684)	3,248
Net deferred income tax liabilities	(12,145)	(3,267)	(251)	(546)	(8,081)

26 INCOME TAX (CONTINUED)

At 31 December 2012, the Group had recognized deferred income tax assets of RR 1,474 million (31 December 2011: RR 1,375 million) in respect of unused tax loss carry forwards of RR 7,370 million (31 December 2011: RR 6,875 million). Tax losses can be carried forward for relief against taxable profits for 10 years after they are incurred, subject to certain limitations. In determining future taxable profits and the amount of tax benefits that are probable in the future management makes judgments including expectations regarding the Group's ability to generate sufficient future taxable income and the projected time period over which deferred tax benefits will be realized.

27 FINANCIAL INSTRUMENTS AND FINANCIAL RISK FACTORS

The accounting policies for financial instruments have been applied to the line items below:

Financial assets	At 31 December 2012	At 31 December 2011
Loans and receivables
Non-current
Long-term loans	12,502	9,323
Trade and other receivables	648	22,806
Long-term deposits	3	1
Current
Trade and other receivables	16,409	16,699
Russian rouble denominated loans	428	6,859
Short-term bank deposits	10	17
Cash restricted in the form of guarantee	1,959	-
Cash and cash equivalents	18,420	23,831
At fair value through profit or loss
Non-current
Commodity derivatives	148	-
Current
Commodity derivatives	451	-

Total assets	50,978	79,536
Financial liabilities	At 31 December 2012	At 31 December 2011
At amortized cost
Non-current
Long-term debt	97,805	75,180
Current
Current portion of long-term debt	34,682	20,298
Trade and other payables	12,141	22,811
At fair value through profit or loss
Non-current
Commodity derivatives	592	-
Current
Commodity derivatives	43	-
Total liabilities	145,263	118,289

Derivative instruments. Certain foreign long-term natural gas purchase and sales contracts were entered into for trading purposes on active markets that do not meet the expected own-use requirements. These contracts include pricing terms that are based on a variety of commodities and indices and volume flexibility options that collectively qualify them under the scope of IAS 39, Financial instruments: recognition and measurement, although the activity surrounding these contracts involves the physical delivery of natural gas. Such contracts are recognized in the statement of financial position at fair value with movements in fair value recognized in the income statement.

The Group determines the fair values of these financial commodity derivative contracts using the mark-to-market and mark-to-model methods and as such, the Group evaluates the quality and reliability of the assumptions and data used to measure fair value in accordance with IFRS 7, Financial instruments: Disclosures, in the three hierarchy levels as follows:

i. quoted prices in active markets (Level 1);
ii. inputs other than quoted prices included in Level 1 that are directly or indirectly observable in the market (externally verifiable inputs) (Level 2); and
iii. inputs that are not based on observable market data (unobservable inputs). These inputs reflect the Group's own assumptions about the assumptions a market participant would use in pricing the asset or liability (Level 3).

The fair values of natural gas derivative contracts are estimated using internal models and other valuation techniques due to the absence of quoted prices or other observable, market-corroborated data, for the duration of the contracts. Valuations were derived from quoted market prices for the periods in which market quotes are available; thereafter, forward natural gas prices were developed by reference to equivalent oil and oil products prices on other analogous markets. For periods beyond observable market prices the fair values of the long-term contracts were calculated using the market yield curve at the reporting date. Due to the assumptions underlying their fair value, the gas contracts are categorized as Level 3 in the fair value hierarchy, described above.

At 31 December 2012, the Group recognized RR 599 million of assets and RR 635 million of liabilities related to long-term natural gas contracts in the consolidated statement of financial position. For the year ended 31 December 2012, a loss of RR 36 million was included within other operating income (loss) representing noncash mark-to-market net movements in fair values on these derivative instruments during the reporting period. Trading operations under these contracts in 2012 resulted in the net income of RR 112 million that was recognized in the consolidated income statement within other operating profit (loss).

The fair value of natural gas derivative contracts is sensitive to price changes in the event of a one-off shift step in the market. The table below represents the effect on the fair value estimation of these derivative contracts that would occur from price changes by RR 201.14 (five Euros) by 1 megawatt-hour:

Sensitivity summary	Price decrease	Price increase
Market shift from 2014 sensitivity	2,454	(3,379)
Market shift from 2019 sensitivity	2,011	(2,695)

Financial risk management objectives and policies. In the ordinary course of business, the Group is exposed to market risks from fluctuating prices on commodities purchased and sold, prices of other raw materials, currency exchange rates and interest rates. Depending on the degree of price volatility, such fluctuations in market prices may create volatility in the Group's financial results. To effectively manage the variety of exposures that may impact financial results, the Group's overriding strategy is to maintain a strong financial position.

The Group's principal risk management policies are established to identify and analyze the risks faced by the Group, to set appropriate risk limits and controls, and to monitor risks and adherence to these limits. Risk management policies and systems are reviewed regularly to reflect changes in market conditions and the Group's activities.

Market risk. Market risk is the risk that changes in market prices, such as foreign exchange rates, interest rates, commodity prices and equity prices, will affect the Group's financial results or the value of its holdings of financial instruments. The primary objective of mitigating these market risks is to manage and control market risk exposures, while optimizing the return on risk.

The Group is exposed to market price movements relating to changes in commodity prices such as crude oil, gas condensate, liquefied petroleum gas and natural gas (commodity price risk), foreign currency exchange rates, interest rates, equity prices and other indices that could adversely affect the value of the Group's financial assets, liabilities or expected future cash flows.

(a) Foreign exchange risk

The Group is exposed to foreign exchange risk arising from various exposures in the normal course of business, primarily with respect to the US dollar. Foreign exchange risk arises primarily from future commercial transactions, recognized assets and liabilities when assets and liabilities are denominated in a currency other than the functional currency.

The Group's overall strategy is to have no significant net exposure in currencies other than the Russian rouble or the US dollar. Foreign currency derivative instruments may be utilized to manage the risk exposures associated with fluctuations on certain firm commitments for sales and purchases, debt instruments and other transactions that are denominated in currencies other than the Russian rouble, and certain non-Russian rouble assets and liabilities.

The carrying amounts of the Group's financial instruments are denominated in the following currencies:

	Russian
At 31 December 2012	rouble	US dollar	Other	Total
Financial assets
Non-current
Long-term loans receivable	8,136	4,366	-	12,502
Trade and other receivables	562	67	19	648
Commodity derivatives	-	-	148	148
Long-term deposits	-	-	3	3
Current
Trade and other receivables	9,604	4,794	2,011	16,409
Russian rouble denominated loans	428	-	-	428
Short-term bank deposits	-	-	10	10
Commodity derivatives	-	-	451	451
Cash restricted in the form of guarantee	-	1,959	-	1,959
Cash and cash equivalents	8,251	9,740	429	18,420
Financial liabilities
Non-current
Long-term debt	(29,818)	(67,987)	-	(97,805)
Commodity derivatives	-	-	(592)	(592)
Current
Current portion of long-term debt	(24,963)	(9,719)	-	(34,682)
Trade and other payables	(9,135)	(1,400)	(1,606)	(12,141)
Commodity derivatives	-	-	(43)	(43)
Net exposure at 31 December 2012	(36,935)	(58,180)	830	(94,285)

At 31 December 2011	Russian rouble	US dollar	Other	Total
Financial assets
Non-current
Long-term loans receivable	9,103	220	-	9,323
Trade and other receivables	22,761	14	31	22,806
Long-term deposits	-	-	1	1
Current
Trade and other receivables	8,692	7,618	389	16,699
Russian rouble denominated loans	6,859	-	-	6,859
Short-term bank deposits	-	-	17	17
Cash and cash equivalents	10,774	12,113	944	23,831
Financial liabilities
Non-current
Long-term debt	(24,937)	(50,243)	-	(75,180)
Other non-current liabilities	-	-	-	-
Current
Current portion of long-term debt	(10,000)	(10,298)	-	(20,298)
Trade and other payables	(4,949)	(17,799)	(63)	(22,811)
Net exposure at 31 December 2011	18,303	(58,375)	1,319	(38,753)

The Group chooses to provide information about market risk and potential exposure to hypothetical loss from its use of financial instruments through sensitivity analysis disclosures in accordance with IFRS requirements.

The sensitivity analysis depicted in the table below reflects the hypothetical loss that would occur assuming a 10 percent increase in exchange rates and no changes in the portfolio of instruments and other variables at 31 December 2012 and 2011, respectively:

		Year ended 31 December:
Effect on pre-tax profit	Increase in exchange rate	2012	2011
RUB / USD	10%	(5,818)	(5,838)

The effect of a corresponding 10 percent decrease in exchange rate is approximately equal and opposite.

(b) Commodity price risk

The Group's overall commercial trading strategy in natural gas and liquid hydrocarbons is centrally managed. Changes in commodity prices could negatively or positively affect the Group's results of operations. The Group manages the exposure to commodity price risk by optimizing its core activities to achieve stable price margins.

Natural gas supplies on the Russian domestic market. As an independent natural gas producer, the Group is not subject to the government's regulation of natural gas prices, except for those volumes sold to residential customers. Nevertheless, the Group's prices for natural gas sold are strongly influenced by the prices regulated by the Federal Tariffs Service (FTS), a governmental agency. In November 2006, the FTS approved and published a plan to liberalize the price of natural gas sold on the Russian domestic market by the year 2011.

In February 2011, the Government of the Russian Federation announced certain revisions to the domestic natural gas market liberalization plan. According to the revised plan, the target date to implement full liberalization of the domestic natural gas market is planned on 1 January 2015; however, the Government reserves the right to amend or change the proposed timetable. As part of the plan, in June 2012, the FTS approved an increase of 15 percent in the regulated prices effective 1 July 2012. According to the Government's program, the regulation of the domestic natural gas price after 2015 will be based on the net-back parity of natural gas prices on the domestic and export markets.

Management believes it has limited downside commodity price risk for natural gas and does not use commodity derivative instruments for trading purposes. All of the Group's natural gas purchase and sales contracts in the domestic market are entered to meet supply requirements to fulfil contract obligations or for own consumption and are not within the scope of IAS 39, Financial instruments: recognition and measurement. However, to effectively manage the margins achieved through its natural gas trading activities, management has established targets for volumes sold to wholesale traders, end-customers and eventually to the natural gas exchange when trading commences.

Natural gas foreign trading activities. The Group purchases and sells natural gas on the European market under long-term supply contracts based on formulas with reference to benchmark natural gas prices quoted for the North-Western European natural gas hubs, crude oil and oil products prices and/or a combination thereof. As a result, the Group's results from natural gas trading are subject to commodity price volatility based on fluctuations or changes in the respective benchmark reference prices.

Natural gas foreign trading activities are exercised by Novatek Gas & Power GmbH, the Group's wholly owned subsidiary, and are managed within the Group's integrated trading function.

Liquid hydrocarbons. The Group sells all its crude oil and gas condensate under spot contracts. Gas condensate volumes sold to the US, European, South American and Asian-Pacific Region (hereinafter referred to as "APR") markets are based on benchmark reference crude oil prices of WTI, Brent IPE and Dubai (or a combination thereof) or Naphtha Japan and Naphtha CIF NWE, respectively, plus a margin or discount, depending on current market situation. Crude oil sold internationally is based on benchmark reference crude oil prices of Brent dated, plus a discount and on a transaction-by-transaction basis for volumes sold domestically. As a result, the Group's revenues from the sales of liquid hydrocarbons are subject to commodity price volatility based on fluctuations or changes in the crude oil benchmark reference prices. All of the Group's liquid hydrocarbon purchase and sales contracts are entered to meet supply requirements to fulfil contract obligations or for own consumption and are not within the scope of IAS 39, Financial instruments: recognition and measurement.

(c) Cash flow and fair value interest rate risk

The Group is subject to interest rate risk on financial liabilities with variable interest rates. To mitigate this risk, the Group's treasury function performs periodic analysis of the current interest rate environment and depending on that analysis management makes decisions whether it would be more beneficial to obtain financing on a fixed-rate or variable-rate basis. In cases where the change in the current market fixed or variable interest rates is considered significant management may consider refinancing a particular debt on more favorable interest rate terms.

Changes in interest rates impact primarily debt by changing either their fair value (fixed rate debt) or their future cash flows (variable rate debt). Management does not have a formal policy of determining how much of the Group's exposure should be to fixed or variable rates. However, at the time of raising new debts management uses its judgment to decide whether it believes that a fixed or variable rate would be more favorable over the expected period until maturity.

The interest rate profiles of the Group's interest-bearing financial instruments at the reporting dates were as follows:

	At 31 December 2012	At 31 December 2011
At fixed rate At variable rate	122,779 9,708	74,919 20,559
Total debt	132,487	95,478

The Group centralizes the cash requirements and surpluses of controlled subsidiaries and the majority of their external financing requirements, and applies, on its consolidated net debt position, a funding policy to optimize its financing costs and manage the impact of interest rate changes on its financial results in line with market conditions. In this way, the Group is able to ensure that the balance between the floating rate portion of its debt and its cash surpluses has a low level of exposure to any change in interest rates over the short term. This policy makes it possible to significantly limit the Group's sensitivity to interest rate volatility.

The Group's financial results are sensitive to changes in interest rates on the floating rate portion of the Group's debt portfolio. If the interest rates applicable to floating rate debt were to increase by 100 basis points at the reporting dates, assuming all other variables remain constant, it is estimated that the Group's profit before taxation would decrease by the amounts shown below:

	Year ended 31 December:
Effect on pre-tax profit	2012	2011
Increase by 100 basis points	97	206

The effect of a corresponding 100 basis points decrease in interest rate is approximately equal and opposite.

The Group is examining various ways to manage its cash flow interest rate risk by using a combination of floating and fixed interest rates. No swaps or other similar instruments were in place as of 31 December 2012 and 2011, or during 2012 and 2011.

Credit risk. Credit risk refers to the risk exposure that a potential financial loss to the Group may occur if a counterparty defaults on its contractual obligations.

Credit risk is managed on a Group level and arises from cash and cash equivalents, including short-term deposits with banks, as well as credit exposures to customers, including outstanding trade receivables and committed transactions. Cash and cash equivalents are deposited only with banks that are considered by the Group at the time of deposit to minimal risk of default.

The Group's trade and other receivables consist of a large number of customers, spread across diverse industries and geographical areas. Most of the Group's international liquid sales are made to customers with independent external ratings; however, if the customer has a credit rating below BBB, the Group requires the collateral for the trade receivable to be in the form of letters of credit from banks with an investment grade rating. All domestic sales of liquid hydrocarbons are made on a 100 percent prepayment basis. Although the Group generally does not require collateral in respect of trade and other receivables, it has developed standard credit payment terms and constantly monitors the status of trade receivables and the creditworthiness of the customers.

As a result of recent acquisitions of Russian regional natural gas trading companies, the Group's exposure to small and medium-size industrial users and individuals has increased. The Group monitors the recoverability of these debtors by analyzing the ageing of receivables by type of customers and their respective prior payment history.

The maximum exposure to credit risk is represented by the carrying amount of each financial asset in the consolidated statement of financial position.

The table below highlights the Group's trade and other receivables to published credit ratings of its counterparties and/or their parent companies:

Moody's, Fitch and/or Standard & Poor's	At 31 December 2012	At 31 December 2011
Investment grade rating	7,208	9,059
Non-investment grade rating	4,825	1,581
No external rating	4,376	6,059
Total trade and other receivables	16,409	16,699

The table below highlights the Group's cash and cash equivalents balances to published credit ratings of its banks and/or their parent companies:

Moody's, Fitch and/or Standard & Poor's	At 31 December 2012	At 31 December 2011
Investment grade rating	16,887	19,381
Non-investment grade rating	1,526	4,358
No external rating	7	92
Total cash and cash equivalents	18,420	23,831

Investment grade ratings classification referred to as Aaa to Baa3 for Moody's Investors Service, and as AAA to BBB- for Fitch Ratings and Standard & Poor's.

Liquidity risk. Liquidity risk is the risk that the Group will not be able to meet its financial obligations as they fall due. The Group's approach to managing liquidity is to ensure that it will always have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Group's reputation. In managing its liquidity risk, the Group maintains adequate cash reserves and debt facilities, continuously monitors forecast and actual cash flows and matches the maturity profiles of financial assets and liabilities.

The Group prepares various financial plans (monthly, quarterly and annually) which ensures that the Group has sufficient cash on demand to meet expected operational expenses, financial obligations and investing activities for a period of 30 days or more. The Group has entered into a number of short-term credit facilities. Such credit lines and overdraft facilities can be drawn down to meet short-term financing needs. To fund cash requirements of a more permanent nature, the Group will normally raise long-term debt in available international and domestic markets.

All of the Group's financial liabilities represent non-derivative financial instruments. The following tables summarize the maturity profile of the Group's financial liabilities, except of natural gas derivative contracts, based on contractual undiscounted payments, including interest payments:

At 31 December 2012	Less than 1 year	Between 1 and 2 years	Between 2 and 5 years	More than 5 years	Total
Debt at fixed rate
Principal (*)	25,000	10,000	38,224	50,115	123,339
Interest	7,589	6,097	11,062	11,279	36,027
Debt at variable rate
Principal (*)	9,719	-	-	-	9,719
Interest	116	-	-	-	116
Trade and other payables	12,141	-	-	-	12,141
Total financial liabilities	54,565	16,097	49,286	61,394	181,342

OAO NOVATEK Notes to the Consolidated Financial Statements

(in Russian roubles, [tabular amounts in millions] unless otherwise stated)

27 FINANCIAL INSTRUMENTS AND FINANCIAL RISK FACTORS (CONTINUED)

At 31 December 2011	Less than 1 year	Between 1 and 2 years	Between 2 and 5 years	More than 5 years	Total

Debt at fixed rate
Principal (*)	10,000	25,000	19,318	20,927	75,245
Interest	4,748	3,825	6,298	5,655	20,526
Debt at variable rate
Principal (*)	10,303	10,302	-	-	20,605
Interest	366	135	-	-	501
Trade and other payables	22,811	-	-	-	22,811
Total financial liabilities	48,228	39,262	25,616	26,582	139,688

(*) – differs from long-term debt (See Note 13) for transaction costs.

The following table represents the maturity profile of the Group's derivative commodity contracts based on undiscounted cash flows:

At 31 December 2012	Less than 1 year	Between 1 and 2 years	Between 2 and 5 years	More than 5 years	Total
Cash inflow Cash outflow	23,150 (22,678)	23,600 (23,175)	69,289 (68,593)	108,742 (107,598)	224,781 (222,044)
Net cash flows	472	425	696	1,144	2,737

Capital management. The primary objectives of the Group's capital management policy is to ensure a strong capital base to fund and sustain its business operations through prudent investment decisions and to maintain investor, market and creditor confidence to support its business activities.

At the reporting date, the Group had investment grade credit ratings of Baa3 (stable outlook) by Moody's Investors Service, BBB- (stable outlook) by Fitch Ratings, as well as a credit rating of BBB- (stable outlook) by Standard & Poor's. To maintain its credit ratings, the Group has established certain financial targets and coverage ratios that it monitors on a quarterly and annual basis.

The Group manages its liquidity on a corporate-wide basis to ensure adequate funding to sufficiently meet group operational requirements. All external debts are centralized at the parent level, and all financing to Group entities is facilitated through inter-company loan arrangements or additional contributions to share capital.

The Group has a stated dividend policy that distributes at least 30 percent of its parent company's non-consolidated statutory net profit determined according to Russian accounting standards. However, the dividend for a specific year is determined after taking into consideration future earnings, capital expenditure requirements, future business opportunities and the Group current financial position. Dividends are recommended by the Board of Directors and approved by the NOVATEK's shareholders.

The Group defines the term "capital" as equity attributable to OAO NOVATEK shareholders plus net debt (total debt less cash and cash equivalents). There were no changes to the Group's approach to capital management during the year ended 31 December 2012. At 31 December 2012 and 2011, the Group's capital totalled RR 404,117 million and RR 312,660 million, respectively.

28 CONTINGENCIES AND COMMITMENTS

Operating environment. The Russian Federation continues to display some characteristics of an emerging market. These characteristics include, but are not limited to, the existence of a currency that is in practice not convertible in most countries outside of the Russian Federation, and relatively high inflation. The tax, currency and customs legislation is subject to varying interpretations, frequent changes and other legal and fiscal impediments contribute to the challenges faced by entities currently operating in the Russian Federation. The future economic direction of the Russian Federation is largely dependent upon the effectiveness of economic, financial and monetary measures undertaken by the Government, together with tax, legal, regulatory, and political developments.

The Group's business operations are primarily located in the Russian Federation and are thus exposed to the economic and financial markets of the country.

Commitments. At 31 December 2012, the Group had contractual capital expenditures commitments aggregating approximately RR 22,476 million (at 31 December 2011: RR 17,805 million) mainly for ongoing development activities at the Yurkharovskoye field (through 2015), development at the North-Russkoe field (through 2014), both the Salmanovskoye (Utrenneye) and the Geofizicheskoye fields (through 2016), phase three construction of the Purovsky Gas Condensate Plant (through 2013), construction of the terminal for the transshipment and fractionation of stable gas condensate (through 2013) and ongoing development of the East-Tarkosalinskoye (through 2014) and Khancheyskoye fields (through 2013) all in accordance with duly signed agreements. Furthermore, the Group's share in capital commitments for its interests in joint ventures aggregates approximately RR 31,411 million (at 31 December 2011: RR 5,850 million) for development of the South-Tambeyskoye (through 2014), Termokarstovoye (through 2016), North-Urengoiskoye (through 2015) and Samburgskoye (through 2014) fields.

Taxation. Russian tax, currency and customs legislation is subject to varying interpretations, and changes, which can occur frequently. Correspondingly, the relevant regional and federal tax authorities may periodically challenge. Management's interpretation of such taxation legislation as applied to the Group's transactions and activities. Furthermore, events within the Russian Federation suggest that the tax authorities may be taking a more assertive position in its interpretation of the legislation and assessments, and it is possible that transactions and activities that have not been challenged in the past may be challenged. As a result, significant additional taxes, penalties and interest may be assessed. Fiscal periods remain open to review by the authorities in respect of taxes for three calendar years preceding the year of review. Under certain circumstances reviews may cover longer periods.

As at 31 December 2012, management believes that its interpretation of the relevant legislation is appropriate and that it is probable that the Group's tax, currency and customs positions will be sustained. Where management believes it is probable that a position cannot be sustained, an appropriate amount has been accrued.

Mineral licenses. The Group is subject to periodic reviews of its activities by governmental authorities with respect to the requirements of its mineral licenses. Management cooperates with governmental authorities to agree on remedial actions necessary to resolve any findings resulting from these reviews. Failure to comply with the terms of a license could result in fines, penalties or license limitation, suspension or revocation. The Group's management believes any issues of non-compliance will be resolved through negotiations or corrective actions without any material adverse effect on the Group's financial position, results of operations or cash flows.

28 CONTINGENCIES AND COMMITMENTS (CONTINUED)

The Group's oil and gas fields and license areas are situated on land located in the Yamal-Nenets Autonomous Region. Licenses are issued by the Federal Agency for the Use of Natural Resources of the Russian Federation and the Group pays unified natural resources production tax to produce crude oil, natural gas and unstable gas condensate from these fields and contributions for exploration of license areas. The principal licenses of the Group and its joint ventures and their expiry dates are:

Field	License holder	License expiry date
	Subsidiaries:
Yurkharovskoye	OOO NOVATEK-Yurkharovneftegas	2034
Salmanovskoye (Utrenneye)	OOO NOVATEK-Yurkharovneftegas	2031
Geofizicheskoye	OOO NOVATEK-Yurkharovneftegas	2031
East-Tarkosalinskoye	OOO NOVATEK-Tarkosaleneftegas	2043
North-Russkoe	OOO NOVATEK-Tarkosaleneftegas	2031
Khancheyskoye	OOO NOVATEK-Tarkosaleneftegas	2044
Urengoiskoye (within the Olimpiyskiy license area)	OOO NOVATEK-Tarkosaleneftegas	2026
Malo-Yamalskoye	OAO Tambeyneftegas	2019
Yarudeyskoye	OOO Yargeo	2029
	Joint ventures:
South-Tambeyskoye	OAO Yamal LNG	2045
North-Urengoyskoye	ZAO Nortgas	2018
Urengoiskoye (within the Samburgskiy and Yevo-Yakhinskiy license areas)	OAO Arkticheskaya gazovaya kompaniya (Subsidiary of OOO SeverEnergia)	2018
Samburgskoye	OAO Arkticheskaya gazovaya kompaniya (Subsidiary of OOO SeverEnergia)	2018
Yaro-Yakhinskoye	OAO Arkticheskaya gazovaya kompaniya (Subsidiary of OOO SeverEnergia)	2018
North-Chaselskoye	OAO Arkticheskaya gazovaya kompaniya (Subsidiary of OOO SeverEnergia)	Life of field
Termokarstovoye	ZAO Terneftegas	2021
Beregovoe	OAO Sibneftegas	2023
Pyreinoye	OAO Sibneftegas	2021

Management believes the Group has the right to extend its licenses beyond the initial expiration date under the existing legislation and intends to exercise this right on all of its fields.

Environmental liabilities. The Group and its predecessor entities have operated in the oil and gas industry in the Russian Federation for many years. The enforcement of environmental regulation in the Russian Federation is evolving and the enforcement posture of government authorities is continually being reconsidered. The Group periodically evaluates its obligations under environmental regulations and, as obligations are determined, they are recognized as an expense immediately if no future benefit is discernible. Potential liabilities arising as a result of a change in interpretation of existing regulations, civil litigation or changes in legislation cannot be estimated. Under existing legislation, management believes that there are no probable liabilities, which will have a material adverse effect on the Group's financial position, results of operations or cash flows.

Legal contingencies. The Group is subject of, or party to a number of court proceedings (both as a plaintiff and a defendant) arising in the ordinary course of business. In the opinion of management, there are no current legal proceedings or other claims outstanding, which could have a material effect on the result of operations or financial position of the Group.

29 PRINCIPAL SUBSIDIARIES AND JOINT VENTURES

The principal subsidiaries and joint ventures of the Group and respective ownership in the ordinary share capital at 31 December 2012 and 2011 are set out below:

	Ownership percent at 31 December:		Country of	Principal
	2012	2011	incorporation	activities
Subsidiaries
				Exploration
OOO NOVATEK-Yurkharovneftegas	100	100	Russia	and production
				Exploration
OOO NOVATEK-Tarkosaleneftegas	100	100	Russia	and production
				Gas Condensate
OOO NOVATEK-Purovsky ZPK	100	100	Russia	Processing Plant
				Transportation
OOO NOVATEK-Transervice	100	100	Russia	services
				Construction of
				transhipment and fractionation
OOO NOVATEK-Ust-Luga	100	100	Russia	facilities
				Wholesale and
OOO NOVATEK-AZK	100	100	Russia	retail trading
OOO NOVATEK-Chelyabinsk				Trading
(formerly OOO Yamalgazresurs-Chelyabinsk)	100	100	Russia	and marketing
OOO Gazprom mezhregiongas Chelyabinsk				Trading
(merged into OOO NOVATEK-Chelyabinsk in June 2012)	-	100	Russia	and marketing
				Trading
OOO Gazprom mezhregiongas Kostroma	84.54	-	Russia	and marketing
				Trading
OOO NOVATEK-Perm	100	100	Russia	and marketing
OOO Yamalenergogas (merged into OOO NOVATEK-Perm in January 2012)	-	100	Russia	Trading and marketing

OOO Yargeo	51	51	Russia	Exploration and development
				Trading
Novatek Gas & Power GmbH	100	100	Switzerland	and marketing
				Trading
Novatek Polska Sp. z o.o.	100	100	Poland	and marketing
Joint ventures
				Exploration
OAO Yamal LNG	80	80	Russia	and development
				Exploration
OAO Sibneftegas	51	51	Russia	and production
				Exploration
ZAO Terneftegas	51	51	Russia	and development
				Holding
OOO Yamal Development	50	50	Russia	company
OOO SeverEnergia				Holding
(includes a producing subsidiary, see Note 7)	25.5	25.5	Russia	company
				Exploration
ZAO Nortgas	49	-	Russia	and production

30 RELATED PARTY TRANSACTIONS

Transactions between NOVATEK and its subsidiaries, which are related parties of NOVATEK, have been eliminated on consolidation and are not disclosed in this Note.

For the purposes of these consolidated financial statements, parties are generally considered to be related if one party has the ability to control the other party, is under common control, or can exercise significant influence over the other party in making financial and operational decisions. Management has used reasonable judgments in considering each possible related party relationship with attention directed to the substance of the relationship, not merely the legal form. Related parties may enter into transactions, which unrelated parties might not, and transactions between related parties may not be affected on the same terms, conditions and amounts as transactions between unrelated parties.

	Year ended 31 December:
Related parties – joint ventures	2012	2011
Transactions
ɈȺɈ Sibneftegas: Interest income on loans issued Oil and gas products sales Purchases of natural gas	901 41 (5,272)	1,023 39 (3,661)
OOO Yamal Development: Interest income on loans issued	-	1,325
OOO SeverEnergia: Interest income on loans issued Purchases of unstable gas condensate	145 (1,956)	247 -
ZAO Terneftegas: Interest income on loans issued	45	5
OAO Yamal LNG (from October 2011): Interest income on loans issued Other revenues (operator services sales)	17 97	167 15
ZAO Nortgas (from 27 November 2012): Purchases of unstable gas condensate	(312)	-

In October 2011, the Group disposed of a 20 percent equity stake in OAO Yamal LNG, and in accordance with the new shareholders' agreement lost effective control over the entity, but joint control was retained (see Note 5); therefore, subsequent to that event, the Group's balances and transactions with this entity are disclosed as related parties – equity investments.

Related parties – joint ventures	At 31 December 2012	At 31 December 2011
Balances
ɈȺɈ Sibneftegas:
Long-term loans receivable	8,136	9,103
Interest on long-term loans receivable	187	775
Short-term loans receivable	428	634
Trade payables and accrued liabilities	705	387
OOO Yamal Development: Long-term loans and receivables	-	16,348
OOO SeverEnergia:
Short-term loans receivable	-	6,225
Interest on short-term loans receivable	-	94
Trade payables and accrued liabilities	398	-

30 RELATED PARTY TRANSACTIONS (CONTINUED)

Related parties – joint ventures	At 31 December 2012	At 31 December 2011
Balances
ZAO Terneftegas: Long-term loans receivable Interest on long-term loans receivable	1,451 50	220 5
OAO Yamal LNG: Long-term loans receivable Long-term receivables Interest on long-term loans receivable	2,915 - 17	- 3,955 -
ZAO Nortgas (from 27 November 2012): Trade payables and accrued liabilities	368	-

In September 2011, the Chairman of the Management Committee of NOVATEK acquired a controlling stake in OAO SIBUR Holding. As a result, the Group's balances and transactions with this company and its subsidiaries following that date were disclosed as related parties – parties under control of key management personnel.

In October 2012, the Group signed an agreement for the transport of stable gas condensate from the Purovsky Gas Condensate Plant to the Port of Vitino on the White Sea with OOO Transoil, an entity under control of a member of the Board of Directors of NOVATEK. The Group's balances and transactions with this company are disclosed below as related parties – parties under control of key management personnel of the Group.

Year ended 31 December:
2012	2011


	-
	-
(45)	-

(472)	-

	At 31 December 2011


1,224	4,066

	1,424
1,568	248
826	-
1,690	-

170	-
61	-
	2,042 (9,434) At 31 December 2012 -

30 RELATED PARTY TRANSACTIONS (CONTINUED)

Key management compensation. The Group paid to key management personnel (members of the Board of Directors and the Management Committee) short-term compensation, including salary, bonuses, and excluding dividends the following amounts.

	Year ended 31 December:
Related parties – members of the key management personnel	2012	2011
Board of Directors Management Committee	105 1,282	103 1,242
Total compensation	1,387	1,345

Such amounts include personal income tax and are net of payments to non-budget funds made by the employer. Some members of key management personnel have direct and/or indirect interests in the Group and receive dividends under general conditions based on their respective shareholdings. The Board of Directors consists of nine members. The Management Committee consisted of 15 members until 24 March 2011 and was subsequently reduced to eight members.

31 SEGMENT INFORMATION

The Group's activities are considered by the chief operating decision maker (hereinafter referred to as "CODM", represented by the Management Committee of NOVATEK) to comprise one operating segment: "exploration, production and marketing".

Segment information is provided to the CODM in accordance with Regulations on Accounting and Reporting of the Russian Federation ("RAR") with reconciling items largely representing adjustments and reclassifications recorded in the consolidated financial statements for the fair presentation in accordance with IFRS.

The CODM assesses reporting segment performance based on income before income taxes, since income taxes are not allocated. No business segment assets or liabilities (except for capital expenditures for the period) are provided to the CODM for decision-making.

Segment information for the year ended 31 December 2012 is as follows:

For the year ended 31 December 2012	References	Exploration, production and marketing	Segment information as reported to CODM	Reconciling items	Total per consolidated financial statements
External revenues	a	211,885	211,885	(912)	210,973
Operating expenses	a - e	(130,558)	(130,558)	4,783	(125,775)
Other operating income (loss)	c	(292)	(292)	428	136
Interest expense	f	(5,231)	(5,231)	1,995	(3,236)
Interest income		1,479	1,479	252	1,731
Foreign exchange gain (loss)	f	4,358	4,358	133	4,491
Segment result		81,641	81,641	6,679	88,320
Share of profit (loss) of joint ventures, net of income tax					(2,105)
Profit before income tax					86,215
Depreciation, depletion and amortization Capital expenditures	b, c f	15,286 36,021	15,286 36,021	(3,787) 7,533	11,499 43,554

31 SEGMENT INFORMATION (CONTINUED)

Reconciling items mainly related to:

a. different methodology of liquefied petroleum gas sales recognition under IFRS and the RAR which requires reclassification of external revenues and expenses for RR 951 million under IFRS;
b. different methodology in calculating depreciation, depletion and amortization for oil and gas properties between IFRS (units of production method) and management accounting (straight-line method), which resulted in reversal of RR 3,987 million in operating expenses under IFRS;
c. different methodology in the classification of depreciation, depletion and amortization for operating assets, which have not completed their statutory registration, between IFRS and management accounting, which resulted in the reclassification of RR 147 million from other operating income (loss) to depreciation, depletion and amortization in operating expenses under IFRS;
d. different methodology in recognizing expenses relating to natural gas storage services and payroll (including share-based payments, pension obligation, discounting loans to employee and bonus accruals) between IFRS and management accounting, which resulted in additional transportation expenses of RR 216 million and additional payroll expenses of RR 1,962 million recorded in operating expenses under IFRS;
e. different methodology in recognizing of exploration expenses, which resulted in the reversal of operating expenses of RR 2,364 million under IFRS; and
f. different methodology in interest capitalization policy and certain recognition policy differences in capital expenditures between IFRS and management accounting, which resulted in additional capitalized interest and foreign exchange differences of RR 2,156 million and additional capital expenditures of RR 5,377 million under IFRS.

Segment information for the year ended 31 December 2011 is as follows:

For the year ended 31 December 2011	References	Exploration, production and marketing	Segment information as reported to CODM	Reconciling items	Total per consolidated financial statements
External revenues	a	176,340	176,340	(1,067)	175,273
Operating expenses	a - e	(101,659)	(101,659)	4,839	(96,820)
Other operating income (loss)	c, f	12,950	12,950	50,205	63,155
Interest expense	g	(5,392)	(5,392)	3,242	(2,150)
Interest income		3,137	3,137	255	3,392
Foreign exchange gain (loss)	g	(4,368)	(4,368)	423	(3,945)
Segment result		81,008	81,008	57,897	138,905
Share of profit (loss) of joint ventures, net of income tax					(3,880)
Profit before income tax					135,025
Depreciation, depletion and amortization Capital expenditures	b, c g	12,925 30,510	12,925 30,510	(3,450) 7,521	9,475 38,031

31 SEGMENT INFORMATION (CONTINUED)

Reconciling items mainly related to:

a. different methodology of liquefied petroleum gas sales recognition under IFRS and the RAR which requires reclassification of external revenues and expenses for RR 998 million under IFRS;
b. different methodology in calculating depreciation, depletion and amortization for oil and gas properties between IFRS (units of production method) and management accounting (straight-line method), which resulted in reversal of RR 3,892 million in operating expenses under IFRS;
c. different methodology in the classification of depreciation, depletion and amortization for operating assets, which have not completed their statutory registration, between IFRS and management accounting, which resulted in the reclassification of RR 280 million from other operating income (loss) to depreciation, depletion and amortization in operating expenses under IFRS;
d. different methodology in recognizing expenses relating to natural gas storage services and payroll (including share-based payments, pension obligation, discounting loans to employee and bonus accruals) between IFRS and management accounting, which resulted in additional transportation expenses of RR 37 million and additional payroll expenses of RR 233 million recorded in operating expenses under IFRS;
e. different methodology in the recognition of impairment expenses between IFRS and management accounting, which resulted in net reversal of RR 755 million recorded in operating expenses under IFRS;
f. different methodology in recognizing the gain on disposal of ownership interest in OAO Yamal LNG between IFRS and management accounting, which resulted in additional gain of RR 49,589 million recorded in other operating income (loss) under IFRS; and
g. different methodology in interest capitalization policy and certain recognition policy differences in capital expenditures between IFRS and management accounting, which resulted in additional capitalized interest and foreign exchange differences of RR 3,942 million and additional capital expenditures of RR 3,579 million under IFRS.

Geographical information. The Group operates in the following geographical areas:

Russian Federation exploration, development, production and processing of hydrocarbons, and sales of natural gas, stable gas condensate, crude oil and related products;
USA sales of stable gas condensate;
Europe sales of stable gas condensate, liquefied petroleum gas and crude oil; and
Asian-Pacific Region ("APR") sales of stable gas condensate.

Geographical information for the years ended 31 December 2012 and 2011 is as follows:

For the year ended	Russian	Outside Russian Federation
31 December 2012	Federation	Europe	USA	APR	Other	Export duty	Subtotal	Total
Natural gas Stable gas condensate	142,613 319	- 22,857	- 8,614	- 46,351	- 3,597	- (35,054)	- 46,365	142,613 46,684
Liquefied petroleum gas	5,968	12,137	-	-	-	(2,506)	9,631	15,599
Crude oil Oil and gas products	3,215 350	3,661 -	- -	- -	- -	(1,876) -	1,785 -	5,000 350
Oil and gas sales	152,465	38,655	8,614	46,351	3,597	(39,436)	57,781	210,246
Other revenues	642	85	-	-	-	-	85	727
Total external revenues	153,107	38,740	8,614	46,351	3,597	(39,436)	57,866	210,973

31 SEGMENT INFORMATION (CONTINUED)

For the year ended	Russian	Outside Russian Federation
31 December 2011	Federation	Europe	USA	APR	Other	Export duty	Subtotal	Total

Natural gas	110,932	-	-	-	-	-	-	110,932
Stable gas condensate	46	28,265	17,920	35,642	-	(35,095)	46,732	46,778
Liquefied petroleum gas	5,728	11,024	-	-	10	(2,326)	8,708	14,436
Crude oil	1,458	2,143	-	-	-	(1,122)	1,021	2,479
Oil and gas products	186	-	-	-	-	-	-	186
Oil and gas sales	118,350	41,432	17,920	35,642	10	(38,543)	56,461	174,811
Other revenues	323	139	-	-	-	-	139	462
Total external revenues	118,673	41,571	17,920	35,642	10	(38,543)	56,600	175,273

Revenues are based on the geographical location of customers even though all revenues are generated from assets located in the Russian Federation. Substantially all of the Group's operating assets are located in the Russian Federation.

Major customers. For the years ended 31 December 2012 and 2011, the Group has one and two major customers to whom individual annual revenues exceed 10 percent of total external revenues, which on an aggregate basis represent 19 percent and 30 percent of total external revenues, respectively.

32 EXPLORATION FOR AND EVALUATION OF MINERAL RESOURCES

	Year ended 31 December:
	2012	2011
Net book value of assets value at 1 January	16,251	6,372
Additions	1,212	13,500
Disposals	(940)	(1,921)
Reclassification in proved properties	(7,192)	(574)
Transfers	(584)	(1,126)
Net book value of assets at 31 December	8,747	16,251
Liabilities	1,483	650
Cash flows used for operating activities	1,174	1,469
Cash flows used for investing activities	1,730	10,093

33 SUBSEQUENT EVENTS

On 20 February 2013, the Group issued four-year non-convertible Russian rouble denominated Eurobonds in the amount of RR 14 billion with a coupon rate of 7.75 percent per annum.

On 28 February 2013, the Group repaid a Russian rouble denominated loan in the amount of RR 15 billion obtained from OAO Sberbank. The loan was repaid ahead of its maturity schedule.

On 1 March 2013, the Group repaid the US dollar denominated loan in the amount of US 200 million obtained from OAO Nordea bank. The loan was repaid ahead of its maturity schedule.

34 NEW ACCOUNTING PRONOUNCEMENTS

The Group has reviewed new and revised accounting pronouncements that have been issued but are not yet effective for the Group and determined that the following may have an impact on the Group.

IFRS 9, Financial Instruments: Classification and Measurement. IFRS 9, issued in November 2009, replaces those parts of IAS 39 relating to the classification and measurement of financial assets. IFRS 9 was further amended in October 2010 to address the classification and measurement of financial liabilities and in December 2011 to (i) change its effective date to annual periods beginning on or after 1 January 2015 and (ii) add transition disclosures. Key features of the standard are as follows:

x Financial assets are required to be classified into two measurement categories: those to be measured subsequently at fair value, and those to be measured subsequently at amortized cost. The decision is to be made at initial recognition. The classification depends on the entity's business model for managing its financial instruments and the contractual cash flow characteristics of the instrument.
x An instrument is subsequently measured at amortized cost only if it is a debt instrument and both (i) the objective of the entity's business model is to hold the asset to collect the contractual cash flows, and (ii) the asset's contractual cash flows represent payments of principal and interest only (that is, it has only "basic loan features"). All other debt instruments are to be measured at fair value through profit or loss.
x All equity instruments are to be measured subsequently at fair value. Equity instruments that are held for trading will be measured at fair value through profit or loss. For all other equity investments, an irrevocable election can be made at initial recognition, to recognize unrealized and realized fair value gains and losses through other comprehensive income rather than profit or loss. There is to be no recycling of fair value gains and losses to profit or loss. This election may be made on an instrument-by-instrument basis. Dividends are to be presented in profit or loss, as long as they represent a return on investment.
x Most of the requirements in IAS 39 for classification and measurement of financial liabilities were carried forward unchanged to IFRS 9. The key change is that an entity will be required to present the effects of changes in own credit risk of financial liabilities designated at fair value through profit or loss in other comprehensive income.

While adoption of IFRS 9 is mandatory from 1 January 2015, earlier adoption is permitted. The Group is considering the implications of the standard, the impact on the Group and the timing of its adoption by the Group.

IFRS 10, Consolidated Financial Statements (issued in May 2011 and effective for annual periods beginning on or after 1 January 2013), replaces all of the guidance on control and consolidation in IAS 27, Consolidated and separate financial statements, and SIC-12, Consolidation—special purpose entities. IFRS 10 changes the definition of control so that the same criteria are applied to all entities to determine control. This definition is supported by extensive application guidance.

IFRS 11, Joint Arrangements, (issued in May 2011 and effective for annual periods beginning on or after 1 January 2013), replaces IAS 31, Interests in Joint Ventures, and SIC-13, Jointly Controlled Entities—Non-Monetary Contributions by Ventures. Changes in the definitions have reduced the number of types of joint arrangements to two: joint operations and joint ventures. The existing policy choice of proportionate consolidation for jointly controlled entities has been eliminated. Equity accounting is mandatory for participants in joint ventures.

34 NEW ACCOUNTING PRONOUNCEMENTS (CONTINUED)

IFRS 12, Disclosure of Interest in Other Entities, (issued in May 2011 and effective for annual periods beginning on or after 1 January 2013), applies to entities that have an interest in a subsidiary, a joint arrangement, an associate or an unconsolidated structured entity. It replaces the disclosure requirements currently found in IAS 28, Investments in associates. IFRS 12 requires entities to disclose information that helps financial statement readers to evaluate the nature, risks and financial effects associated with the entity's interests in subsidiaries, associates, joint arrangements and unconsolidated structured entities. To meet these objectives, the new standard requires disclosures in a number of areas, including significant judgments and assumptions made in determining whether an entity controls, jointly controls, or significantly influences its interests in other entities, extended disclosures on share of non-controlling interests in group activities and cash flows, summarized financial information of subsidiaries with material non-controlling interests, and detailed disclosures of interests in unconsolidated structured entities.

The Group will adopt IFRS 10, IFRS 11 and IFRS 12 from January 1, 2013. The adoption of IFRS 10 and IFRS 12 is not expected to have a material impact on the Group's financial position or operations but will require additional disclosures to be presented in the consolidated financial statements.

IFRS 13, Fair value measurement, (issued in May 2011 and effective for annual periods beginning on or after 1 January 2013), aims to improve consistency and reduce complexity by providing a revised definition of fair value, and a single source of fair value measurement and disclosure requirements for use across IFRSs. The adoption of this standard is not expected to have a material impact on the Group's financial position or operations.

IAS 27, Separate Financial Statements, (revised in May 2011 and effective for annual periods beginning on or after 1 January 2013), was changed and its objective is now to prescribe the accounting and disclosure requirements for investments in subsidiaries, joint ventures and associates when an entity prepares separate financial statements. The guidance on control and consolidated financial statements was replaced by IFRS 10, Consolidated Financial Statements. The adoption of this amendment is not expected to have a material impact on the Group's financial position or operations.

IAS 28, Investments in Associates and Joint Ventures, (revised in May 2011 and effective for annual periods beginning on or after 1 January 2013). The amendment of IAS 28 resulted from the International Accounting Standards Board's ("Board") project on joint ventures. When discussing that project, the Board decided to incorporate the accounting for joint ventures using the equity method into IAS 28 because this method is applicable to both joint ventures and associates. With this exception, other guidance remained unchanged. The adoption of this amendment is not expected to have a material impact on the Group's financial position or operations.

Amendments to IAS 1, Presentation of Financial Statements (issued June 2011, effective for annual periods beginning on or after 1 July 2012), changes the disclosure of items presented in other comprehensive income. The amendments require entities to separate items presented in other comprehensive income into two groups, based on whether or not they may be reclassified to profit or loss in the future. The suggested title used by IAS 1 has changed to 'statement of profit or loss and other comprehensive income'. The Group expects the amended standard to change presentation of its consolidated financial statements, but have no impact on measurement of transactions and balances.

Amended IAS 19, Employee Benefits (issued in June 2011, effective for periods beginning on or after 1 January 2013), makes significant changes to the recognition and measurement of defined benefit pension expense and termination benefits, and to the disclosures for all employee benefits. The standard requires recognition of all changes in the net defined benefit liability (asset) when they occur, as follows: (i) service cost and net interest in profit or loss; and (ii) remeasurements in other comprehensive income. The Group does not expect these amendments to have a material impact on the Group's financial position or operations.

34 NEW ACCOUNTING PRONOUNCEMENTS (CONTINUED)

Amendments to IFRS 7, Disclosures—Offsetting Financial Assets and Financial Liabilities (issued in December 2011 and effective for annual periods beginning on or after 1 January 2013). The amendment requires disclosures that will enable users of an entity's financial statements to evaluate the effect or potential effect of netting arrangements, including rights of set-off. The amendment will have an impact on disclosures but will have no effect on measurement and recognition of financial instruments.

Amendments to IAS 32, Offsetting Financial Assets and Financial Liabilities (issued in December 2011 and effective for annual periods beginning on or after 1 January 2014). The amendment added application guidance to IAS 32 to address inconsistencies identified in applying some of the offsetting criteria. This includes clarifying the meaning of 'currently has a legally enforceable right of set-off' and that some gross settlement systems may be considered equivalent to net settlement. The Group is considering the implications of the amendment, the impact on the Group and the timing of its adoption by the Group.

Improvements to International Financial Reporting Standards (issued in May 2012 and effective for annual periods beginning on or after 1 January 2013). The improvements consist of changes to five standards. IFRS 1 was amended to (i) clarify that an entity that resumes preparing its IFRS financial statements may either repeatedly apply IFRS 1 or apply all IFRSs retrospectively as if it had never stopped applying them, and (ii) to add an exemption from applying IAS 23, Borrowing costs, retrospectively by first-time adopters. IAS 1 was amended to clarify that explanatory notes are not required to support the third balance sheet presented at the beginning of the preceding period when it is provided because it was materially impacted by a retrospective restatement, changes in accounting policies or reclassifications for presentation purposes, while explanatory notes will be required when an entity voluntarily decides to provide additional comparative statements. IAS 16 was amended to clarify that servicing equipment that is used for more than one period is classified as property, plant and equipment rather than inventory. IAS 32 was amended to clarify that certain tax consequences of distributions to owners should be accounted for in the income statement as was always required by IAS 12. IAS 34 was amended to bring its requirements in line with IFRS 8. IAS 34 will require disclosure of a measure of total assets and liabilities for an operating segment only if such information is regularly provided to chief operating decision maker and there has been a material change in those measures since the last annual consolidated financial statements. The Group does not expect these amendments to have a material impact on the Group's financial position or operations.

UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES

The accompanying consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS"). In the absence of specific IFRS guidance, the Group has reverted to other relevant disclosure standards, mainly US GAAP, that are consistent with norms established for the oil and gas industry. While not required under IFRS, this section provides unaudited supplemental information on oil and gas exploration and production activities but excludes disclosures regarding the standardized measures of discounted cash flows related to oil and gas activities.

The Group's exploration and production activities are mainly within the Russian Federation; therefore, all of the information provided in this section pertains to this country. The Group operates through various oil and gas production subsidiaries, and also has an interest in oil and gas companies that are accounted for under the equity method.

Oil and Gas Exploration and Development Costs

The following tables set forth information regarding oil and gas acquisition, exploration and development activities. The amounts reported as costs incurred include both capitalized costs and costs charged to expense during the years ended 31 December 2012 and 2011 (amounts in millions of Russian roubles).

	Year ended 31 December:
	2012	2011
Costs incurred in exploration and development activities
Acquisition of unproved properties	-	7,053
Exploration costs	2,028	2,447
Development costs	29,988	23,493
Total costs incurred in exploration and development activities	32,016	32,993
The share of the Group in joint ventures	80,777	2,051
	At 31 December 2012	At 31 December 2011
Capitalized costs relating to oil and gas producing activities
Wells and related equipment and facilities	157,048	145,063
Support equipment and facilities	38,922	30,717
Uncompleted wells, equipment and facilities	17,312	12,862
Total capitalized costs relating to oil and gas producing activities	213,282	188,642
Less: accumulated depreciation, depletion and amortization	(46,131)	(35,540)
Net capitalized costs relating to oil and gas producing activities	167,151	153,102
The share of the Group in joint ventures	226,887	150,449

The Group has reclassified capitalized costs relating to oil and gas producing activities of Yamal LNG due to cessation of control on 6 October 2011 and the subsequent accounting of its activities under the equity method (see Note 5).

Results of Operations for Oil and Gas Producing Activities

The Group's results of operations for oil and gas producing activities are shown below. The results of operations for oil and gas producing activities do not include general corporate overhead or its associated tax effects. Income tax is based on statutory rates. In the following table, revenues from oil and gas sales are comprised of the sale of the Group's hydrocarbons and include processing costs, related to the Group's processing facilities as well as transportation expenses to the customer (amounts in millions of Russian roubles).

	Year ended 31 December:
	2012	2011
Revenues from oil and gas sales	184,629	162,975
Lifting costs		(5,403)
Transportation expenses	(57,888)	(46,216)
Taxes other than income tax	(7,599) (16,546) (10,589) (2,022) (94,644) 89,985 (17,997) 71,988 729 72,717	(16,307)
Depreciation, depletion and amortization		(8,937)
Exploration expenses		(1,819)
Total production costs		(78,682)
Results of operations for oil and gas producing activities before income tax		84,293
Less: related income tax expenses		(16,859)
Results of operations for oil and gas producing activities		67,434
Share of profit (loss) of joint ventures		(555)
Total results of operations for oil and gas producing activities		66,879

Proved Oil and Gas Reserves

The Group's oil and gas reserves estimation and reporting process involves an annual independent third party reserve appraisal as well as internal technical appraisals of reserves. The Group maintains its own internal reserve estimates that are calculated by qualified technical staff working directly with the oil and gas properties. The Group's technical staff periodically updates reserve estimates during the year based on evaluations of new wells, performance reviews, new technical information and other studies.

The Group estimates its oil and gas reserves in accordance with rules promulgated by the Securities and Exchange Commission (SEC) for proved reserves.

The oil and gas reserve estimates reported below are determined by the Group's independent petroleum reservoir engineers, DeGolyer and MacNaughton ("D&M"). The Group provides D&M annually with engineering, geological and geophysical data, actual production histories and other information necessary for the reserve determination. The Group's and D&M's technical staffs meet to review and discuss the information provided, and upon completion of this process, senior management reviews and approves the final reserve estimates issued by D&M.

The following reserve estimates were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir is tempered by experience with similar reservoirs, stages of development, quality and completeness of basic data, and production history.

The following information presents the quantities of proved oil and gas reserves and changes thereto as at and for the years ended 31 December 2012 and 2011.

Extensions of production licenses are assumed to be at the discretion of the Group. Management believes that proved reserves should include quantities which are expected to be produced after the expiry dates of the Group's production licenses. The Group's licenses for exploration and production expire between 2018 and 2045, with the most significant licenses for Yurkharovskoye and East-Tarkosalinskoye fields, expiring in 2034 and 2043, respectively. Legislation of the Russian Federation states that, upon expiration, a license is subject to renewal at the initiative of the license holder provided that further exploration, appraisal, production or remediation activities are necessary and provided that the license holder has not violated the terms of the license. Management intends to extend its licenses for properties expected to produce beyond the license expiry dates.

Proved developed reserves are those reserves which are expected to be recovered through existing wells with existing equipment and operating methods. Undeveloped reserves are those reserves which are expected to be recovered as a result of future investments to drill new wells, to re-complete existing wells and/or install facilities to collect and deliver the production.

Net reserves exclude quantities due to others when produced.

The reserve quantities below include 100 percent of the net proved reserve quantities attributable to the Group's consolidated subsidiaries and the Group's ownership percentage of the net proved reserves quantities of the joint ventures. A portion of the Group's total proved reserves are classified as either developed non-producing or undeveloped. Of the non-producing reserves, a portion represents existing wells which are to be returned to production at a future date.

For convenience, reserves estimates are provided both in English and Metric units.

Net proved reserves of natural gas are presented below.

	Net proved reserves		Group's share in joint ventures		Total net proved reserves
	Billions of cubic feet	Billions of cubic meters	Billions of cubic feet	Billions of cubic meters	Billions of cubic feet	Billions of cubic meters
Reserves at 31 December 2010	41,585	1,178	6,057	171	47,642	1,349
Changes attributable to:
Revisions of previous
estimates	(106)	(3)	370	11	264	8
Extension and discoveries	3,398	97	676	19	4,074	116
Disposals	(3,331)	(95)	-	-	(3,331)	(95)
Reclassifications	(13,323)	(377)	13,323	377	-	-
Production	(1,676)	(48)	(190)	(5)	(1,866)	(53)
Reserves at 31 December 2011	26,547	752	20,236	573	46,783	1,325
Changes attributable to:
Revisions of previous
estimates	231	6	(9)	-	222	6
Extension and discoveries	738	21	1,018	29	1,756	50
Acquisitions (*)	12,717	360	2,729	77	15,446	437
Production	(1,781)	(50)	(211)	(6)	(1,992)	(56)
Reserves at 31 December 2012	38,452	1,089	23,763	673	62,215	1,762
Net proved developed reserves (included above)
At 31 December 2010	22,515	638	2,536	71	25,051	709
At 31 December 2011	20,763	588	2,348	66	23,111	654
At 31 December 2012	20,053	568	3,222	91	23,275	659
Net proved undeveloped reserves (included above)
At 31 December 2010	19,070	540	3,521	100	22,591	640
At 31 December 2011	5,784	164	17,888	507	23,672	671
At 31 December 2012	18,399	521	20,541	582	38,940	1,103

(*) – the acquisitions include the first time reserve estimation for the Salmanovskoye (Utrenneye) and Geofizicheskoye fields, that were acquired late in 2011 and additionally explored in 2012.

The net proved reserves reported in the table above included reserves of natural gas attributable to non-controlling interest of 128 billion of cubic feet and 4 billion of cubic meters and 120 billion of cubic feet and 4 billion of cubic meters at 31 December 2012 and 2011, respectively.

Net proved reserves of crude oil, gas condensate and natural gas liquids are presented below.

	Net proved reserves		Group's share in joint ventures		Total net proved reserves
	Millions of barrels	Millions of metric tons	Millions of barrels	Millions of metric tons	Millions of barrels	Millions of metric tons
Reserves at 31 December 2010	566	68	103	13	669	81
Changes attributable to: Revisions of previous
estimates	10	1	4	1	14	2
Extension and discoveries	116	14	38	4	154	18
Disposals	(34)	(4)	-	-	(34)	(4)
Reclassifications	(138)	(16)	138	16	-	-
Production	(35)	(4)	-	-	(35)	(4)
Reserves at 31 December 2011	485	59	283	34	768	93
Changes attributable to:
Revisions of previous
estimates	2	-	(37)	(4)	(35)	(4)
Extension and discoveries	13	1	40	3	53	4
Acquisitions (*)	78	9	85	10	163	19
Production	(35)	(4)	(1)	-	(36)	(4)
Reserves at 31 December 2012	543	65	370	43	913	108
Net proved developed reserves (included above)
At 31 December 2010	304	36	-	-	304	36
At 31 December 2011	282	33	-	-	282	33
At 31 December 2012	269	32	26	3	295	35
Net proved undeveloped reserves (included above)
At 31 December 2010	262	32	103	13	365	45
At 31 December 2011	203	26	283	34	486	60
At 31 December 2012	274	33	344	40	618	73

(*) – the acquisitions include the first time reserve estimation for the Salmanovskoye (Utrenneye) and Geofizicheskoye fields, that were acquired late in 2011 and additionally explored in 2012.

The net proved reserves reported in the table above included reserves of crude oil, gas condensate and natural gas liquids attributable to non-controlling interest of 17 million of barrels and 2 million of metric tons and 16 million of barrels and 2 million of metric tons at 31 December 2012 and 2011, respectively.

In November 2012, the Group acquired 49 percent of the outstanding ordinary shares of ZAO Nortgas, which holds license on North-Urengoyskoye field (see Note 5).

In October 2011, the Group's effective control over OAO Yamal LNG, the holder of the South-Tambeyskoye field, ceased. As a result, the Group's interest in Yamal LNG is accounted for using the equity method (see Note 5).

OAO NOVATEK was incorporated as a joint stock company in accordance with the Russian law and is domiciled in the Russian Federation.

The Group's registered office is:

Ulitsa Pobedy 22a 629850 Tarko-Sale Yamal-Nenets Autonomous Region Russian Federation

The Group's office in Moscow is:

Ulitsa Udaltsova 2 119415 Moscow Russian Federation

Telephone:	7 (495) 730-60-00
Fax:	7 (495) 721-22-53

www.novatek.ru

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis of our financial condition and results of operations as of 31 December 2012 and for the year then ended in conjunction with our audited consolidated financial statements as of and for the years ended 31 December 2012 and 2011. The consolidated financial statements and the related notes thereto have been prepared in accordance with International Financial Reporting Standards (IFRS).

The financial and operational information contained in this "Management's Discussion and Analysis of Financial Condition and Results of Operations" comprises information of OAO NOVATEK and its consolidated subsidiaries (hereinafter jointly referred to as "we" or the "Group").

OVERVIEW

We are Russia's largest independent natural gas producer and the second-largest producer of natural gas in Russia after Gazprom, in each case according to the Central Dispatch Administration of the Fuel and Energy Complex (the "CDU-TEK") for 2012. In terms of proved natural gas reserves, we are also the second largest holder of natural gas resources in Russia after Gazprom, under the Petroleum Resources Management System ("PRMS") reserve reporting methodology.

Our exploration, development, production and processing of natural gas, gas condensate and crude oil have been conducted primarily within the Russian Federation, and, in accordance with Russian law, we sell our produced natural gas volumes exclusively in the Russian domestic market. We export our stable gas condensate directly to international markets, while our liquefied petroleum gas ("LPG") and crude oil are generally delivered to both international (including the Commonwealth of Independent States ("CIS")) and domestic markets.

RECENT DEVELOPMENTS

In February 2013, the Group issued four-year Russian rouble denominated Eurobonds in the aggregate amount of RR 14 billion with the annual coupon rate of 7.75%.

In December 2012, the Group acquired 82% of equity interest in OOO Gazprom mezhregiongas Kostroma ("Gazprom mezhregiongas Kostroma") to support and expand natural gas sales opportunities in the Kostroma region. Gazprom mezhregiongas Kostroma is a regional natural gas trader in the Kostroma region of the Russian Federation.

In December 2012, the Group established OOO NOVATEK Moscow region, a wholly owned subsidiary, to support the Group's current natural gas deliveries to the Moscow region, as well as to expand sales in the region.

In December 2012, the Group issued ten-year USD denominated Eurobonds in the aggregate amount of USD one billion with a coupon rate of 4.422% per annum.

In November 2012, the Group acquired a 49% ownership interest in ZAO Nortgas ("Nortgas") for total consideration of USD 1,375 million. Nortgas is a Russian oil and gas production company that holds the production license for the North-Urengoyskoye field (expires in 2018), located in the Yamal Nenets Autonomous Region ("YNAO"), which is located in a close proximity to our transport and processing infrastructure. The estimated proved reserves appraised under the PRMS reserve methodology totalled 186 billion cubic meters (bcm) of natural gas and 25 million tons of liquid hydrocarbons as of 31 December 2012, for combined total of 1.4 billion barrels of oil equivalent.

In October 2012, we launched the fourth stage of the second phase development at our Yurkharovskoye field, which allows achieving design production capacity of the field. The fourth stage complex includes two gas treatment trains with total annual capacity of seven billion cubic meters. The fourth stage launch increases natural gas production at the field to a plateau level of 36.5 bcm per annum.

In 2012, the Group signed long-term natural gas purchase and sales contracts with third parties on the European market. The gas purchase and sales contracts have been signed for a period of 10 years starting from 1 October 2012 with the total volume of natural gas supplied over this period is estimated to be approximately 210 terawatt-hours (or approximately 20 bcm). The financial result from natural gas trading activities, including the effect from changes in fair value of gas contracts, was recorded in the consolidated statement of income within other operating profit (loss).

During 2012, our joint venture OOO SeverEnergia ("SeverEnergia") launched the first and the second phases of the Samburgskoye field with combined annual natural gas production capacity of approximately 4.6 bcm and 650 thousand tons of gas condensate.

In November 2011, the Group acquired OOO Gazprom mezhregiongas Chelyabinsk ("Gazprom mezhregiongas Chelyabinsk"), a regional natural gas trader, serving the Chelyabinsk region of the Russian Federation, to support and expand the Group's natural gas sales commercial operations in this region.

In September 2011, the Group increased its equity interest in OAO Yamal LNG from 51% to 100% and subsequently disposed of a 20% interest in the company in October 2011 to TOTAL S.A., the Group's strategic partner in the Yamal LNG project. The Yamal LNG project plans to construct a natural gas liquefaction plant comprising three trains of 5.5 million tons per annum to exploit the hydrocarbon resources of the South-Tambeyskoye field, located on the Yamal peninsula.

In June 2011, the Group took part in a tender organized by the Federal Agency for the Use of Natural Resources of the Russian Federation for four licenses in the YNAO: exploration and production licenses for the Salmanovskoye (Utrenneye) and Geofizicheskoye fields, as well as geological studies and production licenses for the North-Obskiy and East-Tambeyskiy license areas. In August 2011, the Russian Government approved the transfer of these licenses to us for RR 6.9 billion in total consideration. The estimated proved reserves at our Salmanovskoye (Utrenneye) and Geofizicheskoye fields appraised under the PRMS reserve methodology totalled 492 billion cubic meters (bcm) of natural gas and 14 million tons of liquid hydrocarbons as of 31 December 2012. Our combined resources at North-Obskiy and East-Tambeyskiy license areas according to the Russian reserve classification category D1 totalled 1,763 bcm of natural gas and 221 million tons of liquid hydrocarbons.

SELECTED DATA

	Year ended 31 December:
millions of Russian roubles except as stated	2012	2011	Change %
Financial results
Total revenues (net of VAT, export duties, excise and fuel taxes)	210,973	175,273	20.4%
Operating expenses	(125,775)	(96,820)	29.9%
Profit attributable to shareholders of OAO NOVATEK	69,458	119,655	(42.0%)
Normalized profit attributable to shareholders of
OAO NOVATEK (1)	69,518	56,707	22.6%
EBITDA (2)	95,106	148,349	(35.9%)
Normalized EBITDA (3)	95,166	85,401	11.4%
Normalized EBITDAX (4)	97,188	87,220	11.4%
Earnings per share (in Russian roubles)	22.89	39.45	(42.0%)
Normalized Earnings per share (in Russian roubles) (5)	22.91	18.69	22.6%
Operating results
Natural gas sales volumes (million cubic meters)	58,880	53,667	9.7%
Stable gas condensate sales volumes (thousand tons)	2,847	2,984	(4.6%)
Liquefied petroleum gas sales volumes (thousand tons)	905	880	2.8%
Crude oil sales volumes (thousand tons)	442	242	82.6%
Total hydrocarbons production (million barrels of oil equivalent) (6)	405.1	380.6	6.4%
Total daily production (thousand barrels of oil equivalent per day) (6)	1,107	1,043	6.1%
Cash flow results
Net cash provided by operating activities	75,825	71,907	5.4%
Capital expenditures (7)	43,554	31,161	39.8%
Free cash flow (8)	32,271	40,746	(20.8%)

(1) Normalized profit attributable to shareholders of OAO NOVATEK represents profit attributable to shareholders of OAO NOVATEK excluding net gain (loss) on disposal of interest in subsidiaries.

(2) EBITDA represents profit (loss) attributable to shareholders of OAO NOVATEK adjusted for the add-back of net impairment expenses (reversals), income tax expense and finance income (expense) from the Consolidated Statement of Income, income (loss) from changes in fair value of derivative financial instruments from the "Financial instruments and financial risk factors" in the notes to the consolidated financial statements and depreciation, depletion and amortization from the Consolidated Statement of Cash Flows.

(3) Normalized EBITDA represents EBITDA excluding net gain (loss) on disposal of interest in subsidiaries.

(4) Normalized EBITDAX represents EBITDA as adjusted for the add-back of exploration expenses and excludes net gain (loss) on disposal of interest in subsidiaries.

(5) Normalized Earnings per share represents Earnings per share adjusted for net gain (loss) on disposal of interest in subsidiaries.

(6) Total hydrocarbons production and total daily production are calculated based on net production, including our proportionate share in the production of our joint ventures.

(7) Capital expenditures represent additions to property, plant and equipment excluding prepayments for participation in tender for mineral licenses.

(8) Free cash flow represents the excess of Net cash provided by operating activities over Capital expenditures.

	Year ended 31 December:		Change %
millions of Russian roubles	2012	2011
3UR¿WORVVDWWULEXWDEOHWRVKDUHKROGHUVRI2\$2129\$7(.	69,458	119,655	(42.0%)
Depreciation, depletion and amortization	11,499	9,475	21.4%
Net impairment expenses	325	782	(58.4%)
Loss (income) from changes in fair value
of derivative financial instruments	36	-	n/a
Total finance expense (income)	(2,986)	2,703	n/a
Total income tax expense	16,774	15,734	6.6%
EBITDA	95,106	148,349	(35.9%)
Net loss (gain) on disposal of interest in subsidiaries	60	(62,948)	n/a
Normalized EBITDA	95,166	85,401	11.4%
Exploration expenses	2,022	1,819	11.2%
Normalized EBITDAX	97,188	87,220	11.4%

Reconciliation of adjusted (%,7'\$ DQG (%,7'\$; WR SUR¿W (loss) attributable to shareholders of OAO NOVATEK is as follows:

SELECTED MACRO-ECONOMIC DATA

Exchange rate, Russian	1 quarter		2 quarter		3 quarter		4 quarter		Year		Change
roubles for one US dollar (1)	2012	2011	2012	2011	2012	2011	2012	2011	2012	2011	Y-o-Y, %

At the beginning of the period	32.20	30.48	29.33	28.43	32.82	28.08	30.92	31.88	32.20	30.48	5.6%
At the end of the period	29.33	28.43	32.82	28.08	30.92	31.88	30.37	32.20	30.37	32.20	(5.7%)
Average for the period	30.26	29.27	31.01	27.99	32.01	29.05	31.08	31.23	31.09	29.39	5.8%
Depreciation (appreciation) of
Russian rouble to US dollar	(8.9%)	(6.7%)	11.9%	(1.2%)	(5.8%)	13.5%	(1.8%)	1.0%	(5.7%)	5.6%	n/a

(1) According to the Central Bank of Russian Federation (CBR). The average rates are calculated as the average of the daily exchange rates on each business day (which rate is announced by the CBR for each such business day) and on each nonbusiness day (which rate is equal to the exchange rate on the previous business day).

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	1 quarter		2 quarter		3 quarter		4 quarter		Year		Change
Crude oil prices, USD / bbl	2012	2011	2012	2011	2012	2011	2012	2011	2012	2011	Y-o-Y, %
WTI (2) At the end of the period Average for the period	103.0 103.0	106.7 94.6	85.0 93.5	95.4 102.3	92.1 92.2	79.2 89.5	91.8 88.2	98.8 94.1	91.8 94.2	98.8 95.1	(7.1%) (0.9%)
Brent (3) At the end of the period Average for the period	123.5 118.6	116.9 105.4	94.5 108.3	111.5 117.0	111.0 109.5	105.2 113.4	110.0 110.1	106.5 109.4	110.0 111.7	106.5 111.3	3.3% 0.4%
Urals (3) At the end of the period Average for the period	120.0 116.9	113.1 102.6	94.2 106.6	110.1 113.7	109.9 108.9	102.3 111.5	108.1 108.8	104.3 108.7	108.1 110.4	104.3 109.1	3.6% 1.2%

(2) Based on New York Mercantile Exchange Light Sweet prices provided by Reuters to Platts.

(3) Based on Brent (Dtd) prices and Russian Urals/ESPO spot assessments prices as provided by Reuters to Platts. ESPO stands for East Siberian Pipeline Ocean crude oil.

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Propane-butane mix prices,	1 quarter		2 quarter		3 quarter		4 quarter		Year		Change
USD / ton (4)	2012	2011	2012	2011	2012	2011	2012	2011	2012	2011	Y-o-Y, %
At the end of the period Average for the period	837.5 782.6	740.0 734.6	612.5 786.4	814.0 795.9	812.5 720.7	890.0 834.4	840.0 829.6	808.5 847.5	840.0 779.8	808.5 803.5	3.9% (2.9%)

(4) Based on spot prices for propane-butane mix at the Belarusian-Polish border (DAF, Brest) as provided by Argus.

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	1 quarter		2 quarter		3 quarter		4 quarter		Year		Change
Export duties, USD / ton (5)	2012	2011	2012	2011	2012	2011	2012	2011	2012	2011	Y-o-Y, %
Crude oil, stable gas condensate
At the end of the period Average for the period	411.2 400.8	365.0 343.0	419.8 443.0	462.1 446.5	393.8 366.6	444.1 442.5	396.5 406.6	406.6 403.7	396.5 404.3	406.6 408.9	(2.5%) (1.1%)
LPG
At the end of the period Average for the period	157.3 180.0	150.2 166.1	237.1 197.4	189.8 137.0	76.2 92.7	192.0 182.6	197.4 187.4	221.8 218.3	197.4 164.4	221.8 176.0	(11.0%) (6.6%)

(5) Export duties are determined by the Government of the Russian Federation in US dollars and are paid in Russian roubles.

CERTAIN FACTORS AFFECTING OUR RESULTS OF OPERATIONS

Current financial market conditions

The economic instability in the Euro-Zone has appeared to subside with the various measures taken by the respective governments, Central Banks and other quasi-governmental financial institutions. Although the main financial and economic issues plaguing the Euro-Zone over the twelve months remains in the forefront of present discussions, we will continue to monitor the credit situation very closely and take various measures, we deem necessary, to ensure the integrity of our financial condition and mitigate counter-party credit exposure from our natural gas and liquid hydrocarbon sales. In addition, we continue to take proactive steps to ensure the safety of our excess funds deposited with both domestic and international banks, as well as limit our risk exposure from prepayments to various service providers. Presently, our cash and deposits are diversified and maintained in banks that we believe are well capitalized in accordance with international capital adequacy rules.

We have reviewed our capital expenditure program for the upcoming year and have concluded that we have sufficient liquidity, through current internal cash flows and short-term borrowing facilities, to adequately fund our core natural gas business operations and planned capital expenditure program.

Management will continue to closely monitor the economic environment in Russia, as well as the domestic and international capital markets to determine if any further corrective and/or preventive measures are required to sustain and grow our business. In addition, we will continue to assess the trends in the capital markets for opportunities to access long-term funding at a reasonable cost to the Group commensurate with our investment grade credit ratings and our capital requirements.

Exchange rate volatility between the Russian rouble and the US dollar exchange rate may significantly influence the Group's reporting financial results due to the fact that a significant portion of our long-term debt is denominated in US dollars (see "Profit attributable to shareholders and earnings per share" below).

Natural gas prices

As an independent natural gas producer, we are not subject to the Russian Government's regulation of natural gas prices, except for those volumes delivered to residential customers, although the prices we can achieve on the domestic market are strongly influenced by the prices regulated by the Federal Tariffs Service ("FTS"), a governmental agency, and present market conditions.

In February 2011, the Government of the Russian Federation announced certain revisions to the domestic natural gas market liberalization plan. According to the revised plan, the target date for full liberalization of the domestic natural gas market is 1 January 2015 but there are various Governmental discussions indicating that this program may be further extended. The regulation of the domestic natural gas price prior to 2015 will be based on the netback parity of natural gas prices on the domestic and export markets.

As part of the liberalization plan, the FTS increased the regulated price for natural gas by 15% effective from 1 January 2011 and 1 July 2012, respectively.

According to the Russian Government Directive No.1205 on Improvement of State Gas Price Regulation as of 31 December 2010, starting from 2013 natural gas prices for sales to end-customers on the domestic market (excluding residential customers) are set for each region of the Russian Federation on a quarterly basis using a price formula within the range of maximum and minimum wholesale price. The maximum and minimum wholesale gas prices may be revised semiannually – as of 1 January and 1 July. In addition, the wholesale gas prices may be recalculated twice a year (as of 1 April and 1 October) based on changes in oil products prices on the European markets within a range of +/-3% from the average prices set previously.

According to the Forecast of Socio-economic Development for 2013, the regulated natural gas prices will be increased by 15% effective in 2013, 2014 and 2015.

The FTS under the Governmental decisions may modify the percentages published, as well as to potentially prolong the timetable toward market price liberalization based on market conditions and other factors.

The specific terms for delivery of natural gas affect our average realized prices. Natural gas sold "ex-field" is sold primarily to wholesale gas traders, in which case the buyer is responsible for the payment of gas transportation tariffs. Sales to wholesale gas traders allow us to diversify our natural gas sales without incurring additional commercial expenses. Historically, we have realized higher prices and net margins for natural gas volumes sold directly to end-customers, as the gas transportation tariff is included in the contract price and no retail margin is lost to wholesale gas traders. However, the historical norm may or may not prevail in the present or future market situations.

In December 2011, we commenced natural gas sales to residential customers at regulated prices in the Chelyabinsk region as a result of the acquisition of a regional gas trader Gazprom mezhregiongas Chelyabinsk. In December 2012, we acquired a regional gas trader Gazprom mezhregiongas Kostroma and commenced natural gas sales to residential customers at regulated prices in the Kostroma region in 2013. We disclose such sales within our end-customers category.

In 2012, our average natural gas price to end-customers and ex-field price increased by 7.4% and 9.1%, respectively, whereas our average transportation expense for the delivery of natural gas to end-customers increased by 2.2% primarily due to a 7.0% increase in the average transportation tariff set by the FTS effective 1 July 2012 (see "Transportation tariffs" below). As a result, our average netback price on end-customers sales increased by 11.9%, while our total average natural gas price excluding transportation expense increased by 11.3% compared to respective prices in 2011.

The following table shows our average realized natural gas sales prices (net of VAT), excluding volumes purchased for resale in the location of our end-customers:

	Year ended 31 December:
Russian roubles per mcm	2012	2011	Change %
Average natural gas price to end-customers (1)	2,821	2,627	7.4%
Average natural gas transportation expense for sales to end-customers	(1,234)	(1,207)	2.2%
Average natural gas netback price on end-customer sales	1,589	1,420	11.9%
Average natural gas price ex-field (wholesale traders)	1,518	1,392	9.1%
Total average natural gas price excluding transportation expense	1,566	1,407	11.3%

(1) Includes cost of transportation.

Crude oil, stable gas condensate, liquefied petroleum gas and oil products prices

Crude oil, stable gas condensate, LPG and oil products prices on international markets have historically been volatile depending on, among other things, the balance between supply and demand fundamentals, the ability and willingness of oil producing countries to sustain or change production levels to meet changes in global demand and potential disruptions in global crude oil supplies due to war, geopolitical developments, terrorist activities or natural disasters.

The actual prices we receive for our liquid hydrocarbons on both the domestic and international markets are dependent on many external factors beyond the control of management, such as movements in international benchmark crude oil prices. Crude oil that we sell bound for international markets is transported through the OAO AK Transneft ("Transneft") pipeline system where it is blended with other crude oil of varying qualities to produce an export blend commonly referred to as "Urals blend", which normally (or historically) trades at a discount to the international benchmark Brent crude oil. Volatile movements in benchmark crude oil prices can have a positive and/or negative impact on the ultimate prices we receive for our liquids volumes sold on both the domestic and international markets, among many other factors.

Our stable gas condensate, LPG and crude oil and oil products' prices on both international and domestic markets include transportation expense in accordance with the specific terms of delivery.

In 2012, our stable gas condensate export delivery terms were cost and freight (CFR), or delivery to the port of destination ex-ship (DES), or delivery at point of destination (DAP), or priced at cost, insurance and freight (CIF), while in 2011 our delivery terms were either CFR, DES, DAP, CIF or delivery at terminal (DAT). Our average stable gas condensate export contract price, including export duties, in 2012, was approximately USD 933 per ton compared to approximately USD 931 per ton in 2011.

In 2012, as well as in 2011, our crude oil export delivery terms were DAP (Feneshlitke, Hungary). Our average crude oil export contract price, including export duties, was approximately USD 786 per ton compared to USD 787 per ton in 2011.

The following table shows our average realized stable gas condensate and crude oil sales prices (net of VAT and export duties, where applicable; prices in US dollars were translated from Russian roubles using the average exchange rate for the period):

	Year ended 31 December:	Change
Russian roubles or US dollars per ton	2012	2011	%
Stable gas condensate
Net export price, RR per ton	16,432	15,676	4.8%
Net export price, USD per ton	528.5	533.4	(0.9%)
Domestic price, RR per ton	12,489	13,818	(9.6%)
Crude oil
Net export price, RR per ton	11,935	10,983	8.7%
Net export price, USD per ton	383.9	373.7	2.7%
Domestic price, RR per ton	10,985	9,792	12.2%

In 2012, as well as in 2011, our LPG export delivery terms were DAP at the border of the customer's country, carriage paid to (CPT) the Port of Temryuk (southern Russia) and free carrier (FCA) at terminal points in Poland. In 2012, our average export contract price for LPG produced at the Purovsky Gas Condensate Plant ("Purovsky Plant"), including export duties and excluding excise and fuel taxes expense, was approximately USD 817 per ton compared to USD 829 per ton in 2011.

In 2012, as well as in 2011, we sold 426 thousand tons of our LPG on the domestic market at an average price of RR 14,011 per ton and RR 13,458 per ton, respectively, including volumes purchased for resale and sold through our wholly owned subsidiary OOO NOVATEK-AZK ("NOVATEK-AZK").

In 2012, we sold approximately nine thousand tons of methanol produced by our production subsidiaries to our joint ventures and third parties at an average price of RR 10,659 per ton as compared to sales of approximately four thousand tons at an average price of RR 10,000 per ton in 2011.

The following table shows our average realized LPG and methanol sales prices, excluding LPG trading activities. Prices in the table below are shown net of VAT, export duties, excise and fuel taxes expense, where applicable. Prices in US dollars were translated from Russian roubles using the average exchange rate for the period.

	Year ended 31 December:	Change
Russian roubles or US dollars per ton	2012	2011	%
LPG
Net export price, RR per ton	20,109	19,199	4.7%
Net export price, USD per ton	646.8	653.3	(1.0%)
Domestic price, RR per ton	14,009	13,458	4.1%
Methanol
Domestic price, RR per ton	10,659	10,000	6.6%

Transportation tariffs

Natural gas

We transport our natural gas through our own pipelines into the Unified Gas Supply System ("UGSS"), which is owned and operated by OAO Gazprom, a Russian Government controlled monopoly. Transportation tariffs for the use of the UGSS by independent producers are set by the FTS.

In accordance with the methodology of calculating transportation tariffs for natural gas produced in the Russian Federation for shipments to consumers located within the customs territory of the Russian Federation and the member states of the Customs Union Agreement (Belarus, Kazakhstan, Kyrgyzstan and Tajikistan), the transportation tariff consists of two parts: a rate for the utilization of the trunk pipeline and a transportation rate per mcm per 100 kilometers (km). The rate for utilization of the trunk pipeline is based on an "input/output" function, which is determined by where natural gas enters and exits the trunk pipeline and includes a constant rate for end-customers using Gazprom's gas distribution systems. The constant rate is deducted from the utilization rate for end-customers using non-Gazprom gas distribution systems.

Effective from 1 January 2011, the FTS approved a 9.3% average increase in the transportation tariff for natural gas and the rate for utilization of the trunk pipeline averaged between RR 44.97 to RR 1,964.13 (excluding VAT) per mcm and the transportation rate was RR 11.23 (excluding VAT) per mcm per 100 km.

Effective from 1 July 2012, the FTS approved a 7.0% average increase of the transportation tariff for natural gas and the rate for utilization of the trunk pipeline averaged between RR 50.78 to RR 1,995.44 (excluding VAT) per mcm and the transportation rate was RR 12.02 (excluding VAT) per mcm per 100 km.

According to the Forecast of Socio-economic Development of the Russian Federation for 2013 announced in September 2012 by the Ministry of Economic Development of the Russian Federation, the transportation tariff for natural gas produced by independent producers will be increased in 2013, 2014 and 2015 as of the same date as the increase in the regulated natural gas prices (expected to be 1 July) and will not exceed the forecasted inflation rate (excluding the effect of possible property tax benefit cancellation for OAO Gazprom). According to preliminary estimates of the Ministry of Economic Development, the transportation tariff will be increased by 5.4% effective from 1 July 2013, by 5.0% effective from 1 July 2014 and by 4.8% effective from 1 July 2015 (excluding the effect of possible property tax benefit cancellation for OAO Gazprom).

Crude oil

We transport most of our crude oil through the pipeline network owned and operated by Transneft, Russia's state-owned monopoly crude oil pipeline operator. The FTS sets tariffs for transportation of crude oil through Transneft's pipeline network, which includes transport, dispatch, pumping, loading, charge-discharge, transshipment and other services. The FTS sets tariffs for each separate route of the pipeline network, so the overall expense for the transport of crude oil primarily depends on the length of the transport route from the producing fields to the ultimate destination, transportation direction and other factors.

Crude oil transportation tariffs were increased in September and November 2011 on average by approximately 2.9% and 5.0%, respectively, and in November 2012 on average by approximately 5.5%.

Stable gas condensate and LPG

We transport our stable gas condensate (from the Purovsky Plant to the Port of Vitino on the White Sea or to customers on the domestic markets) and LPG (from the Purovsky Plant to the customers on the domestic market) by rail which is owned and operated by Russia's state-owned monopoly railway operator – OAO Russian Railways. Our transportation tariffs for transport by rail are set by the FTS and vary depending on product and length of the transport route. For our stable gas condensate and LPG transportation purposes we use our own rail cars and rail cars rented from independent Russian transportation companies.

In 2012 and 2011, we applied the discount co-efficients to existing rail road transportation tariffs related to export deliveries of stable gas condensate and LPG shipped from the Limbey rail station. In 2011, the discount co-efficient for stable gas condensate was set at 0.89 for companies with annual shipped volumes of 2,600 thousand tons or more, and the discount co-efficient for LPG was set at 0.68 for delivered annual volumes of 415 thousand tons or more. In 2012, the discount co-efficient for stable gas condensate was set at 0.89 for companies with annual shipped volumes of 3,000 thousand tons or more, and the discount co-efficient for LPG was set at 0.71 for delivered annual volumes of 445 thousand tons or more.

We deliver our stable gas condensate to international markets using the loading and storage facilities at the Port of Vitino on the White Sea and tankers for transportation to US, European, South American and countries of the APR. The cost of tanker transportation is generally determined by the distance to the final destination, tanker availability, seasonality of deliveries and standard shipping terms, all in accordance with general industry practice.

Our tax burden and obligatory payments

We are subject to a wide range of taxes imposed at the federal, regional, and local levels, many of which are based on revenue or volumetric measures. In addition to income tax, significant taxes to which we are subject include VAT, unified natural resources production tax ("UPT", commonly referred as "MET" – mineral extraction tax), export duties, property tax, payments to non-budget funds and other contributions.

In practice, Russian tax authorities often have their own interpretation of tax laws that rarely favours taxpayers, who have to resort to court proceedings to defend their position against the tax authorities. Differing interpretations of tax regulations exist both among and within government ministries and organizations at the federal, regional and local levels, creating uncertainties and inconsistent enforcement. Tax declarations, together with related documentation such as customs declarations, are subject to review and investigation by a number of authorities, each of which may impose fines, penalties and interest charges. Generally, taxpayers are subject to an inspection of their activities for a period of three calendar years immediately preceding the year in which the audit is conducted. Previous audits do not completely exclude subsequent claims relating to the audited period. In addition, in some instances, new tax regulations have been given retroactive effect.

We have not employed any tax minimization schemes using offshore or domestic tax zones in the Russian Federation.

UPT

In 2012, according to the Russian Tax Code, the UPT rate for natural gas was set at RR 251 per mcm (consisting of base rate of RR 509 per mcm and a reducing co-efficient for independent natural gas producers of 0.493) as compared to RR 237 per mcm in 2011.

In November 2012, the amendments to the Russian Tax Code were passed into law, according to which the UPT rates were changed effective from 1 January 2013. According to these amendments, the UPT rate for natural gas produced by independent natural gas producers was set at RR 265 per mcm effective from 1 January 2013, RR 402 per mcm from 1 July 2013, RR 471 per mcm from 1 January 2014 and RR 552 per mcm from 1 January 2015. In addition, the Government of the Russian Federation is currently considering replacing the existing approach to the calculation of the UPT rate for natural gas with a formula that takes into account the category of extracted gas, field's location, access to export markets and dynamics in regulated prices and transportation tariffs. The proposed change in the tax calculation may take place in the nearest future; however, the discussions are not yet completed as of the date of the issuance of our financial statements.

In 2011, the UPT rate for gas condensate was set at 17.5% of gas condensate revenues recognized by the producing entities. Effective from 2012, the approach to the taxation of produced gas condensate was changed, and the UPT rate for gas condensate for 2012 was set at RR 556 per ton. According to the amendments to the Russian Tax Code, approved in November 2012, the UPT rate for gas condensate for 2013, 2014 and 2015 was set at RR 590, RR 647 and RR 679 per ton, respectively.

The UPT rate for crude oil is linked to the Urals benchmark crude oil price and changes every month. It is calculated in US dollar and translated and paid in Russian roubles using the monthly average exchange rate established by the Central Bank of Russia.

The Russian Tax Code provides for reduced or zero UPT rate for crude oil produced in certain geographical areas. We did not use the reduced or zero UPT rates from the production of crude oil prior to 1 January 2012. According to the amendments to the Russian Tax Code, effective from 1 January 2012, a zero UPT rate is set for crude oil produced at fields located in the YNAO to the north of the 65th degree of the northern latitude. Our East-Tarkosalinskoye and Khancheyskoye fields are located in the mentioned geographical area; therefore, we applied the allowed zero UPT rate for crude oil produced at these fields effective from 1 January 2012.

Export duties

We are subject to export duties on our exports of stable gas condensate, LPG and crude oil. The Government of the Russian Federation sets the export customs duties for exported liquids on a monthly basis.

The export duty rate for stable gas condensate and crude oil is calculated based on the average Urals crude oil price for the period from the 15th calendar day in the previous month to the 14th calendar day of the current month and is set for the following month after the current calendar month.

The export duty rate for LPG is calculated based on the average LPG price at the Polish border (DAF, Brest) for the period from the 15th calendar day in the previous month to the 14th calendar day of the current month and is set for the following month after the current calendar month (see "Selected macro-economic data" above).

Social insurance tax

Effective from 1 January 2012, the social insurance tax rate for contributions to the Pension Fund of the Russian Federation decreased from 26% to 22%, but the maximum taxable base per each employee was increased from RR 463 thousand to RR 512 thousand of annual salary. In addition, effective from 1 January 2012, a new insurance rate of 10% was implemented for amounts above the maximum taxable base of RR 512 thousand. Effective from 1 January 2013, the maximum taxable base per each employee was increased to RR 568 thousand of annual salary.

OIL AND GAS RESERVES

We do not file with the SEC nor are obliged to report our reserves in compliance with these standards. However, we have consistently disclosed proved oil and gas reserves as unaudited supplemental information in the Group's IFRS audited consolidated financial statements. We also provide additional information about our hydrocarbon reserves based on the widely-industry accepted PRMS reserves reporting classification, which in addition to total proved reserves discloses information on our probable and possible reserves.

Our proved reserves estimates are appraised by the Group's independent petroleum engineers, DeGolyer and MacNaughton ("D&M"). The Group's total proved reserves, comprised of proved developed and proved undeveloped reserves as of 31 December 2012 and 2011, were appraised using both reporting and disclosure requirements promulgated by the SEC and the PRMS reserves reporting classification.

Proved reserves disclosed in the "Unaudited Supplemental Oil and Gas Disclosures" in the Group's IFRS consolidated financial statements are presented under SEC reserve reporting methodology based on 100% of the reserves attributable to all consolidated subsidiaries (whether or not wholly owned), as well as our proportionate share of proved reserves accounted for by the equity method based on our equity ownership interest.

The tables below provide a comparison of the Group's estimated reserves under SEC and PRMS reserve classifications attributable to all consolidated subsidiaries and joint ventures based on the Group's equity ownership interest in the respective fields. Thus the proved reserves disclosure as noted above do not reconcile to the proved reserves in the consolidated financial statements.

	Natural gas
	SEC		PRMS
		Billions		Billions
	Billions of	of cubic	Billions of	of cubic
Based on our equity ownership interest in the fields	cubic feet	meters	cubic feet	meters
Total proved reserves at 31 December 2010	40,415	1,144	46,245	1,310
Changes attributable to:
Revisions of previous estimates, extensions and discoveries	3,284	94	4,580	129
Acquisitions (1)	8,161	231	11,861	336
Disposals (2)	(3,331)	(95)	(4,841)	(137)
Production	(1,866)	(53)	(1,866)	(53)
Total proved reserves at 31 December 2011	46,663	1,321	55,979	1,585
including subsidiaries	26,427	748	27,417	776
including joint ventures	20,236	573	28,562	809
Changes attributable to:
Revisions of previous estimates, extensions and discoveries	1,970	56	2,920	83
Acquisitions of prior periods (3)	12,717	360	17,386	492
Acquisitions of current period (4)	2,729	77	3,221	91
Production	(1,992)	(56)	(1,992)	(56)
Total proved reserves at 31 December 2012	62,087	1,758	77,514	2,195
including subsidiaries	38,324	1,085	44,062	1,248
including joint ventures	23,763	673	33,452	947

(1) Acquisitions in 2011 represent reserves attributable to increased equity interest in Yamal LNG from 51% to 100%.

(2) Disposals in 2011 represent reserves attributable to the disposal of a 20% interest in Yamal LNG to TOTAL S.A.

(3) Acquisitions of prior periods represent reserves attributable to licenses acquired in 2011 (Salmanovskoye (Utrenneye) and Geofizicheskoye fields), which were appraised in 2012 and include exploration surveys made after acquisition.

(4) Acquisitions of current period represent reserves attributable to our acquisition of a 49% equity stake in our joint venture Nortgas completed in 2012.

	Crude oil, gas condensate and natural gas liquids
	SEC		PRMS
		Millions		Millions
	Millions	of metric	Millions	of metric
Based on our equity ownership interest in the fields	of barrels	tons	of barrels	tons
Total proved reserves at 31 December 2010	604	73	761	93
Changes attributable to:
Revisions of previous estimates, extensions and discoveries	133	16	170	20
Acquisitions (1)	84	10	125	15
Disposals (2)	(34)	(4)	(51)	(6)
Production	(35)	(4)	(35)	(4)
Total proved reserves at 31 December 2011	752	91	970	118
including subsidiaries	469	57	571	70
including joint ventures	283	34	399	48
Changes attributable to:
Revisions of previous estimates, extensions and discoveries	17	0	89	9
Acquisitions of prior periods (3)	78	9	119	14
Acquisitions of current period (4)	85	10	100	12
Production	(36)	(4)	(36)	(4)
Total proved reserves at 31 December 2012	896	106	1,242	149
including subsidiaries	526	63	706	86
including joint ventures	370	43	536	63

(1) Acquisitions in 2011 represent reserves attributable to increased equity interest in Yamal LNG from 51% to 100%.

(2) Disposals in 2011 represent reserves attributable to the disposal of a 20% interest in Yamal LNG to TOTAL S.A.

(4) Acquisitions of current period represent reserves attributable to our acquisition of a 49% equity stake in our joint venture Nortgas completed in 2012.

Our total SEC proved reserves, as presented in the tables above, differ from the total net proved reserves as reported in the "Unaudited Supplemental Oil and Gas Disclosures" in the Group's IFRS consolidated financial statements, in that total net proved reserves as presented in the Group's IFRS consolidated financial statements include net proved reserves of natural gas and liquids attributable to non-controlling interest in our subsidiaries. A reconciliation between total proved reserves at 31 December 2012 under the SEC reserve classification as reflected in the "Unaudited Supplemental Oil and Gas Disclosures" in the Group's IFRS consolidated financial statements and total proved reserves in the tables above is set forth below:

	Natural gas		Crude oil, gas condensate and natural gas liquids
Under SEC classification	Billions of cubic feet	Billions of cubic meters	Millions of barrels	Millions of metric tons
Total proved reserves at 31 December 2012 presented in "Oil and Gas Reserves" above	62,087	1,758	896	106
Net proved reserves of natural gas and liquids attributable to non-controlling interest	128	4	17	2
Total net proved reserves per "Unaudited Supplemental Oil and Gas Disclosures"	62,215	1,762	913	108

The following table provides for our combined SEC and PRMS proved reserves on a total barrel of oil equivalent basis.

	Combined natural gas, crude oil, gas condensate and natural gas liquids in millions of barrels of oil equivalent
Based on our equity ownership interest in the fields	SEC	PRMS
Total proved reserves:
At 31 December 2010	8,088	9,325
At 31 December 2011	9,393	11,337
At 31 December 2012	12,394	15,597
including subsidiaries	7,623	8,866
including joint ventures	4,771	6,731

The PRMS reserve classification standards allows for the reporting of reserves estimates for probable and possible reserves as presented in the following table:

	Natural gas		Crude oil, gas condensate and natural gas liquids
Under PRMS classification (based on our equity ownership interest in the fields)	Billions of cubic feet	Billions of cubic meters	Millions of barrels	Millions of metric tons
Probable reserves:
At 31 December 2010	18,748	531	587	73
At 31 December 2011	18,471	523	652	81
At 31 December 2012	32,168	911	801	98
including subsidiaries	21,515	609	456	56
including joint ventures	10,653	302	345	42
Possible reserves:
At 31 December 2010	14,867	421	915	117
At 31 December 2011	17,187	487	1,000	127
At 31 December 2012	24,664	698	1,193	146
including subsidiaries	14,752	418	734	92
including joint ventures	9,912	280	459	54

The Group's PRMS proved reserves attributable to consolidated subsidiaries and joint ventures based on the Group's equity ownership interest in the respective fields aggregated approximately 2.2 trillion cubic meters ("tcm") of natural gas and 149 million tons of crude oil, gas condensate and natural gas liquids as of 31 December 2012. Combined, these proved reserves represent approximately 15.6 billion barrels of oil equivalent.

Our total PRMS proved reserves in barrels of oil equivalent basis attributable to consolidated subsidiaries and joint ventures based on the Group's equity ownership interest in their respective fields have increased by 37.6% during 2012. The increase was primarily due to the first-time appraisal of the reserves of the Salmanovskoye (Utrenneye) and Geofizicheskoye fields acquired in 2011, which also included exploration surveys performed on these fields in 2012, and the acquisition of a 49% equity stake in Nortgas. As we continue to invest capital into the development of our fields, we anticipate that we will increase our resource base as well as migrate reserves among the reserve categories.

The increase in the Group's PRMS probable and possible reserves during 2012 was also primarily due to the appraisal in 2012 of reserves attributable to the Salmanovskoye (Utrenneye) and Geofizicheskoye fields and the acquisition of a 49% equity stake in Nortgas (holder of the production license for the North-Urengoyskoye field).

The Group's reserves are all located in the Russian Federation, in the Yamal-Nenets Autonomous Region (Western Siberia), thereby representing one geographical area.

The below table contains information about reserve/production ratios for the years ended 31 December 2012 and 2011 under both reserves reporting methodologies based on our equity ownership interest in the fields attributable to consolidated subsidiaries and joint ventures:

	SEC		PRMS
	At 31 December:		At 31 December:
Number of years (based on our equity ownership interest in the fields)	2012	2011	2012	2011

Total proved reserves to production	31	25	39	30
Total proved and probable reserves to production	-	-	55	40
Total proved, probable and possible reserves to production	-	-	69	51

The increase in our reserve/production ratios was primarily due to an increase in our reserves estimates at 31 December 2012 as compared to 31 December 2011. The increase was mainly attributable to the reserves acquired as previously noted, which more than offset our increase in production.

The Group's oil and gas estimation and reporting process involves an annual independent third party appraisal as well as internal technical appraisals of reserves. The Group maintains its own internal reserve estimates that are calculated by qualified technical staff working directly with the oil and gas properties. The Group periodically updates reserves estimates during the year based on evaluations of new wells, performance reviews, new technical information and other studies.

The Group provides D&M annually with engineering, geological and geophysical data, actual production histories and other information necessary for reserve determinations. The method or combination of methods used in the analysis of each reservoir is tempered by experience with similar reservoirs, stages of development, quality and completeness of basic data, and production history. Our reserves estimates were prepared using standard geological and engineering methods generally accepted in the petroleum industry. The Group's and D&M's technical staffs meet to review and discuss the information provided, and upon completion of the process, senior management reviews and approves the final reserves estimates issued by D&M.

The Reserves Management and Assessment Group ("RMAG") is comprised of qualified technical staff from various departments – geological and geophysical, gas and liquids commercial operations, capital construction, production, financial planning and analysis and includes technical and financial representatives from the Group's subsidiaries, which are the principal holders of the mineral licenses. The person responsible for overseeing the work of the RMAG is a member of the Management Board.

The approval of the final reserve estimates is the sole responsibility of the Group's senior management.

OPERATIONAL HIGHLIGHTS

Oil and Gas Production Costs

Oil and gas production costs are derived from our results of operations for oil and gas producing activities as reported in the "Unaudited Supplemental Oil and Gas Disclosures" in our consolidated financial statements and relate to our consolidated subsidiaries. Oil and gas production costs do not include general corporate overheads or their associated tax effects. The following tables set forth certain operating information with respect to our oil and gas production costs during the years presented in millions of Russian roubles and on a boe basis in Russian roubles and US dollars:

		Year ended 31 December:
millions of Russian roubles	2012	2011	Change %
Production costs:
Lifting costs	6,505	5,347	21.7%
Taxes other than income tax	16,546	16,307	1.5%
Transportation expenses	57,888	46,216	25.3%

Total production costs before DDA	80,939	67,870	19.3%
Depreciation, depletion and amortization ("DDA")	10,589	8,937	18.5%
Total production costs	91,528	76,807	19.2%
	Year ended 31 December:		Change
RR per boe	2012	2011	%
Production costs:
Lifting costs	17.8	15.5	14.8%
Taxes other than income tax	45.3	47.2	(4.0%)
Transportation expenses	158.4	133.8	18.4%
Total production costs before DDA	221.5	196.5	12.7%
Depreciation, depletion and amortization	29.0	25.9	12.0%
Total production costs	250.5	222.4	12.6%
	Year ended 31 December:		Change
USD per boe (1)	2012	2011	%
Production costs:
Lifting costs	0.57	0.53	7.5%
Taxes other than income tax	1.46	1.61	(9.3%)
Transportation expenses	5.09	4.55	11.9%

Total production costs before DDA	7.12	6.69	6.4%
Depreciation, depletion and amortization	0.94	0.88	6.8%
Total production costs	8.06	7.57	6.5%

(1) Production costs in US dollars per boe were translated from Russian roubles per boe using the average exchange rate for the period (see "Selected macro-economic data" above).

Production costs represent the amounts directly related to the extraction of natural gas and liquids, gas condensate and crude oil from the reservoir and other related costs; including production expenses, taxes other than income tax (production taxes), insurance expenses and shipping, transportation and handling costs to endcustomers. The average production cost on a barrel of oil equivalent basis is calculated by dividing the applicable costs by the respective barrel of oil equivalent of our hydrocarbons produced during the year. Natural gas, gas condensate and crude oil volumes produced by our fields are converted to a barrel of oil equivalent based on the relative energy content of each fields' hydrocarbons.

Our lifting costs, as presented in the tables above, differ from lifting costs as reflected in the "Unaudited Supplemental Oil and Gas Disclosures" in the Group's IFRS consolidated financial statements, in that the lifting costs as presented in the Group's IFRS consolidated financial statements include changes in balances of natural gas and hydrocarbon liquids to more appropriately match costs incurred to revenues under the IFRS matching principles. A reconciliation of lifting costs as reflected in the "Unaudited Supplemental Oil and Gas Disclosures" in the Group's IFRS consolidated financial statements is set forth below:

	Year ended 31 December:		Change
millions of Russian roubles	2012	2011	%
Lifting costs presented in "Oil and Gas Production Costs" above	6,505	5,347	21.7%
Change in balances of natural gas and hydrocarbon liquids stated at cost in the Group's Consolidated Statement of Financial Position	1,094	56	n/a
Lifting costs per "Unaudited Supplemental Oil and Gas Disclosures"	7,599	5,403	40.6%

Hydrocarbon sales volumes

Our natural gas sales volumes increased primarily due to a combination of increased production at our core fields and purchases from our related party OAO SIBUR Holding ("SIBUR"), which were partially offset by an increase in natural gas inventory balances in 2012 as compared to a decrease in 2011. Liquids sales volumes increased due to the initiation of unstable gas condensate purchases from the Group's joint ventures, as well as the increase in crude oil production, which were partially offset by an increase in liquids inventory balances in 2012 as compared to a decrease in 2011. Our liquids inventory balances tend to fluctuate periodically due to loading schedules and final destinations of stable gas condensate shipments.

Natural gas sales volumes

	Year ended 31 December:	Change
millions of cubic meters	2012	2011	%
Production from (subsidiaries):
Yurkharovskoye field	34,054	32,035	6.3%
East-Tarkosalinskoye field	12,742	12,151	4.9%
Khancheyskoye field	3,647	3,263	11.8%
Other fields	64	72	(11.1%)
Total natural gas production	50,507	47,521	6.3%
Purchases from the Group's joint ventures	5,335	5,384	(0.9%)
Total production and purchases from Group's joint ventures	55,842	52,905	5.6%
Other purchases	3,533	841	320.1%
Total production and purchases	59,375	53,746	10.5%
Purovsky Plant, own usage and methanol production	(126)	(109)	15.6%
Decrease (increase) in UGSF, UGSS and own pipeline infrastructure	(369)	30	n/a
Total natural gas sales volumes	58,880	53,667	9.7%
Sold to end-customers	40,806	29,332	39.1%
Sold ex-field	18,074	24,335	(25.7%)

In 2012, our total natural gas production increased by 2,986 mmcm, or 6.3%, to 50,507 mmcm from 47,521 mmcm in 2011 primarily due to increases in production at our core producing fields (Yurkharovskoye, East-Tarkosalinskoye and Khancheyskoye). We were able to increase natural gas production at the Yurkharovskoye field resulting from the field's ongoing development activities and the launch of the fourth stage of the second phase development in October 2012 (see "Recent developments" above). The increase in natural gas production at the East-Tarkosalinskoye and Khancheyskoye fields in 2012 was due to increased demand resulting in a greater utilization of the field's production capacity.

In January 2012, we commenced purchasing natural gas from our related party, SIBUR, and purchased 3,533 mmcm during the year. In December 2011, we purchased 841 mmcm of natural gas from third parties in the Chelyabinsk region, the price of which included the cost of transportation to this region, through our subsidiary Gazprom mezhregiongas Chelyabinsk, a regional gas trader acquired in November 2011. The purchases were made according to pre-existing contractual obligations and, effective January 2012 we did not purchase natural gas under these agreements. Purchases from SIBUR in 2012 and from third parties in 2011 are disclosed as "Other purchases" in the table above.

In 2012, we used 75 mmcm of natural gas as feedstock for the production of methanol compared to 63 mmcm in 2011. A significant portion of the methanol we produce is used for our own internal purposes to prevent hydrate formation (condensation) during the production, preparation and transportation of hydrocarbons.

Liquids sales volumes

	Year ended 31 December:		Change
thousands of tons	2012	2011	%
Production from (subsidiaries):
Yurkharovskoye field	2,672	2,718	(1.7%)
East-Tarkosalinskoye field	984	808	21.8%
Khancheyskoye field	518	560	(7.5%)
Other fields	19	25	(24.0%)
Total liquids production	4,193	4,111	2.0%
Purchases from:
The Group's joint ventures	259	-	n/a
Other	38	6	n/m
Total production and purchases	4,490	4,117	9.1%
Losses and own usage (1)	(49)	(37)	32.4%
Decreases (increases) in liquids inventory balances	(238)	31	n/a
Total liquids sales volumes	4,203	4,111	2.2%
Stable gas condensate export	2,821	2,981	(5.4%)
Stable gas condensate domestic	26	3	n/m
Subtotal stable gas condensate	2,847	2,984	(4.6%)
LPG export	479	453	5.7%
LPG CIS	-	1	n/a
LPG domestic	323	336	(3.9%)
LPG sold through domestic retail and small wholesale stations	103	90	14.4%
Subtotal LPG	905	880	2.8%
Crude oil export	149	93	60.2%
Crude oil domestic	293	149	96.6%
Subtotal crude oil	442	242	82.6%
Oil products domestic	9	5	80.0%
Subtotal oil products	9	5	80.0%

(1) Losses associated with processing at the Purovsky Plant, as well as during railroad, trunk pipeline and tanker transportation.

In 2012, our liquids production increased by 82 thousand tons, or 2.0%, primarily due to an increase in crude oil production at the East-Tarkosalinskoye field that was partially offset by a decrease in gas condensate production at our core producing fields. Natural declines in the concentration of gas condensate at our mature fields are expected due to decreasing reservoir pressure at the current gas condensate producing horizons.

Starting from 1 November 2012, we commenced purchasing of unstable gas condensate from Nortgas, which became our joint venture from the end of November 2012. Purchases from Nortgas in November 2012 are disclosed as "Other purchases" and purchases in December 2012 are disclosed as "Purchases from the Group's joint ventures" in the table above.

In April 2012, we commenced purchasing unstable gas condensate from our joint venture, SeverEnergia, after the launch of the first phase of Samburgskoye field's development activities.

RESULTS OF OPERATIONS FOR THE YEAR ENDED 31 DECEMBER 2012 COMPARED TO THE YEAR ENDED 31 DECEMBER 2011

The following table and discussion is a summary of our consolidated results of operations for the years ended 31 December 2012 and 2011. Each line item is also shown as a percentage of our total revenues.

	Year ended 31 December:
		% of total		% of total
millions of Russian roubles	2012	revenues	2011	revenues
Total revenues (net of VAT, export duties,
excise and fuel taxes)	210,973	100.0%	175,273	100.0%
including:
natural gas sales	142,613	67.6%	110,932	63.3%
liquids' sales	67,633	32.1%	63,879	36.4%
Operating expenses	(125,775)	(59.6%)	(96,820)	(55.2%)
Net gain (loss) on disposal of interest in
subsidiaries	(60)	(0.1%)	62,948	35.9%
Other operating income (loss)	196	0.1%	207	0.1%
Profit from operations	85,334	40.4%	141,608	80.8%
Finance income (expense)	2,986	1.5%	(2,703)	(1.6%)
Share of profit (loss) of joint ventures,
net of income tax	(2,105)	(1.0%)	(3,880)	(2.2%)
Profit before income tax	86,215	40.9%	135,025	77.0%
Total income tax expense	(16,774)	(8.0%)	(15,734)	(8.9%)
Profit (loss)	69,441	32.9%	119,291	68.1%

Non-controlling interest	17	0.0%	364	0.2%
Profit attributable to
shareholders of OAO NOVATEK	69,458	32.9%	119,655	68.3%
Normalized profit attributable to
shareholders of OAO NOVATEK	69,518	33.0%	56,707	32.4%

Total revenues

The following table sets forth our sales (net of VAT, export duties, excise and fuel taxes expense, where applicable) for the years ended 31 December 2012 and 2011:

	Year ended 31 December:		Change
millions of Russian roubles	2012	2011	%
Natural gas sales	142,613	110,932	28.6%
End-customers	115,180	77,046	49.5%
Ex-field sales	27,433	33,886	(19.0%)
Stable gas condensate sales	46,684	46,778	(0.2%)
Export	46,365	46,732	(0.8%)
Domestic	319	46	593.5%
Liquefied petroleum gas sales	15,599	14,436	8.1%
Export	9,631	8,698	10.7%
CIS	-	10	n/a
Domestic	5,968	5,728	4.2%
Crude oil sales	5,000	2,479	101.7%
Export	1,785	1,021	74.8%
Domestic	3,215	1,458	120.5%
Oil and gas products sales	350	186	88.2%
Domestic	350	186	88.2%
Total oil and gas sales	210,246	174,811	20.3%
Other revenues	727	462	57.4%
Total revenues	210,973	175,273	20.4%

Natural gas sales

In 2012, our revenues from sales of natural gas increased by RR 31,681 million, or 28.6%, compared to 2011 due primarily to an increase in our average realized natural gas price and, to a lesser extent, due to an increase in our total sales volumes. The increase in our average realized natural gas price was driven by a combination of increases in the regulated FTS price tariff for natural gas by 15% effective from 1 July 2012 and in our proportion of end-customer sales to total natural gas sales volumes.

Our proportion of natural gas sold to end-customers to total natural gas sales volumes increased to 69.3% in 2012 as compared to 54.7% in 2011. The increase was due to higher natural gas deliveries to the Chelyabinsk region through our regional natural gas trader acquired in November 2011.

In 2012, our average netback price on end-customers sales, excluding volumes purchased for resale in the location of our end-customers, increased by 11.9% as compared to 2011, while our average realized endcustomers sales price increased by 7.4%. The increase in our average realized end-customers sales netback price was primarily due to a 15% increase in the regulated FTS price for natural gas effective from 1 July 2012 combined with a 7% increase in the average transportation tariff set by the FTS effective from 1 July 2012 (see "Transportation tariffs" above). Our average realized ex-field price was higher by 9.1% than in 2011.

Stable gas condensate sales

In 2012, our revenues from sales of stable gas condensate decreased by RR 94 million, or 0.2%, compared to 2011 primarily due to a decrease in volumes sold, that was partially offset by an increase in our average realized prices in Russian roubles.

Our total stable gas condensate sales volumes decreased by 137 thousand tons, or 4.6%, due to a combination of an increase in the stable gas condensate inventory balance in 2012 as compared to a decrease in 2011 (see "Change in natural gas, liquid hydrocarbons and work-in-progress" below) and a decrease in gas condensate production at our core fields, that was partially offset by unstable gas condensate purchases from our joint ventures in 2012. During 2012, we exported 2,821 thousand tons of stable gas condensate, or 99.1% of our total sales volumes, to the APR, Europe, the United States and South America with the remaining 26 thousand tons sold domestically. In 2011, we exported 2,981 thousand tons of stable gas condensate, or 99.9% of our total sales volumes, to the APR, Europe and the United States, with the remaining three thousand tons sold domestically.

In 2012, our average realized net export price for stable gas condensate, excluding export duties and translated to US dollars from Russian roubles using the average annual exchange rate, decreased by USD 4.9 per ton, or 0.9%, to USD 528.5 per ton (CFR, DES, DAP and CIF) from USD 533.4 per ton (CFR, DES, DAP, CIF and DAT) in 2011 due to an increase in average annual exchange rate of Russian rouble against the US dollar approximately by 5.8% in 2012 as compared to 2011, that was partially offset by a 0.4% decrease in our average export duty per ton and an 0.2% increase in our average export contract price in US dollars.

Liquefied petroleum gas sales

In 2012, our revenues from sales of LPG increased by RR 1,163 million, or 8.1%, compared to 2011 due to both increases in our average realized prices and volumes sold.

In 2012, we sold 479 thousand tons of LPG, or 52.9% of our total LPG sales volumes, to export markets as compared to 453 thousand tons, or 51.5%, in 2011. In 2012, as well as in 2011, our export sales volumes of LPG representing greater than 10% of total LPG export volumes were to customers located in Poland and Finland.

Our average realized LPG net export price, excluding export duties, excise and fuel taxes expense and translated to US dollars from Russian roubles using the average annual exchange rate, decreased by USD 6.5 per ton, or 1.0%, to USD 646.8 per ton in 2012 (DAP, CPT and FCA) compared to USD 653.3 per ton in 2011 (DAP, CPT and FCA) primarily due to an increase in the average annual exchange rate of Russian rouble against the US dollar, that was partially offset by a decrease in our average export duty per ton by 3.5%. The reduction in our average contract price by 1.4% was due to a decrease in the underlying benchmark prices on international markets used in the price formulation in 2012 compared to 2011.

In 2012, we sold 426 thousand tons of LPG, or 47.1% of our total LPG sales volumes, on the domestic market at an average price of RR 14,011 per ton (excluding VAT) representing an increase of RR 553 per ton, or 4.1%, compared to 2011.

Crude oil sales

In 2012, our revenues from sales of crude oil increased by RR 2,521 million, or 101.7%, compared to 2011 primarily due to an increase in sales volumes and, to a lesser extent, an increase in our average realized prices. Our crude oil sales volumes increased by 200 thousand tons, or 82.6%, to 442 thousand tons from 242 thousand tons in 2011 due primarily to an increase in crude oil production at our East-Tarkosalinskoye field.

The majority of our crude oil sales volumes, accounting for 66.3% in 2012, were sold domestically at an average price of RR 10,985 per ton (excluding VAT) representing an increase of RR 1,193 per ton, or 12.2%, compared to 2011. The remaining 33.7% of our crude oil volumes were sold to export markets at an average price of USD 383.9 per ton (DAP, excluding export duties) representing an increase of USD 10.2 per ton, or 2.7%, compared to 2011. The increase in the average realized net export price (excluding export duties and translated to US dollars from Russian roubles using the average annual exchange rate) was due to an increase in average annual exchange rate of Russian rouble against the US dollar approximately by 5.8% and a 1.7% decrease in our average export duty per ton.

Oil and gas products sales

Oil and gas products sales include trading operations with oil products on the domestic market through our retail stations and methanol sales to third parties. In 2012, our revenue from sales of oil and gas products increased by RR 164 million, or 88.2%, to RR 350 million from RR 186 million in 2011.

Our revenues from oil products trading operations through our retail stations on the domestic market increased by RR 103 million, or 70.1%, to RR 250 million in 2012 compared to RR 147 million in 2011 primarily due to an increase in volumes sold. In 2012, we sold approximately nine thousand tons of oil products (diesel fuel and petrol) for an average price of RR 29,054 per ton, compared to sales of approximately five thousand tons for an average price of RR 27,232 per ton in 2011.

In 2012, our revenue from methanol sales increased by RR 61 million, or 156.4%, to RR 100 million from RR 39 million in 2011 primarily due to an increase in volumes sold.

Other revenues

Other revenues include geological and geophysical research services, rent, sublease, transportation, handling, storage and other services. In 2012, other revenues increased by RR 265 million, or 57.4%, to RR 727 million from RR 462 million in 2011. The increase was primarily comprised of a RR 162 million increase in revenue from transportation, handling and storage services, as well as a RR 99 million increase in revenues from geological and geophysical research services provided primarily to our joint ventures. In addition, in 2012, we recognized RR 69 million of revenue by re-charging a part of icebreaking expenses to the third parties as compared to RR 131 million of revenue for the sublet of a leased tanker in 2011. The remaining increase of RR 66 million in other revenues was made up of various immaterial items.

Operating expenses

In 2012, our total operating expenses increased by RR 28,955 million, or 29.9%, to RR 125,775 million compared to RR 96,820 million in 2011 primarily due to an increase in transportation expenses and purchases of natural gas and liquid hydrocarbons. As a percentage of total operating expenses, our non-controllable expenses, such as transportation and taxes other than income tax, decreased to 61.8% in 2012 compared to 67.0% in 2011 primarily due to a significant increase in purchases of natural gas from our related party, SIBUR, and purchases of unstable gas condensate from our joint ventures in 2012 (see "Purchases of natural gas and liquid hydrocarbons" below).

In 2012, total operating expenses as a percentage of total revenues increased to 59.6% in 2012 compared to 55.2% in 2011, as shown in the table below. The increase in our operating expenses as a percentage of total revenues was caused by two main reasons. In January 2012, we commenced purchasing natural gas, which included the cost of transportation, for subsequent resale to the regions where our end-customers are located, and there was an increase in the UPT rate for natural gas effective 1 January 2012, while the regulated price for natural gas was increased effective 1 July 2012.

	Year ended 31 December:
millions of Russian roubles	2012	% of total revenues	2011	% of total revenues
Transportation expenses	60,848	28.8%	48,329	27.6%
Taxes other than income tax	16,846	8.0%	16,559	9.4%
Subtotal non-controllable expenses	77,694	36.8%	64,888	37.0%
Purchases of natural gas and liquid hydrocarbons	17,483	8.3%	5,994	3.4%
Depreciation, depletion and amortization	11,185	5.3%	9,277	5.3%
General and administrative expenses	10,936	5.2%	8,218	4.7%
Materials, services and other	7,216	3.4%	5,947	3.4%
Exploration expenses	2,022	1.0%	1,819	1.0%
Net impairment expenses	325	n/m	782	n/m
Change in natural gas, liquid hydrocarbons
and work-in-progress	(1,086)	n/m	(105)	n/m
Total operating expenses	125,775	59.6%	96,820	55.2%

Non-controllable expenses

A significant proportion of our operating expenses are characterized as non-controllable expenses since we are unable to influence the increase in regulated tariffs for transportation of our hydrocarbons or the rates imposed by federal, regional or local tax authorities. In 2012, non-controllable expenses of transportation and taxes other than income tax increased by RR 12,806 million, or 19.7%, to RR 77,694 million from RR 64,888 million in 2011. The change in transportation expenses was primarily due to an increase in the natural gas volumes sold to end-customers in which we incurred transportation expenses, and excluded volumes of natural gas purchased for resale in the location of our end-customers. Taxes other than income tax increased primarily due to an increase in natural gas production volumes, as well as a 5.9% increase in the natural gas production tax rate effective from 1 January 2012 that was partially offset by the application of a zero UPT rate for crude oil from 1 January 2012 (see "Our tax burden" above). As a percentage of total revenues, our non-controllable expenses marginally decreased to 36.8% in 2012 compared to 37.0% in 2011.

Transportation expenses

In 2012, our total transportation expenses increased by RR 12,519 million, or 25.9%, compared to 2011.

	Year ended 31 December:
million of Russian roubles	2012	2011	Change %
Natural gas transportation to customers	45,925	34,441	33.3%
Liquid hydrocarbons transportation by rail	10,537	9,791	7.6%
Liquid hydrocarbons transportation by tankers	3,742	3,647	2.6%
Crude oil transportation to customers	527	281	87.5%
Other	117	169	(30.8%)
Total transportation expenses	60,848	48,329	25.9%

In 2012, our transportation expenses for natural gas increased by RR 11,484 million, or 33.3%, to RR 45,925 million from RR 34,441 million in 2011. The change was mainly due to a 30.8% increase in our natural gas sales volumes to end-customers, for which we incurred transportation expense, and excluding volumes of natural gas purchased for resale in the location of our end-customers, as well as a 7% average increase in the natural gas transportation tariff set by the FTS effective 1 July 2012 (see "Transportation tariffs" above). We do not incur transportation expenses in respect of natural gas volumes purchased for resale in the location of our end-customers, as the purchase price includes the cost of transportation. Our average transportation distance for natural gas sold to end-customers fluctuates period-to-period and depends on the location of end-customers and the specific routes of transportation.

In 2012, our total expenses for liquids transportation by rail increased by RR 746 million, or 7.6%, to RR 10,537 million from RR 9,791 million in 2011 due to higher average liquids transportation tariffs that was partially offset by a decrease in our stable gas condensate volumes sold and transported via rail. In 2012, our combined liquids volumes sold and transported via rail decreased by 115 thousand tons, or 3.0%, to 3,749 thousand tons from 3,864 thousand tons in 2011 due primarily to an increase in stable gas condensate inventory balance during 2012 compared to a decrease in 2011. The transportation costs incurred in respect of liquids volumes recognized as part of our inventory balance or in transit are capitalized in current assets as future period expenses until the recognition of such volumes as sold.

In 2012, our weighted average transportation tariff for liquids delivered by rail increased by 11.0% to RR 2,811 per ton from RR 2,533 per ton in 2011 primarily due to a 6.0% increase in rail tariffs for the domestic market set by the FTS effective 1 January 2012, an increase in rail tariffs for LPG transportation on the territory of CIS to export markets and a decrease in stable gas condensate share in total liquids volumes sold and transported via rail. The change in the share of stable gas condensate volumes in our total liquids volumes delivered by rail affects our weighted average rail tariff due to the relatively low transportation expense for stable gas condensate compared to other liquids. Our weighted average transportation tariff for liquids delivered by rail fluctuates period-to-period and depends on products type and the geography of deliveries.

Total transportation expense for liquids delivered by tankers to international markets increased by RR 95 million, or 2.6%, to RR 3,742 million in 2012 from RR 3,647 million in 2011. The increase was due to a change in the mix in geographical regions where we sold our stable gas condensate that was partially offset by a 5.4% decrease in volumes sold as a result of inventory movements and a decrease in unstable gas condensate production. In 2012, we sold 56.4% of our total stable gas condensate export volumes to APR, 28.7% to Europe, 10.6% to the United States and 4.3% to the South America, whereas in 2011, we sold 43.4% to APR, 34.3% to Europe and 22.3% to the United States.

Taxes other than income tax

millions of Russian roubles	Year ended 31 December:	Change
	2012	2011	%
Unified natural resources production tax	14,833	14,523	2.1%
Property tax	1,754	1,742	0.7%
Other taxes	259	294	(11.9%)
Total taxes other than income tax	16,846	16,559	1.7%

In 2012, taxes other than income tax increased by RR 287 million, or 1.7%, primarily due to an increase in the unified natural resources production tax expense.

In 2012, our UPT expense for natural gas increased by RR 1,446 million, or 12.8%, due to both a 5.9% increase in the natural gas production tax rate effective from 1 January 2012 (from RR 237 per mcm to RR 251 per mcm) and a 6.3% increase in our natural gas production volumes. In addition, our UPT for unstable gas condensate production increased by RR 119 million, or 6.2%, due primarily to a change in the UPT rate (see "Our tax burden" above).

In 2012, we applied a zero UPT rate for crude oil produced at our East-Tarkosalinskoye and Khancheyskoye fields due to changes in the Russian Tax Code effective from 1 January 2012 (see "Our tax burden" above). In 2011, we incurred RR 1,255 million of UPT expense for crude oil produced.

Purchases of natural gas and liquid hydrocarbons

	Year ended 31 December:		Change
millions of Russian roubles	2012	2011	%
Natural gas	14,706	5,854	151.2%
Unstable gas condensate	2,498	-	n/a
Other liquid hydrocarbons	279	140	99.3%
Total purchases of natural gas and liquids hydrocarbons	17,483	5,994	191.7%

In 2012, our purchases of natural gas and liquid hydrocarbons increased by RR 11,489 million, or 191.7%, to RR 17,483 million from RR 5,994 million in 2011. The increase of RR 8,852 million, or 151.2%, was related to purchases of natural gas, of which the major part related to purchases of natural gas from SIBUR, a related party, commencing from 1 January 2012.

During 2012, we commenced purchasing unstable gas condensate from our joint ventures SeverEnergia and Nortgas, which accounted for RR 2,498 million of total purchases in 2012. We had no purchases of unstable gas condensate in 2011.

In 2012, our purchases of other liquid hydrocarbons increased by RR 139 million, or 99.3%, to RR 279 million from RR 140 million in 2011 due to the expansion of trading activities at our wholly owned subsidiary NOVATEK-AZK. Other liquid hydrocarbons purchases represent our purchases of oil products (diesel fuel and petrol) and LPG.

Depreciation, depletion and amortization

In 2012, our depreciation, depletion and amortization ("DDA") expense increased by RR 1,908 million, or 20.6%, to RR 11,185 million from RR 9,277 million in 2011 as a result of an increase in our depletable cost base, as well as a 5.8% increase in our total hydrocarbon production (excluding our proportionate share in the production of joint ventures) in barrels of oil equivalent basis. The Group accrues depreciation and depletion using the "units of production" method for producing assets and straight-line method for other facilities.

In 2012, our DDA per barrel of oil equivalent was RR 26.4 compared to RR 23.1 in 2011. The increase in our DDA charge calculated on a barrel of oil equivalent basis was due to the capitalization of costs related to the launch of the fourth stage of the second phase development at our Yurkharovskoye field and ongoing crude oil development activities at the East-Tarkosalinskoye field, as well as a decrease in our proved reserves estimates as of 31 December 2012 compared to 31 December 2011, used as the denominator in the calculation of the DDA under the "units of production" method, at our core producing fields.

Our reserve base, used as the denominator in the calculation of the DDA charge under the "units of production" method, is only appraised on an annual basis as of 31 December and does not fluctuate during the year, whereas our depletable cost base does change each quarter due to the ongoing capitalization of our costs throughout the year.

General and administrative expenses

In 2012, our general and administrative expenses increased by RR 2,718 million, or 33.1%, to RR 10,936 million compared to RR 8,218 million in 2011. The main components of these expenses were employee compensation, legal, audit, and consulting services and social expenses and compensatory payments, which, on aggregate, comprised 83.6% and 80.7% of total general and administrative expenses in the years ended 31 December 2012 and 2011, respectively.

	Year ended 31 December:	Change
millions of Russian roubles	2012	2011	%
Employee compensation	6,869	4,650	47.7%
Legal, audit, and consulting services	1,274	774	64.6%
Social expenses and compensatory payments	1,001	1,212	(17.4%)
Depreciation – administrative buildings	314	198	58.6%
Business trip expenses	292	218	33.9%
Fire safety and security expenses	199	178	11.8%
Repair and maintenance expenses	168	115	46.1%
Rent expense	113	140	(19.3%)
Insurance expense	86	58	48.3%
Bank charges	82	58	41.4%
Other	538	617	(12.8%)
Total general and administrative expenses	10,936	8,218	33.1%

Employee compensation increased by RR 2,219 million, or 47.7%, to RR 6,869 million in 2012 as compared to RR 4,650 million in 2011. The increase was primarily due to an indexation of base salaries by 6.0% effective 1 July 2012, increases in the average number of employees, insurance contributions to the non-budget funds, as well as an increase in bonuses accrued to key management for the results achieved in 2012. The increase in average number of employees resulted from the acquisition of a regional gas trader in November 2011 and the expansion of activities at our Ust-Luga project. Our insurance contributions to the non-budget funds increased in 2012 compared to 2011 due to the change of insurance contributions to the Pension Fund of the Russian Federation effective from 1 January 2012 (see "Our tax burden" above). In addition, our expenses related to defined benefit pension plan increased by RR 401 million in 2012 compared to 2011 primarily due to an indexation of future payments, an increase in number of retirement age employees and the recognition in 2012 of additional lump sum retirement benefits. The aforementioned increases were partially offset by a decrease of RR 114 million in the recognition of charges related to NOVATEK's share-based compensation program for the Group's senior and key management.

Legal, audit, and consulting services expenses increased by RR 500 million, or 64.6%, to RR 1,274 million compared to RR 774 million in 2011 largely due to consulting services related to our recent acquisitions, as well as an increase in services to prolong and acquire software solutions for our core subsidiaries.

In 2012, our social expenses and compensatory payments decreased by RR 211 million, or 17.4%, to RR 1,001 million compared to RR 1,212 million in 2011 primarily due to the fact, that we did not consolidate compensatory payments of Yamal LNG in 2012 as a result of a disposal of a 20% interest in Yamal LNG in October 2011 and the consolidation of the company under the equity method starting from that date. Social expenses and compensatory payments in 2012 were primarily related to our donations to sport clubs and activities, educational schools, as well as continued support for charities and social programs in the regions where we operate. Social expenses and compensatory payments fluctuate period-on-period depending on the funding needs and the implementation schedules of specific programs we support in the regions where we operate.

In 2012, depreciation of administrative buildings increased by RR 116 million, or 58.6%, primarily due to the completion and opening of our new Moscow head-office in May 2011. Fixed assets of administrative nature are depreciated on a straight-line basis over their estimated useful lives.

Fire safety and security expenses increased by RR 21 million, or 11.8%, to RR 199 million in 2012 from RR 178 million in 2011 as a result of the opening of our new Moscow head-office in May 2011, as well as an increase in rates charged for security services.

Repair and maintenance expenses increased by RR 53 million, or 46.1%, to RR 168 million in 2012 from RR 115 million in 2011 primarily due to start of maintenance and repair works of administrative fixed assets rented by our subsidiaries, OOO NOVATEK-Chelyabinsk and NOVATEK-Ust-Luga.

In 2012, our rent expense decreased by RR 27 million, or 19.3%, to RR 113 million from RR 140 million in 2011 primarily due to the relocation of Moscow head-office employees to our new office building in May 2011. The decrease was partially offset by the consolidation of the regional gas trader acquired in November 2011, which rents an office space for its employees and additional office space rented by NOVATEK-Ust-Luga since May 2012.

Insurance expenses increased by RR 28 million, or 48.3%, to RR 86 million in 2012 from RR 58 million in 2011 due to insuring of recently launched fixed assets at our production subsidiaries.

Bank charges increased by RR 24 million, or 41.4%, to RR 82 million in 2012 from RR 58 million in 2011 primarily due to service charges applied to letters of credit, as well as commission services fees charged by banks for the acceptance of payments from residential customers of natural gas at our recently acquired subsidiaries, supplying natural gas in the regional markets.

In 2012, other general and administrative expenses decreased by RR 79 million, or 12.8%, to RR 538 million from RR 617 million in 2011 primarily due to a RR 63 million decrease in expenses related to the termination at the end of 2011 of the concession agreement at El-Arish concession area located in Egypt, which was partially offset by the RR 27 million increase in expenses related to our participation in international economic, geological and oil and gas forums and exhibitions, and RR 19 million increase in expenses related to the advertising. The remaining decrease of RR 62 million was made up of other immaterial expense items of an administrative nature.

Materials, services and other

In 2012, our materials, services and other expenses increased by RR 1,269 million, or 21.3%, to RR 7,216 million compared to RR 5,947 million in 2011. The main components of this expense category were employee compensation and repair and maintenance services, which on aggregate comprised 74.9% and 73.8% of total materials, services and other expenses in 2012 and 2011, respectively.

	Year ended 31 December:	Change
millions of Russian roubles	2012	2011	%
Employee compensation	3,808	2,953	29.0%
Repair and maintenance services	1,598	1,435	11.4%
Electricity and fuel	457	405	12.8%
Materials and supplies	412	309	33.3%
Security expenses	271	237	14.3%
Transportation expenses	186	184	1.1%
Processing fees	99	99	0.0%
Other	385	325	18.5%
Total materials, services and other	7,216	5,947	21.3%

Our employee compensation increased by RR 855 million, or 29.0%, to RR 3,808 million compared to RR 2,953 million in 2011. The increase was primarily due to a 6.0% indexation of base salaries effective from 1 July 2012 and an increase in the average number of employees. The increase in the average number of employees was the result of the acquisition of a regional gas trader Gazprom mezhregiongas Chelyabinsk in November 2011 and an expansion of our trading activities at NOVATEK-AZK. In addition, in 2012 our expenses related to defined benefit pension plan increased by RR 232 million as compared to 2011 primarily due to changes in actuarial assumptions, as well as recognition of additional lump sum retirement benefit in 2012.

Repair and maintenance services increased by RR 163 million, or 11.4%, to RR 1,598 million in 2012 compared to RR 1,435 million in 2011. The increase was primarily related to on-going repair works at our wholly owned subsidiaries OOO NOVATEK-Tarkosaleneftegas and the OOO NOVATEK-Purovsky ZPK and was consistent with our ongoing maintenance schedules.

In 2012, electricity and fuel expenses increased by RR 52 million, or 12.8%, to RR 457 million from RR 405 million in 2011. The increase was primarily due to an increase in electricity and fuel volumes used by our production subsidiaries resulting from recently completed infrastructure projects, as well as higher electricity rates in 2012 as compared to 2011.

Materials and supplies expense increased by RR 103 million, or 33.3%, to RR 412 million in 2012 from RR 309 million in 2011 mainly due to an increase in materials used for repair works of our production assets and own rail cars used for transportation of LPG.

Security expenses increased by RR 34 million, or 14.3%, to RR 271 million in 2012 from RR 237 million in 2011 largely due to additional security services related to recently completed infrastructure projects at our production subsidiaries and an increase in security services rates effective from January 2012.

Transportation expenses related to the delivery of materials and equipment to our fields marginally increased by RR two million, or 1.1%, to RR 186 million in 2012 from RR 184 million in 2011.

In 2012, other material, services and other expenses increased by RR 60 million, or 18.5%, to RR 385 million from RR 325 million in 2011 primarily due to increases in ecological and feasibility studies services provided to our production subsidiaries.

Exploration expenses

In 2012, we incurred RR 2,022 million of exploration expenses of which RR 851 million was related to the capitalized cost of two exploratory wells at the West-Urengoyskoye and North-Yubileynoye license areas, written-off in accordance with our successful efforts accounting policy. In addition, we also recognized RR 428 million as exploration expense related to 3-D seismic activities, which were not classified as development costs in accordance with our accounting policy.

In 2011, we incurred RR 1,819 million of exploration expenses of which RR 740 million related to the capitalized cost of three exploratory wells at the Raduzhniy and Yarudeiskiy licence areas, written-off in accordance with our successful efforts accounting policy.

Net impairment expense

In 2012, we recognized net impairment expense of RR 325 million, of which the significant portion was related to the impairment of trade accounts receivable for natural gas sold to small industrial companies and residential customers.

In 2011, we recognized net impairment expense of RR 782 million, of which RR 548 million was related to the write-off of assets at the Middle-Chaselskiy license area and RR 120 million to the impairment of our investments at the El-Arish project.

Change in natural gas, liquid hydrocarbons and work-in-progress

In 2012, we recorded a reversal of RR 1,086 million to change in inventory expense as compared to a reversal of RR 105 million in 2011:

	Year ended 31 December:
millions of Russian roubles	2012	2011
Natural gas Stable gas condensate Other	(228) (897) 39	(112) 91 (84)
Increase (decrease) in operating expenses due to
change in inventory balances and work-in-progress	(1,086)	(105)

In 2012, we recorded a reversal to our operating expenses of RR 228 million primarily due to a 369 mmcm increase in our natural gas inventory balance. Our volumes of natural gas injected into Gazprom's underground gas storage facilities fluctuate period-to-period depending on market conditions, storage capacity constraints and our development plans to sustain and/or grow production during periods of seasonality.

In addition, in 2012, we recorded a reversal of RR 897 million to our operating expenses due to a 233 thousand tons increase in our inventory balance of stable gas condensate in transit and storage and an increase in the cost of stable gas condensate per ton.

The following table highlights movements in our inventory balances:

		2012			2011
Inventory balances in	At	At	Increase /	At	At	Increase /
transit or in storage	31 December	1 January	(decrease)	31 December	1 January	(decrease)
Natural gas (millions of cubic meters)	1,129	760	369	760	790	(30)
including Gazprom's UGSF	1,096	732	364	732	761	(29)
Liquid hydrocarbons (thousand tons)	563	325	238	325	356	(31)
including stable gas condensate	461	228	233	228	264	(36)

Net gain (loss) on disposal of interest in subsidiaries

In 2012, we recognized a net loss of RR 60 million on the disposal of the Groups' wholly owned, non-core subsidiary OOO Purovsky Terminal in December 2012.

In 2011, we realized a net gain of RR 62,948 million on the disposal of a 20% equity interest in OAO Yamal LNG to TOTAL S.A., our strategic partner in the Yamal LNG project. The net gain is comprised of a net gain on disposal of RR 28,685 million and a gain of RR 34,263 million due to the revaluation to fair value of our remaining 80% equity interest.

Other operating income (loss)

In 2012, we recognized other operating income of RR 196 million. In October 2012, we commenced trading operations for the purchase and sale of natural gas on the European market. As a result, in the fourth quarter of 2012, we purchased and sold approximately 4.7 terawatt-hours of natural gas. The total effect from natural gas trading operations on the European market and from the changes in fair values of long-term contracts, which were classified as derivative instruments in accordance with IAS 39 "Financial instruments: recognition and measurement", in 2012 resulted in the recognition of net income in the amount of RR 76 million.

The remaining other operating income of RR 120 million was primarily related to penalties charges received from our suppliers due to non-compliance of their contractual obligations and other immaterial profit and loss items.

In 2011, we recognized other operating income of RR 207 million of which RR 192 million related to insurance compensation received in respect of an insured accident in 2010.

Profit from operations

As a result of the factors discussed above, our profit from operations decreased by RR 56,274 million, or 39.7%, to RR 85,334 million in 2012, compared to RR 141,608 million in 2011. Our profit from operations, adjusted for non-recurring transactions, primarily excluding the net gain (loss) on disposal of interest in subsidiaries, increased by RR 6,734 million, or 8.6%, to RR 85,394 million in 2012 from RR 78,660 million in 2011. In 2012, our profit from operations, excluding the net gain (loss) on disposal of interest in subsidiaries, as a percentage of total revenues decreased to 40.5% compared to 44.9% in 2011 primarily due to the commencement in January 2012 of natural gas purchases for resale in the regions where our end-customers are located and the lower trading margins we received for these volumes.

In addition, our operating expenses exceeded the growth rate of our total revenues during the year due primarily to the UPT rate for natural gas, which was increased effective from 1 January 2012, while the regulated price for natural gas was increased effective from 1 July 2012.

Finance income (expense)

In 2012, we recorded net finance income of RR 2,986 million as compared to a net finance expense of RR 2,703 million in 2011 due primarily to the appreciation of the Russian rouble relative to the US dollar in 2012 compared to the depreciation of the Russian rouble relative to the US dollar in 2011.

In 2012, our total accrued interest expense on loans amounted to RR 5,702 million compared to RR 5,422 million in 2011. In 2012 and 2011, we capitalized RR 2,698 and RR 3,709 million, respectively, of interest expense to the cost of our property, plant and equipment construction account in accordance with the Group's accounting policy. In addition, we recognized as part of interest expense RR 232 million and RR 225 million related to the unwinding of the present value discount related to provisions of asset retirement obligations in 2012 and 2011, respectively, and RR 212 million related to the effect of discounting of long-term financial liabilities in 2011.

Interest income decreased by RR 1,661 million, or 49.0%, to RR 1,731 million in 2012 from RR 3,392 million in 2011 due to a decrease in loans provided to our joint ventures. In February 2012, the loan as well as the accrued interest on this loan provided to our joint venture OOO Yamal Development was converted to charter capital.

In 2012, we recorded a net foreign exchange gain of RR 4,491 million compared to a net foreign exchange loss of RR 3,945 million in 2011 due primarily to the revaluation of our US dollar denominated borrowings. The Russian rouble appreciated by 5.7% against the US dollar during 2012 compared to the depreciation of the Russian rouble by 5.6% in 2011. We will continue to record foreign exchange gains and losses each period based on the movements between exchange rates and the currency denomination of our debt portfolio.

Share of profit (loss) of joint ventures, net of income tax

In 2012, our proportionate share of loss of joint ventures decreased to RR 2,105 million compared to a loss of RR 3,880 million in 2011.

In 2012, our proportionate share of loss relating to our joint venture Yamal Development decreased by RR 1,643 million due to the conversion of loans received by the company to charter capital in February 2012, which resulted in a decrease in interest expense.

In 2012, our proportionate share of loss relating to our joint venture Sibneftegas decreased by RR 1,544 million due to increases in natural gas sales prices effective from 1 January and 1 July 2012. The losses we recognized in Sibneftegas were primarily due to the revaluation of oil and gas properties acquired to fair value and the subsequent amortization of those costs under IFRS.

In 2012, we recognized our share of the losses in our joint venture Yamal LNG amounting to RR 1,811 million as compared to a loss of RR 707 million in 2011 due primarily to an increase in compensatory payments related to the Yamal LNG project.

Income tax expense

Our overall consolidated effective income tax rates (total income tax expense calculated as a percentage of our reported IFRS profit before income tax) were 19.5% and 11.7% for the years ended 31 December 2012 and 2011, respectively.

After excluding the effect of 20% disposal of Yamal LNG, the Group's effective income tax rate for the year ended 31 December 2011 was 21.7%. The decrease in the effective income tax rate in 2012 as compared to 2011 was due to the application of a reduced income tax rate of 15.5% in respect of the Group's priority investment project in YNAO.

The Russian statutory income tax rate for both periods was 20%. The difference between our effective and statutory income tax rates is primarily due to certain non-deductible expenses or non-taxable income.

Profit attributable to shareholders and earnings per share

Our profits attributable to shareholders and earnings per share tend to fluctuate periodically due to one-off events or extraordinary items that require adjustments to exclude these events to normalize earnings and to make period-on-period comparisons more meaningful.

As a result of the factors discussed above, our profit for the period decreased by RR 49,850 million, or 41.8%, to RR 69,441 million in 2012 from RR 119,291 million in 2011. The profit attributable to shareholders of OAO NOVATEK decreased by RR 50,197 million, or 42.0%, to RR 69,458 million in 2012 from RR 119,655 million in 2011. The profit attributable to shareholders of OAO NOVATEK, adjusted to exclude the net gain (loss) on disposal of subsidiaries, increased by RR 12,811 million, or 22.6%, to RR 69,518 million in 2012 from RR 56,707 million in 2011.

Our weighted average basic and diluted earnings per share, calculated from the profit attributable to shareholders of OAO NOVATEK, decreased by approximately RR 16.56 per share, or 42.0%, to RR 22.89 per share in 2012 from RR 39.45 per share in 2011. Our weighted average basic and diluted earnings per share, calculated from the profit attributable to shareholders of OAO NOVATEK, adjusted to exclude the net gain (loss) on disposal of subsidiaries, increased by RR 4.22 per share, or 22.6%, to RR 22.91 per share in 2012 from RR 18.69 per share in 2011.

LIQUIDITY AND CAPITAL RESOURCES

The following table shows our net cash flows from operating, investing and financing activities for the years ended 31 December 2012 and 2011:

	Year ended 31 December:		Change
millions of Russian roubles	2012	2011	%
Net cash provided by operating activities	75,825	71,907	5.4%
Net cash provided by (used in) investing activities	(84,124)	(46,643)	80.4%
Net cash provided by (used in) financing activities	2,603	(11,735)	n/a

Liquidity and credit ratios	31 December 2012	31 December 2011	Change, %

Current ratio	1.06	1.16	(8.6%)
Total debt to total equity	0.45	0.40	12.5%
Long-term debt to long-term debt and total equity	0.25	0.24	4.2%
Net debt to total capitalization (1)	0.26	0.20	30.0%
Net debt to EBITDA (2)	1.20	0.48	150.0%
Net debt to Normalized EBITDA (2)	1.20	0.84	42.9%
Interest coverage ratio (3)	24	42	(42.9%)

(1) Net debt represents total debt less cash and cash equivalents. Total capitalization represents total debt, total equity and deferred income tax liability.

(2) Net debt to EBITDA and to Normalized EBITDA ratios are calculated as Net debt divided by EBITDA or Normalized EBITDA for the last twelve months.

(3) Interest coverage ratio is calculated as Normalized EBITDA divided by interest expense, including capitalized interest, less interest income from the Consolidated Statement of Income.

Net cash provided by operating activities

In 2012, our net cash provided by operating activities increased by RR 3,918 million, or 5.4%, to RR 75,825 million compared to RR 71,907 million in 2011 mainly due to higher natural gas sales volumes and prices that was partially offset by an increase in income tax payments.

Net cash provided by (used in) investing activities

In 2012, our net cash used in operating activities increased by RR 37,481 million, or 80.4%, to RR 84,124 million compared to RR 46,643 million in 2011, due primarily to the payment for shares of our joint venture Nortgas, which was acquired in November 2012, as well as an increase in our cash used for purchases of property, plant and equipment and ongoing development activities at our fields.

Net cash provided by (used in) financing activities

In 2012, our net cash provided by financing activities was RR 2,603 million compared to net cash used in financing activities of RR 11,735 million in 2011. In 2012, cash provided by new borrowings increased by RR 32,564 million to RR 81,149 million from RR 48,585 million in 2011, which was partially offset by an increase in repayment of debts by RR 10,539 million from RR 29,873 million in 2011 to RR 40,412 million in 2012. Our cash used to pay dividends increased by RR 4,552 million in 2012 compared to 2011. The remaining change was related to repayment of interest on debts and other miscellaneous categories.

Working capital

Our net working capital position (current assets less current liabilities) at 31 December 2012 was a positive RR 3,113 million compared to RR 8,202 million at 31 December 2011. The change of our net working capital position was primarily due to the increase in the current portion of long-term debt as of 31 December 2012. In February 2013, the Group issued four-year, Russian rouble denominated Eurobonds in the amount of RR 14 billion the proceeds from which were used to refinance our current portion of long-term debt (see "Debt obligations" below).

The Group's management believes that it presently has and will continue to have the ability to generate sufficient cash flows (from operating and financing activities) to repay all current liabilities and to finance the Group's capital construction programs.

Capital expenditures

Our total capital expenditures on property, plant and equipment for the years ended 31 December 2012 and 2011 were as follows:

	Year ended 31 December:		Change
millions of Russian roubles	2012	2011	%

Capital expenditures	43,554	31,161	39.8%
Prepayments for participation in tender for mineral licenses per consolidated statement of cash flows	-	6,870	n/a
Total additions to property, plant and equipment per
Note "Property, plant and equipment" in the Group's
IFRS Consolidated Financial Statements	43,554	38,031	14.5%

Our total capital expenditures (including capitalized 3-D seismic surveys) represent our investments in developing our oil and gas properties. The following table shows the expenditures at our main fields and processing facilities for the years ended 31 December 2012 and 2011:

	Year ended 31 December:
millions of Russian roubles	2012	2011
Yurkharovskoye field	14,067	11,403
Gas Condensate Fractionation Complex and Transshipment Facility (Ust-Luga)	11,801	3,923
East-Tarkosalinskoye field	7,157	2,430
Purovsky Plant	1,443	1,369
Khancheyskoye field	1,017	612
North-Khancheyskiy license area	982	147
Salmanovskoye (Utrenneye) field	819	-
North-Russkiy license area	657	574
Olimpiyskiy license area	599	345
Geofizicheskoye field	343	30
West-Urengoiskiy license area	327	515
North-Yamsoveiskiy license area	316	169
South-Tambeyskoye field	-	4,148
Other	4,026	5,496
Capital expenditures	43,554	31,161

Total capital expenditures on property, plant and equipment in 2012 increased by RR 12,393 million, or 39.8%, to RR 43,554 million from RR 31,161 million in 2011. The increase was primarily related to the construction of processing assets at Ust-Luga, ongoing development activities and the launch of the fourth stage of the second phase development at our Yurkharovskoye field, as well as further field development on the crude oil layers at the East-Tarkosalinskoye and Khancheyskoye fields. The increase was partially offset by the fact, that we did not consolidate capital expenditures related to South-Tambeyskoye field in 2012 as a result of the disposal of a 20% equity interest in Yamal LNG in October 2011, which is accounted for under the equity method starting from that date.

Debt obligations

We utilize a variety of financial instruments to ensure the flexibility of our financing strategy. This includes maintaining a debt portfolio with a balance of short-term and long-term financing, a mix of fixed and floating interest rate instruments and a debt portfolio denominated in either Russian roubles or US dollars.

Subsequent events

In February 2013, the Group placed Russian rouble denominated Eurobonds in the amount of RR 14 billion with a four-year maturity and an annual coupon rate of 7.75%.

In February 2013, we repaid a RR 15 billion loan from OAO Sberbank ahead of its maturity schedule.

In March 2013, we repaid a USD 200 million loan from OAO Nordea Bank ahead of its maturity schedule.

Overview

Our total debt increased from RR 95,478 million at 31 December 2011 to RR 132,487 million at 31 December 2012, or by RR 37,009 million. We periodically utilize credit facilities to supplement our internally generated cash flows for the financing of capital expenditures related to the development of our fields and to construct and/or expand processing assets such as the Purovsky Plant and Ust-Luga, as well as acquisitions of new oil and gas assets. The increase in our total debt was largely due to the placement of a ten-year, US dollar denominated Eurobond in December 2012 to finance the Nortgas acquisition.

Our total debt position (net of unamortized transaction costs) at 31 December 2012 and 31 December 2011 was as follows:

				Year ended 31 December:
Facility	Amount	Maturity	Interest rate	2012	2011

Eurobonds Ten-Year	USD 1 billion	December 2022	4.422%	30,232	-
Russian rouble Bonds	RR 20 billion	October 2015	8.35%	19,969	-
Eurobonds Ten-Year	USD 650 million	February 2021	6.604%	19,620	20,776
Eurobonds Five-Year	USD 600 million	February 2016	5.326%	18,146	19,206
Sberbank	RR 15 billion	December 2013	7.5%	14,984	14,966
Russian rouble Bonds	RR 10 billion	June 2013	7.5%	9,991	9,971
Sberbank	RR 10 billion	December 2014	8.9%	9,837	-
Nordea Bank	USD 200 million	November 2013	LIBOR+1.9%	6,075	6,439
Sumitomo Mitsui (1)	USD 300 million	December 2013	LIBOR+1.45%	3,633	7,685
UniCredit Bank	USD 200 million	October 2012	LIBOR+3.25%	-	6,435
Gazprombank (2)	RR 10 billion	November 2012	8.0%	-	10,000

Total 132,487 95,478

(1) Sumitomo Mitsui Banking Corporation Europe Limited.

(2) The loan from OAO Gazprombank was repaid ahead of maturity schedule in January 2012.

Maturities of long-term loans

Scheduled maturities of our long-term debt at 31 December 2012 were as follows:

Maturity schedule:	RR million
1 January to 31 December 2014 1 January to 31 December 2015 1 January to 31 December 2016 1 January to 31 December 2017 After 31 December 2017	9,837 19,970 18,146 - 49,852
Total long-term debt	97,805

Available credit facilities

At 31 December 2012, the Group had available funds under short-term credit lines in the form of bank overdrafts with various international banks in the aggregate amount of RR 7,327 million (USD 175 million and EUR 50 million) on variable interest rates subject to the specific type of credit facility.

At 31 December 2012, the Group also had funds available under credit facilities with interest rates predetermined or negotiated at time of each withdrawal:

		Expiring
	Par value	Within one year	Between 1 and 3 years
BNP PARIBAS Bank	USD 100 million	3,037	-
Credit Agricole Corporate and Investment Bank	USD 100 million	3,037	-
UniCredit Bank	USD 350 million	-	10,630
Sberbank (1)	RR 30 billion	30,000	-
Total available credit facilities		36,074	10,630

(1) The period of availability of the credit line facility ended 31 January 2013.

Management believes it has sufficient internally generated cash flows, as well as access to available external borrowings (both short- and long-term) to fund its capital expenditure program, service its existing debt and meet its current obligations as they become due.

QUALITATIVE AND QUANTITATIVE DISCLOSURES AND MARKET RISKS

We are exposed to market risk from changes in commodity prices, foreign currency exchange rates and interest rates. We are exposed to commodity price risk as our prices for crude oil and stable gas condensate destined for export sales are linked to international crude oil prices and other benchmark price references. We are exposed to foreign exchange risk to the extent that a portion of our sales, costs, receivables, loans and debt are denominated in currencies other than Russian roubles. We are subject to market risk from changes in interest rates that may affect the cost of our financing. From time to time we may use derivative instruments, such as commodity forward contracts, commodity price swaps, commodity options, foreign exchange forward contracts, foreign currency options, interest rate swaps and forward rate agreements, to manage these market risks, and we may hold or issue derivative or other financial instruments for trading purposes.

Foreign currency risk

Our principal exchange rate risk involves changes in the value of the Russian rouble relative to the US dollar. As of 31 December 2012, the total amount of our long-term debt denominated in US dollars was RR 67,987 million, or 51.3% of our total borrowings at that date. Changes in the value of the Russian rouble relative to the US dollar will impact our foreign currency-denominated costs and expenses and our debt service obligations for foreign currency-denominated borrowings in Russian rouble terms, as well as receivables at our foreign subsidiaries. We believe that the risks associated with our foreign currency exposure are partially mitigated by the fact that a portion of our total revenues, approximately 24.8% in 2012, is denominated in US dollars. As of 31 December 2012, the Russian rouble appreciated by approximately 5.7% against the US dollar since 31 December 2011.

A hypothetical and instantaneous 10% depreciation in the Russian rouble in relation to the US dollar as of 31 December 2012 would have resulted in an estimated non-cash foreign exchange loss of approximately RR 7,771 million on foreign currency denominated borrowings held at that date.

Commodity risk

Substantially all of our crude oil, stable gas condensate and LPG export sales are sold under spot market contracts, and our export prices are primarily linked to international crude oil prices. External factors such as geopolitical developments, natural disasters and the actions of the Organization of Petroleum Exporting Countries affect crude oil prices and thus our export prices.

The weather is another factor affecting demand for natural gas. Changes in weather conditions from year to year can influence demand for natural gas and to some extent gas condensate and oil products.

From time to time we may employ derivative instruments to mitigate the price risk of our sales activities. In our consolidated financial statements all derivative instruments are recorded at their fair values. Unrealized gains or losses on derivative instruments are recognized within other operating income (loss), unless the underlying arrangement qualifies as a hedge.

The Group purchases and sells natural gas on the European market under long-term contracts based on formulas with reference to benchmark natural gas prices quoted for the North-Western European natural gas hubs, crude oil and oil products prices and/or a combination thereof. Therefore, the Group's financial results from natural gas trading activities are subject to commodity price volatility based on fluctuations or changes in the respective benchmark reference prices.

Pipeline access

We transport substantially all of our natural gas through the Unified Gas Supply System ("UGSS") owned and operated by OAO Gazprom, which is responsible for gathering, transporting, dispatching and delivering substantially all natural gas supplies in Russia. Under existing legislation, Gazprom must provide access to the UGSS to all independent suppliers on a non-discriminatory basis provided there is capacity available that is not being used by Gazprom. In practice, Gazprom exercises considerable discretion over access to the UGSS because it is the sole owner of information relating to capacity. There can be no assurance that Gazprom will continue to provide us with access to the UGSS; however, we have not been denied access in prior periods.

Ability to reinvest

Our business requires significant ongoing capital expenditures in order to grow our production and meet our strategic plans. An extended period of reduced demand for our hydrocarbons available for sale and the corresponding revenues generated from these sales would limit our ability to maintain an adequate level of capital expenditures, which in turn could limit our ability to increase or maintain current levels of production and deliveries of natural gas, gas condensate, crude oil and other associated products; thereby, adversely affecting our financial and operating results.

Off balance sheet activities

As of 31 December 2012, we did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which are typically established for the purpose of facilitating off-balance sheet arrangements.

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FORWARD–LOOKING STATEMENTS

This Annual Review includes 'forward-looking information' within the meaning of Section 27A of the US Securities Act of 1933, as amended, and Section 21E of the US Securities Exchange Act of 1934, as amended. Certain statements included in this Annual Report and Accounts, including, without limitation, statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements, which are other than statements of historical facts. The words "believe," "expect," "anticipate," "intends," "estimate," "forecast," "project," "will," "may," "should" and similar expressions identify forward-looking statements. Forward-looking statements include statements regarding: strategies, outlook and growth prospects; future plans and potential for future growth; liquidity, capital resources and capital expenditures; growth in demand for our products; economic outlook and industry trends; developments of our markets; the impact of regulatory initiatives; and the strength of our competitors. The forward-looking statements in this Annual Review are based upon various assumptions, many of which are based, in turn, upon further assumptions, including without limitation, management's examination of historical operating trends, data contained in our records and other data available from third parties. Although we believe that these assumptions were reasonable when made, these assumptions are inherently subject to significant uncertainties and contingencies, which are difficult or impossible to predict and are beyond our control. As a result, we may not achieve or accomplish these expectations, beliefs or projections. In addition, important factors that, in our view, could cause actual results to differ materially from those discussed in the forward-looking statements include:

changes in the balance of oil and gas supply and demand in Russia and Europe;
the effects of domestic and international oil and gas price volatility and changes in regulatory conditions, including prices and taxes;
the effects of competition in the domestic and export oil and gas markets;
our ability to successfully implement any of our business strategies;
the impact of our expansion on our revenue potential, cost basis and margins;
our ability to produce target volumes in the event, among other factors, of restrictions on our access to transportation infrastructure;
the effects of changes to our capital expenditure projections on the growth of our production;
potentially lower production levels in the future than currently estimated by our management and/or independent petroleum reservoir engineers;
inherent uncertainties in interpreting geophysical data;
changes to project schedules and estimated completion dates;
our success in identifying and managing risks to our businesses;
the effects of changes to the Russian legal framework concerning currently held and any newly acquired oil and gas production licenses;
changes in political, social, legal or economic conditions in Russia and the CIS;
the effects of technological changes;
the effects of changes in accounting standards or practices.

This list of important factors is not exhaustive. When relying on forward-looking statements, one 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. Accordingly, 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

200 ANNUAL REPORT OAO NOVATEK 2012

GROWTH EFFICIENCY INNOVATION

of many possible scenarios and should not be viewed as the most likely or standard scenario. The information and opinions contained in this document are provided as at the date of this review and are subject to change without notice.

Mentions in this Annual Report of "OAO NOVATEK", "NOVATEK", "the Company", "we" and "our" refer to OAO NOVATEK and/or its subsidiary enterprises, depending upon the context, in which the terms are used.

ABBREVIATIONS

barrel	one stock tank barrel, or 42 US gallons of liquid volume
bln	billion
bcm	billion cubic meters
boe	barrels of oil equivalent. For natural gas, we use the conversion factor of one mcm equals 6.54 barrels.
km	kilometer(s)
LNG	liquified natural gas
LPG	liquified petroleum gases
mboe	thousand boe
mcm	thousand cubic meters
mln	million
mmboe	million boe
mmcm	million cubic meters
mmt	million metric tons
mt	thousand metric tons
PRMS	Petroleum Resources Management System
RR	Russian rouble
SEC	United States Securities and Exchange Commission
sq.	square
th.	thousand
ton	metric ton
UGSS	Unified Gas Supply System
YNAO	Yamal-Nenets Autonomous Region

CONVERSION FACTORS

1000 cubic meters of gas = 6.54 boe. To convert crude oil and gas condensate reserves from tons to barrels we used various coefficients depending on the liquids density at each field.

RESPONSIBILITY STATEMENT

I hereby confirm that to the best of my knowledge:

(a) the set of financial statements, which has been prepared in accordance with International Accounting Standards, gives a true and fair view of the assets, liabilities, financial position and profit or loss of the undertakings included in the consolidation

as a whole as required by the Disclosure and Transparency Rule (DTR) 4.1.6R,

(b) the management report includes a fair review of the information required by DTR 4.1.9R, being a balanced and comprehensive analysis of development and performance of the business and the position of the company and the undertakings included in the consolidation taken as a whole, together with a description of the principal risks and uncertainties that the company faces.

Mark Gyetvay,

Chief Financial Officer

202 GROWTH ANNUAL REPORT OAO NOVATEK 2012

EFFICIENCY INNOVATION

CONTACT INFORMATION

LEGAL ADDRESS 22 A Pobedy Street, Tarko-Sale, Yamal-Nenets Autonomous Region, 629850, Russia

OFFICE IN MOSCOW 2, Udaltsova Street, 119415, Moscow, Russia

CENTRAL INFORMATION SERVICE Tel: +7 495 730-6000 Fax: +7 495 721-2253 E-mail: [email protected]

PRESS SERVICE

Tel: +7 495 721-2207 E-mail: [email protected]

INVESTOR RELATIONS

Tel: +7 495 730-6013 Fax: +7 495 730-6000 E-mail: [email protected]

WEBSITE:

www.novatek.ru (Russian version) www.novatek.ru/eng (English version)

REGISTRAR

ZAO "Computershare Registrar" 8 Ivana Franko Street, Moscow Russia 121108 Tel: +7 (495) 926-8160 Fax: +7 (495) 926-8178 E-mail: [email protected]

GDR PROGRAM ADMINISTRATOR

Deutsche Bank Trust Company Americas 60 Wall Street, New York, New York 100056, USA London +44 20 7547 6500 New York +1 212 250 9100 Moscow +7 495 797 5209

INDEPENDENT AUDITOR

ZAO PricewaterhouseCoopers Audit White Square Office Center, Butyrsky Val 10, 125047 Moscow, Russia Tel: +7 495 967-6000 Fax: +7 495 967-6001

INDEPENDENT RESERVES AUDITOR

DeGolyer and MacNaughton 5001 Spring Valley Road, Suite 800, East Dallas, Texas 75244, USA Tel: +1 214 368-6391 Fax: +1 214 369-4061 E-mail: [email protected]

AI Terminal

NOVATEK

6442_10-k_2012-12-31_8923a3c8-59b6-4612-981e-9846dc4a79c1.pdf

NOVATEK IS RUSSIA'S LARGEST INDEPENDENT NATURAL GAS PRODUCER AND THE SECOND-LARGEST NATURAL GAS PRODUCER IN RUSSIA

57.3 16% 9%

FIELDS AND LICENSE AREAS

LETTER TO SHAREHOLDERS

Dear Shareholders,

STRATEGY

GROSS PRODUCTION

EFFICIENCY

HIGH QUALITY RESOURCE BASE AND USE OF STATE-OF-THE-ART TECHNOLOGIES

YURKHAROVSKOYE FIELD

INNOVATION

1 DRILLING 2

DRILLING CUTTINGS PROCESSING PLANT

3 4 PRODUCTION WELLS

TURBO-EXPANDERS

5 6 METHANOL PRODUCTION FACILITY

ALTERNATIVE ENERGY SOURCES

KEY EVENTS

01

02

03

04

05

06

07

08

09

KEY INDICATORS

PROVED NATURAL GAS RESERVES (SEC), BCM

01 REVIEW OF OPERATING RESULTS

LICENSES AND RESERVES

OF PROVED HYDROCARBON RESERVES ADDED IN 2012 (INCLUDING PRODUCTION) BLN BOE 3.4

Exploration work

GEOLOGICAL EXPLORATION

FIELD DEVELOPMENT

Gross hydrocarbon production*

HYDROCARBON PRODUCTION

Main Producing Fields

Yurkharovskoye field

SALES PRODUCTION OF NATURAL GAS AT THE YURKHAROVSKOYE FIELD, BCM

East-Tarkosalinskoye field

Khancheyskoye field (Khancheyskiy license area)

25 NUMBER OF

PRODUCTION WELLS AT THE SAMBURGSKOYE FIELD AS OF 31 DECEMBER 2012

Other producing fields

Beregovoy license area and Pyreinoye field

Samburgskoye field (Samburgskiy license area)

North-Urengoyskoye field

Sterkhovoye field (Olimpiyskiy license area)

Yumantilskoye field (Yumantilskiy license area)

Prospective fields and license area

421BCM PROVED NATURAL GAS RESERVES OF SEVERENERGIA FIELDS

SeverEnergia fields

Termokarstovoye field

North-Khancheyskoye field

481BCM PROVED NATURAL GAS RESERVES OF THE SOUTH-TAMBEYSKOYE FIELD

Yarudeyskoye field

North-Russkoye field

Olimpiyskiy license area

South-Tambeyskoye field (Yamal LNG project)

235 BCM

Fields and license areas on the Gydan Peninsula and the offshore Gulf of Ob

4.03 MMT

PROCESSING

Ust-Luga Stable Gas Condensate Transshipment and Fractionation Complex

PUROVSKY PLANT OUTPUT IN 2012, %

58.9 BCM

MARKETING

Natural gas sales

NATURAL GAS SALES VOLUMES, BCM

BREAKDOWN OF 2012 NATURAL GAS SALES VOLUMES, %

NATURAL GAS SALES REVENUES, RR BLN*

Natural gas and liquids sales volumes

Liquid Hydrocarbon Sales

LIQUID HYDROCARBON SALES VOLUMES, MT

LIQUID HYDROCARBON SALES REVENUES, RR BLN*

LIQUID HYDROCARBON SALES