Preliminary Results

1 April 2014

VOLGA GAS PLC

Preliminary results for the year ended 31 December 2013

Volga Gas plc ("Volga Gas", the "Group" or the "Company"), the oil and gas exploration and production group operating in the Volga region of Russia, is pleased to announce its preliminary unaudited annual results for the year ended 31 December 2013.

The key event of 2013 was the significant increase in throughput at the Dobrinskoye gas plant which has enabled full production from the existing wells on the Group's largest field, Vostochny Makarovskoye("VM"). This has enabled the Group to exit 2013 producing at a rate of over 4,500 barrels of oil equivalent per day ("boepd"), an increase of 58% over the rate of production at the start of the year. The financial results for 2013 show a significant improvement on 2012 and the Group is poised to deliver further significant growth in profits and cash flow in 2014.

FINANCIALHIGHLIGHTS

· Revenues up 22% to US$34.6 million (2012: US$28.3 million)

· EBITDA up 85% to US$14.8 million (2012: US$8.0 million)

· EBITDA per barrel of oil equivalent ("boe") up 26% to US$13.80/boe (2012: US$10.96/boe)

· Profit before tax of US$9.1 million (2012: loss of US$6.3 million)

· Net operating cash flow up 202% to US$15.4 million (2012: US$5.4 million)

· Bank debt fully repaid at 31 December 2013 (31 December 2012: bank debt of US$ 8.0 million).

· US$8.1 million in cash at 31 December 2013 (31 December 2012: US$7.0 million)

PRODUCTION & DEVELOPMENT

· Group average production up 48% to 2,958 boepd (2012: 1,995 boepd)

· Successful workover of well #1 on VM field during H1 2013 more than doubled the estimated productive capacity of that well to over 10 mmcf/d

· New production stream from the Sobolevskoye field from June 2013.

· After five years of production, output from the Uzenskoye field has been reduced pending future installation of water separation equipment

· Two new wells on the VM field VM#3 and VM#5 being drilled during 2014

DOBRINSKOYE GAS PLANT UPGRADE

· Key phases of the upgrade to the Dobrinskoye gas plant were completed in October 2013 and regulatory approval of the upgrade work was obtained in November 2013

· Since November 2013 the plant has been operating at a capacity of 500,000 cubic metres per day (approximately 17.7 mmcf/d)

· Continuing upgrade to expand capacity to 1 million cubic metres per day (35 mmcf/d) during 2014

CURRENT TRADING AND OUTLOOK

· During January and February 2014 production averaged 4,563 boepd, 54% above the full year 2013 average production rate

· Increases in oil and condensate selling prices have partly offset weakness of the Rouble against the US dollar

· With continued improvements in cost efficiency, unit EBITDA in US dollars per boe has been maintained at above the average rate for 2013

· Proposal to create distributable reserves to enable cash distributions to shareholders

Mikhail Ivanov, Chief Executive of Volga Gas, commented:

"2013 was a pivotal year for Volga Gas with a significant increase in production achieved in the final quarter of the year and sustained in the subsequent period. Completion of the current development drilling programme on VM in 2014 should enable additional production from our gas and condensate fields to maximise utilisation of anticipated gas processing capacity which we estimate would lift Group production to over 8,000 boepd. This will continue to drive growth in revenues and cash flow for Volga Gas and provide a basis for the Company to provide tangible financial returns to shareholders.

"We remain positive about the potential for growth, both in reserves and production from our licences. Our financial position and cash generation outlook have reached a point at which cash returns to shareholders can be contemplated. The Board is taking the necessary steps to enable the Company to make distributions. We will also continue seek value accretive opportunities beyond our existing licence areas, building a focused exploration and production business."

For additional information please contact:

Editors' notes:

Volga Gas is an independent oil and gas exploration and production company operating in the Volga region of European Russia. The Company has 100% interests in its four licence areas.

The information contained in this announcement has been reviewed and verified by Mr. Mikhail Ivanov, Director and Chief Executive Officer of Volga Gas plc, for the purposes of the Guidance Note for Mining, Oil and Gas companies issued by the London Stock Exchange in June 2009. Mr. Mikhail Ivanov holds a M.S. Degree in Geophysics from Novosibirsk State University. He also has an MBA degree from Kellogg School of Management (Northwestern University). He is a member of the Society of Petroleum Engineers and has more than 20 years of experience in the sector.

Availability of report and accounts

The Group's full report and accounts, including notice of the annual general meeting of the Company to be held at the London office of Akin Gump Strauss Hauer & Feld at Ten Bishops Square, London E1 6EG on 6 June 2014 at 10.00 a.m., will be dispatched to shareholders as soon as is practicable. Copies will also be available on the Company's website www.volgagas.com and on request from the Company at, Ground Floor, 17-19 Rochester Row, London SW1P 1QT.

Chairman's Statement

2013 was a pivotal year for Volga Gas, with the main event for the Company being the significant increase in capacity and throughput at the Dobrinskoye gas plant which has enabled full production from the existing wells on the Group's largest field, Vostochny Makarovskoye. This has enabled the Group to exit 2013 producing at a rate of over 4,500 barrels of oil equivalent per day, an increase of 58% over the rate of production at the start of the year. As the majority of the increase came in November 2013, the full year production, revenue and cash flow numbers in 2013, although well ahead of 2012, do not properly reflect the current capabilities of the Group's fields.

With the major portion of production growth in 2013 coming from gas rather than condensate and oil, the growth in revenue was not as marked as that in volume. However, the relatively lower taxation applied in Russia to gas and condensate as opposed to crude oil is a benefit to the profit margin and to the economics of gas production.

It is gratifying to report that even though Volga Gas is still very much on a growth track in terms of production and development, it has remained strongly cash generative. The Group has funded its 2013 capital expenditures and fully repaid its bank debt with cash generated from operations.

The key operational objectives for 2014 will be to complete the final stages of the upgrade to the Dobrinskoye gas plant, obtain the required permits for full commercial operation at the design rate of over 35 million cubic feet per day, and to continue to build on the fields' production capability to make full utilisation of the gas plant capacity. Meanwhile, the current production levels generate sufficient cash to fund the continuing development of the assets which in turn we anticipate will lead to further growth in production and cash flow.

We believe Volga Gas is now in a position to consider providing cash returns to shareholders. The Board has initiated a process which will enable Volga Gas to have sufficient distributable reserves to enable distributions. You will see in the Notice of Annual General Meeting for 2014, a Special Resolution that relates to this matter.

The Group maintains significant proven reserves in its three principal fields, which were subject to an independent evaluation during 2012. These fields form the basis of growth in production in the near term. Our fields are advantageously located and our costs are sufficiently low for us to achieve good returns at oil and gas prices significantly lower than those we currently experience. Most importantly, these assets provide a strong platform for the Group to grow in the future, both through successful exploration and by selective value accretive acquisitions.

Volga Gas has also identified material exploration prospects within existing acreage that can be tested at low cost.

The Board believes that Volga Gas has a strong asset base and the financial and operational capability to develop and extend these assets to provide long term value growth for our shareholders.

Aleksey Kalinin

Chairman

Chief Executive's Report

Volga Gas reached another key milestone in 2013 with the approval received in November 2013 for the upgrade works on the Group's Dobrinskoye gas processing plant, following which the field output was progressively increased to make full use of the production capacity in the Group's existing gas and condensate production wells on the Vostochny Makarovskoye ("VM") and Dobrinskoye fields. Consequently towards the end of 2013 production increased significantly and reached an average rate of over 4,500 barrels of oil equivalent per day in December 2013, an increase of 58% compared to the average rate for December 2012. Thus, while Volga Gas has realised a significant increase in production rates during 2013, the benefit of these increases will continue through 2014 and beyond.

As detailed in the Operational Review below, the majority of the work on our producing assets base remained focused on the two gas fields. On VM, the Group completed a workover on the main producing well, VM#1, the effect of which was to increase significantly the production capacity of that well.

For much of 2013, the Group's gas and condensate production was constrained by the requirement to operate the Dobrinskoye gas processing plant with a throughput of 250,000 cubic metres (8.8 million cubic feet per day). However, in November 2013, after receipt of the regulatory approvals detailed below, throughput was increased and reached up to 530,000 cubic metres per day (18.7 million cubic feet per day) during December 2013. Production of condensate, which is separated from the gas stream at the processing plant, increased in line with the gas production.

Crude oil production, on the other hand, was lower in 2013 than 2012. Production from the Uzenskoye field was reduced as wells on the edge of the field began to exhibit some water cut. The reduction in the Uzenskoye field was partly offset by new production from the single well on the Sobolevskoye field.

In aggregate, production in 2013 was 2,958 barrels of oil equivalent per day (boepd), which represents a 48% increase on 2012. The revenue and EBITDA performance of the Group in 2013 reflected this increased production, although as the majority of the volume growth was in gas, the revenue growth was not as large. Nevertheless, as an indication of rising profitability, EBITDA per barrel of oil equivalent sold increased 26% from US$10.96 in 2012 to US$13.80 in 2013. See the Financial Report below for details.

In 2013, exploration activity was limited, although a number of significant exploration prospects in the Group's Karpenskiy licence area have been identified for future exploration drilling.

Our key operational objectives in 2014 are to complete the remaining work on the Dobrinskoye gas plant upgrade, with the aim of fulfilling the regulatory requirements to enable the Group to operate at a processing capacity of 1 million cubic metres per day (35 million cubic feet per day) and to bring the VM field into full scale production. The latter involves development drilling of two wells during 2014, the first of which is already under way.

Finance

The Group maintained a strong level of cash generation from operating activities throughout 2013, enabling it to fund its capital expenditure for the year from operating cash flow and to make full repayment its bank loans, which at 31 December 2012 were US$8.0 million. As at 31 December 2013, the Group had net cash of US$8.1 million and no debt.

Although the planned investments in 2014 are expected to be less than operating cash flow, the Group considers a moderate level of borrowing to be appropriate as part of the longer term capital structure. As the Group's assets have established a track record of reliable cash generation, with prospects for continued significant growth in the near future, the Board considers it appropriate to consider distributions to shareholders and is taking measures to enable this.

Current trading

In January and February 2014, Group production averaged 4,563 boepd comprising 1,900 bpd of oil and condensate of and 16.0 mmcf/d of gas and, in spite of some softening in the US dollar equivalent realisations for sales as a result of the weakening Ruble, monthly revenues and gross cash margins are significantly ahead of the average run rate for 2013. Higher cash flows have continued to drive increases in the Group's cash balances ahead of the planned capital expenditure.

Outlook

Key activities for 2014 will be focused on delivering increased production from the VM field enabling full utilization of the capacity at the Dobrinskoye gas plant. It is our current expectation that works on the final stage of the upgrade will be completed during H1 2014 when, subject to obtaining the necessary permits, we expect to achieve full operation at a capacity of up to 1 million cubic metres per day (35.3 million cubic feet per day).

Having mobilized a drilling rig in January, drilling of the new development well VM#3 on the VM field has commenced and is expected to be completed in the first half of 2014. This will be followed by a further well, VM#5 shortly thereafter. The total capital expenditure budgeted for 2014 is US$13.8 million and is expected to be funded entirely from existing cash resources and cash generated from operations.

We look forward to delivering a rising stream of production and further financial growth.

Mikhail Ivanov

Chief Executive Officer

Operational Review

The key event for the Group in 2013 was the increase in throughput at the Dobrinskoye gas processing plant in November 2013, after receipt of the formal approval of the upgrade works. This enabled production of gas and condensate towards the end of 2013 to reflect the productive capacity of the wells on the Group's VM and Dobrinskoye fields, more than doubling the production rates achieved hitherto.

The overall level of production in 2013, at 2,958 boepd, was 48% above the 1,995 boepd achieved in 2012. This is a result of a full year's production from the VM field which commenced full time production in November 2012 and was further boosted by the increase in plant throughput achieved in November 2013. Production of condensate followed in line with gas as they are extracted simultaneously and separated at the gas processing plant.

Oil production was lower in 2013 than in 2012, averaging 826 bopd in 2013 compared to 1,109 bopd in 2012. The reasons for the decline in production are detailed below.

As a consequence of the significant increase in production in 2013, revenues and EBITDA levels in 2013 were well ahead of 2012, although with the rapidly increasing proportion of gas in the mix, the revenue growth was not quite as impressive as production growth. Full details are discussed in the Financial Review below.

Gas processing plant

The major part of the construction work for the upgrade of the Dobrinskoye gas processing plant was undertaken in 2012, including enhanced H2S extraction, expansions to condensate separation and increased condensate storage capacity. During 2013, the majority of the remaining construction work required to increase the processing capacity to the planned level of 1 million cubic metres per day (37 mmcf/d) was completed in October 2013.

In November 2013, the Groupreceived regulatory approval for the upgrade works on the Dobrinskoye gas processing plant. Following the installation of certain additional minor modules, as required by the state construction agency, Gosstroi, final approval of the completed upgrade will be sought, which will allow GNS to utilise the plant at full plant capacity on a permanent basis. Pending this, the Company has been operating at test rates utilising the full current well capacity.

Since November 2013 the Group increased the output from wells on the VM and Dobrinskoye gas fields and during December 2013 reached an average production rate of 432,000 cubic metres per day (15.2 mmcf/d), although during the period production rates of up to 530,000 cubic metres per day (18.7 mmcf/d) were achieved.

During 2013, the Group has also been investigating means of enhancing the gas processing by the use of alternative chemicals. Following successful trials conducted during the year modifications to the process are beginning to deliver material savings on the cost of chemicals used in the process. As a result of these savings and the substantial fixed cost portion of the operating costs, unit production costs in the future on the gas production are expected to reduce significantly.

The Group spent approximately US$3.6 million on the upgrade project during 2013 and the required investment to complete the project is expected to be no more than US$2.0 million. The Group is currently evaluating the merits of additional processing to extract an LPG stream from the gas, primarily propane and butane, which currently is delivered into the sales gas pipeline.

Gas/condensate production

The Dobrinskoye and VM fields are managed as a single business unit. Production from the fields is processed at the gas plant located next to the Dobrinskoye field, extracting the condensate and processing the gas to pipeline standards before input into Gazprom's regional pipeline system via an inlet located at the plant. Prior to November 2013 the plant was permitted to operate at a capacity of 250,000 cubic metres per day (8.8 mmcf/d), so the fields were not producing at their full capacity. Moreover, during 2013 the continuing upgrade works to upgrade the plant meant that the plant's downtime was slightly higher than would be expected under normal operations. However, as mentioned above, since November 2013, production has increased to levels that more closely reflect the estimated current production capacity of the wells which is over 500,000 cubic metres per day (17.8 mmcf/d) of gas and 120 tonnes per day (1,050 barrels per day) of condensate.

During 2013, production derived from both fields averaged 8.7 mmcf/d of gas and 682 bpd of condensate (2012: 3.3 mmcf/d of gas and 346 bpd of condensate). In total, there are three producing wells on VM and two producing wells on Dobrinskoye.

Gas continues to be sold to Trans Nafta under contract. An increase in the Rouble contract gas sales price took effect on 1 January 2013 and a further price increase took effect in July 2013. The average gas sales price for 2013 was the equivalent of US$2.73 per thousand cubic feet, net of VAT (2012: US$2.32). During 2013 the average condensate sales price was US$47.00 per barrel (2012, US$45.70 per barrel).

Average unit production costs on the gas-condensate fields remained relatively high at US$8.27 per boe in 2013 (2012: US$10.70) primarily as a result of a significant element of fixed plant costs and chemicals consumed in the gas processing unit. With the increasing plant utilization, however, the unit costs have reduced compared to 2012 and with higher utilization and cost savings on chemicals, management anticipates further reductions in unit costs.

During 2013, a workover was conducted on the VM#1 production well, perforating an additional 23 metres of the pay zone in the well. Following the successful workover operations, a production test on a 10 mm choke on the well achieved a higher than expected maximum flow rate of 274,000 cubic metres (9.7 million cubic feet) per day of gas and 794 barrels per day of condensate. This is approximately twice the production level that was previously achieved with the well. Estimated production capacity from the existing wells is now up to 20.0 mmcf/d of gas and over 1,000 bpd of condensate.

On the Dobrinskoye field, sidetracks were drilled on both production wells during 2011 and 2012 and there were no significant development operations conducted on the field during 2013.

In January 2014, the Group mobilized a drilling rig to commence a two well development drilling programme on the VM field. The first well is VM#3 which is located in the centre of the field. The well is expected to reach its target depth in the first half of 2014. The second well, to be drilled subsequently is VM#5.

Oil production

Having completed its fifth year of full time production, the Yuzhny Uzenskoye oil field is the Group's longest established field. It continues to produce under natural reservoir pressure drive and with no water cut. As the oil has been produced, the oil:water contact in the reservoir has risen and since the start of 2013, wells at the edge of the field have exhibited some water cut and were shut in. As a consequence, oil production from the field has been managed at lower production rates. In addition, during the spring and, exceptionally, during the Autumn of 2013 weather related downtime had a further impact on production from the field. Consequently, production from Yuzhny Uzenskoye during 2013 reduced to 735 bopd (2012: 1,109 bopd).

In June 2013, following a successful flow test and workover, the Sobolevskaya #11 well in the Urozhainoye-2 licence was put on production. Since starting production, this well has produced a total of 31,637 barrels of oil (2012: nil). Between August and December 2013 the well has been producing steadily at a rate of 170 bopd. The well was originally drilled by a previous licencee. The Group acquired the rights to produce from the well for a nominal consideration in 2011.

Production from the Yuzhny Uzenskoye and Sobolevskoye fields, whilst of modest scale, remains very profitable for the Group and a useful contributor of cash flow.

Exploration

The Group has identified a number of exploration targets in the Karpenskiy Licence Area at shallow horizons of between 1,000 and 2,000 metres depth. These provide low cost opportunities to add potentially material oil reserves. The Group's current priority is the development of its gas and condensate fields and a return to active exploration is to be considered for 2015 and beyond.

The Group has fulfilled all its licence commitments on the Karpenskiy Licence Area and further drilling in the area is discretionary. Following completion of exploration activities on the Pre-Caspian and Urozhainoye-2 licence areas, the Group decided to relinquish the Pre-Caspian licence entirely as well as the exploration areas of Urozhainoye-2, although in the latter block an area covering the producing Sobolevskoye oil field has been retained.

Oil, gas and condensate reserves as of 1 January 2014

During 2012, an independent evaluation of the Company's oil, gas and condensate reserves was conducted by Miller and Lents Ltd.

The independent assessment of the reserves and net present value of future net revenue ("NPV") attributable to the Company's three principal fields, Dobrinskoye, Vostochny Makarovskoye and Uzenskoye, as at 1 August 2012, was prepared in accordance with reserve definitions prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE).

The following table shows the Proven and Probable reserves as evaluated by Miller & Lents as at 1 August 2012, adjusted by management for subsequent production.

Oil, gas and condensate reserves

Notes:

1. The reserves and production numbers shown exclude all volumes related to the Sobolevskoye field which was not included in the Miller and Lents reserve study of 2012. The numbers for Sobolevskoye are estimated by management not to be material in the context of total Group reserves.

2. There has been no external re-assessment of reserves subsequent to the Miller and Lents reserve study of 2012.

3. The above reserve estimates, prepared in accordance with reserve definitions prepared by the Oil and Gas Reserves Committee of the SPE, have been reviewed and verified by Mr. Mikhail Ivanov, Director and Chief Executive Officer of Volga Gas plc, for the purposes of the Guidance Note for Mining, Oil and Gas companies issued by the London Stock Exchange in June 2009. Mr. Mikhail Ivanov holds a M.S. Degree in Geophysics from Novosibirsk State University. He also has an MBA degree from Kellogg School of Management (Northwestern University). He is a member of the Society of Petroleum Engineers.

Financial Review

Results for the year

In 2013, the Group generated US$34.6 million in turnover (2012: US$28.3 million) from the sale of 547,257 barrels of crude oil and condensate (2012: 529,501 barrels) and 3,128 million cubic feet of natural gas (2012: 1,193 million cubic feet). Oil and condensate sales were made into the domestic market during the period. The average price realised for liquids was the equivalent of US$47.63 per barrel (2012: US$48.21 per barrel). The gas sales price during 2013 averaged US$2.73 per thousand cubic feet (2012: $2.32 per thousand cubic feet). With sales made exclusively into the regional market in the Volga region at the wellhead, our oil and condensate sales prices closely reflect international prices, adjusted for export taxes and transportation costs. Production activities generated a gross profit of US$16.2 million in 2013 (2012: gross profit of US$11.7 million).

In 2013, the total cost of production increased to US$5.9 million (2012: US$3.8 million), with the incremental costs primarily incurred in gas processing expenses. Production based taxes were US$8.1 million (2012: US$8.9 million) reflecting the increase in the proportion of gas in the Group's production and lower rates of Mineral Extraction Tax ("MET") charged on gas condensate compared to crude oil. MET in 2013 represented 23.0% of revenues (2012: 31.6% of revenues). The gross profit margin in 2013 was 46.7% (2012: 41.4%).

Operating and administrative expenses in 2013 were US$4.0 million (2012: US$9.9 million, including a provision of US$2.9 million for disputed recovery of VAT).

The Group experienced a significant increase in EBITDA (defined as operating profit before non-cash charges, including the VAT provision, exploration expense, depletion and depreciation) to US$14.8 million (2012: US$8.0 million) as a result of the higher revenues partly offset by higher expenses. As a reflection of increasing cost efficiency with rising throughput at the gas plant EBITDA per barrel of oil equivalent sold in 2013 was US$13.80 (2012: US$10.96).

After recording an exploration and evaluation expense of US$2.5 million (2012: US$8.5 million), and other non-cash expenses of US$ 1.4 million (2012: US$ 0.2 million) the Group recorded an operating profit for 2013 of US$8.2 million (2012: operating loss of US$5.9 million). The exploration and evaluation charge in 2013 was primarily related to the write off of the remaining assets associated with the Pre-Caspian Licence area which has been relinquished.

After including net interest expense of US$0.2 million (2012: US$0.2 million) and other gains of $1.6 million net of foreign exchange (2012: net other and foreign exchange losses of US$0.2 million), the Group recognised a profit before tax of US$9.6 million (2012: loss before tax of US$6.3 million) and reported net profit after tax of US$8.6 million (2012: net loss after tax of US$7.4 million) after taking a deferred tax charge of US$1.0 million (2012: US$1.1 million).

No dividends have been paid or proposed for the year (2012: nil).

Cash flow

Group cash flow from operating activities was US$15.4 million (2012: US$5.4 million). Net working capital movements contributed to a cash outflow of US$1.2 million in 2013 (2012: US$2.4 million inflow from working capital movements). With reduced capital expenditures in 2013, the net outflow from investing activities was US$6.3 million (2012: US$13.7 million). Net cash outflow from financing activities was US$8.1 million (2012: inflow of US$4.8 million) as a result of amortization payments and prepayment of the final balance of the bank loan.

Capital Expenditure

During 2013 a total of US$6.2 million was utilised in investing activities (2012: US$13.7 million). In 2013 all of the capital expenditure was on development and producing assets (2012: US$10.3 million on producing and development assets and US$ 3.4 million on exploration and appraisal). The most significant individual components of the capital expenditure in 2013 relate to the Dobrinskoye gas plant upgrade.

Balance sheet and financing

As at 31 December 2013, the Group held cash and bank deposits of US$8.1 million (2012: US$7.0 million) with no debt (31 December 2012: US$8.0 million bank debt). The bank loan was drawn during 2012 and was subject to monthly repayments from October 2012. In December 2013 the remaining balance of the bank loan was repaid in full. All of the Group's cash balances are held in bank accounts in the UK and Russia.

As at 31 December 2013, the Group's intangible assets decreased to US$6.4 million (2012: US$9.6 million) after the write off of assets relating to the PreCaspian Licence. Property, plant and equipment, decreased to US$98.3 million (2012: US US$103.7 million, primarily reflecting the impact of foreign exchange adjustments.

Management believes that the Group's continuing capital expenditures will be less than cash flow from operations and cash-on-hand. The Group will consider additional debt facilities to fund the longer term development of its existing licences as appropriate.

The Group's financial statements are presented on a going concern basis.

Financial and operational summary

Group Income Statement

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Group Statement of Comprehensive Income

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Group Balance Sheet

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Group Cash Flow Statement

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Group Statement of Changes in Shareholders' Equity

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1. Summary of significant accounting policies

The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied to all the years presented, unless otherwise stated.

1.1 Basis of preparation

Both the parent company financial statements and the Group financial statements have been prepared in accordance with International Financial Reporting Standards (IFRSs), as adopted by the European Union (EU), International Financial Reporting Interpretations Committee (IFRIC) interpretations, and the Companies Act 2006 applicable to companies reporting under IFRS. The consolidated financial statements have been prepared under the historical cost convention and in accordance with applicable accounting standards.

The preparation of financial statements in conformity with IFRSs requires the use of certain critical accounting estimates. It also requires management to exercise its 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.

No income statement is presented for Volga Gas plc as permitted by Section 408 of the Companies Act 2006.

The Group's business activities, together with the factors likely to affect its future development, performance and position set out in the Business Review in pages 5 to 10; the financial position of the Group, its cash flows, liquidity position and borrowing facilities are described in the financial review on page 7. In addition, the Group's objectives, policies and processes for measuring capital, financial risk management objectives, details of financial instruments and exposure to credit and liquidity risks are described in Note 3. Having reviewed the future cash flow forecasts of the Group, the Directors have concluded that the Group will continue to have access to sufficient funds in order to meet its obligations as they fall due for at least the foreseeable future and thus continue to adopt the going concern basis of accounting in preparing the annual financial statements.

Following a review by management, it was decided, as of 2013, to allocate property tax expenses from Other Operating and Administrative costs to Cost of Sales as this more accurately reflects the nature of the expenses. The respective prior year costs have been restated accordingly.

1.2 Oil and gas assets

The Company and its subsidiaries apply the successful efforts method of accounting for Exploration and Evaluation ("E&E") costs, in accordance with IFRS 6 "Exploration for and Evaluation of Mineral Resources". Costs are accumulated on a field-by-field basis.

Capital expenditure is recognised as property, plant and equipment or intangible assets in the financial statements according to the nature of the expenditure and the stage of development of the associated field, i.e. exploration, development, production.

(a) Exploration and evaluation assets

Costs directly associated with an exploration well, including certain geological and geophysical costs, and exploration and property leasehold acquisition costs, are capitalised as intangible assets until the determination of reserves is evaluated. If it is determined that a commercial discovery has not been achieved, these costs are charged to expense after the conclusion of appraisal activities. Exploration costs such as geological and geophysical that are not directly related to an exploration well are expensed as incurred.

Once commercial reserves are found, exploration and evaluation assets are tested for impairment and transferred to development assets. No depreciation or amortisation is charged during the exploration and evaluation phase.

(b) Development assets

Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells into commercially proven reserves, is capitalised within property, plant and equipment. When development is completed on a specific field, it is transferred to producing assets as part of property, plant and equipment. No depreciation or amortisation is charged during the development phase.

(c) Oil and gas production assets

Production assets are accumulated generally on a field by field basis and represent the cost of developing the commercial reserves discovered and bringing them into production together with E&E expenditures incurred in finding commercial reserves and transferred from the intangible E&E assets as described above.

The cost of production assets also includes the cost of acquisitions and purchases of such assets, directly attributable overheads, finance costs capitalised and the cost of recognising provisions for future restoration and decommissioning.

Where major and identifiable parts of the production assets have different useful lives, they are accounted for as separate items of property, plant and equipment. Costs of minor repairs and maintenance are expensed as incurred.

(d) Depreciation/amortisation

Oil and gas properties are depreciated or amortised using the unit-of-production method. Unit-of-production rates are based on proved and probable reserves, which are oil, gas and other mineral reserves estimated to be recovered from existing facilities using current operating methods. Oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the field storage tank.

(e) Impairment - exploration and evaluation assets

Exploration and evaluation assets are tested for impairment prior to reclassification to development tangible assets, or whenever facts and circumstances indicate that an impairment condition may exist. An impairment loss is recognised for the amount by which the exploration and evaluation assets' carrying amount exceeds their recoverable amount. The recoverable amount is the higher of the exploration and evaluation assets' fair value less costs to sell and their value in use. For the purposes of assessing impairment, the exploration and evaluation assets subject to testing are grouped with existing cash-generating units of production fields that are located in the same geographical region.

(f) Impairment - proved oil and gas production properties

Proven oil and gas properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset's carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset's fair value less costs to sell and value in use. The cash generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped together where the cash flows of each field are interdependent, for instance where surface infrastructure is used by one or more field in order to process production for sale.

(g) Decommissioning

Provision is made for the cost of decommissioning assets at the time when the obligation to decommission arises. Such provision represents the estimated discounted liability (the discount rate used currently being at 10% per annum) for costs which are expected to be incurred in removing production facilities and site restoration at the end of the producing life of each field. A corresponding item of property, plant and equipment is also created at an amount equal to the provision. This is subsequently depreciated as part of the capital costs of the production facilities. Any change in the present value of the estimated expenditure attributable to changes in the estimates of the cash flow or the current estimate of the discount rate used are reflected as an adjustment to the provision and the property, plant and equipment. The unwinding of the discount is recognised as a finance cost.

1.3 Inventories

Crude oil inventories are stated at the lower of cost of production and net realisable value. Materials and supplies inventories are recorded at average cost and are carried at amounts which do not exceed the expected recoverable amount from use in the normal course of business. Cost comprises direct materials and, where applicable, direct labour plus attributable overheads based on a normal level of activity and other costs associated in bringing inventories to their present location and condition.

1.4 Trade and other receivables

Trade and other receivables are recorded initially at fair value and subsequently measured at amortised cost using the effective interest method, less provision for impairment. A provision for impairment of trade 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 the 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.

1.5 Current and deferred income tax

The tax expense for the period comprises current and deferred tax. Tax is recognised in the income statement, except to the extent that it relates to items recognised in other comprehensive income or directly in equity. In this case the tax is also recognised in other comprehensive income or directly in equity, respectively.

The current income tax charge is calculated on the basis of the tax laws enacted or substantively enacted at end of the reporting period in the countries where the Company's subsidiaries operate and generate taxable income. Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation. It establishes provisions where appropriate on the basis of amounts expected to be paid to the tax authorities.

Deferred income tax is recognised, using the liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the consolidated financial statements. However, the deferred income tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at the time of the transaction affects neither accounting nor taxable profit or loss. Deferred income tax is determined using tax rates (and laws) that have been enacted or substantially enacted by the end of the reporting period and are expected to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled.

Deferred income tax assets are recognised to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilised.

Deferred income tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets against current tax liabilities and when the deferred income taxes assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the balances on a net basis.

1.6 Revenue recognition

Revenue comprises the fair value of the consideration received or receivable for the sale of oil and gas in the ordinary course of the Group's activities. Revenue is shown net of value added tax, returns, rebates and discounts and after eliminating sales within the Group. Revenue from the sale of oil or gas is recognised when the oil/gas is delivered to customers and title has transferred. In 2013 and 2012 , the Group's revenue related to sales of crude oil and condensate collected directly by customers and gas sales made at the entry to the gas distribution system.

1.7 Prepayments

Prepayments are carried at cost less provision for impairment. A prepayment is classified as non-current when the goods or services relating to the prepayment are expected to be obtained after one year, or when the prepayment relates to an asset which will itself be classified as non-current upon initial recognition. Prepayments to acquire assets are transferred to the carrying amount of the asset once the Group has obtained control of the asset and it is probable that future economic benefits associated with the asset will flow to the Group. Other prepayments are written off to profit or loss when the goods or services relating to the prepayments are received. If there is an indication that the assets, goods or services relating to a prepayment will not be received, the carrying value of the prepayment is written down accordingly and a corresponding impairment loss is recognised in profit or loss for the year.

1.8 Provisions

Provisions for environmental restoration, restructuring costs and legal claims are recognised when: the group has a present legal or constructive obligation as a result of past events; it is probable that an outflow of resources will be required to settle the obligation; and the amount has been reliably estimated. Restructuring provisions comprise lease termination penalties and employee termination payments. Provisions are not recognised for future operating losses.

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 recognised even if the likelihood of an outflow with respect to any one item included in the same class of obligations may be small.

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. The increase in the provision due to passage of time is recognised as interest expense.

2. Cost of sales and administrative expenses

Cost of sales and administrative expenses are as follows:

 (a) Exploration and evaluation The principal component of the 2012 exploration and evaluation expense is the impairment charge on the carrying value of intangible assets relating to the two unsuccessful exploration wells completed during 2012 . This includes licence acquisition costs as wells as the cost of seismic studies and costs of drilling and testing operations. For 2013, the principal component was impairment of the carrying value of the Pre-Caspian licence which was relinquished after the year end.

 (f) Provision for disputed VAT During 2012, the Group paid a sum of US$2.9 million in settlement of a disputed VAT claim. Recovery of this is subject to a continuing court process in Russia. Management continues to pursue its recovery.

(g) Taxes other than payroll and mineral extraction In the year ended 31 December 2013 property taxes relating to producing assets were allocated to Field operating expenses rather than to Taxes other than payroll and mineral extraction. The 2012 comparative numbers have been re-stated accordingly.

(h) Write-off of development assets The Write off of development assets comprises and impairment of US$1.3 million (2012: nil) of amounts of Property Plant and Equipment associated with redundant assets (Note 11.) and costs of US$0.1 million (2012: US$0.2 million) incurred during the year in dismantling and site restitution in relation to these assets.

3. Finance income

Finance income comprises interest earned during the period on cash balances with different financial institutions (Note 13). Interest expense in 2012 relates to a two year amortising debt facility (Note 18).

4. Other gains and losses

Mineral extraction tax refund related to amounts over-charged in 2009, 2010 and 2011.

5. Intangible assets

Intangible assets represent exploration and evaluation assets such as licenses, studies and exploratory drilling, which are stated at historical cost.

During 2012 management undertook a review of the cost pool allocation of its assets. Following this review the licence acquisition costs and other intangible assets associated with producing oil and gas fields were transferred to Property, plant and equipment (Note 11). As a result of this transfer all producing assets are allocated to the same financial statement caption and are therefore consistent with how the results are monitored.

During 2012 certain costs relating to the drilling of appraisal and exploration wells were transferred from PP&E Work in Progress to Intangible Assets Work in Progress: Exploration and Evaluation, in line with the clarified accounting policy on exploration and evaluation assets (see Note 2a). The opening balances and movements in the relevant portions of Intangible Assets and PP&E have been restated to reflect this. As the related costs were expensed entirely in 2012, there was no restatement in the closing balances as at 31 December 2012.

6. Property, plant and equipment

Movements in property, plant and equipment, for the years ended 31 December 2013 and 2012 are as follows:

The opening balance at 1 January 2012 and movements during 2012 of Work in Progress have been restated to allocate costs of certain exploration and appraisal drilling to Intangible Assets Work in Progress: Exploration and Evaluation. See Note 10 above.

Impairment of US$1.3 million in 2013 relates to amounts of Property Plant and Equipment associated with redundant assets (Note 5.) Impairments of US$7.3 million in 2012 relate to the costs of an unsuccessful exploratory well.

7. Non-current assets

Management believes that it may not be able to recover all VAT specific to license and exploration and evaluation contractors' payments within the 12 months of the balance sheet date. Therefore this VAT is classified as a non-current asset.

8. Inventories

 9. Other receivables - Group

Prepayments are to contractors and relate to initial advances made in respect of drilling, construction and other projects. Trade receivables relate to sales of gas and condensate. A significant increase in sales volumes occurred during the latter months of 2013. The receivables were settled on schedule subsequent to the balance sheet date.

10. Debt

On 26 March 2012, the Group entered into a loan agreement to provide up to US$10 million by way of a two year amortising credit facility. The balance of the loan was repaid in full by 31 December 2013.

11. Trade and other payables