Preliminary Results

30 March 2015

VOLGA GAS PLC

Preliminary results for the year ended 31 December 2014

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 2014.

During 2014 the Group benefitted from a full year's operation at increased throughput at the Dobrinskoye gas plant which enabled sustained production from the Group's largest field, Vostochny Makarovskoye ("VM"). This has enabled the Group to produce at an average rate of 4,244 barrels of oil equivalent per day ("boepd") during 2014, an increase of 45% over the average rate for 2013. This higher rate of production has resulted in record Group revenues, EBITDA and profits for 2014 and enabled the Group to increase its net cash position after paying a maiden interim dividend.

FINANCIALHIGHLIGHTS

· Revenues up 14% to US$39.4 million (2013: US$34.6 million).

· EBITDA up 18% to US$17.4 million (2013: US$14.5 million).

· Profit before tax up 79% to US$16.3 million (2013: US$9.1 million), including other income (mainly foreign exchange gain) of US$3.3 million (2013: US$1.6 million).

· Net operating cash flow up 6% to US$16.3 million (2013: US$15.4 million).

· Net cash increased to US$15.8 million as at 31 December 2014 (31 December 2013: US$8.1 million) after payment of US$3.0 million maiden interim dividend.

· Final dividend of US$0.0125 per Ordinary Share recommended.

PRODUCTION & DEVELOPMENT

· Group average production in 2014 up 45% to 4,244 boepd (2013: 2,958 boepd).

· VM and Dobrinskoye fields produced steadily from existing wells at an average of 3,543 boepd (2013: 2,132 boepd), up by 66%.

· Plan to complete drilling the VM#3 well, to drill a sidetrack on VM#4 and start drilling the new VM#5 well during 2015.

DOBRINSKOYE GAS PLANT

· Dobrinskoye gas plant operated successfully during 2014 at rates of over 500,000 cubic metres per day (17.7 mmcf/d).

· Completed minor additional modifications to meet regulatory requirements and improve efficiency.

· Commenced preliminary feasibility and design work for a major upgrade to capture and produce liquid petroleum gases ("LPG") from the gas stream.

· LPG construction expected to commence in 2016.

CURRENT TRADING AND OUTLOOK

· Start to 2015 impacted by

- Lower international oil prices and weak Rouble reduce US$ equivalent revenues.

- Production in January and February disrupted by changes in the domestic market following adjustments to new export tax regime.

- Domestic prices for oil and condensate currently below netback parity.

- Significant increases in Mineral Extraction Tax rates imposed since the start of 2015.

· The Board is confident that the Group is well positioned with a strong balance sheet, sustainable production and potential to increase profitability with the LPG project.

Mikhail Ivanov, Chief Executive of Volga Gas, commented:

"2014 was financially a successful year for Volga Gas with strong cash generation enabling the Group to strengthen its liquidity. This will enable the Group to weather the currently challenging position in the domestic oil and gas markets in Russia and to continue with the plans to develop its key assets, including the significant investment represented by the proposed LPG project. In the light of the current financial conditions prevailing in Russia and given the Group's requirement to fund the proposed LPG project and to provide greater flexibility, the Board has decided that it is in the best interests of the shareholders for dividend payments to be kept at a level which can be sustained and grown as the profits increase in the future.

"We remain positive about the potential for growth, both in reserves and production from our licences. 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 and final dividend

The Group's full report and accounts, including notice of the annual general meeting of the Company 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.

The final dividend of US$0.0125 proposed by the Board is to be paid on 10 June 2015, subject to approval at the Company's Annual General Meeting on 5 June 2015, to shareholders on the register on 15 May 2015.

Chairman's Statement

Dear Shareholder,

2014 was a significant year for Volga Gas, in which the Group achieved its first full year of gas and condensate production with its wells producing up to their current capacity. The average production rate for 2014 was 4,244 barrels of oil equivalent per day ("boepd"), a 43% increase over the average 2,965 boepd achieved in 2013. With strong cash generation arising from this production, it was gratifying to see the financial position strengthen sufficiently for the Company to make its first interim dividend payment and still report a significant increase in net cash during the year.

The Group now faces a number of challenges, not the least of which is the general economic situation in Russia, where the dramatic fall in international oil prices are likely to have a significant impact on the domestic economy at least in the short term. While the weakness of the Russian Ruble, largely matching the drop in the oil price, is likely to enable the Group's profitability to be maintained, our profits for future periods as reported in US Dollars may be significantly lower than in recent years. The declining Ruble has also led to a significant shrinking of the Group balance sheet as assets have been adjusted to the exchange rate prevailing on 31 December 2014.

Since the year end production based taxes have increased significantly - especially as applied to condensate, which hitherto had been taxed at a rate comparable to gas, but is now taxed closer to the level applied to oil. While there is nothing that can be done by the Group to change the tax rates, management is considering ways to optimize the business. A key project that is currently under consideration is the installation of additional units at the Dobrinskoye gas plant to extract liquid petroleum gases ("LPG"). Initial studies suggest that this could be a rewarding investment for the Group and a significant enhancement to the value of the reserves.

Most importantly, Volga Gas benefits from low operating costs and, with its fields based close to market is able to operate profitability even with significantly reduced oil and gas prices. The strong balance sheet, with no debt and a liquidity position of US$15.8 million built up from retained cash flow, provides a solid foundation for the Group to continue development of its fields and to maximize its production profile.

The Group holds significant proven reserves in its three principal fields. These fields form the basis of sustainable and growing production in the near term. Our fields are advantageously located and our costs are sufficiently low for us to achieve positive returns at current oil and gas prices. 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.

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.

In the light of the current financial conditions prevailing in Russia and given the Group's requirement to fund the proposed LPG project, which as outlined by the Chief Executive below is expected to enhance the profitability of the Group's gas and condensate production, the Board has decided that it is in the best interests of the shareholders for a final dividend to be at a level which can be sustained and grown as the profits increase in the future. Accordingly, the Board is recommending a final dividend of US$0.0125 per Ordinary Share bringing the total dividend for the year to US$0.05 per Ordinary Share.

You will be aware that in June 2014 the Board was exploring strategic options for the business, including seeking potential offerors for the Company by means of a "formal sale process" under which the Board of Volga Gas is able to have discussions with third parties interested in such a transaction on a confidential basis. Whilst there was some interest received, the subsequent developments in the external conditions led the Board to conclude that an acceptable proposal would not be received. The formal sale process was accordingly concluded in January 2015. The Board continues to seek to maximize the value of the Company for shareholders.

Aleksey Kalinin

Chairman

Chief Executive's Report

As the Chairman has noted, 2014 was the first full year in which Volga Gas produced its gas and condensate wells at capacity with the gas plant operating fully to expectations and enabling the Group to record a 43% increase in production compared to 2013. This increased production combined with steady oil and gas prices - at least for the first ten months of 2014 - enabled the Group to enjoy strong cash flow and strengthen its financial position, while providing the flexibility to manage the effects of the subsequent downturn in international oil prices.

As detailed in the Operational Review below, the majority of the work on our producing assets base remained focused on our main field, Vostochny Makarovskoye ("VM"). On VM, the Group commenced the drilling of a new producing well, VM#3. Although, as detailed below, the well was not completed during 2014, we now expect it to be producing in mid-2015.

Crude oil production, on the other hand, continued to decline. Production from the Uzenskoye field was further reduced to prevent a rising water cut. In addition, production from the single well Sobolevskoye field ceased. While it is now a minor part of the Group's business, Volga Gas had made very good returns from these assets and continues to benefit from the cash generation they provide.

In 2014 as 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.

2015 Objectives - VM Development and LPG Project

The Group's key operational objectives in 2015 are to complete the drilling of the VM#3 and VM#4 wells on the VM field and to complete the Front End Engineering and Design work for an LPG extraction project. The aim is to increase production from the VM field so as to maximize the utilisation of the 1 million m3 per day (35 mmcf/d) processing capacity of the gas plant.

Based on initial studies, the LPG project could enable the Group to achieve a significant enhancement of the value of the gas plant output and the investment required for this could be recovered within three years from the increased income and improved profitability.

Finance

The Group maintained a strong level of cash generation from operating activities throughout 2014, enabling it to fund its capital expenditure for the year from operating cash flow and to make its maiden interim dividend payment of $0.0375 per Ordinary Share in October 2014, while increasing its cash balance from US$8.1 million to US$15.8 million during the year.

Capital expenditure in 2014 was less than originally planned mainly because the operational difficulties experienced on drilling the VM#3 well led to a delay in the completion of that well and deferral of further drilling into 2015.

Although the planned field development expenditures in 2015 and beyond are expected to be funded from operating cash flow, the Group may consider a moderate level of borrowing to be appropriate to fund significant value accretive investments like the LPG project.

Current trading

As announced on 19 February 2015, during January and February 2015 disruption to the domestic oil market in Russia following the recently implemented tax changes had an impact on the ability of purchasers of condensate from Volga Gas to take delivery and subsequently led to the temporary suspension of production at the Company's VM and Dobrinskoye gas fields. Consequently for this period actual production was significantly below the capacity of the fields. Since 16 February 2015, Group production has resumed at close to full production capacity of approximately 4,500 barrels of oil equivalent per day.

The major tax changes implemented at the start of 2015 included a significant reduction in the rate of export tax coupled with a rise in Mineral Extraction Taxes on oil and condensate. However the domestic market prices in Russia, which hitherto reflected full netback pricing, have not risen to match the drop in export taxes. Meanwhile MET charges are calculated with reference to export prices and this has led to the group experiencing higher than anticipated MET charges relative to income since the start of 2015.

Outlook

It is our current expectation that the VM#3 well will be completed during H1 2015. In addition, we have mobilized a second rig to drill a sidetrack to the VM#4 well, which was originally drilled in 2008 but was not productive. The sidetrack will be deviated towards the centre of the field where it is expected to intersect productive reservoir. Further drilling, notably the VM#5 well, is also anticipated for later in 2015. Assuming successful drilling of the new wells, management expects to increase production to above 5,000 boepd by the end of 2015.

Clearly with significantly lower oil prices and a sharply devalued Ruble, the revenues as reported in US dollars would not reflect this progress. However, with its costs almost entirely in Rubles, the Group is expected to remain profitable and cash generative even without a significant recovery in oil prices and in spite of the increased rate of production taxes that have come into effect.

The total capital expenditure budgeted for 2015 is approximately US$14 million. All of this expenditure is discretionary and can be deferred or cancelled if necessary. Management expects the 2015 capital expenditure 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

Operations overview

After the Group received formal approval of the upgrade works at the Dobrinskoye gas processing plant in November 2013, production of gas and condensate from the Group's VM and Dobrinskoye fields increased to reflect their existing productive capacity, more than doubling the production rates achieved hitherto.

The overall level of production in 2014, at 4,244 boepd, was 43% above the 2,958 boepd achieved in 2013. This was driven by increased gas and condensate production from the VM and Dobrinskoye fields partly offset by declines in total oil production.

Average Oil production was lower in 2014 than in 2013, averaging 689 bopd in 2014 compared to 826 bopd in 2013. The reasons for the decline in oil production are detailed below.

As a consequence of the significant increase in production in 2014, revenues and EBITDA levels in 2014 were well ahead of 2013, although with the rapidly increasing proportion of gas in the mix, the revenue growth was not quite as impressive as production growth.

Gas processing plant

Since November 2013, the Dobrinskoye gas processing plant has been consistently operating at rates of over 500,000 m3 per day (17.7 million cubic feet per day("mmcf/d")) with the exception of periods of planned shut down for maintenance. During 2014 a number of minor additional modules, as required by the state construction agency, Gosstroi, were installed on the plant. During 2014 the Group incurred approximately US$2.7 million (2013: US$ 3.6 million) of capital expenditure on the gas plant.

During 2014, 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 savings on the cost of chemicals used in the process.

The Group has conducted a preliminary evaluation of the feasibility of additional processing to extract an LPG stream from the gas, primarily propane and butane. The initial studies suggest that there are significant benefits from this project, from the extraction of additional higher value product that are otherwise either flared or sent down the gas pipeline with the sales gas. In addition, consideration is being given to a modification of the sulphur extraction process that would significantly reduce the cost of chemicals. The initial economic modelling suggests that the capital investment on this project can be recovered within three years from the incremental revenue and cost savings.

In November 2014, the Group commissioned a front end engineering and design study which will form the basis of a final investment decision on this project by the Board during 2015.

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. Since November 2013, production 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("bpd") of condensate.

During 2014, production derived from both fields averaged 15.5 mmcf/d of gas and 966 bpd of condensate (2013: 8.7 mmcf/d of gas and 682 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 at a fixed Ruble contract gas sales price. With the devaluation of the Ruble during 2014, the US dollar equivalent of the price declined during 2014. The average gas sales price for 2014 was the equivalent of US$2.15 per thousand cubic feet, net of VAT (2013: US$2.73). During 2014 the average condensate sales price was US$45.07 per barrel (2013: US$47.00 per barrel).

Average unit production costs on the gas-condensate fields declined to US$6.49 per boe in 2014 (2013: US$8.27) primarily as the significant element of fixed plant costs were spread over higher production rates. Management anticipates further reductions in unit costs as capacity utilisation rises towards 100%.

During 2014, the main development activity was the drilling of the VM#3 production well. Following slow progress with the drilling, it eventually became clear that the drilling contractor had encountered mechanicals difficulties, with the drill pipe being stuck at a depth of 2,556 metres. Subsequent attempts by the drilling contractor to release the stuck drill pipe were not successful and operations were temporarily suspended in September 2014. The Group subsequently agreed with the drilling contractor a cost effective means of completing the VM#3 production well. Operations recommenced in January 2015 with the aim of completing the well in time to commence production during the first half of 2015. As the well is being drilled on a turnkey contract basis the cost has not been materially affected.

In January 2015, a second rig was mobilized to drill a sidetrack to the VM#4 well which is currently not producing. There are, in addition, contingent plans to drill a further well, VM#5 later in 2015.

Oil production

Having completed its sixth 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 minimal 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 declining production rates. There remains a shallower undeveloped reservoir which may be brought into production by re-using existing wells on the field.

In June 2013, following a successful flow test and workover, the Sobolevskaya #11 well in the Urozhainoye-2 licence was put on production. However, in August 2014 production from the well ceased. An undeveloped oil pool has been identified within the Sobolevskaya field. The 2015 capital budget includes a sidetrack from the #11 well to develop this resource.

The Group's oil production, 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 later in 2015 and beyond. The Group has fulfilled all its licence commitments on the Karpenskiy Licence Area and further drilling in the area is discretionary.

Oil, gas and condensate reserves as of 1 January 2015

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 Group'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. There has been no external reassessment of reserves subsequent to the Miller and Lents reserve study of 2012.

2. The reserves and production numbers shown above 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 Group reserves.

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 2014, the Group generated US$39.4 million in turnover (2013: US$34.6 million) from the sale of 603,950 barrels of crude oil and condensate (2013: 547,257 barrels) and 5,671 million cubic feet of natural gas (2013: 3,128 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$45.07 per barrel (2013: US$47.63 per barrel). The gas sales price during 2014 averaged US$2.15 per thousand cubic feet (2013: US$2.73 per thousand cubic feet), the fall being entirely attributable to the devaluation of the Ruble. With sales made exclusively into the market in the Volga region at the wellhead, our oil and condensate sales prices reflect international prices, adjusted for export taxes and transportation costs. Production activities generated a gross profit of US$16.9 million in 2014 (2013: gross profit of US$16.2 million).

In 2014, the total cost of production increased to US$7.8 million (2013: US$5.9 million), with the incremental costs primarily incurred in volume related costs at the Group's gas processing plant. Production based taxes were US$8.3 million (2013: US$8.1 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 compared to crude oil. MET in 2014 represented 21.2% of revenues (2013: 23.0% of revenues). The gross profit margin in 2014 was 42.9% (2013: 46.7%).

Operating and administrative expenses in 2014 were US$4.2 million (2013: US$4.0 million).

The Group experienced a significant increase in EBITDA (defined as operating profit before non-cash charges, including exploration expense, depletion and depreciation) to US$17.4 million (2013: US$14.8 million) as a result of the higher revenues partly offset by higher expenses. As a reflection of the increasing proportion of gas in the sales mix. EBITDA per barrel of oil equivalent sold in 2014 was US$11.24 (2013: US$13.81).

After recording no exploration and evaluation expense (2013: US$2.5 million), or other asset impairment expenses (2013: US$ 1.4 million) the Group recorded an operating profit for 2014 of US$12.8 million (2013: US$8.2 million).

After including net interest income of US$0.2 million (2013: net interest expense of US$0.2 million) and other gains, predominantly from foreign exchange, of $3.3 million (2013: net other gains of US$1.6 million), the Group recognised a profit before tax of US$16.3 million (2013: US$9.6 million) and reported net profit after tax of US$13.1 million (2013: US$8.6 million) after taking a deferred tax charge of US$3.3 million (2013: US$1.0 million). Included in Other income in 2014 was a foreign exchange gain of US$3.2 million arising from US dollar cash balances held by Russian subsidiaries which have the Ruble as functional currency (2013: US$0.3 million loss on foreign exchange).

Cash flow

Group cash inflow from operating activities was US$16.2 million (2013: US$15.4 million). Net working capital movements contributed to a cash inflow of US$0.5 million in 2014 (2013: US$1.2 million outflow from working capital movements). With slightly lower capital expenditures in 2014, the net outflow from investing activities was US$5.5 million (2013: US$6.2 million). Net cash outflow from financing activities was US$3.0 million (2013: outflow of US$8.1 million).

Dividend

 In July 2014, the Board announced the adoption of a policy to distribute approximately 50% of consolidated net profit after tax as a cash dividend. A maiden interim dividend of US$0.0375 per share was paid on 24 October 2014. In light of the material reduction in the oil price in recent months, adverse financial conditions currently prevailing in Russia and the Group's plans for significant new investment in the LPG project the Board has decided to restrain the level of dividend payments. Accordingly, the Board is recommending a final dividend of US$0.0125 per Ordinary share, bringing the total payment for the year to US$0.05 per Ordinary Share (2013: nil).

Capital expenditure

During 2014 capital expenditure of US$5.9 million was incurred (2013: US$5.9 million). In both 2014 and 2013 all of the capital expenditure was on development and producing assets. The most significant individual components of the capital expenditure in 2014 relate to the Dobrinskoye gas plant and drilling on the VM field.

Balance sheet and financing

As at 31 December 2014, the Group held cash and bank deposits of US$15.8 million (2013: US$8.1 million) with no debt. All of the Group's cash balances are held in bank accounts in the UK and Russia and the majority of the Group's cash is held in US dollars.

As at 31 December 2014, the Group's intangible assets decreased to US$3.7 million (2013: US$6.4 million). Property, plant and equipment, decreased to US$57.8 million (2013: US$98.3 million), primarily reflecting the impact of foreign exchange adjustments.

On 9 July 2014 the capital reduction approved by shareholders at the Company's Annual General Meeting on 6 June 2014 became effective following confirmation by the High Court, the filing of the Court Order and a Statement of Capital with Companies House and the fulfilment of certain minor undertakings given to the Court. As a result, the Share Premium Account of the Company, amounting to US$165.9 million, was cancelled and the equivalent sum credited to the Company's Profit and Loss Account, thereby creating distributable reserves.

The Group's committed capital expenditures are less than expected cash flow from operations and cash-on-hand and such expenditures can be managed in light of the sharp reduction in international oil prices and the devaluation of the Ruble. The Group may consider additional debt facilities to fund the longer-term development of its existing licences and operational facilities as appropriate.

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

Tony Alves

Chief Financial Officer

Five year financial and operational summary

Principal Risks and Uncertainties

The Group is subject to various risks relating to political, economic, legal, social, industry, business and financial conditions.

The following risk factors, which are not exhaustive, are particularly relevant to the Group's business activities:

Volatility of oil prices

The supply, demand and prices for oil are influenced by factors beyond the Group's control. These factors include global and regional demand and supply, exchange rates, interest and inflation rates and political events. A significant prolonged decline in oil and gas prices could impact the profitability of the Group's activities. Additionally, the Group's production is predominantly sold in the domestic Russian markets which are influenced by domestic supply and demand factors, the level of Russian export taxes and regional transportation costs.

Substantially all of the Group's revenues and cash flows come from the sale of oil, gas and condensate. If sales prices should fall below and remain below the Group's cost of production for any sustained period, the Group may experience losses and may be forced to curtail or suspend some or all of the Group's production, at the time such conditions exist. In addition, the Group would also have to assess the economic impact of low oil and gas prices on its ability to recover any losses the Group may incur during that period and on the Group's ability to maintain adequate reserves.

The Group does not currently hedge its crude oil production to reduce its exposure to oil price volatility as the structure of taxes applied to oil production in Russia effectively reduce the exposure to international market prices for oil.

Oil and gas production taxes

The Group's sales generated from oil and gas production are subject to Mineral Extraction Taxes, which form a material proportion of the total costs of sales. The rates of these taxes are subject to changes by the Russian government. Changes to rates which come into effect during 2015 will materially increase the rates on crude oil, condensate and natural gas.

Exploration and reserve risks

Whilst the Group will seek to apply the latest technology to assess exploration licences, the exploration for, and development of, hydrocarbons is speculative and involves a high degree of risk. These risks include the uncertainty that the Group will discover sufficient commercially exploitable oil or gas resources in unproven areas of its licences. Unsuccessful exploration efforts may result in impairment to the balance sheet value of exploration assets.

During 2012, the Group commissioned a reserve evaluation based on reporting standards set by the Society of Petroleum Engineers. If the actual results of producing the Group's fields are significantly different to expectations, there may be changes in the future estimates of reserves. These may impact the balance sheet values of the Group's Intangible Assets and the Group's Property, Plant and Equipment.

Environmental risk

The oil and gas industry is subject to environmental hazards, such as oil spills, gas leaks, ruptures and discharges of petroleum products and hazardous substances. These environmental hazards could expose the Group to material liabilities for property damages, personal injuries, or other environmental harm, including costs of investigating and remediating contaminated properties.

The Group is subject to stringent environmental laws in Russia with regards to its oil and gas operations. Failure to comply with such laws and regulations could subject the Group to material administrative, civil, or criminal penalties or other liabilities. Additionally, compliance with these laws may, from time to time, result in increased costs to the Group's operations, impact production, or increase the costs of potential acquisitions.

The Group liaises closely with the Federal Service of Environmental, Technological and Nuclear Resources of the Saratov and Volgograd Oblasts on potential environmental impact of its operations and conducts environmental studies both as required by, and in addition to, its licence obligations to mitigate any specific risk. The Group's operations are regularly subject to independent environmental audit.

The Group did not incur any material costs relating to the compliance with environmental laws during the period.

Risk of operating oil and gas properties

The oil and gas business involves certain operating hazards, such as well blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and releases of toxic substances. Any of these operating hazards could cause serious injuries, fatalities, or property damage, which could expose the Group to liabilities. The settlement of these liabilities could materially impact the funds available for the exploration and development of the Group's oil and gas properties. The Group maintains insurance against many potential losses and liabilities arising from its operations in accordance with customary industry practices, but the Group's insurance coverage cannot protect it against all operational risks.

Foreign currency risk

The Group's capital expenditures and operating costs are predominantly in Russian rubles ("RUR") while a minority of costs are also in US dollars. Revenues are predominantly received in RUR so consequently the operating profitability is not materially exposed to moderate short-term exchange rate movements. The functional currency of the Group's operating subsidiaries is the RUR and the Group's assets and liabilities are predominantly RUR denominated. As the Group's presentational currency is the US dollar, the significant devaluation of the RUR against the US dollar would negatively impact the Group's financial statements.

Business in Russia

Amongst the risks that face the Group in conducting business and operations in Russia are:

§ Economic instability, including in other countries or the global economy that could lead to consequences such as hyperinflation, currency fluctuations and a decline in per capita income in the Russian economy.

§ Governmental and political instability that could disrupt, delay or curtail economic and regulatory reform, increase centralised authority or result in nationalisations.

§ Social instability from any ethnic, religious, historical or other divisions that could lead to a rise in nationalism, social and political disturbances or conflict.

§ Uncertainties in the developing legal and regulatory environment, including, but not limited to, conflicting laws, decrees and regulations applicable to the oil and gas industry and foreign investment.

§ Unlawful or arbitrary action against the Group and its interests by the regulatory authorities, including the suspension or revocation of their oil or gas contracts, licences or permits or preferential treatment of their competitors.

§ Lack of independence and experience of the judiciary, difficulty in enforcing court or arbitration decisions and governmental discretion in enforcing claims.

§ Unexpected changes to the federal and local tax systems.

§ Laws restricting foreign investment in the oil and gas industry.

Legal systems

Russia, and other countries in which the Group may transact business in the future, have or may have legal systems that are less well developed than those in the United Kingdom. This could result in risks such as:

• Potential difficulties in obtaining effective legal redress in the court of such jurisdictions, whether in respect of a breach of contract, law or regulation, including an ownership dispute.

• A higher degree of discretion on the part of governmental authorities.

• The lack of judicial or administrative guidance on interpreting applicable rules and regulations.

• Inconsistencies or conflicts between and within various laws, regulations, decrees, orders and resolutions.

• Relative inexperience of the judiciary and courts in such matters.

In certain jurisdictions, the commitment of local business people, government officials and agencies and the judicial system to abide by legal requirements and negotiated agreements may be more uncertain, creating particular concerns with respect to licences and agreements for business. These may be susceptible to revision or cancellation and legal redress may be uncertain or delayed. There can be no assurance that joint ventures, licences, licence applications or other legal arrangements will not be adversely affected by the jurisdictions in which the Group operates.

Liquidity risk

At 31 December 2014 the Group had US$15.8 million of cash and cash equivalents of which US$8.6 million was held in bank accounts in Russia. The Group intends to fund its ongoing operations and development activities from its cash resources and cash generated by its established operations. At 31 December 2014 the Group has budgeted capital expenditures of approximately US$14 million primarily for the continuing development of gas and condensate production. The Board considers that the Group will have sufficient liquidity to meet its obligations. All current and planned capital expenditures are discretionary and may be deferred or cancelled in the light of the Group's cash generation and liquidity position.

Through its ordinary course activities, the Group is exposed to legal, operational and development risk that could delay growth in its cash generation from operations or may require additional capital investment that could place increased burden on the Group's available financial resources.

Capital risk

The Group manages capital to ensure that it is able to continue as a going concern whilst maximising the return to shareholders. The Group is not subject to any externally imposed capital requirements. The Board regularly monitors the future capital requirements of the group, particularly in respect of its ongoing development programme. During 2012 management decided that having established a track record of reliable cash generation it was appropriate to introduce a modest proportion of debt into the capital structure and as such a loan of US$10 million was taken and which was fully repaid by 31 December 2013. Management expects that the cash generated by the operating fields will be sufficient to sustain the Group's operations and committed capital investment for the foreseeable future. Further short term debt facilities may be arranged to provide financial headroom for future development activities.

Abbreviated Financial Statements for the year ended 31 December 2014

Group Income Statement

(presented in US$ 000)

Group Statement of Comprehensive Income

(presented in US$ 000)

Group Balance Sheet

(presented in US$ 000)

Group Cash Flow Statements

(presented in US$ 000)

Notes to the Abbreviated Financial Statements for the year ended 31 December 2014

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 judgement in the process of applying the Group's accounting policies.

The Group's business activities, together with the factors likely to affect its future development, performance and position set out in the Strategic Report; the financial position of the Group, its cash flows, liquidity position and borrowing facilities are described in the Financial Review. 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.

Disclosure of impact of new and future accounting standards

There are no IFRSs or IFRIC interpretations that are effective for the first time for the financial year beginning on 1 January 2014 that have a material impact on the Group.

In accordance with the transitional provisions of IFRS 10, the Group reassessed the control conclusion for its investees at 1 January 2014. No modifications of previous conclusions about control regarding the Group's investees were required.

The Group is yet to assess the full impact of new standards and amendments that are not yet effective and have not been early adopted by the Group but does not expect them to have a material impact on the financial statements, with the main effect being the requirement for additional disclosures.

1.2 Consolidation

(a) Subsidiaries

The consolidated financial statements include the financial statements of the Company and its subsidiaries. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases. Losses applicable to the non-controlling interests in a subsidiary are allocated to the non-controlling interests even if doing so causes the non-controlling interests to have a deficit balance.

Investments in subsidiaries are accounted for at cost less impairment. Cost is adjusted to reflect changes in consideration arising from contingent consideration amendments. Cost also includes direct attributable costs of investment.

Inter-company transactions, balances and unrealised gains on transactions between Group companies are eliminated; unrealised losses are also eliminated unless the cost cannot be recovered.

The Company and its subsidiaries outside the Russian Federation maintain their financial statements in accordance with IFRSs as adopted by the EU. The Russian subsidiaries of the Group maintain their statutory accounting records in accordance with the Regulations on Accounting and Reporting of the Russian Federation. The consolidated financial statements are based on these statutory accounting records, appropriately adjusted and reclassified for fair presentation in accordance with International Financial Reporting Standards as adopted by the EU.

1.3 Segment reporting

Segmental reporting follows the Group's internal reporting structure. No geographic segmental information is presented as all of the companies operating activities are based in the Russian Federation.

Management has determined therefore that the operations of the Group comprise one class of business, being oil and gas exploration, development and production and the Group operates in only one geographic area - the Russian Federation.

1.4 Foreign currency translation

(a) Functional and presentation currency

Items included in the financial statements of each of the Group's entities are measured using the currency of the primary economic environment in which the entity operates ("the functional currency"). The consolidated financial statements are presented in US dollars, which is the Company's functional and the Group's presentation currency.

The functional currency of the Group's subsidiaries that are incorporated in the Russian Federation is the Russian rouble ("RUR"). It is the Management's view that the RUR best reflects the financial results of its Cyprus subsidiaries because they are dependent on entities based in Russia that operate in an RUR environment in order to recover their investments. As a result, the functional currency of the subsidiaries continues to be the RUR.

 (b) Transactions and balances

Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the income statement.

Foreign exchange gains and losses that relate to cash and cash equivalents, borrowings and other foreign exchange gains and losses are presented in the income statement within "Other gains and losses".

(c) Group companies

The results and financial position of all the Group entities (none of which has the currency of a hyper-inflationary economy) that have a functional currency different from the presentation currency are translated into the presentation currency as follows:

(i) assets and liabilities for each balance sheet item presented are translated at the closing rate at the date of that balance sheet;

(ii) income and expenses for each income statement are translated at average exchange rates (unless this average is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the rate on the dates of the transactions); and

(iii) all resulting exchange differences are recognised in other comprehensive income.

The major exchange rates used for the revaluation of the closing balance sheet at 31 December 2014 were

· GBP 1.5532: US$ (2013: GBP 1: US$ 1. 6488)

· EUR 1.2148: US$ (2013: 1.374)

· US$ 1:56.2584 RUR. (2013: US$ 1: RUR. 32.729)

1.5 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.

1.6 Other business and corporate assets

Property, plant and equipment not associated with exploration and production activities are carried at cost less accumulated depreciation. These assets are also evaluated for impairment when circumstances dictate.

Land is not depreciated. Depreciation of other assets is calculated on a straight line basis as follows:

1.7 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.

1.8 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.

2. Cost of sales and administrative expenses - Group

Cost of sales and administrative expenses are as follows:

3. Other gains and losses - Group

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

4. Intangible assets - Group

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

5. Property, plant and equipment - Group

Movements in property, plant and equipment, for the years ended 31 December 2014 and 2013 are as follows:

Impairment of US$1.3 million in 2013 relates to amounts of Property Plant and Equipment associated with redundant assets.

6. Non-current assets - Group

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.

7. Term deposits, cash and cash equivalents

An analysis of Group deposits, cash and cash equivalents by bank and currency is presented in the table below:

8. Inventories

9. Other receivables

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. The receivables were settled on schedule subsequent to the balance sheet date.

10. Accumulated profit/(loss) - Group and Company

On 9 July 2014 the capital reduction approved by shareholders at the Company's Annual General Meeting on 6 June 2014 became effective following confirmation by the High Court, the filing of the Court Order and a Statement of Capital with Companies House and the fulfilment of certain minor undertakings given to the Court. As a result, the Share Premium Account of the Company, amounting to US$165.9 million, was cancelled and the equivalent sum credited to the Company's Profit and Loss Account, thereby creating distributable reserves.

11. Trade and other payables

The maturity of the Group's and of the Company's financial liabilities are all between 0 to 3 months.