Preliminary Results

1 April 2016

VOLGA GAS PLC

Preliminary results for the year ended 31 December 2015

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, announces its preliminary unaudited annual results for the year ended 31 December 2015.

During 2015, the Group had to face significantly reduced oil prices and devaluation of the Russian Ruble as well as relatively higher rates of Mineral Extraction Taxes and disruptions to the regional market for condensate. Nevertheless, the Group maintained positive EBITDA and Operating Cash flow and remained in a positive net cash position while increasing capital expenditure to facilitate the completion of development drilling on its Vostochny Makarovskoye ("VM") gas/condensate field.

As a result of successful drilling activities in 2015, the effective production rates of the Group's fields increased by one third from approximately 4,500 barrels of oil equivalent per day ("boepd") to the current level of over 6,000 boepd.

FINANCIAL RESULTS

· Revenues of US$17.8 million (2014: US$39.4 million).

· EBITDA of US$0.9 million (2014: US$17.4 million).

· Loss before tax of US$5.0 million (2014: profit of US$16.3 million), after exploration expenses and impairments of US$3.7 million (2014: nil), a loss of $0.7 million from unauthorised transfers from Group bank accounts in Russia (2014: nil) and a foreign exchange gain of US$0.9 million (2014: US$3.3 million).

· Net operating cash flow of US$1.2 million (2014: US$16.3 million).

· Net cash decreased to US$6.7 million as at 31 December 2015 (31 December 2014: US$15.8 million) after utilising US$8.7 million for capital expenditure (2014: US$5.5 million) and paying a final dividend of US$1.0 million (2014: US$3.0 million interim dividend).

PRODUCTION & DEVELOPMENT

· Group average production in 2015 was 3,278 boepd (2014: 4,244 boepd).

· Production from VM and Dobrinskoye fields was impacted by disruption in the local market for condensate during early and mid-2015 and consequently averaged 2,876 boepd in 2015 (2014: 3,549 boepd).

· Drilling of the VM#3 well and of a sidetrack on VM#4 were successfully completed during 2015, effectively concluding development drilling on the VM field. The total wellhead capacity is currently estimated to exceed the planned 1 million cubic metres per day maximum output of the gas plant.

DOBRINSKOYE GAS PLANT

· Dobrinskoye gas plant operated successfully during 2015 and in December 2015 throughput was increased by 50% to 750,000 cubic metres per day (26.5 mmcf/d), when the recently completed VM#4 well was brought on line.

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

· Completed feasibility and design work to increase throughput and cost efficiency with Amine gas sweetening project.

CURRENT TRADING AND OUTLOOK

· After the normal seasonal slow start in January, production has been sustained at higher levels and is currently running steadily at over 6,000 boepd.

· Oil prices and the Russian Ruble weakened in January and, although having recovered somewhat, remain at low levels compared to recent years. In the current environment, the Group expects to improve on the financial performance of 2015.

· Exports now represent a substantial proportion of condensate sales, protecting the business from disruptions to local markets.

· Capital expenditure commitments have been reduced to a minimal level - to below US$1.5 million of new capital expenditure in 2016.

· Aim to preserve financial strength and to benefit from an eventual upturn in oil prices.

Andrey Zozulya, Chief Executive of Volga Gas, commented:

"The business environment in 2015 has been very challenging for a small, domestically oriented Russian oil, gas and condensate producer like Volga Gas. It is fortunate that the Group entered this challenging period in sound financial condition so that it has been able to complete the drilling on its main producing field with successful outcomes. Now, with the majority of the current capital programme executed, the Group should be able to benefit from its increased production capacity and has a solid base from which to grow its production.

"I am excited about the Group's assets and 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. Andrey Zozulya, 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. Andrey Zozulya has a degree in Geophysics and Engineering from the Groznensky Oil & Gas Institute and is a member of the Society of Petroleum Engineers.

Availability of report and accounts

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, 40 Dukes Place, London EC3A 7NH.

Glossary

Bpd/ Bopd Barrels per day /Barrels of oil per day

Boepd Barrels of oil equivalent per day, in which 6,000 cubic feet of natural gas is equated to one barrel of oil

mcm thousands of standard cubic metres

mcm/d thousands of standard cubic metres per day

m3 standard cubic metre

mmcf/d millions of standard cubic feet per day

mmcm/d millions of standard cubic metres per day

RUR Russian Rouble

Chairman's Statement

Dear Shareholder,

As anticipated by my predecessor in the 2014 Annual Report, 2015 was a challenging year for the oil and gas industry worldwide, for Russia and no less challenging for Volga Gas. The collapse in oil prices and in the value of the Russian Ruble had significant impact on the financial statements and the performance of the Company as reported in US dollars. Furthermore, changes to the production tax formulae that came into effect in 2015 meant that a greater proportion of gross revenue was paid out in taxes than in previous years.

However, on an operational level, the results of 2015 were satisfactory. The development drilling on the Vostochny Makarovskoye ("VM") field was successfully concluded during the year, which will enable this field, the Group's principal producing asset, to reach and sustain the planned plateau production rate of one million cubic metres per day of gas plus associated condensate.

With production from the first of the two new wells coming only in December 2015, this drilling activity did not make a significant contribution to the production for the full year. However, during mid December 2015, new the production from the VM#4 well enabled total output from the VM and Dobrinskoye fields to reach the intermediate target rate of 750,000 cubic metres per day of gas plus 180 tonnes per day of condensate, in total approximately 5,700 barrels of oil equivalent per day. This production is the core of stable production which provides the main cash generation engine for the Group.

The next strategic development to be undertaken is further enhancement of the existing gas processing facilities, first to introduce a more efficient process for the sweetening of the gas and secondly to capture for sale the liquid petroleum gases ("LPG") that are currently vented and flared. The former is intended to achieve significant cost savings and enable higher production rates of over one million cubic metres per day of gas, while the latter will provide an additional and potentially highly profitable product stream.

In the meanwhile, however, the Group continues to face a number of significant challenges, not the least of which is the general economic situation in Russia, where the dramatic fall in international oil prices has had a significant impact on the domestic economy as well as on the profitability and cash generation from our production.

While the Group remains in a healthy financial position, with positive net cash balances, the Board has made the strategic decision to preserve liquidity and to reduce capital expenditures to a minimal level. This means that the strategic investments outlined earlier will need to be deferred until cash generation recovers to a sustainably higher level than currently being experienced or acceptable external finance, consistent with a prudent financial strategy, can be arranged.

Volga Gas continues to benefit 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. During 2015 there were periods when local market conditions made it difficult to sell our condensate production and during these periods, gas and condensate production had to be suspended. Towards the end of 2015, the Group developed channels for exporting condensate and consequently there are alternatives to sales solely into the local domestic market.

The Group holds significant proven reserves in its three principal fields. These reserves form the basis of sustainable production with growth potential in the near term. These assets provide a 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.

Finally, I would like to pay tribute to my predecessor as Chairman, Aleksey Kalinin, for his leadership of the Company since its foundation and appreciation for his continued service as a non-executive director. I also welcome my successor as Chief Executive Officer, Andrey Zozulya who assumed that position in May 2015. He has had to take up his responsibilities at a very challenging time in our industry and has the full support and confidence of the Board as he manages the future development of the business.

Mikhail Ivanov

Chairman

Chief Executive's Report

As the Chairman has noted, Volga Gas faced significant challenges during 2015, with market factors constraining gas and condensate production during the first half of the year, declines in production from the mature oil wells, dramatic reductions in international oil prices and higher rates of production taxes. Each of these factors has had an impact on the financial performance of the Group.

There was, however, continued operational progress during the year. Development drilling on our main field, Vostochny Makarovskoye ("VM") was successfully concluded and towards the end of 2015 we increased the rate of production from the VM and Dobrinskoye fields by 50%. However, this late lift in production did not make a material contribution to the Group's full year's average daily production which was severely impacted by lower production earlier in the year.

Another factor in the Group's overall production in 2015 was the continuing decline in oil production from the mature Uzenskoye field. However, Volga Gas had made very good returns from these assets and management has identified opportunities to revive oil production both by further development of proven reserves and by exploration for new reserves. As part of this strategy, a number of operations were carried out during 2015, as detailed in the Operations Report below. Unfortunately, these did not result in immediate success, but I am optimistic that the strategy will yield significant levels of oil production in the future.

Following my appointment as Chief Executive on 5 May 2015, I decided it would be most effective if I were to be based close to the operations in the city of Saratov, rather than in Moscow. Since then, I have initiated a restructuring of the operational teams with the aim of improving the effectiveness of our operational capabilities. In addition, following an incident that led to a loss of funds from certain of our bank accounts, detailed below, I decided to improve the online security and make changes to the financial management in the operating companies. I believe that with these changes implemented, the Group is well placed to develop successfully in the future.

2016 Objectives and Medium Term Strategy

Having successfully completed the drilling of the VM#3 and VM#4 wells, the VM field is now effectively fully developed and is expected to be able to deliver sufficient production to maintain a production plateau of 1 million m3 per day (35.3 million cubic feet per day - "mmcf/d"). However, based on its current configuration, we believe the gas processing plant is capable of sustaining production at a rate of 750,000 m3 per day (26.5 mmcf/d). Following extensive technical evaluation and consideration of alternatives, it has been decided that the most effective solution for the longer term is to re-configure the gas plant to utilise an Amine-based gas sweetening process. We believe that this can be achieved with a modest investment, recently estimated at approximately US$8 million. If successful, this would significantly reduce the costs of chemicals consumed in gas processing and allow the gas plant to process the targeted 1 million m3 per day (35.3 mmcf/d) of gas. A more ambitious plan, to install equipment to capture and sell liquid petroleum gases ("LPG"), would be a follow-on project which could add a valuable further income stream.

Meanwhile, however, the Board of Volga Gas has decided to preserve the financial strength of the Group and defer capital expenditures while oil prices remain at very low levels. For the time being, capital expenditure will be limited to completing payments for ongoing projects and necessary items to maintain producing assets.

A new commercial initiative that has been implemented is the development of a channel for exports of our condensate production. A small number of cargoes were exported in November and December 2015. It is our aim to provide a viable alternative for sales in the event that the local domestic market for condensate closes, as it did during a number of weeks during 2015.

Finance

In spite of the challenges mentioned above, the Group managed to maintain positive net cash flow from operations, although as a result of the capital expenditure incurred during 2015, there was a net cash outflow of US$9.0 million. This includes a sum equivalent to approximately US$0.7 million lost from certain Group bank accounts as a result of unauthorized transfers in an apparent cyber-attack. The Group remained in a net cash position and the closing cash balance at 31 December 2015 was US$6.8 million with no debt.

Further development and exploration expenditures in 2016 and beyond have been deferred until the Board is confident that these can be funded from operating cash flow. In addition, the Group may consider a moderate level of borrowing to be appropriate to fund significant value accretive investments such as the upgrade to amine processing at the gas plant. 

Current trading and outlook

During January and February 2016, Group production averaged 5,632 barrels of oil equivalent per day, in line with management's plan. The gas plant is consistently operating at planned capacity of 750,000 m3 per day, with condensate output running at over 1,700 barrels per day, the majority of which is being sold to export markets. International oil prices have recovered from the low levels seen in January, as has the Ruble. Oil production is now a minor part of the Group's output and has suffered moderate disruption as the mild winter caused difficulties in transportation of oil sales.

In the current environment, and at current production rates, management expects the Group's financial performance in 2016 to improve on that of 2015. Meanwhile, new capital expenditure commitments have been reduced to minimal levels - below US$1.5 million.

Andrey Zozulya

Chief Executive Officer

Operational Review

Operations overview

The overall level of production in 2015, at 3,278 boepd, was 23% below the 4,244 boepd achieved in 2014. The principal reason for this was that in periods during January, February and again in May and June 2015, the local market for our condensate was effectively closed and production of gas and condensate had to be suspended for a period of close to six weeks. In addition, we experienced continued declines in oil production from the mature Uzen field.

However, in the periods when the condensate market was functioning normally, production from the VM and Dobrinskoye fields was exactly as planned. Furthermore with the successful completion of the drilling operations on the VM#3 and VM#4 wells, the production capacity on the VM field increased significantly and, in December 2015, the VM#4 well was brought into production, leading to an immediate increase of 50% in gas and condensate production.

As a consequence of the lower production in 2015, significantly lower oil prices and the devaluation of the Ruble, revenues were down by 56% in US dollar terms. The increase in formula rates of Mineral Extraction Taxes put further pressure on EBITDA which, although still positive, was down by 94% compared to the 2014 level. Full details are discussed in the Financial Review below.

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. Since November 2013, production has normally been running at levels that reflect the capacity of the existing wells in the two fields, that is approximately 500,000 m3 per day (17.8 mmcf/d) of gas and 120 tonnes per day (1,050 barrels per day ("bpd")) of condensate.

During January and February 2015 and again during May and June 2015, production of gas and condensate had to be temporarily suspended since it was not possible to sell the condensate produced in the local market. (Gas and condensate are produced simultaneously from the wells and once the storage capacity at the gas plant is full, it is necessary to cease production.) In addition, during July, Gazprom was undertaking extensive maintenance to the local gas pipeline network and for this period, there were limitations to the volume of gas that could be accepted in the pipeline. For these reasons production during 2015 averaged 12.5 mmcf/d of gas and 784 bpd of condensate (2014: 15.5 mmcf/d of gas and 966 bpd of condensate).

Gas continues to be sold to Trans Nafta under contract at a fixed Ruble contract gas sales price. The Ruble price increased from RUR 3,887 per thousand cubic metres ("mcm") to RUR 4,201 per mcm in July 2015. However, with the devaluation of the Ruble during 2015, the US Dollar equivalent of the price declined further during 2015. Historically, condensate was sold entirely into the local domestic market. However, with the periods of low domestic demand which impacted our business during 2015, it was decided to develop new commercial channels for exporting condensate. During November and December 2015, a number of cargoes of condensate were sold to export customers in the Baltic region. While realisations were less than we would normally achieve in the domestic market, exports provide a viable alternative sales route for our production. We continue to work on these sales and on improving the realisations.

The average gas sales price for 2015 was the equivalent of US$1.51 per thousand cubic feet, net of VAT (2014: US$2.15). During 2015 the average condensate sales price was US$23.89 per barrel (2014: US$44.11 per barrel).

Average unit production costs on the gas-condensate fields declined to US$5.06 per boe in 2015 (2014: US$6.49). The decline in the Ruble, in which effectively all the costs are denominated, partly offset higher costs associated with chemicals consumed in gas processing and higher costs of waste disposal as well as other inflationary cost increases.

During 2015, the main development activity was the drilling of the VM#3 and VM#4 production wells. The VM#3 well had commenced drilling in 2014, however, the local drilling contractor was unable to overcome mechanical difficulties and the operations were suspended after various attempts. Subsequently, the Group contracted Eurasia Drilling to complete this well and to drill a sidetrack to the VM#4 well, and a new rig was mobilised during February 2015.

The initial operation was on VM#4, a well that was originally drilled in 2008-2009 but which intersected a low permeability zone in the target horizon. A productive target was identified with a bottom-hole location approximately 500 metres from the original well. By May 2015, drilling on the VM#4 sidetrack was concluded, the deviated well section having intersected a total reservoir of 40 metres. Based on flow testing, management estimated that this well could be the most productive on the VM field, being capable of sustaining a flow rate of up to 350 mcm/d (12.4 mmcf/d). The tie back of this well was undertaken and in December 2015 the well was put in production. After a short build-up, by 16 December 2015, the combined daily output of gas from four wells, VM#1, VM#2, VM#4 and Dobrinskoye #22, produced 755,000 m3 per day of sales gas.

On conclusion of the drilling on VM#4, the rig was mobilised to the VM#3 location and in August 2015, the well reached the planned target depth. In this well, the top of the reservoir section was found higher than anticipated and total pay of close to 100 metres was logged. In addition, the well was drilled deeper than the original plan, and a high specification logging operation undertaken to gather data that may be used for future development of the field.

Given the strong flow rates from VM#4, and that current well capacity is sufficient to fully utilise available plant capacity, the tie-back of the VM#3 well has been deferred to the springtime of 2016 when the operations can be concluded more conveniently.

Based on this successful drilling and with continuing management of the existing well stock including, as appropriate, acid wash treatments, it seems likely that no further drilling will be required to produce the VM field at the target plateau rate of 1.0 mmcm/d (35.3 mmcf/d).

Gas processing plant

Since December 2015, the Dobrinskoye gas processing plant has been consistently operating at rates of over 750,000 m3 per day (26.5 million cubic feet per day), a 50% increase above the normal operating rates achieved in 2014 and most of 2015. While the physical process plant and pipelines were designed to operate at 1 million m3 per day, the need to dispose of bulky spent chemicals used in gas sweetening is the principal constraint on the operations.

During 2015, a number of technical and feasibility studies were conducted, including consideration of alternative sweetening chemical processes and a more ambitious project to simultaneously install amine sweetening and LPG extraction. Given the financial constraints, it was decided that these investments should be deferred until a significant recovery in cash generation could be confidently expected.

Oil production

Having completed its seventh 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 although water cut has risen. 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 anticipated declining production rates.

During 2015, a sidetrack from the currently non-producing Uzen #8 well was drilled with the intention of producing oil from a potentially bypassed "attic" in the Aptian reservoir. Unfortunately this operation was not successful owing to mechanical difficulties, although at the equivalent of US$0.4 million, the cost was modest.

There remain significant proved undeveloped reserves in the shallower Albian reservoir. Following a technical study carried out during 2015, it appears that a viable development plan for this reservoir would be to drill two horizontal production wells. The cost of each of these wells is currently estimated to be US$2.0 million and would expect to develop over 2 million barrels of reserves at a capital cost equating to US$4.00 per barrel of reserves. Along with other discretionary capital expenditure, however, this investment has been temporarily deferred.

Also during 2015, a sidetrack to the Sobolevskaya-11 well on the Urozhainoye-2 licence was drilled. This well, which was originally drilled by a previous licencee, had been produced by Volga Gas during 2013 and 2014 but was depleted. The sidetrack was intended to access a potential small undeveloped oil reserve. Mechanical difficulties with the drilling prevented this sidetrack from reaching the intended target and the operations have been suspended. Further operations on this have been deferred pending evaluation.

The Group's oil production, whilst of modest scale, has been 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.

During December 2015, an exploration well was drilled on one of these targets, the Yuzhno Mironovskaya prospect. This well was drilled to a total vertical depth of 940 metres within a time of 21 days, a record drilling rate for the Group. After running logs, the principal and secondary target zones in the Cretaceous post-salt Albian and Aptian formations were found to be water bearing and the well was plugged and abandoned. With the efficient well drilling, the total cost of this well was limited to approximately US$0.6 million.

The Group has fulfilled all its licence commitments on the Karpenskiy Licence Area and further drilling in the area is discretionary. Nevertheless future development of the oil potential in the Group's licences is a key element of management's medium term strategy.

Oil, gas and condensate reserves as of 1 January 2016

During 2012, an independent evaluation of the Group'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 set 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 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. Andrey Zozulya, 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. Zozulya holds a degree in Geophysics and Engineering from the Groznensky Oil & Gas Institute and is a member of the Society of Petroleum Engineers.

Financial Review

Results for the year

In 2015, the Group generated US$17.8 million in turnover (2014: US$39.4 million) from the sale of 438,910 barrels of crude oil and condensate (2014: 603,950 barrels) and 4,545 million cubic feet of natural gas (2014: 5,671 million cubic feet).

The average price realised for liquids was the equivalent of US$25.16 per barrel (2014: US$45.07 per barrel). Oil and condensate sales were primarily made into the domestic market during the period, although during November and December 2015 approximately 12,000 barrels of condensate, a little less than 2% of the total liquids sales, were exported to customers in Lithuania (2014: nil). Our oil and condensate sales prices in the domestic market reflect international prices after adjusting for export taxes and transportation costs.

The gas sales price during 2015 averaged US$1.49 per thousand cubic feet (2014: US$2.15 per thousand cubic feet), the fall being entirely attributable to the devaluation of the Ruble. The sales price of gas in Rubles increased by 8.1% in July 2015 (9.5% in July 2014). Production activities generated a gross profit of US$2.2 million in 2015 (2014: US$16.9 million).

In 2015, the total cost of production decreased to US$7.4 million (2014: US$9.5 million), primarily reflecting the effect of devaluation on our predominantly Ruble denominated costs. Production based taxes were US$5.9 million (2014: US$8.3 million) reflecting lower volumes and the impact of lower oil prices and Ruble exchange rates on Mineral Extraction Tax ("MET") rates. However, with formula changes coming into effect on 1 January 2015, MET paid in 2015 represented 35% of revenues (2014: 22% of revenues).

Operating and administrative expenses in 2015 were US$3.4 million (2014: US$4.2 million).

The Group experienced a significant reduction in EBITDA (defined as operating profit before non-cash charges, including exploration expense, depletion and depreciation) to US$0.9 million (2014: US$17.4 million) as a result of the lower revenues, partly offset by lower expenses.

After incurring exploration and evaluation expenses of US$0.6 million (2014: nil) on unsuccessful exploration drilling and other asset impairment expenses, mainly arising from unsuccessful drilling activities, of US$3.0 million (2014: nil) the Group recorded an operating loss for 2015 of US$5.0 million (2014: operating profit of US$12.8 million).

Including net interest income of US$0.1 million (2014: US$0.2 million) and other net gains of US$0.3 million (2014: US$3.3 million) the Group recognised a loss before tax of US$4.6 million (2014: profit before tax of US$16.3 million) and reported net loss after tax of US$4.1 million (2014: net profit after tax of US$13.1 million) after a deferred tax credit of US$0.6 million (2014: deferred tax charge of US$3.2 million).

Included in Other gains and losses in 2015 was a foreign exchange gain of US$1.0 million arising from US Dollar cash balances held by Russian subsidiaries which have the Ruble as functional currency (2014: US$3.3 million gain on foreign exchange) and a loss of approximately US$0.7 million equivalent arising from unauthorised withdrawals from bank accounts held by the Group's Russian operating subsidiaries (2014: nil).

Cash flow

Group cash flow from operating activities was US$1.2 million (2014: US$16.2 million). Net working capital movements contributed cash inflow of US$0.8 million in 2015 (2014: US$0.6 million). With higher capital expenditures in 2015, the net outflow from investing activities was US$8.7 million (2014: US$5.5 million). Net cash outflow from financing activities was US$1.0 million (2014: outflow of US$3.0 million), in both cases related to payment of equity dividends.

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. Dividends of US$0.05 per ordinary share were declared in respect of the year ended 31 December 2014. In light of the material reduction in the oil price, adverse financial conditions prevailing in Russia and the losses incurred, the Board is not recommending a dividend in respect of the year ended 31 December 2015

Capital expenditure

During 2015 capital expenditure of US$10.4 million was incurred (2014: US$5.6 million), of which US$9.8 million was on development and producing assets (2014: US$ 5.6 million) and US$0.6 million was incurred on exploration (2014: nil). The most significant components of the capital expenditure in 2015 relate to successful drilling on the VM field with additional sums on unsuccessful drilling on the Uzenskoye and Sobolevskoye fields and on the Yuzhny Mironovskaya exploration prospect. The unsuccessful expenditure has been expensed.

Balance sheet and financing

As at 31 December 2015, the Group held cash and bank deposits of US$6.8 million (2014: US$15.8 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 2015, the Group's intangible assets decreased to US$2.9 million (2014: US$3.7 million). Property, plant and equipment, decreased to US$48.3 million (2014: US$57.8 million), primarily reflecting the impact of foreign exchange adjustments. The carrying value of the Group's assets relating to its main cash generating units have been subject to impairment testing. The result of the impairment tests, including sensitivity analysis around the central economic assumptions as detailed in Note 4(b) to the Accounts, showed no requirement for impairment, although as noted above there were impairments and write-offs relating to unsuccessful operations.

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.

For the year ending 31 December 2015, the Group recorded a currency retranslation expense of US$15.3 million (2014: US$49.0 million) in its Other comprehensive income, relating to the devaluation of the Ruble against the US dollar.

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.

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 and condensate production in Russia effectively reduce the exposure to international market prices for oil.

Market risks

The Group's revenues generated from oil and condensate production have typically been from sales to local domestic customers. There have been periods when the local market has been unable to purchase condensate, causing temporary suspension of production and loss of revenues. The Group has developed arrangements to sell oil and condensate into regional export markets to mitigate this risk. Gas sales are made, via an intermediary, into the domestic market via the Gazprom pipeline network. The region in which the Group operates is reliant on external gas supplies. Consequently the risk of insufficient demand for the Group's gas is considered low. Gas sales have generally been conducted as expected, subject to occasional constraints during pipeline maintenance operations. However, the Group is studying the feasibility of construction of a separate pipeline to connect with a facility owned by a nearby upstream operator.

 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 materially increased the rates on crude oil, condensate and natural gas. With oil prices at low levels and Russian Government budgets under pressure, there are risks of further adverse changes to production taxes.

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 carrying 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 administrative costs are in US Dollars, Euros and Pounds Sterling. 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 negatively impacts 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 2015 the Group had US$6.8 million of cash and cash equivalents of which US$2.0 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 2015 the Group has budgeted capital expenditures of less than US$1 million primarily for the continuing development of gas and condensate production and approximately US$1.5 million of accounts payable relating to capital expenditures incurred in the year ended 31 December 2015. 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.

The Group is also exposed to fraudulent transfers of funds from its bank accounts. During the year ended 31 December 2015, the Group significantly enhanced its protections and procedures after suffering such fraudulent transfers.

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. 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 and has a policy of maintaining a minimum level of liquidity to cover forward obligations. Further short-term debt facilities may be arranged to provide financial headroom for future development activities.

Tony Alves

Chief Financial Officer

Abbreviated Financial Statements

 for the year ended 31 December 2015

Group Income Statement

(presented in US$ 000)

Group Statement of Comprehensive Income

(presented in US$ 000)

Group Balance Sheet

(presented in US$ 000)

Approved by the Board of Directors on 31 March 2016 and signed on its behalf by

Tony Alves

Chief Financial Officer

Group Cash Flow Statements

(presented in US$ 000)

Group Statement of Changes in Shareholders' Equity

(presented in US$ 000)

Notes to the Abbreviated Financial Statements

for the year ended 31 December 2015

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 areas involving a higher degree of judgement 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 Strategic Report in pages 4 to 11; the financial position of the Group, its cash flows, liquidity position and borrowing facilities are described in the Financial Review on pages 8 to 9. 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.

Disclosure of impact of new and future accounting standards

(a) New and amended standards and interpretations:

There are no IFRSs or IFRIC interpretations that are effective for the first time for the financial year beginning on 1 January 2015 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 2015. No modifications of previous conclusions about control regarding the Group's investees were required.

(b) Standards, amendments and interpretations to existing standards that are not yet effective and have not been early adopted by the Group. The following new standards, amendments to standards and interpretations have been issued, but are not effective for the financial year beginning 1 January 2015 and have not been early adopted:

· IFRS 9: Financial Instruments

· IFRS 15: Revenue from Contracts with Customers

· IFRS 16: Leases

The Group is yet to assess the full impact of these new standards and amendments 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. Subsidiaries are entities controlled by the Group. The Group controls an entity when it is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. In assessing control, the Group takes into consideration potential voting rights that are currently exercisable. The acquisition date is the date on which control is transferred to the acquirer. 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

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.

The Group's gas sales, representing a substantial proportion of revenues are made to a single customer. Details are provided in Note 2.1(b).

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 2015 were:

· GBP 1.517: US$ (2014: 1. 5532)

· EUR 1.091: US$ (2014: 1. 2148)

· US$ 1:72.883 RUR. (2014: 56.258)

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. Financial risk management

2.1 Financial risk factors

The Group's activities expose it to a variety of financial risks: market risk (including foreign exchange risk, price risk, and cash flow interest rate risk), credit risk, and liquidity risk. The Group's overall risk management programme focuses on the unpredictability of financial markets and seeks to minimise potential adverse effects on the Group's financial performance.

(a) Market Risk

(i) Foreign exchange risk

The Group is exposed to foreign exchange risk arising from currency exposures, primarily with respect to the RUR. Foreign exchange risk arises from future commercial transactions, recognised assets and liabilities.

 (ii) Price risk

The Group is not exposed to price risk as it does not hold financial instruments of which the fair values or future cash flows will be affected by changes in market prices. The Group is not directly exposed to the levels of international marker prices of crude oil or oil products, although these clearly influence the prices at which it sells its oil and condensate. Mineral Extraction Taxes ("MET") are calculated by reference to Urals oil prices and are therefore directly influenced by this. Taking into account the marginal rates of export taxes and MET, management estimates that if international oil prices had been US$5 per barrel higher or lower and all other variables been unchanged, the Group's profit before tax would have been US$1.2 million higher or lower (2014: $1.7 million).

(iii) Cash flow and fair value interest rate risk

As the Group currently has no significant interest-bearing assets and liabilities, the Group's income and operating cash flows are substantially independent of changes in market interest rates.

(b) Credit risk

The Group's maximum credit risk exposure is the fair value of each class of assets, presented in note 2.1(a)(i) of US$6,769,000 and US$15,767,000 at 31 December 2015 and 2014 respectively.

The Group's principal financial asset is cash and credit risk arises from cash and cash equivalents and deposits with banks and financial institutions. It is the Group's policy to monitor the financial standing of these assets on an ongoing basis. Bank balances are held with reputable and established financial institutions.

The Group's oil and condensate sales are normally undertaken on a prepaid basis and accordingly the Group has no trade receivables and consequently no credit risk associated with the related trade receivables. Gas sales accounting for 38.4% of Group revenues in 2015 (2014: 33.3%) are made to OOO Trans Nafta. As at 31 December 2015 there were trade receivables of US$1.0million (31 December 2014: US$0.6 million) relating to gas sales. As at 31 December 2015 there was no provision for bad debts (2014: nil).

(c) Liquidity risk

Cash flow forecasting is performed by Group finance. Group finance monitors rolling forecasts of the Group's liquidity requirements to ensure it has sufficient cash to meet operational needs. The Group believes it has sufficient liquidity headroom to fund its currently planned exploration and development activities.

The Group expects to fund its capital investments, as well as its administrative and operating expenses, through 2016 using a combination of cash generated from its oil and gas production activities, existing working capital and, when appropriate, medium-term bank borrowings. If the Group is unsuccessful in generating enough liquidity to fund its expenditures, the Group's ability to execute its long-term growth strategy could be significantly affected. The Group may need to raise additional equity or debt finance as appropriate to fund investments beyond its current commitments.

(d) 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. Management expects that the cash generated by the operating fields will be sufficient to sustain the Group's operations and future capital investment for the foreseeable future. Further short-term debt facilities may be arranged to provide financial headroom for future development activities.

3. Critical accounting estimates and judgements

The Group makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below.

(a) Carrying value of fixed assets, intangible assets and impairment

Fixed assets and intangible assets are assessed for impairment when events and circumstances indicate that an impairment condition may exist. The carrying value of fixed assets and intangible assets are evaluated by reference to their value in use and primarily looks to the present value of management's best estimate of the cash flows expected to be generated from the asset. In identifying cash flows management firstly determine the cash generating unit or group of assets that give rise to the cash flows. The cash generating unit ("CGU") is the lowest level of asset at which independent cash flows can be generated. For this purpose the directors consider the Group to have two CGUs: the VM and Dobrinskoye fields with the Dobrinskoye gas processing plant are treated as a single CGU, and the Uzen oil field is a separate CGU.

The estimation of forecast cash flows involves the application of a number of significant judgements and estimates to a number of variables including production volumes, commodity prices, operating costs, capital investment, hydrocarbon reserves estimates, inflation and discount rates. Key assumptions and estimates in the impairment models relate to: commodity prices that are based on forward curves for two years and the long-term corporate economic assumptions which include a long term oil price of US$50 per barrel. The models utilised are based on the remaining reserves in the Proved category and future production profiles based on established field development plans. Cost assumptions are based on current experience and expectations, and levels of export and mineral extraction taxes reflect rates set by current legislation. A discount rate of 15% per annum is utilised in the models.

As at 31 December 2015, the Group's impairment testing of the property, plant and equipment related to each CGU indicated that no impairment was required. Variations of the each of key economic assumptions, including long term oil prices US$10 per barrel below the central assumption, yielded net present values in excess of carrying value for each CGU. However, following unsuccessful operations on certain non-producing wells during 2015, management decided to write off assets associated with these specific operations. This is further detailed in Note 4(b).

(b) Estimation of oil and gas reserves

Estimates of oil and gas reserves are inherently subjective and subject to periodic revision. In addition, the results of drilling and other exploration or development activity will often provide additional information regarding the Group's reserve base that may result in increases or decreases to reserve volumes. Such revisions to reserves can be significant and are not predictable with any degree of certainty. Management considers the estimation of reserves to represent a significant judgement in the context of the financial statements as reserve volumes are used as the basis for assessing the useful life of oil and gas assets, applying depreciation to oil and gas assets and in assessing the carrying value of oil and gas assets. Decreases in reserve estimates can lead to significant impairment of oil and gas assets where revisions (positive or negative) can have a significant effect on depreciation rates from period to period. Management have considered the sensitivity of this key assumption and in order for an impairment issue to present itself to the Group, reserve estimates would need to reduce by more than 25%.

An 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 set by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers ("SPE").

(c) Income taxes

Significant judgement is frequently required in estimating provisions for deferred taxes. This process involves an assessment of temporary differences resulting from differing treatment of items for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within the balance sheet.

4. Cost of sales and administrative expenses - Group

Cost of sales and administrative expenses are as follows:

 (a) Exploration and evaluation: The principal component was the write off of costs relating to the Yuzhny Mironovskaya prospect on which an unsuccessful well was drilled during.

(b) Write off of development assets: In the year ended 31 December 2015, the principal sources of the write off of development assets were impairment of the carrying value of the Sobolevskoye field, the Urozhainoye-2 licence area in which it is located and the cost of the attempted sidetrack to the Sobolevskoye-11 well. There were also charges relating to unsuccessful operations on well in the Uzen field and other minor asset write offs.

5. Other gains and losses

6. Intangible assets

Intangible assets represent exploration and evaluation assets such as licenses, studies and exploratory drilling, which are stated at historical cost, less any impairment charges or write-offs.

7. Property, plant and equipment - Group

Movements in property, plant and equipment, for the years ended 31 December 2015 and 2014 are as follows:

8. 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:

9. Inventories

10. 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.

11. Accumulated profit/(loss)

12. Trade and other payables

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