VGAS.L Regulatory News (VGAS)

2 April 2013

VOLGA GAS PLC

Preliminary results for the year ended 31 December 2012

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 2012.

The key event of 2012 was the commencement of production from the Group's largest field, Vostochny Makarovskoye ("VM"), which was achieved on completion of the first stages of an ongoing upgrade to the Group's gas processing plant located at the Dobrinskoye gas field. While production and financial performance in 2012 was impacted by extended shut-ins, during the upgrade works, the Group is poised to deliver growing production in 2013 and beyond. In addition, an independent evaluation of the Group's fields assigned Proven and Probable reserves, as at 1 August 2012, of 44 million barrels of oil equivalent with a net present value of future net revenue ("NPV") of over US$300 million, based on a 10% annual discount rate. (See note 1.)

FINANCIALHIGHLIGHTS

·; Revenues of US$28.3 million (2011 US$28.6 million).

·; EBITDA of US$8.0 million (2011 US$8.9 million).

·; Loss before tax of US$6.3 million (2011: loss of US$1.1 million) after exploration and other expenses of US$11.6 million (2011: US$5.8 million).

·; Net operating cash flow of US$5.4 million (2011: US$5.7million).

·; US$7.0 million in cash at 31 December 2012 (US$10.1 million at 31 December 2011).

·; No exposure to Cypriot banks as all cash balances are held in bank accounts in the UK and Russia.

·; Bank debt of US$ 8.0 million at 31 December 2012 (31 December 2011: loans payable to Trans Nafta of US$4.2 million).

DOBRINSKOYEGAS PLANT UPGRADE

·; First phases of the upgrade to the Dobrinskoye Gas Plant, to enable processing of gas from the VM field, were completed in September 2012, enabling the start of commercial production from the VM field.

·; The plant is currently operating close to its processing capacity of 250,000 cubic metres per day (approximately 8.8 million cubic feet per day ("mmcf/d")).

·; Continuing upgrade to expand capacity to 1 million cubic metres per day (35 mmcf/d) during 2013.

PRODUCTION & DEVELOPMENT

·; Group average production of 1,995 barrels of oil equivalent per day (2011: 2,147 boepd).

·; During January and February 2013 production averaged 2,679 boepd, with the Dobrinskoye gas plant operating at near full capacity.

·; Uzenskoye oil field production maintained at 1,050 barrels of oil per day ("bopd") (2011: 1,178 bopd).

·; After four years of production, some water is beginning to be produced at some Uzenskoye wells, requiring installation of water separation at the field site - modest cost of less than US$1.0 million.

·; Successful sidetracks on Dobrinskoye wells #22 and #26 restored production early 2013.

·; Full time VM production commenced in October 2012 from two wells: VM#1 and VM#2.

·; Successful workover of well #30 on VM field during H1 2012 to add a third production well to the field in 2013.

EXPLORATION & APPRAISAL

·; Completed two licence commitment exploration wells during 2012: Yuzhny Romanovskaya-1 in the Urozhainoye-2 licence area and Mirnaya #2 in the PreCaspian licence area, both were unsuccessful.

·; A workover of the Sobolevskaya #11 oil discovery in the Urozhainoye-2 licence area has been completed successfully and is to be put on production during 2013.

RESERVE REPORT

·; Independent evaluation of reserves completed by Miller & Lents in 2012.

·; Proven and Probable reserves of 44 million barrels of oil equivalent as at 1 August 2012 with a NPV, based on a 10% p.a. discount rate, of US$ 301 million.(See note 1.)

CURRENT TRADING AND OUTLOOK

·; During January and February 2013 production has averaged 2,679 boepd.

·; Oil and condensate selling prices net at the wellhead have remained firm at over US$50 per barrel and an 11.6% increase in our contract gas price to the equivalent of US$2.62 per mcf net of VAT came into effect on 1 January 2013.

·; Plan to complete the gas plant upgrade and achieve full capacity of 35 mmcf/d during 2013.

·; Plan to implement water separation at Uzenskoye at a cost of less than US$1.0 million.

·; Sobolevskaya #11 well to add a new production stream during 2013.

Mikhail Ivanov, Chief Executive of Volga Gas, commented:

"2012 was a pivotal year for Volga Gas and while our production was marginally down compared to 2011, the start of production from VM and the continuing upgrade to the gas plant capacity will signal a new growth phase for production from our fields. The key strategic aim for 2013 and 2014 is to realise the full production potential of the VM field by completing the gas plant upgrade and adding further production wells to the field. This will provide a significant lift in revenues and cash flows and a platform for future growth for Volga Gas.

"We remain positive about the potential for growth, both in reserves and production from our five licences. However, we are also seeking value accretive opportunities beyond our existing licence areas, as we build a focused exploration and production business."

For additional information please contact:

Note 1

The independent assessment of the reserves and NPV attributable to the Company's three principal fields, Dobrinskoye, Vostochny Makarovskoye and Uzenskoye, as at 1 August 2012, was prepared in accordance with reserve definitions prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE). The NPV evaluation was conducted on a constant pricing basis, assuming no future escalations of oil prices, operating expenses, capital, or mineral extraction taxes above the respective 1 August 2012 values. Future net revenues are defined as the total gross revenues less operating costs, Mineral Extraction Tax and capital expenditures. The total gross revenues are the total revenues received at the wellhead. The future net revenues include deductions for other capital and property taxes but do not include deductions for profit taxes. The constant price assumptions used in the calculation of future cash flows were as follows: Crude Oil - US$49.53 per barrel; Condensate - US$47.66 per barrel; Natural Gas - US$2.40 per mcf.

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 five 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 18 years of experience in the sector.

Availability of report and accounts

The Group's full report and accounts, including notice of the annual general meeting of the Company to be held at the London office of Akin Gump Strauss Hauer & Feld at Ten Bishops Square, London E1 6EG on 7 June 2013 at 10.00 a.m., will be dispatched to shareholders as soon as is practicable. Copies will also be available on the Company's website www.volgagas.com and on request from the Company at, Ground Floor, 17-19 Rochester Row, London SW1P 1QT.

Chairman's Statement

Dear Shareholder,

2012 has been a pivotal year for Volga Gas, with the main focus of the Company on completion of a project to upgrade the Dobrinskoye gas plant to enable the start of commercial production from the Group's largest field, Vostochny Makarovskoye. While this work was under way, there was extended disruption to production from the other gas field, Dobrinskoye, as a result of which overall production realised in 2012 of 1,995 barrels of oil equivalent per day ("boepd") was slightly less than in 2011. Nevertheless, as we exit 2012 and start 2013, Volga Gas has three fields in commercial production and, following the anticipated increase in gas processing capacity, is poised to increase production significantly during 2013.

Improved realisations from our oil production, which has remained steady through 2012, partly offset lower gas production and helped the Group maintain its relatively strong cash flow.

The cash generating capability of the fields was also an important factor in the Group's ability to secure its first commercial debt facility which was drawn down during the first half of 2012. This facility was utilized to support the Group's short and medium term investment strategy and provided extra financial flexibility as we drive production growth in 2012 and 2013.

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

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

During 2013, the strategic priority of the Group will be to enable full production from the existing wells in the Vostochny Makarovskoye field and to continue the development drilling on that field. The Board is also evaluating opportunities to extend the Group's activities into new areas, where we have identified the potential to add significant value and incremental production volumes.

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.

Alexey Kalinin

Chairman

Chief Executive's Report

Volga Gas reached a key milestone in 2012 with first commercial production of gas and condensate with its largest field, Vostochny Makarovskoye ("VM"). This followed from the successful completion of the first two phases of the upgrade to the gas processing plant located at the Dobrinskoye field site, 5 km from the VM field. The Dobrinskoye field and gas plant were both acquired in 2011 through the purchase of Gazneftedobycha. Another significant event of 2012 was the completion of an independent evaluation of our oil, gas and condensate reserves under SPE standards. The study , by Miller and Lents Ltd, with an effective date of 1 August 2012, confirmed the total Proven and Probable Reserves of the Group at 44.0 million barrels of oil equivalent ("mmboe") and gave a NPV of US$301 million (with a 10% per annum discount rate) to those reserves. Of these reserves, the overwhelming majority are classified as Proven.

As detailed in the Operational Review below, the majority of the work done on our producing assets base was focused on the two gas fields. On VM, the Group added to the wells drilled in earlier years by re-completing an old exploration well, #30, into a third production well. On the Dobrinskoye field, both of the production wells have been sidetracked with the aim of restoring production to earlier levels on this field. The third producing field, Yuzhny Uzenskoye, in the Karpenskiy Licence Area, produced steadily for its fourth full year of production.

For much of 2012, our gas and condensate production was limited to the output from a single well on Dobrinskoye and was, indeed, shut in while the construction on the gas plant upgrade project was completed. Thus, although with volumes from VM the final quarter saw a rise in production to over 2,500 boepd, aggregate production in 2012, of 1,995 boepd, was slightly lower than 2011. Consequently the revenue and EBITDA performance of the Group in 2012 reflected this lower production. See the Financial Report on pages 8-9 for details.

In 2012, exploration activity was limited to the fulfillment of exploration licence commitments in the Urozhainoye-2 and Pre-Caspian licence areas. Drilling operations on two wells, one in each licence area, concluded in 2012 without discovering potentially commercial hydrocarbons and both wells have been plugged and abandoned.

Our key strategic objective is to complete the last phases of the Dobrinskoye gas plant upgrade, with the intention of increasing permitted processing capacity fourfold to 1 million cubic metres per day (35 million cubic feet per day) and to bring the VM field into full scale production. The latter will require further development drilling of two wells, which is planned to take place in 2013 and 2014.

While the immediate strategic objective is to bring our existing assets into peak production, we remain active in our search for complementary assets to expand our business.

Finance

Historically, the Group's investments in exploration and capital expenditure have been funded from equity and cash generated from operational activities. Now that the Group's assets have established a track record of reliable cash generation, the Board decided that it is an appropriate time to bring bank debt into the capital structure of the Group. On 26 March 2012 the Group arranged its first debt facility, with ZAO Raiffeisen Bank, for a sum of US$10 million.

Current trading

In January and February 2013, production from the Dobrinskoye, VM and Uzenskoye fields averaged 2,679 boepd. Having produced water-free oil for four years, we are beginning to see some water cut in Uzenskoye as a result of which we plan to install water separation facilities at the field shortly, a modest investment of less than US$1.0 million. With oil and condensate prices remaining firm and an 11.6% increase in our gas sales price since the start of the year to an equivalent of US$2.62 per mcf, Volga Gas continues to experience positive net operating cash flow.

Outlook

Key activities for 2013 will be the ongoing management and development of existing production across the portfolio. The Group's priority is to achieve the targeted fourfold increase in the Dobrinskoye gas plant capacity and to extend the well production to utilise this capacity to the maximum extent. It is our current expectation that works on the final stage of the upgrade will be completed during Q3 2013 from when, subject to obtaining the necessary permits, it would be possible to operate the plant at the higher capacity.

With three wells on the VM field and two recently worked over wells on the Dobrinskoye field, the wellhead capacity is higher than the currently permitted plant throughput. Nevertheless, during 2013 and 2014 we intend to bring further wells into production on VM by sidetracking the previously drilled well VM#4 and by drilling new wells, VM#3 and VM#5.

We are managing the oil production on the Yuzhny Uzenskoye field pending installation of water separation equipment but expect overall output from the field to remain steady at approximately 1,000 bopd. Meanwhile in the Urozhainoy-2 Licence Area, a successful workover recently carried out on the Sobolevskaya #11 well, which was originally drilled by a former licensee, will provide a new stream of oil production after we install production facilities at the well site.

We look forward to delivering a successful new stream of production while also pursuing the other growth opportunities that we see for the business.

Mikhail Ivanov

Chief Executive Officer

Operational Review

Operations overview

The key event for the Group in 2012 was the completion of the first two stages of the upgrade to the Dobrinskoye gas processing plant which enabled the start-up of commercial production from the Vostochny Makarovskoye gas field. This represents a turning point for the Group's production activities with all three of the fields now in production.

The overall level of production in 2012, at 1,995 boepd was below the 2,114 boepd achieved in 2011. The cause for the lower output was the Dobrinskoye gas/condensate field being subject to extended periods of shut down pending drilling of sidetracks to the two production wells - both completed during 2012 - and for the installation of the process plant upgrades at the Dobrinskoye gas plant. Consequently revenues and EBITDA levels in 2012 were both lower than those of 2011. Full details are discussed in the Financial Review.

During 2012, two exploration wells were completed in fulfillment of outstanding licence obligations. Neither of these was commercially successful and the costs related to these wells were expensed.

Gas processing plant upgrade

The Group gained ownership of the producing Dobrinskoye gas/condensate field and the gas processing plant via the acquisition of Gazneftedobycha in April 2011. Ownership of the processing infrastructure and access to the Gazprom trunk line enabled the VM field to commence commercial production.

Following a successful test of the chemical process to be used for sulphur extraction, the plan for the gas plant upgrade was approved at the end of 2011. The first stage of the upgrade, aimed at increasing processing capacity and enhancing H2S extraction, was completed in September 2012 and gas from the VM field started flowing through the plant from the beginning of October 2012.

The build-up of production from VM has been gradual as a series of tests have been carried out to optimise the process flow. The plant normally operates at its current permitted capacity of 250,000 cubic metres per day (approximately 9 million cubic feet per day ("mmcf/d")).

The final stages of the plant upgrade, currently under way, are intended to raise the processing capacity of the plant to 1 million cubic metres per day (35 mmcf/d). The key construction elements are upgrades to the condensate processing and storage facilities and an upgrade to the safety flaring system in the plant. Following completion of these, the plant can be certified by the regulatory authorities to operate at full capacity. The equipment required for the processing and storage upgrade has been delivered to the plant site and construction and installation is close to completion. For the flaring system, the major long lead items have been delivered. The physical completion of the work is anticipated during the first half of 2013, after which regulatory approval of the increased throughput will be sought.

The Group has spent approximately US$6.0 million to date on the upgrade project.

Vostochny Makarovskoye gas/condensate field

The VM field is the Group's largest in terms of its reserves, representing some 74% of the Group total Proven and Probable reserves. Although the initial production wells were drilled in 2008 and 2009, full time production was held up pending the resolution of various legal and commercial matters relating to gas processing. These issues were finally resolved in April 2011 when the Group acquired the Dobrinskoye gas field and processing facility and as mentioned above, full time production commenced in October 2012 on completion of the first two phases of the gas plant upgrade.

In addition to the existing production wells, a previously suspended exploration well, #30, drilled and tested by a previous licensee in the Bobrikovskiy sandstone formation, was worked over and re-completed in April 2012. After the recompletion under a series of production tests the well flowed at a rate of 161,890 cubic metres per day (approximately 5.7 mmcf/d) through a 10 mm choke. Management estimates that when placed on permanent operation, the production rates for the well will exceed 100,000 cubic metres per day (3.5 mmcf/d) with condensate of approximately 20 cubic metres (125 barrels) per day.

During the early months of 2012, the Group continued with its extended pilot production programme on the VM#1 and VM#2 wells. The wells were individually flowed through a test separator installed at the field site. Condensate was gathered in storage tanks on location for sale while gas produced from the wells was flared. Although this activity was primarily a technical test programme, it provided a small profit contribution.

The data gathered from the test programme has enabled the Group to develop a production plan for the VM field. Initial production from the field will be managed to enable higher recovery of condensate from the reservoir in the early years while in the later years an increasing proportion of gas is planned to be produced from the wells. In 2013, the development plan for the VM field includes a sidetrack of the existing well VM #4, which was drilled early in 2009, and up to two new production wells, VM#3 and VM#5.

Dobrinskoye field

The Dobrinskoye gas/condensate field was acquired by the Group in April 2011 and produced steadily for some months after the purchase. During July and August 2011, the field was shut in while repairs were undertaken on the two wells in the Dobrinskoye field. It was decided during this operation that a sidetrack to well #22 would be necessary to enable optimum production from that well.

The sidetrack on well #22 was completed in August 2012. While the sidetrack well #22 tested at commercial rates, some water ingress was observed in the well, suggesting that the production that might be achieved would need to be managed carefully. The decision was taken at that time to drill a sidetrack to well #26 with the aim of improving field productivity.

By November 2012, the sidetrack to well #26 had been successfully drilled and tested. The well #26 sidetrack encountered the upper section of the producing Evlansko-Livenskiy carbonate reservoir as expected at a total vertical depth of 2342 metres, four metres higher than at the original vertical hole. The well was completed with a fourteen metre deviated open hole section (eight metres vertical) in the producing interval.

The well was tested with a 10 mm choke and produced at a stabilized rate of 136,500 cubic metres (4.8 million cubic feet) of gas per day and 62.8 cubic metres (395 barrels) per day of condensate (a total of approximately 1,195 boepd). The condensate ratio is 460 cm3/m3 (82.3 barrels per million cubic feet).

Volga Gas plans to operate well #26 with an 8mm choke and expects production of approximately 3.5 mmcf/d of gas and 280 bpd of condensate (close to 900 boepd in total), with some additional production from well #22.

During H1 2012, the Dobrinskoye field, produced on average 3.5 mmcf/d of gas and 327 bpd of condensate (April to June 2011 8.0 mmcf/d of gas and 623 bpd of condensate) from a single well, #26, while the sidetrack on the other production well, #22, was being drilled. By August, with the upgrade nearing completion, the gas plant was not available for operation. On completion of the gas plant upgrade, management decided to utilise the capacity entirely for the VM field. Consequently the Dobrinskoye field remained shut in for that period.

Uzenskoye oil field

Having reached its fourth year of full time production, the Yuzhny Uzenskoye oil field is the Group's longest established field. During 2012, as in 2011, the focus was on managing and optimizing the output from the five established production wells on the field. Average production for the full year 2012 was 1,106 bopd (2011: 1,178 bopd).

During 2011, the Group identified the potential to increase production from the field by drilling sidetracks on two non-producing wells, #4 and #9. These wells were drilled at the edge of the field and were seen as potential future water injection wells. However, with clear evidence of good natural water drive in the reservoir, it was decided that water injection would not be required in the medium term and that the wells could be partially re-drilled into more advantageous locations and put on production. These drilling operations commenced towards the end of 2011. As announced on 13 March 2012, when the first of these sidetracked wells, #9, was put on stream, it produced only water. This indicates that the oil:water contact had migrated to a higher elevation than had been anticipated on the basis of cumulative production of oil from the field. On the basis of the new information, the Proven and Probable reserves of the field have been independently calculated at 5.6 million barrels. See the paragraph relating to reserves below.

A consequence of the rising oil:water contact is that some of the wells on the field have, since the start of 2013, exhibited some water cut. It is expected that water separation facilities will need to be installed in order to maintain the production levels. The investment required for this is likely to be modest - less than US$1.0 million - and may be implemented during 2013.

The Yuzhny Uzenskoye field, whilst of modest scale, remains very profitable to the Group. With the field being located close to market and producing high quality oil, the sales prices achieved are comparatively advantageous. Furthermore, as the oil is sold directly at the field facilities, the field bears no oil transportation costs. It was developed at a cost of US$1.91 per barrel of 2P reserves and benefits from very low production costs, averaging US$ 1.66 per barrel in 2012 (2011: US$2.00 per barrel).

Exploration activity

The Group drilled two exploration wells completed during 2012 in fulfillment of outstanding licence obligations.

Urozhainoye-2 Licence area

Drilling operations on the YR#1 exploration were completed during H1 2012 with no commercial hydrocarbons found. The well was consequently plugged and abandoned and the costs of the well have been written off. During the period, the Group acquired for a nominal sum the rights to produce from the Sobolevskaya #11 well, an oil discovery drilled by a former licensee. The Sobolevskaya #11 well has recently been successfully worked over and, after installation of production facilities at the well site, will provide an additional, albeit modest, production stream.

Pre-Caspian Licence area

During H2 2012 an exploration well on the Mirnaya prospect was drilled. No hydrocarbons were identified in the potential target Jurassic and Triassic layers. On conclusion of the operations the well was plugged and abandoned.

Oil, gas and condensate reserves as of 1 August 2012

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

The independent assessment of the reserves and net present value of future net revenue ("NPV") attributable to the Company's three principal fields, Dobrinskoye, Vostochny Makarovskoye and Uzenskoye, as at 1 August 2012, was prepared in accordance with reserve definitions prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE). The NPV evaluation was conducted on a constant pricing basis, assuming no future escalations of oil prices, operating expenses, capital, or mineral extraction taxes above the respective 1 August, 2012 values.

The reserve report attributes Proved and Probable ("2P") reserves of 16.1 million barrels ("mmbbl") of oil and condensate and 167.5 billion cubic feet ("bcf") of gas, a total of 44.0 million barrels of oil equivalent ("mmboe"), to the Company's principal fields, and a NPV of US$301.2 million with a 10% per annum discount rate.

The following table shows the Proven and Probable reserves as evaluated by Miller & Lents as at 1 August 2012.

Mikhail Ivanov

Chief Executive Officer

Oil, gas and condensate reserves

As at 1 August 2012

Notes:

1. Future net revenues are defined as the total gross revenues less operating costs, Mineral Extraction Tax ("MET") and capital expenditures. The total gross revenues are the total revenues received at the wellhead. The future net revenues include deductions for other capital and property taxes but do not include deductions for profit taxes.

2. The constant price assumptions used in the calculation of future cash flows were as follows: Crude Oil - US$49.53 per barrel; Condensate - US$47.66 per barrel; Natural Gas - US$2.40 per mcf.

Financial Review

Results for the year

In 2012, the Group generated US$28.3 million in turnover (2011: US$28.6 million) from the sale of 529,501 barrels of crude oil and condensate (2011: 546,818 barrels) and 1,193 million cubic feet of natural gas (2011: 1,348 million cubic feet). Oil and condensate sales were made into the domestic market during the period. In the early part of 2012 the gas sales proceeds were offset against payments of debt outstanding between Gazneftedobycha and Trans Nafta but from April 2012, all gas sales were made for cash payment. The average price realised for liquids was the equivalent of US$48.21 per barrel (2011: US$46.50 per barrel). The contract price for gas sales during 2012 averaged US$2.32 per thousand cubic feet (2011: $2.33 per thousand cubic feet). With sales made exclusively into the regional market in the Volga region at the wellhead, our oil and condensate sales prices closely reflect international prices, adjusted for export taxes and transportation costs. Production activities generated a gross profit of US$12.6 million in 2012 (2011: US$13.0 million).

In 2012, the total cost of production increased to US$2.9 million (2011: US$2.4 million), including a full year of operating costs of the Dobrinskoye gas plant and field. Production based taxes were lower at US$8.9 million (2011: US$9.5 million) reflecting lower rates of Mineral Extraction Tax ("MET") for condensate offset partly by higher MET rates for crude oil and natural gas, and lower production volumes. MET in 2012 represented 31.6% of revenues (2011: 33.3% of revenues). The gross profit margin in 2012 was 44.5% (2011: 45.5%).

Operating and administrative expenses in 2012 included a provision of US$2.9 million for disputed recovery of VAT (2011: nil) while other operating and administrative expenses were US$6.9 million (2011: US$6.7 million).

During the first half of 2012, the Group continued extended production testing on the Vostochny Makarovskoye gas-condensate field. The full costs incurred, including installation of test equipment and operating costs, were expensed during this period. These costs, offset by condensate sales from test production, were included in exploration and evaluation expenses. Following the start-up of commercial production from VM in October 2012, revenues and costs associated with this field were included in the Income Statement.

The Group experienced a decline in EBITDA (defined as operating profit before non-cash charges, including the VAT provision, exploration expense, depletion and depreciation) to US$8.0 million (2011: US$8.9 million) as a result of the higher operating costs and slightly lower revenues.

After recording an exploration and evaluation expense of US$8.5 million (2011: US$0.2 million), and other non-cash expenses of US$ 0.2 million (2011: US$ 5.6 million) the Group recorded an operating loss for 2012 of US$5.9 million (2011: operating profit of US$0.5 million). The exploration and evaluation expense arose primarily from the two unsuccessful exploration wells on which drilling was completed during 2012, reflecting impairment of capitalized costs and actual expenditure incurred in 2012.

After including net interest expense of US$0.2 million (2011: interest income of US$0.2 million) and foreign exchange and other losses of US$0.2 million (2011: US$1.8 million), the Group recognised a loss before tax of US$6.3 million (2011: US$1.1 million) and reported net loss after tax of US$7.4 million (2011: US$1.1 million) after taking a deferred tax charge of US$1.1 million (2011: US$18,000).

No dividends have been paid or proposed for the year (2011: nil).

Cash flow

Group cash flow from operating activities was US$5.4 million (2011: US$5.7 million). The net cash flow of the Group was reduced by US$1.1 million of gas sales being applied to repayment of Trans Nafta loans (2011: US$3.1 million) as well as settlement of disputed VAT for which a US$2.9 million (2011: nil) provision for recovery has been made. Net working capital movements contributed to a cash inflow of US$2.4 million in 2012 (2011: US$1.8 million outflow from working capital movements). With increased capital expenditures in 2012, the net outflow from investing activities was US$13.7 million (2011: US$5.6 million). Net cash inflow from financing activities was US$4.8 million (2011: outflow of US$15.7 million) with the drawing of the bank facility offset by final repayments of the Trans Nafta debt and the commencement of amortization payments under the bank loan. During 2011, the majority of the net cash outflow from financing arose from the repayment of debts owed by GND to its former owner Trans Nafta, amounting to US$15.7 million.

Capital Expenditure

During 2012 a total of US$13.6 million was utilised in investing activities (2011: US$5.6 million) as detailed below:

The most significant individual components of the capital expenditure were on development and producing assets and primarily relates to the Dobrinskoye gas plant upgrade and to drilling of sidetracks to the wells on the Dobrinskoye field. Expenditure on exploration was on two exploration wells completed during 2012, both of which were written off in the year.

Balance sheet and financing

As at 31 December 2012, the Group held cash and bank deposits of US$7.0 million (2011: US$10.1 million) and total bank debt outstanding of US$8.0 million (2011: nil), including a current portion of US$6.4 million (2011: nil). The bank loan was drawn during 2012 and is subject to monthly repayments which commenced in October 2012. As at 31 December 2011 there were loans payable by a Group company to Trans Nafta of US$4.2 million which were repaid during 2012. All of the Group's cash balances are held in bank accounts in the UK and Russia.

As at 31 December 2012, the Group's intangible assets decreased to US$9.6 million (2011: US$39.5 million), as licence costs relating to producing fields were re-classified as property, plant and equipment, which consequently increased to US$103.7 million (2011: US$ 60.8 million). Other increases in property, plant and equipment reflect investment in the gas plant upgrade and drilling of well sidetracks on the Dobrinskoye field.

The Group intends to fund its continuing development and exploration expenditures using a combination of cash flow from operations and cash-on-hand. The Group will consider additional debt facilities to fund the longer term development of its existing licences as appropriate.

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

Tony Alves

Chief Financial Officer

Financial and operational summary

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 28 March 2013 and signed on its behalf by

Group Cash Flow Statement

(presented in US$ 000)

Group Statement of Changes in Shareholders' Equity

(presented in US$ 000)

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

The consolidated financial statements of Volga 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, as modified by the revaluation of financial assets and financial liabilities (including derivative instruments) at fair value through profit or loss.

The preparation of financial statements in conformity with IFRSs requires the use of certain critical accounting estimates. It also requires management to exercise its judgment in the process of applying the Group's accounting policies. The areas involving a higher degree of judgment or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements are disclosed in Note 4.

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

The consolidated financial statements have been prepared on the going concern basis as the directors, having reviewed the future cash flow forecasts of the Group, 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.

1.2 Oil and gas assets

The Company and its subsidiaries apply the successful efforts method of accounting for Exploration and Evaluation ("E&E") costs, in accordance with IFRS 6 "Exploration for and Evaluation of Mineral Resources". Costs are accumulated on a field-by-field basis. Costs directly associated with an exploration well, including certain geological and geophysical costs, and exploration and property leasehold acquisition costs, are capitalised 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.

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.

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

(a) Development tangible and intangible 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 and intangible assets depending on the nature of the expenditure. When development is completed on a specific field, it is transferred to producing assets as part of property, plant and equipment or intangible assets. No depreciation or amortisation is charged during the development phase.

(b) Oil and gas production assets

Development and 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 development and 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.

(c) 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.

(d) Impairment - exploration and evaluation assets

Exploration and evaluation assets are tested for impairment prior to reclassification to development tangible or intangible 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.

(e) Impairment - proved oil and gas production properties and intangible assets

Proven oil and gas properties and intangible assets 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.

(e) Decommissioning

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

1.3 Inventories

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

1.4 Trade and other receivables

Trade and other receivables are recorded initially at fair value and subsequently measured at amortised cost using the effective interest method, less provision for impairment. A provision for impairment of trade receivables is established when there is objective evidence that the Group will not be able to collect all amounts due according to the original terms of the receivables. The amount of the provision is the difference between the asset's carrying amount and the present value of estimated future cash flows, discounted at the original effective interest rate.

1.5 Trade payables

Trade payables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method.

1.6 Current and deferred income tax

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

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

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

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

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

1.7 Revenue recognition

Revenue comprises the fair value of the consideration received or receivable for the sale of oil and gas in the ordinary course of the Group's activities. Revenue is shown net of value added tax, returns, rebates and discounts and after eliminating sales within the Group.

(a) Sales of oil and gas

Revenue from the sale of oil or gas is recognised when the oil/gas is delivered to customers and title has transferred. Revenue is stated net of value-added tax. In 2011 and 2012 ,the Group's revenue related to sales of crude oil and condensate collected directly by customers and gas sales made at the entry to the gas distribution system.

(b) Interest income

Interest income is recognised on a time-proportion basis using the effective interest method.

1.9 Prepayments

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

1.10 Business combinations

Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the fair value of the assets acquired, equity instruments issued and liabilities incurred or assumed at the date of completion of the acquisition. Acquisition costs incurred are expensed and included in administrative expenses. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. If there is excess of the cost of acquisition over the fair value of the acquired entity's share of the identifiable net assets acquired, then the excess is recorded as goodwill. If the cost of the acquisition is less than acquired entity's share of the net assets required, the difference is recognised directly in the statement of income.

2. Cost of sales and administrative expenses - Group

Cost of sales and administrative expenses are as follows:

Total operating and administrative expenses are analysed as follows:

Exploration & evaluation

The principal component of the 2012 exploration and evaluation expense is the impairment charge on the carrying value of intangible assets relating to the two unsuccessful exploration wells completed during 2012 . This includes licence acquisition costs as wells as the cost of seismic studies and costs of drilling and testing operations.

 Provision for disputed VAT

During 2012, the Group paid a sum of US$2.9 million in settlement of a disputed VAT claim. Recovery of this is subject to a continuing court process in Russia. Management considers recovery of the sum to be likely and intends to pursue the recovery vigorously. However, it was considered prudent to make a provision against an unsuccessful outcome.

3. Finance income - Group

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

4. Other gains and losses - Group

5. Intangible assets - Group

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

During 2012 the licence acquisition costs and other intangible assets associated with producing oil and gas fields were transferred to Property, plant and equipment (Note 11).

6. Property, plant and equipment - Group

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

7. 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.

8. Inventories - Group

9. Other receivables - Group

Prepayments are to contractors relate to initial advances made in respect of drilling, construction and other projects.

10. Debt - Group

On 26 March 2012, the Group entered into a loan agreement to provide up to US$10 million by way of a two year amortising credit facility. Under the facility, the amounts outstanding are amortised over 19 monthly instalments commencing October 2012. The maturity period of the financial liabilities under this facility is disclosed in Note 19 below.

11. Trade and other payables - Group

In April 2011, the Group purchased 100% of the share capital of LLC Gazneftedobycha ("GND"). At the date of the acquisition, GND had loans outstanding due to its former parent, Trans Nafta. The final balances were repaid in April 2012.

The maturity period of the Group's financial liabilities, comprising only trade and other payables at 31 December 2012 and 2011 is as follows: