VGAS.L Regulatory News (VGAS)

The following amendment has been made to the Results for the year ended 31 December 2018 announcement released on 08 April 2019 at 07:00 under RNS No. 3612V.

The record date for the dividend payment stated as 05 May 2019 and the payment date of the dividend stated as 27 May in the RNS were incorrect and should have been 03 May 2019 as the record date for the dividend and 28 May 2019 for the payment of the dividend to shareholders.

Additionally, the final dividend amount per share stated by the Company as US$0.09 was incorrect and should have been stated as a final dividend of US$0.065 per share.

All other details remain unchanged

The full amended version is shown below.

8 April 2019

VOLGA GAS PLC

Results for the year ended 31 December 2018

CORRECTED

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 2018.

During 2018, management's principal objective was to complete the construction at the Dobrinskoye gas plant of the new unit to capture liquid petroleum gases ("LPG") from the gas and condensate stream. This was achieved in April 2018. LPG production commenced in May 2018 and built steadily from that point.

Having made adjustments to the Redox based sweetening process early in the year, gas and condensate production remained steady in 2018, compared to 2017. With LPG sales commencing in May 2018, total sales volumes on a barrel of oil equivalent ("boe") basis increased by 6% in 2018. In addition, thanks to stronger oil prices, revenues in 2018 increased by 24%, resulting in EBITDA and cash flow rising by 93% and 179% respectively. With this strong financial performance and the consequent strengthening in the Group's financial position, the Board is pleased to recommend a final dividend of US$0.065 per share on top of the US$0.06 per share interim dividend paid in November 2018.

FINANCIAL RESULTS FOR 2018

· Sales volumes up 6% to 4,956 boepd (2017: 4,667 boepd)

· Gross revenues up 24% to US$45.9 million (2017: US$37.1 million).

· Netback revenues (after export taxes and transport costs) up 25% to US$43.4 million (2017: US$34.8 million).

· EBITDA up 92% to US$16.9 million (2017: US$8.8 million).

· EBITDA per barrel of oil equivalent sold up 83% to US$9.36 per boe (2017: US$5.13 per boe)

· Profit before tax of US$10.6 million (2017: US$0.17 million)

· Operating cash flow before working capital movements of US$20.7 million (2017: US$9.1million), in line with EBITDA but including a receipt of US$3.1 million court settlement (2017: US$0.3 million)

· Total cash of US$15.2 million as at 31 December 2018 (31 December 2017: US$8.6 million) after utilising US$2.1 million for capital expenditure (2017: US$12.6 million) and paying US$4.9 million in equity dividends (2017: US$5.0 million). Total borrowings, comprising bank debt, at 31 December 2018 were US$1.7 million (2017: US$4.0 million).

PRODUCTION & DEVELOPMENT

· Group average production in 2018 increased 4.0% to 5,144 boepd (2017: 4,948 boepd).

· Production from VM and Dobrinskoye fields was 4.4% higher at 4,537 boepd in 2018 (2017: 4,346 boepd) with steady gas plant throughput new LPG production starting in May 2018.

· Oil production from the Uzen field averaged at 607 bopd (2017: 545 bopd) as production from the horizontal well Uzen #101 offset declines in the mature producing wells.

· Two successful sidetracks to the VM#2 and Dobrinskoye #26 wells are expected to restore production from these currently non-producing wells and increase the available production capacity for gas and condensate.

DOBRINSKOYE GAS PLANT

· Improvements in the operation of the Redox based gas sweetening enabled steady gas throughput and reduced operational downtime in 2018.

· Construction of the LPG extraction plant was completed in April. Test production commenced in May 2018 and the commissioning process is now close to complete.

DIVIDEND

· The Board regards the distribution policy to be of utmost importance to shareholders therefore it is intending to declare payments of 75% of the free cash generation of the Group.

· The Board declared an Interim dividend of US$0.06 per share in September 2018 and is proposing a final dividend of US$0.065 per share which will be paid on 28 May 2019 to shareholders on the register on 3 May 2019, subject to approval at the Company's Annual General Meeting on 20 May 2019.

CURRENT TRADING AND OUTLOOK

· Between January and March 2019, Group production averaged 6,117 boepd, in line with management's plan.

· For the coming months, management expects average daily production of gas, condensate and LPG to be in the region of 5,400 boepd, due to planned maintenance downtime, leading to Group production of approximately 5,900 boepd.

· Oil prices have risen since the start of 2019 and have been relatively stable during the first three months of the year.

· As at 31 December 2018, the Group budgeted capital expenditure of US$3.3 million for 2019, of which US$1.7 million was contracted. The principal uses are for further minor items for the LPG project and drilling of the recently completed sidetrack wells. These sums are less than the anticipated levels of operating cash flow.

Andrey Zozulya, Chief Executive of Volga Gas, commented:

"We are pleased to have delivered on the two key aims; improvement in operational reliability of the Redox gas sweetening and construction of the LPG extraction plant. These have already delivered a higher level of production that is expected be sustainable in the medium to long term. The improvement in profitability achieved in 2018 exceeded management's expectations and, in a stable oil price environment, would be sustainable.

"The Board is very pleased to be recommending further dividend payments to shareholders.

 "We remain excited about the Group's assets and remain positive about the potential for production from our fields and the potential to discover additional fields in our licences. We will also continue to seek value accretive opportunities, beyond our existing licence areas, building a focused exploration and production business."

Market Abuse Regulation (MAR) Disclosure

Certain information contained in this announcement would have been deemed inside information for the purposes of Article 7 of Regulation (EU) No 596/2014 until the release of this announcement.

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 and investor presentation

The Group's full report and accounts and the 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, 6th floor, 65 Gresham Street, London EC2V 7NQ. The latest presentation for investors is also available on the Company's website.

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

mmcf/d millions of standard cubic feet per day

Chairman's Statement

Dear Shareholder,

During 2018 conditions for the oil and gas industry worldwide were generally favourable with periods of strong pricing. Despite challenging geopolitics and some weakness in the Ruble, domestic energy market conditions have also been stable. Volga Gas has been able to benefit from the improved pricing environment with steady production from its fields. The Group also has also benefitted from the switching of the gas sweetening process utilised at its principal production facility, the Dobrinskoye gas processing plant, to a Redox-based system. This has reduced the chemical costs of the operation and has eliminated the need to dispose of bulky spent processing chemicals.

The main accomplishment of 2018 was the completion of the construction of a plant at the gas processing facility to capture for sale the liquid petroleum gases ("LPG") - propane and butane - that were hitherto vented and flared. The LPG project commenced producing and selling product in May 2018. Within a few months of operation, the LPG plant contributed more than the 400 barrels of oil equivalent per day of incremental sales volumes targeted by management. With some other improvements, which can be achieved at low cost, we expect to be able to increase these volumes still further. I am also pleased that this project was completed at a cost of US$5.6 million. This is discussed in greater detail by the Chief Executive Officer in the Operational Review.

With stable underlying production, and seven months' contribution from sales of LPG and stronger prices, the Board is pleased to report that revenues have increased 24% to US$45.9 million (2017: US$37.1 million), EBITDA is up 92% to US$16.9 million (2017: US$8.8 million) and operating cash flow before working capital movements more than doubled to US$20.7 million (2017: US$9.1 million). With a modest capital expenditure programme during 2018 the Group has generated free cash inflow of US$15.6 million (2017: free cash outflow of US$6.2 million). This has enabled the Company to resume dividend payments to shareholders, with an interim US$4.9 million paid in November 2018. The Group ended the year with a healthy cash balance of US$15.2 million (31 December 2017: US$8.6 million). Meanwhile the borrowings of the Group reduced from US$4.0 million at 31 December 2017 to US$1.7 million as at 31 December 2018 and have, subsequent to the year end, been paid off entirely.

As detailed in the 2017 Annual Report, the Board commissioned an updated independent reserves report following water incursion in certain production wells at the VM field and subsequently recognised a 27% reduction in the Group's total proved reserves and a 28% reduction in the proved and probable reserves of oil, gas and condensate. During 2018 studies have been undertaken on the reservoir to optimise future production of the field. These studies are expected to continue through to mid-2019. Based on the currently available data and on the production performance during 2018, the Board is satisfied that the reserves estimate established on 12 April 2018 remain reasonable. As the Chief Executive details in the Operational Review the drilling of sidetracks to two existing wells was completed in February 2019. Based on preliminary results these should restore production from two recently non-producing wells and thereby increasing total productive capacity.

The Board remains confident that its three proven fields 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, through successful exploration and by selective value-accretive acquisitions. The Board believes that Volga Gas has a stable foundation and the financial and operational capability to develop and extend these assets to provide long-term value for our shareholders. As part of a future growth strategy, the Group has acquired at low cost and with limited commitments a new licence block in Bashkiriya region with potential for oil production.

The Board remains committed to prioritising dividend distribution, bearing in mind the requirements of the business and the need to maintain its financial strength. With these considerations, the Board plans to distribute up to 75% of the Group's free cash flow as dividends. The Board is consequently recommending a final dividend of US$0.065 per share, which with the US$0.06 interim dividend declared on 28 September 2018, makes a total distribution of US$0.125 per share in respect of 2018.

With a broadly stable outlook for the oil industry, the finances of the Group will continue to be conservatively managed. Capital investment commitments will continue to be modest and focused on enhancing the profits from the gas and condensate production and optimising the production from the reserves of the Company.

Finally, I would like to update you on the Board. On 14 February 2019, Michael Calvey, a senior partner of Baring Vostok Capital Partners ("Baring Vostok") and a non-executive director of Volga Gas, along with three other employees of Baring Vostok were arrested and detained at the order of the Moscow Bassmaniy Court. Baring Vostok believes that its employees have at all times acted in full compliance with the law and each of them is being defended vigorously. These law enforcement actions are not related to the activities of Volga Gas, and both Volga Gas and Baring Vostok continue to operate as usual.

As Mr Calvey is temporarily unable to fulfil his duties as a director of Volga Gas, the Company has consulted on the nomination and appointment of an alternate. The remainder of the Board supports and has agreed to the appointment of an alternate. A proposed alternate has been identified by Baring Vostok and the regulatory checks required by the Company's nominated adviser have been successfully completed. While the Company waits for the remaining formalities required under the Company's Articles of Association to be fulfilled to complete the appointment the proposed alternate has been invited to attend Board meetings in a non-voting capacity.

Mikhail Ivanov

Chairman

Chief Executive's Report

In 2018, the Group's main focus was to complete the construction and commissioning of the new LPG facility at the Dobrinskoye gas processing plant and to commence production of LPG. The principal construction operations were finished in April 2018 and test production of LPG commenced in May 2018. Since start up, production of LPG has gradually increased as the formal commissioning process continued. During the second half of 2018, LPG contributed approximately 362 boepd to the Group total of 5,560 boepd. With further minor additions and modifications to the LPG plant and infrastructure, management expects to achieve higher levels of LPG extraction during the first half of 2019.

I am pleased to report that the Redox-based sweetening, which was implemented during 2017 at the gas processing plant, is continuing to operate as planned and is providing the expected benefits of lower consumables costs and elimination of waste material that required disposal. The plant has sufficient capacity to process the full gas throughput under the current production management regime on the VM and Dobrinskoye fields.

As discussed in the 2017 Annual Report, there was a reduction in reserves estimates in the VM field following detection of increased formation water, which led management to adopt a conservative production policy to avoid additional water incursion. Nevertheless, total Group production for 2018 averaged 5,144 boepd compared to 4,948 boepd in 2017 reflecting improved processing capacity utilisation on the gas processing plant as well as a seven month contribution from LPG.

In addition, the Group's revenues benefitted from overall higher oil prices during 2018 as international crude markets firmed during the middle of the year before weakening towards the end of 2018. These points are covered in more detail in the Financial Review below.

During 2018, the Group and its technical advisers have been carrying out studies aimed at optimising recovery of reserves from the VM field and technical and operational solutions to mitigate the impact of the reserves reductions and to maximise gas production through the Dobrinskoye gas plant. While the work continues, management decided to drill sidetracks from two existing non-producing wells in order to reinstate production from these wells. Details are discussed in the Operational Review below.

While the focus of activity and investment has been on improving the performance of existing production operations, management has also been developing a strategy for future growth through exploration. In addition to technical work on prospects in the Karpenskiy licence area, the Group has acquired a new licence block in Bashkiriya region with potential for oil production.

2019 objectives and medium-term strategy

Management has the following key objectives in 2019:

· To increase the extraction rates of LPG at the gas processing plant.

· To complete the reservoir and technical studies on the VM field and to commence actions including workovers and reperforations of the well bores to mitigate future formation water production, thereby restoring maximum gas production and the extraction of reserves in place.

· Optimise the production of oil from the new horizontal well Uzen #101 and to manage the more mature oil wells in the field.

· To sustain the profitability and cash generation of operations so as to enable a steady distribution of dividends to shareholders.

Current trading and outlook

Between January and March 2019, Group production averaged 6,117 barrels of oil equivalent per day, in line with management's expectations. Given the anticipated higher levels of planned maintenance downtime in the period for the coming months, management expects to maintain an average daily production of gas, condensate and LPG in the region of 5,400 boepd, resulting in Group production of approximately 5,900 boepd for the full year.

International oil prices strengthened at the start of 2019 and have remained relatively stable.

In the current environment, and at current production rates which now include LPG, management expects the Group's financial performance in 2019 to improve on that of 2018. Meanwhile, new capital expenditure commitments remain significantly less than projected cash generation, so I am pleased to announce that the board has agreed to increase in its sustainable dividend policy for shareholders from the previously announced 50% of net income to 75% of the Group's free cash flow being distributed as dividends.

Andrey Zozulya

Chief Executive Officer

Operational Review

Operations overview

Group production in 2018, at an average daily rate of 5,144 boepd, was 4% higher than the 4,948 boepd achieved in 2017. The production performance is in line with management expectations and reflects the production management strategy adopted on the VM field in light of the observed water incursion into certain of the production wells.

With the successful implementation of Redox based processing and minor improvements to the process achieved during early 2018, the gas plant has sufficient capacity to process planned production from the two gas /condensate fields. In addition, the LPG plant was brought on stream with minimal disruption to production and contributed on average 223 boepd to 2018 production (albeit only from May 2018), with a year end exit production rate of 393 boepd.

While production levels in 2018 were close to those of 2017, international oil prices enjoyed a period during 2018 of considerable strength with the Urals oil price reaching an average level of over US$70 per barrel in 2018 compared to US$53 per barrel in 2017. These stronger international prices fed through into domestic prices in which the Group's oil and condensate sales are made and led to a healthy improvement in revenues for the Group.

Taking into account selling expenses, netback revenues (defined as revenues less selling expenses as shown in the Income statements) in 2018 of US$43.4 million were 25% higher than the US$34.8 million in 2017.

Overall production costs were lower, with benefits of savings from the lower process chemicals costs and the weaker Ruble exchange rate, partly offset by higher personnel and administrative expenses. In addition higher oil prices and the scheduled adjustments to the rate formulas led to higher rates of Mineral Extraction Tax. Nevertheless EBITDA for 2018 was 92% higher at US$16.9 million (2017: US$8.8 million). Sales of LPG of US$2.8 million in 2018 (2017: nil) were a useful contribution to this growth since the direct costs of these sales are relatively low and there is no additional MET as this tax is levied on hydrocarbons extracted from the ground rather than product sales.

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. The VM field was developed with wells drilled by Volga Gas, while the Dobrinskoye wells were acquired from previous licensees.

By the end of 2016, the initial development drilling on the VM field was essentially completed, with a total of four wells in the principal reservoir, the Evlano Livinskiy carbonate, and a further well in the secondary Bobrikovskiy sandstone reservoir. The field has been in full commercial production since then. During 2018 production from VM was derived from three wells, VM#1,VM#3 and VM#4 while small volumes were also derived from the Dobrinskoye #26 well which since April 2018 has not been in commercial production.

Production during 2018 averaged 18.8 mmcf/d of gas and 1,183 bpd of condensate and 223 bpd of LPG (2017: 19.1 mmcf/d of gas and 1,163 bpd condensate and no LPG), a total of 4,537 boepd (2017: 4,353 boepd). During the first half of 2018, there were a number of periods of downtime at the processing plant for minor modifications to the sweetening process and for general maintenance and also some well maintenance operations. During the second half of 2018, production was sustained at a higher level apart from periods in July and September 2018 when there were scheduled maintenance operations at the Gazprom pipeline.

Management estimates the current productive capacity of the three producing wells on the VM field to be approximately 22.5 mmcfd of gas plus 1,370 bpd of condensate and 370 boepd of LPG, a total of 5,490 boepd. This rate is consistent with the strategy of reservoir management adopted after the detection of water influx in certain wells.

Technical and operational studies continue to find solutions to mitigate the impact of the reserves reductions recognised in April 2018, including conducting well interventions on the VM field, workovers and reperforations of the well bores. While the work on the reservoir is yet to be completed, management has decided to proceed with two well sidetracks. The first of these was carried out on the non-producing Dobrinskoye #26 well to develop a likely undepleted portion of the reservoir. The drilling was completed in December 2018 with encouraging signs that it will be more productive than expected by management. Test production is planned during Q2 2019. Drilling of a sidetrack on the VM#2 well which was also non-producing, was completed on 17 February 2019. Flow testing conducted during March 2019 resulted in gas flow but with high water cut. As the well logging indicated gas pay in the well, management believes the water is flowing from an aquifer below the reservoir through a local fault. A further workover to install a cement plug to cut off this water influx is planned. Results of this further intervention will be announced in due course. Management believes there would be no current impact on reserve estimates.

The proven and probable reserves estimates as at 31 December 2017 were independently assessed by OOO Geostream Assets Management. Based on observed field performance and the results of technical studies to date, management believes these estimates remain valid and no further revisions to reserves are currently indicated. The reserves estimates adopted for 31 December 2018 reflect the starting reserves less the volumes produced during the year.

Gas, condensate and LPG sales

Since December 2016, the Group has been making its gas sales directly to Gazprom. Compared to the previous arrangements, this has resulted in an increase in the net realisations, although the Group now pays a transit tariff for delivery via the Gazprom pipeline network to the point of sale and a sales commission. These form part of the selling expenses.

During 2018, the Ruble experienced a sudden devaluation. Since the gas pricing was fixed in Ruble terms, in US Dollar terms the average gas sales realisations were 3% lower in 2018 at US$1.99/mcf (2017: US$2.06).

In November 2015, Volga gas established export channels for condensate as an alternative to domestic sales in periods of low domestic demand. However, in both 2017 and 2018, domestic market conditions were generally more favourable and consequently condensate exports in 2018 were 12% of total sales (2017: 15%).

During 2018, the average condensate netback price (after accounting for export taxes and transportation costs) increased 26% to US$43.32 per barrel (2017: US$34.37).

Production of LPG commenced on a pilot basis in May 2018 and during the year ended 31 December 2018 a total of 6,903 tonnes of LPG was sold - principally to buyers in the Volga region - realising US$412 per tonne or US$35.07 per barrel of oil equivalent. As we gain more experience in marketing LPG and become more established producers, the returns are expected to improve relative to condensate.

Average unit production costs on the gas condensate fields decreased to US$4.21 per boe in 2018 (2017: US$5.39). The decline in the Ruble, in which effectively all the costs are denominated, and improved throughput rates in 2018 which reduced the impact of the fixed cost element of the operating expenses and benefits of lower chemical costs all contributed.

Gas processing plant

From June 2017, the plant was switched over entirely to Redox-based processing. During the initial months of the new process, between June and August 2017, the plant throughput was kept at relatively low levels as the process management was optimised. Throughput increased gradually through the remainder of 2017, from the average rate of 213,000 m3/day (7.5 mmcf/d) in June 2017 to reach 533,000 m3/day (18.8 mmcf/d) in December 2017.

Early in 2018, two further oxidising vessels were added to the current plant configuration. This, led to improvements in efficiency, reduced operational downtime and higher effective operating capacity. During 2018 plant throughput of up to 25 mmcf/d was achieved - sufficient to process the output from the fields. In addition further improvements to the process enabled the plant to operate with minimal interruptions during the 2018-19 winter months.

The key development at the gas plant in 2018 was the completion in April 2018 of the construction of a new unit for the capture, storage and sale of LPG. The plant commenced test production in May and has been in operation since then. LPGs, primarily comprising propane and butane, are currently either included in the sales gas stream or flared. The LPG project provides an additional product stream which by November 2018 increased total sales volumes by more than management's 400 boepd target.

The total capital cost of the LPG project to date was US$5.6 million. Management is targeting further improvements in the efficiency of LPG extraction to increase the yields from the gas stream.

Oil production and development

The Group's oil production is derived from the Uzen field. During 2018 production averaged 607 bopd (2017: 595 bopd). The Uzen field has been producing oil from a cretaceous Aptian reservoir at a depth of approximately 1,000 metres since 2009 and is now at a late stage of maturity of production. The original mature wells produced at an average rate of 422 bopd in 2018 (2017: 595 bopd).

In 2017 the Group drilled a new horizontal well #101 on the Uzen field to develop the proved reserves in the shallower Albian reservoir. Since December 2017, this well has been in continuous production. During 2018, well #101 produced at an average rate of approximately 185 bopd.

Future drilling on the Uzen field is likely to be limited to development of other portions of the Albian reservoir through sidetracks from well #101. This is likely to happen after 2019.

Exploration

During 2018, the Group continued to focus on income-generating investments so exploration activity was confined to internal technical studies.

Nevertheless, 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. In addition, the Group has acquired at low cost and with little committed capital expenditure a new exploration project, the Muradymovsky License Area, in the Bashkiriya region in an area of active oil production. Studies on this indicate the potential for material new reserves that could be brought rapidly into production. However, Volga Gas has not to date prepared estimates of any reserves or resources in this licence.

In parallel, management has been developing a strategy to test multiple shallow oil prospects using an innovative slim hole drilling technique. This has not yet reached the stage of becoming a firm proposal to put to the Board for investment, but management recognises the importance of having a portfolio of low-cost opportunities to add potentially material new reserves.

However, the immediate priority is to maximise the value and cash generation from proven reserves in existing operations.

Oil, gas and condensate reserves as of 1 January 2019

In February 2018, Volga Gas commissioned an updated reserve report of the Group's oil, gas and condensate reserves which were adopted by the Company as a its statement of reserves, leading to significant revisions to previous reserve estimates which were detailed in the 2017 Annual Report. Based on studies undertaken in 2018 and on the production performance of the Group's fields during the year, management believes that no further revisions to reserves are presently indicated. Accordingly the change in the Group's reserves as shown in the table below reflect the volumes produced during the year ended 31 December 2018.

Oil, gas and condensate reserves

Notes:

1. Volga Gas (through its wholly owned subsidiaries PGK and GNS) is the operator and has a 100% interest in five licences to explore for and produce oil, gas and condensate in the Volga region.

2. The reserve estimates as at 31 December 2017 were independently assessed in an updated study conducted by OOO Geostream Assets Management dated 12 April 2018. The full reserve report is available on the Company's website: www.volgagas.com.

3. The reserve estimates were prepared in metric units: tonnes for oil, condensate and LPG and standard cubic metres for gas. The conversion ratios from tonnes to barrels applied in the table above were 7.833 barrels per tonne of oil, 8.75 barrels per tonne of condensate and 11.75 barrels per tonne of LPG. One cubic metre equates to 35.3 cubic feet and one barrel of oil equivalent is given by 6,000 standard cubic feet of gas.

4. The above reserve estimates, prepared in accordance with the PRMS 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 2018, the Group generated US$45.9 million in turnover (2017: US$37.1 million) from the sale of 649,541 barrels of crude oil and condensate (2017: 644,506 barrels), 6,904 tonnes of LPG (2017: nil) and 6,471 million cubic feet of natural gas (2017: 6,378 million cubic feet).

During 2018, 12% by volume of condensate sales were exported (2017: 15%). After accounting for export costs, comprising export tax and transportation, the combined netback revenue for all condensate sales during 2018 was US$43.32 per barrel (2017: US$34.37). The netback from condensate exports was almost identical to the net realisation from domestic sales (2017: export netback US$32.66 and domestic sales US$35.05 per barrel). In 2018 as in 2017 all oil sales were in the domestic market. The average sales price for oil in 2018 was US$45.59 per barrel (2017: US$37.24).

The gas sales price during 2018 averaged US$1.99 per thousand cubic feet (2017: US$2.06 per thousand cubic feet), the decrease being attributable to movement in the Ruble/US Dollar exchange rate which more than offset the increase in the Ruble selling prices. In 2018, as in 2017, the Group's gas sales were direct to Gazprom.

In 2018, the total cost of production decreased to US$8.3 million (2017: US$9.3 million), driven mainly by the devaluation of the Ruble as well as some cost savings from chemicals used for gas sweetening.

Unit field operating costs were lower at US$4.61 per boe (2017: US$5.46 per boe), also mainly as a result of Ruble devaluation. Production-based taxes increased to US$13.2 million (2017: US$10.9 million) reflecting the impact of higher oil Mineral Extraction Tax ("MET") rates as well as the impact of further formula changes that came into effect on 1 January 2018. MET paid in 2018 represented 30.4% of netback revenues (2017: 31.4% of netback revenues).

Production activities generated a gross profit of US$16.1 million in 2018 (2017: US$8.2 million).

Operating and administrative expenses in 2018 were US$4.9 million (2017: US$5.8 million), reflecting the weaker Ruble as well as the non-recurrence in 2018 of certain one-off expenses incurred in 2017.

The Group experienced a 93% increase in EBITDA (defined in the operational and financial summary as operating profit before non-cash charges, including exploration expenses, depletion and depreciation) to US$16.9 million (2017: US$8.8 million).

The unit rate of Depletion, Depreciation and Amortisation ("DD&A") decreased to US$4.53 per boe (2017: US$5.02 per boe) principally as a result of Ruble devaluation as well as modest additions to fixed assets. The DD&A charge in 2018 was US$8.2 million (2017: US$8.6 million) reflecting the modest increase in production partly offsetting the lower unit DD&A rate.

With no significant exploration and evaluation expenses in 2018 (2017: nil) or other provisions (2017: nil), the Group recorded an operating profit for 2018 of US$10.3 million (2017: US$113,000). Included in operating profit in 2018 was a US$3.1 million court award granted in the Group's favour against a drilling contractor, partly offset by the write off of US$1.5 million capitalised costs relating to the sidetrack of the Uzen #4 well which was the subject of the dispute.

Including net interest income of US$0.4 million (2017: US$0.2 million) and other net gains of US$1.4 million (2017: net loss of US$142,000) the Group recognised a profit before tax of US$10.6 million (2017: US$0.17 million).

Net profit after tax was US$8.4 million (2017: US$330,000) after a current tax charge of US$2.2 million (2017: US$243,000) and a deferred tax credit of US$17,000 (2017: deferred tax credit of US$405,000).

Profitability by product

While the Group operates as a single business segment, management estimates the relative profitability, which for this purpose is defined to be gross profit less selling expenses, by product to be as follows:

Cash flow

Group cash flow from operating activities increased almost threefold to US$18.3 million (2017: US$6.3 million). Net working capital movements contributed cash outflow of US$0.7 million in 2018 (2017: net outflow of US$2.3 million). Included in cash flow from operations was the receipt during 2018 of a sum of US$3.1 million (2017: US$0.3 million) being a court awarded settlement of a legal dispute. During 2018 there were payments of profit tax of US$1.8 million (2017: US$0.5 million). With lower capital expenditures in 2018, the net outflow from investing activities was US$2.3 million (2017: US$12.6 million). With dividend payments of US$4.9 million in 2018 (2017: US$5.0 million) and loan repayments of US$1.8 million (2017: US$0.2 million), net cash outflow from financing activities was US$6.7 million (2017: US$5.2 million), leading to a net increase in cash by US$6.6 million (2017: net decrease of US$11.1 million).

Dividend

In November 2018 the Company paid an interim dividend of US$0.06 per ordinary share (2017: total dividends of US$0.062 per share in respect of 2016). As indicated in the 2017 Annual Report, the Board has decided to base dividends on cash generation as well as earnings and, subject to the requirements of the Group, of distributing up to 75% of free cash flow. Consequently the Board is recommending a final dividend of US$0.065 per ordinary share which, subject to approval of the Company's Annual General Meeting on 20 May 2019, is to be paid on 28 May 2019 to shareholders on the register on 3 May 2019.

Capital expenditure

During 2018 capital expenditure of US$2.8 million was incurred (2017: US$12.4 million), of which US$2.6 million was incurred on development and producing assets (2017: US$12.3 million) and US$0.2 million on exploration and evaluation (2017: US$0.1 million). Capital expenditure in 2018 comprised completion of the construction of the LPG plant and minor upgrades to the gas processing plant and minor items of maintenance capital expenditure on the Uzen oil field and the VM field.

Balance sheet and financing

As at 31 December 2018, the Group held cash and bank deposits of US$15.2 million (2017: US$8.6 million). All of the Group's cash balances are held in bank accounts in the UK and Russia. Approximately 61% (2017: 48%) of the Group's cash is held in US Dollars and 38% (2017: 50%) held in Russian Rubles.

In December 2016, the Group drew down from a RUR 240 million (US$4.0 million) bank facility, which was utilised to fund purchases of equipment for the LPG project. Repayments commenced in monthly instalments in December 2017. Total debt as at 31 December 2018 was US$1.7 million (2017: US$4.0 million). Subsequent to the year end, the remaining balance of the debt has been repaid in full.

As at 31 December 2018, the Group's intangible assets were US$3.3 million (2017: US$3.8 million). Property, plant and equipment decreased to US$45.1 million (2017: US$62.3 million), reflecting capital expenditures lower than depreciation in 2018 as well as the impact of foreign exchange adjustments. The carrying values 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 and taking into account the reduction in oil and gas reserves, as detailed in note 4(b) to the accounts, showed no present requirement for impairment.

For the year ending 31 December 2018, the Group recorded a currency retranslation expense of US$11.8 million (2017: income of US$3.5 million) in its other comprehensive income, relating to the movement 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 volatility in international oil prices and the Ruble. The Group may consider additional debt facilities to fund the longer-term development of its existing licences and operational facilities as appropriate. However, management expects to continue to generate positive free cash flow enabling further distributions to shareholders.

The Group's financial statements are presented on a going concern basis, as outlined in note 2.1 to the accounts.

Vadim Son

Chief Financial Officer

Five year financial and operational summary

Netback realisation for oil and condensate is calculated by deducting selling expenses from oil, gas and condensate sales.

EBITDA is calculated from Operating Profit as shown in the Group Income Statement, adding back:

· Depletion, depreciation and amortisation, as disclosed in Note 6, analysis of Cost of Sales;

· Write off of development assets, as disclosed in Note 6, analysis of Total Expenses; and deducting

· Other operating income as disclosed in Note 5(d)

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.

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. In addition, the Ruble exchange rate has tended to move with the oil price, reducing the overall volatility of oil prices when translated into Russian Rubles.

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. Since November 2015, the Group has developed export channels for its condensate into regional export markets to mitigate this risk. Gas sales are made to Gazprom. 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.

 Oil and gas production taxes

The Group's sales generated from oil and gas production are subject to Mineral Extraction Taxes ("MET"), which form a material proportion of the total costs of sales. The rates of these taxes are subject to changes by the Russian government, which relies heavily on such taxes for its revenues. Changes to rate formulas which came into effect during in recent years have materially increased the rates on crude oil, condensate and natural gas. As of 2019, the Russian government's policy is to transfer the burden of taxes from export taxes to MET and the formulas for both taxes are to change to put this into effect over a five year period. It is uncertain that domestic oil sales prices will rise sufficiently to reflect in full the reduction in export taxes to compensate for the increase in MET on oil production sold in the domestic market.

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 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. However, the Group's current plans involve limited expenditure in exploration-related activities.

In February 2018, the Group commissioned an updated reserve evaluation based on reporting standards set by the Society of Petroleum Engineers. The reserve report, delivered to and adopted by management on 12 April 2018, resulted in a downward revision by approximately 27% to the Group's reserves as at 31 December 2017. Management considers the independent reserve estimate to be in line with the currently available field data and accordingly has chosen to adopt the estimates as the statement of the Group's oil, gas and condensate reserves. In addition, management considers the performance of the fields during 2018 to be consistent with the latest reserve evaluations and proposes no further revisions to be currently required. The reserve estimate as at 31 December 2018 is accordingly only adjusted for the volumes produced in the year ended 31 December 2018. The Group's reserve statement is shown in the Operational Review on pages 7 and 8. The impact of the reserve revision in 2018 has been to increase the depletion, depreciation and amortisation charge of the Group with consequent reductions in the profit and net book value of the Group's assets. While the reserve revisions do not appear to have triggered an impairment subsequent, future reserve evaluations may lead to further revisions which may impair the assets. Furthermore, if the 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 both the future profitability and the balance sheet carrying values of 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, including waste materials generated by the sweetening process formerly in use at the Dobrinskoye gas processing plant. 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 regard 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 expenses is in US Dollars, Euros and Pounds Sterling. Revenues are predominantly received in RUR, so 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, fluctuations in the exchange rate of the RUR against the US Dollar impact the Group's financial statements.

Business in Russia

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

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

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

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

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

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

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

§ Unexpected changes to the federal and local tax systems.

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

§ The imposition of sanctions upon certain entities in Russia.

The Group's operations and financial management have not been impacted directly by any sanctions to date.

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 2018, the Group had US$15.2 million (2017: US$8.6 million) of cash and cash equivalents, of which US$13.8 million was held in bank accounts in Russia (2017: $7.9 million). As at 31 December 2018, total bank debt was US$1.7 million (2017: US$4.0 million). The remaining balance of bank debt was repaid in January 2019. The Group has fully drawn on the debt facilities available as at 31 December 2018 and 31 December 2017. 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 2018 the Group had budgeted capital expenditures of US$3.3 million, of which the significant items were US$1.7 million for drilling of sidetrack wells and other development activities. There were approximately US$1.1 million of accounts payable relating to capital expenditures and other expenses incurred in the year ended 31 December 2018 (2017: US$1.1 million).

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

Capital risk

The Group manages capital to ensure that it is able to continue as a going concern whilst maximising the return to shareholders. The Group is not subject to any externally imposed capital requirements. The Board regularly monitors the future capital requirements of the Group, particularly in respect of its ongoing development programme. 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.

Bribery

The Company is subject to numerous requirements and standards, including the UK Bribery Act. In addition the Group is subject to anti-bribery and anti-corruption laws and regulations in all jurisdictions in which it operates. Failure to comply with regulations and requirements, such as failure to implement adequate systems to prevent bribery and corruption, could result in prosecution, fines or penalties imposed on the Company or its officers or suspension of operations. The Group's mitigation measures include compliance-related activities, training, monitoring, risk management, due diligence and regular review of policies and procedures. We prohibit bribery and corruption in any form by all employees and by those working for, or connected with the business. Employees are expected to report actual, attempted or suspected bribery or other issues related to compliance to their line managers or through our confidential reporting process, which is available to all staff as well as third parties.

Fraud

The Group has been exposed to fraudulent transfers of funds from its bank accounts and is at various times at risk to attempted fraud. The Group has established enhanced protections of its information technology infrastructure, operational systems and procedures against fraudulent activities.

Other risks/Brexit

By the end of 2018, the terms and conditions of the UK's exit from the EU on 29 March 2019 had not been agreed with the EU, it therefore remained unclear where the UK was heading with Brexit. The Company is not significantly commercially exposed to the outcome of the Brexit negotiations between the UK and EU (e.g. soft or hard exit, deal or no deal, second referendum):

· Customers and supply chain: The Company conducts no trade between the UK and the EU.

· Employees: The Group has no employees based in the UK. Therefore, there is no impact of Brexit on the Company's employees.

· Financing: The Company does not have significant external financing in place and the day to day requirements are met from its cash balances in Russia. The transfer of money is unlikely to be affected by Brexit and therefore this is not a significant issue.

· Regulations: There are no specific regulations which could potentially have significant impact on the Company in case of Brexit.

The Company continues to monitor the political and economic events and forecasts to manage any potential impacts to its business including its employees.

Vadim Son,

Chief Financial Officer

Abbreviated Financial Statements

for the year ended 31 December 2018

Group Income Statement

(presented in US$ 000)

Group Statement of Comprehensive Income

(presented in US$ 000)

Group Balance Sheet

(presented in US$ 000)

Group Cash Flow Statement

(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 2018

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 are set out in the Strategic Report in pages 2 to 14; the financial position of the Group, its cash flows, liquidity position and borrowing facilities are described in the Financial Review on pages 9 and 10. 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 in the light of the reductions in oil and gas reserves and in consideration of the current financial condition of the Group, the directors have concluded that the Group will continue to have 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.

1.2 Financial instruments (policy applicable from 1 January2018)

Unless specifically disclosed below, the Company generally applied the following accounting policies retrospectively. Nevertheless, as permitted by IFRS 9 Financial Instruments, the Company have elected not to restate the comparatives.

i. Recognition and initial measurement

A financial asset or a financial liability is recognised in the statement of financial position when, and only when, the Company becomes a party to the contractual provisions of the instrument.

A financial asset (unless it is a receivable without a significant financing component) or a financial liability is initially measured at fair value plus or minus, in the case of a financial instrument not at fair value through profit or loss, any directly attributable transaction costs incurred at the acquisition or issuance of the financial instrument. A trade receivable that does not contain a significant financing component is initially measured at the transaction price.

ii. Classification and subsequent measurement

· Financial Assets

Upon adoption of IFRS 9 Financial Instruments, financial assets are classified as measured at: amortised cost, fair value through other comprehensive income (FVOCI) and fair value through profit or loss (FVTPL), as appropriate.

The Company determines the classification of financial assets at initial recognition and they are not subsequently reclassified unless and the Company changes its business model for managing financial assets in which case all affected financial assets are reclassified on the first day of the first reporting period following the change of the business model.

In 2018, all Company's financial assets were measured at amortised cost.

Amortised cost category comprises financial assets that are held within a business model whose objective is to hold assets to collect contractual cash flows and its contractual terms give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding. The financial assets are not designated as fair value through profit or loss.

Subsequent to initial recognition, these financial assets are measured at amortised cost using the effective interest method. Interest income and foreign exchange gains and losses are recognised in profit or loss.

· Financial liabilities

All Company's financial liabilities at initial recognition are recognised at amortised cost. Subsequent to initial recognition, financial liabilities are subsequently measured at amortised cost using the effective interest method. Gains and losses are recognised in the profit or loss when the liabilities are derecognised as well as through the amortisation process.

· Offsetting of financial instruments

Financial assets and financial liabilities are offset and the net amount is reported in the statement of financial position if, and only if, there is a currently enforceable legal right to offset the recognised amounts and there is an intention to settle on a net basis, or to realise the assets and settle the liabilities simultaneously.

· Amortised cost of financial instruments

Amortised cost is computed using the effective interest method. This method uses effective interest rate that exactly discounts estimated future cash receipts or payments through the expected life of the financial instrument to the net carrying amount of the financial instrument. Amortised cost takes into account any transaction costs and any discount or premium on settlement.

· Derecognition of financial instruments

A financial asset is derecognised when the rights to receive cash flows from the asset have expired or, the Company has transferred their rights to receive cash flows from the asset or have assumed an obligation to pay the received cash flows in full without material delay to a third party under a "pass-through" arrangement without retaining control of the asset or substantially all the risks and rewards of the asset.

On derecognition of a financial asset, the difference between the carrying amount and the sum of the consideration received (including any new asset obtained less any new liability assumed) and any cumulative gain or loss that had been recognised in equity is recognised in the profit or loss, except for equity investments at fair value through other comprehensive income where the gain or loss are recognised in other comprehensive income.

A financial liability is derecognised when the obligation under the liability is discharged or cancelled or expired. On derecognition of a financial liability, the difference between the carrying amount of the financial liabilities extinguished or transferred to another party and the consideration paid, including any non-cash assets transferred or liabilities assumed, is recognised in the profit or loss. In the case of waiver of debt from owners, the gain is recognised in equity as capital reserve.

· Impairment

Unless specifically disclosed below, the Company generally applied the following accounting policies retrospectively. Nevertheless, as permitted by IFRS 9 Financial Instruments, the Company have elected not to restate the comparatives.

The Company recognises loss allowances for expected credit losses on financial assets measured at amortised cost and contract assets. The Company measures loss allowances at an amount equal to lifetime expected credit loss, except for debt securities that are determined to have low credit risk at the reporting date, other debt securities for which credit risk has not increased significantly since initial recognition and finance lease receivables, which are measured as 12-month expected credit loss.

Loss allowances for trade receivables and contract assets are always measured at an amount equal to lifetime expected credit loss. When determining whether the credit risk of a financial asset has increased significantly since initial recognition and when estimating expected credit loss, the Company considers reasonable and supportable information that is relevant and available without undue cost or effort. This includes both quantitative and qualitative information and analysis, based on the Company's historical experience and informed credit assessment and including forward-looking information.

The Company assumes that the credit risk on a financial asset has increased significantly if it is past due. The Company considers a financial asset to be in default when the borrower is unlikely to pay its credit obligations to the Company in full, without recourse by the Company to actions such as realising security.

Lifetime expected credit losses are the expected credit losses that result from all possible default events over the expected life of a financial instrument, while 12-month expected credit losses are the portion of expected credit losses that result from default events that are possible within the 12 months after the reporting date.

The maximum period considered when estimating expected credit losses is the maximum contractual period over which the Company is exposed to credit risk.

1.3 Financial instruments (policy applicable prior to 1 January 2018)

· Classification of financial instruments issued by the Company

The Group classifies its financial assets in the following categories:

(a) Financial assets at fair value through profit or loss are financial assets held for trading. This category comprises derivatives unless they are effective hedging instruments. The Group had no financial assets in this class as at 31 December 2017.

(b) Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. This category comprises trade and other receivables, term bank deposits and cash and cash equivalents in balance sheet.

· Non-derivative financial instruments

Non-derivative financial instruments comprise investments in equity and debt securities, trade and other receivables, cash and cash equivalents, loans and borrowings, and trade and other payables.

(a) 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.

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

(c) Investments in debt and equity securities: investments in subsidiaries are carried at cost less impairment.

(d) Cash and cash equivalents include cash in hand, and deposits held at call with banks.

(e) Interest-bearing borrowings are recognised initially at fair value less attributable transaction costs. Subsequent to initial recognition, interest-bearing borrowings are stated at amortised cost using the effective interest method, less any impairment losses.

1.4 Adoption of new and revised pronouncements

As of 1 January 2018, the Company adopted the following pronouncements that have been issued by the International Accounting Standards Board (IASB) and are applicable as listed below:

Effective for annual periods beginning on or after 1 January 2018

· IFRS 9 Financial Instruments (2014)

· IFRS 15 Revenue from Contracts with Customers

· Amendments to IFRS 15 Revenue from Contracts with Customers: Clarifications to IFRS 15

The principal changes in accounting policies and their effects are set out below:

i. IFRS 9 Financial Instruments

IFRS 9 replaces the guidance in IAS 39 Financial Instruments: Recognition and Measurement on the classification and measurement of financial assets and financial liabilities, impairment of financial assets, and on hedge accounting.

IFRS 9 contains a new classification and measurement approach for financial assets that reflects the business model in which assets are managed and their cash flow characteristics. The new standard contains three principal classifications categories for financial assets: measured at amortised cost, fair value through other comprehensive income (FVOCI) and fair value through profit or loss (FVTPL) and eliminates the existing IAS 39 categories of held to maturity, loans and receivables and available for sale.

IFRS 9 also replaces the incurred loss model in IAS 39 with a forward-looking expected credit loss (ECL) model. Under IFRS 9, loss allowances will be measured on either 12-month ECLs or lifetime ECLs.

The Company generally applied the requirements of IFRS 9 retrospectively with practical expedients and transitional exemptions as allowed by the standard. The Company has not restated comparative information for prior periods with respect to classification and measurement (including impairment) requirements. There were no differences in the carrying amounts of financial assets and financial liabilities resulting from the adoption of IFRS 9. Accordingly, the information presented for 2017 does not generally reflect the requirements of IFRS 9, but rather those of IAS 39 Financial Instruments.

The initial application of the abovementioned pronouncement does not have any material impact to the financial statements of the Company.

ii. IFRS15 Revenue from Contracts with Customers

IFRS 15 replaces the guidance in IAS 11 Construction Contracts, IAS 18 Revenue, IFRIC 13 Customer Loyalty Programmes, IFRIC 15 Agreements for Construction of Real Estate, IFRIC 18 Transfers of Assets from Customers and SIC 31 Revenue - Barter Transactions Involving Advertising Services. IFRS 15 provides a single model for accounting for revenue arising from contracts with customers, focusing on the identification and satisfaction of performance obligations.

The initial application of the abovementioned pronouncement does not have any material impact to the financial statements of the Company.

1.5 Adopted IFRS not yet applied

The following standards pronouncements that have been issued by the IASB will become effective in future financial reporting periods and have not been adopted by the Company in these financial statements:

Effective for annual periods beginning on or after 1 January 2019

· IFRS 16 Leases

· Amendments to IAS 19 Plan Amendment, Curtailment or Settlement

· IFRIC 23 Uncertainty over Tax Treatments

Effective for annual periods beginning on or after 1 January 2020

· Amendments to References to Conceptual Framework in IFRS Standards

· Effective for annual periods beginning on or after 1 January 2021

· IFRS 17 Insurance Contracts

The Company is expected to apply the abovementioned pronouncements beginning from the respective dates the pronouncements become effective. The initial application of the abovementioned pronouncements is not expected to have any material impact to the financial statements of the Company.

1.6 Consolidation

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.

1.7 Segment reporting

Segmental reporting follows the Group's internal reporting structure.

Operating segments are defined as components of the Group where separate financial information is available and reported regularly to the chief operating decision maker ("CODM"), which is determined to be the Board of Directors of the Company. The Board of Directors decides how to allocate resources and assesses operational and financial performance using the information provided.

The CODM receives monthly IFRS-based financial information for the Group and its development and production entities. There were two development and production entities during both 2016 and 2017. These entities both engage in upstream production, gathering and sale of hydrocarbons, with common operational management and control. Management has determined that the operations of these production and development entities are sufficiently homogenous (all are concerned with upstream oil and gas development and production activities) for these to be aggregated for the purpose of IFRS 8, "Operating Segments". Common economic drivers for the operations are international oil prices, export and Mineral Extraction Taxes and the costs of drilling, completing and operating wells and production facilities. The Group has other entities that engage as either head office or in a corporate capacity or as holding companies. Management has concluded that due to application of the aggregation criteria that separate financial information for segments is not required.

No geographic segmental information is presented as all of the Group's operating activities are based within a localised area of 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 Volga region of 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 3.1 (b).

1.8 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 Ruble ("RUR"). It is 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 2017 were:

· GBP 1: US$1.2708 (2017: 1.3485)

· EUR 1: US$1.1438 (2017: 1. 1956)

· US$ 1:69.4706 RUR (2017: 57.6002)

·

1.9 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 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.

1.10 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:

Depreciation methods, useful lives and residual values are reviewed at each balance sheet date.

1.11 Share capital

Ordinary shares are classified as equity.

Incremental costs directly attributable to the issue of new shares or options are shown in equity as a deduction, net of tax, from the proceeds.

1.13 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 the 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.

1.14 Employee benefits

(a) Share-based compensation

The fair value of the employee services received in exchange for the grant of the options is recognised as an expense. The total amount to be expensed over the vesting period is determined by reference to the fair value of the options granted, excluding the impact of any non-market vesting conditions (for example, profitability and sales growth targets). Non-market vesting conditions are included in assumptions about the number of options that are expected to vest. The option plan currently in place for certain of the directors is an equity-settled share option plan.

The Company measures the equity instruments granted to employees at the fair value at grant date. The fair value of fully vested shares is expensed immediately. The fair value of shares with vesting requirements is estimated using the Black-Scholes option pricing model. This value is recognised as an expense over the vesting period on a straight-line basis. The estimate is revised, as necessary, if subsequent information indicates that the number of equity instruments expected to vest differs from previous estimates.

(b) Social obligations

Wages, salaries, contributions to the Russian Federation state pension and social insurance funds, paid annual leave, sick leave and bonuses are accrued in the year in which the associated services are rendered by the employees of the Group.

1.15 Revenue recognition

1.15.1 Policy applicable from 1 January 2018

Revenue is measured based on the consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. The Company recognises revenue when or as it transfers control over a product or service to customer. An asset is transferred when (or as) the customer obtains control of the asset. Details of the revenue recognition policies are disclosed in Note 4.

1.15.2 Policy applicable before 1 January 2018

Revenue comprises the fair value of the consideration received or receivable for the sale of oil and gas in the ordinary course of the Group's activities. Revenue is shown net of value added tax, returns, rebates and discounts and after eliminating sales within the Group. Revenue from the sale of oil or gas is recognised when the oil/gas is delivered to customers and title has transferred. In 2016 and 2017, the Group's revenue related to sales of crude oil and condensate collected directly by or delivered to customers and gas sales made at the entry to the gas distribution system.

1.16 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.

1.17 Provisions

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

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

Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the obligation. The increase in the provision due to passage of time is recognised as interest expense.

2. 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.

At 31 December 2018, if the US Dollar had weakened/strengthened by 5% against the RUR with all other variables held constant, post-tax profit for the year would have been US$49,885 (2017: US$220,000) higher/lower, mainly as a result of foreign exchange gains/losses on translation of RUR-denominated trade payables and financial assets. At 31 December 2018, if the US Dollar had weakened/strengthened by 5% against the Euro ("EUR") with all other variables held constant, post-tax profit for the year would have been nil (2017: US$600) higher/lower, mainly as a result of foreign exchange gains/losses on translation of EUR denominated interest charges and financial liabilities. At 31 December 2018, if the US Dollar had weakened/strengthened by 5% against the Pound Sterling ("GBP") with all other variables held constant, post-tax profit for the year would have been US$13,303 (2017: US$6,000) higher/lower, mainly as a result of foreign exchange gains/losses on translation of GBP-denominated trade payables and financial assets.

If the US Dollar had weakened/strengthened by 5% against the RUR with all other variables held constant, shareholders' equity would have been US$2.5 million (2017: US$3.3 million) higher/lower, as a result of translation of RUR-denominated assets. The sensitivity of shareholders' equity to changes in the exchange rates between US Dollar against GBP or EUR is immaterial.

The following table shows the currency structure of financial 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$1.6 million higher or lower (2017: $1.5 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 3.1(a)(i) of US$17,009,000 and US$ US$10,868,000 at 31 December 2018 and 2017 respectively.

The Group's principal financial assets are is cash and trade receivables. Trade receivables relate to one customer Gazprom Mezhregiongas Volgograd. This customer has been transacting with the Group for since 2017. To date this customer's balance has not been ever written off and not deemed credit-impaired at the reporting date. The probability of default of Gazprom Mezhregiongas Volgograd was assessed as low risk. Payments are made within 30 days and there is no history of defaults. All trade receivable at the reporting date were classified as current (less than 30 days) and therefore no impairment was deemed required.

Credit risk also 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. Any impairment on cash and cash equivalents has been measured on a 12-month expected loss basis and reflects the short maturities of the exposures. The Group considers that its cash and cash equivalents have low credit risk based on the external credit ratings of the counterparties.

The Group's oil, condensate and LPG 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.

(c) Interest rate risk

The Group's sole interest rate exposure has been related to its bank loan which as of 1 February 2019 has been repaid in full.

(d) Liquidity risk

The remaining contractual maturities as at 31 December 2018 and 31 December 2017 are as follows:

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 2019 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.

(e) Capital risk management

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. During December 2016, one of the Group's operating subsidiaries entered into a loan agreement of RUR 240 million to fund its LPG project (see note 20). This loan, which has a three-year amortising term, was repaid in full on 1 February 2019. Further short-term debt facilities may be arranged to provide financial headroom for future development activities.

(f) Fair value measurement

The Company's financial instruments consist of cash and cash equivalents, trade and other receivables, and trade and other payables.

The carrying amounts of cash and cash equivalents, trade and other receivables and trade and other payables reasonably approximate their fair values due to the relatively short-term nature of these financial instruments.

2.2 Fair value estimation

Effective 1 January 2009, the Group adopted the amendment to IFRS 7 for financial instruments that are measured in the balance sheet at fair value. This requires disclosure of fair value measurements by level of the following fair value measurement hierarchy:

· Quoted prices (unadjusted) in active markets for identical assets or liabilities (level 1).

· Inputs other than quoted prices included within level 1 that are observable for the asset or liability, either directly (that is, as prices) or indirectly (that is, derived from prices) (level 2).

· Inputs for the asset or liability that are not based on observable market data (that is, unobservable inputs) (level 3).

The Group has no financial assets and liabilities that are required to be measured at fair value.

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 and discount rates. Key assumptions and estimates in the impairment models relate to:

· International oil prices: flat real prices reflecting the average levels pertaining during the period between 1 December 2018 and 28 February 2019 - Urals oil price of US$60 per barrel. No forward price escalation is assumed.

· Selling prices for oil, condensate and LPG that reflect international oil prices, less export taxes at the applicable official rates and a price differential of $5 per barrel to reflect transportation costs. Russian export taxes are being phased out over a six year period starting in 2019 - with the same levy being added to the Mineral Extraction tax formula. It is assumed that domestic prices will continue to track the netback pricing. Based on commercial studies conducted during 2017 and actual commercial experience in 2018, LPG is expected to achieve a premium per tonne over condensate. The models assume price parity per tonne.

· Gas sales price of RUR 4,160 per mcm excluding VAT.

· Production profiles based on remaining reserves in the proved category and approved field development plans. For the purposes of impairment testing, the level of reserves used are those established by the independent consultancy Geostream as adjusted for volumes produced in the year ended 31 December 2018..

· Capital expenditures required to deliver the above production profiles and to maintain the production assets throughout the field life. Total development capital expenditure assumed is US$2.5 million with future maintenance capital expenditure of up to US$2 million per annum. The principal items being the completion of the LPG plant and sidetracks to two gas/condensate wells.

· Cost assumptions are based on current experience and expectations and are broadly in line with unit costs experienced in the year ended 31 December 2018.

· Export and mineral extraction taxes reflect rates set by current legislation, including the phased transfer of export taxes (levied on oil exports) to Mineral Extraction Tax (levied on all oil and condensate production).

· The model reflects real terms cash flows with no inflationary escalation of revenues or costs.

· A real discount rate of 12% per annum is utilised in the models.

· An exchange rate of RUR67 to US$1.00 is assumed.

Under the base case assumptions, the value in use of each CGU was shown to be in excess of its respective carrying value.

In addition to the base case, a number of sensitivity cases have been carried out: varying oil and gas prices by 10%, varying operating expenditure by 10%, varying capital expenditure by 20%, varying reserves by 10% and using a 15% real discount rate. In all of these cases, the net present value under the sensitivities remained above the carrying value of individual CGUs.

Under the base case economic assumptions as outlined above, the reserves at the VM and Dobrinskoye fields would need to drop by a further 30% below the level as at 31 December 2018, and the Uzen oil field reserves would need to drop by 13% below current levels for the value in use to reach the respective carrying value.

Accordingly, as at 31 December 2018, based on the Group's impairment testing of the property, plant and equipment related to each CGU management concluded that no clear impairment was indicated. However, should there be material adverse changes to the assumptions used in future impairment tests, or should there be further reductions in reserve estimates, there may be impairment of one or both of the CGU's.

 (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 or production 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. Variation of 10% from the base level of reserves is among the sensitivity tests carried out in impairment testing as described in note 4(a) above.

An independent assessment of the reserves and net present value of future net revenues ("NPV") attributable to the Group's fields, Dobrinskoye, Vostochny Makarovskoye, Sobolevskoye and Uzenskoye, as at 31 December 2017, was prepared in accordance with reserve definitions set by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers ("SPE"). The results delivered to management imply a negative revision to reserves of approximately 27% below the level of reserves as at 31 December 2016, as adjusted for production during 2017. The catalyst for this revision was a recalculation of recovery factors following the recent detection of the presence of formation water in certain of the wells in the VM field. Management considered these revised estimates to be reasonable and adopted them as the Group's reserves. In addition, management considers the performance of the fields during 2018 to be consistent with the latest reserve evaluations and proposes no further revisions to be currently required. The reserve estimate as at 31 December 2018 is accordingly only adjusted for the volumes produced in the year ended 31 December 2018. As outlined above, management considers that, for the time being, no clear impairment is indicated, although further downward revisions may necessitate impairment charges in the future.

4. Revenue

In the following table, revenue is disaggregated by primary geographical market, major products/service lines and timing of revenue recognition.

5. Cost of sales and administrative expenses - Group

Cost of sales and administrative expenses are as follows:

 (a) Selling expense: Comprise pipeline transit costs and fees related to gas sales as well as export taxes and costs associated with delivering gas condensate sales to export customers.

(b) Field operating expenses: Field operating expenses include certain non-cash items. In the years ended 31 December 2018 and 2017, provisions for the cost of waste removal were reversed, partly offset by other accrued expenses. The resulting net non-cash operating gains in the year ended 31 December 2018 was US$251,000 ( 2017: US$646,000). The amounts shown as field operating expenses above are net of these sums.

(c) Inventory write-off: In the years ended 31 December 2018 and 31 December 2017, certain obsolete and unused items of production equipment were transferred from producing assets to inventory and then written off.

(d) Write off of development assets - During the year ended 31 December 2018, the Group wrote off assets of US$1,513,000 of capitalised costs relating to the sidetrack to the Uzen#4 well which was the subject of a legal dispute with a drilling contractor in which the Group received a court settlement totalling US$3,120,000 and recognised as other operating income in 2018.

6. Other gains and losses

During the year ended 31 December 2018 the Group was awarded and received a Court settlement from a legal dispute with a drilling contractor over drilling operations on a sidetrack on the Groups Uzen #4 well. Following receipt of this award, the Group decided to write off the capitalised costs of the sidetrack.

7. Intangible assets

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

8. Property, plant and equipment

Movements in property, plant and equipment, for the year ended 31 December 2016 are as follows:

Movements in property, plant and equipment for the year ended 31 December 2018 are as follows:

(a) During the year ended 31 December 2018, the Group wrote off assets of US$1,513,000 of capitalised costs relating to the sidetrack to the Uzen#4 well which was the subject of a legal dispute with a drilling contractor ibn which the Group received a court settlement totalling US$3,120,000 (Note 5). There were other assets written off totalling US$61,000.

Movements in property, plant and equipment for the year ended 31 December 2017 are as follows:

9. Cash and cash equivalents - Group and Company

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

10. Inventories

11. 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.

12. Trade and other payables

The maturity of the Group's and the Company's financial liabilities are all between zero to three months. Customer advances are prepayments for oil and condensate sales, normally one month in advance of delivery.

13. Bank loan

The loan was repaid in full on 1 February 2019.