VGAS.L Regulatory News (VGAS)

7 April 2020

VOLGA GAS PLC

Preliminary results for the year ended 31 December 2019

Volga Gas plc ("Volga Gas", the "Group" or the "Company"), the oil and gas exploration and production group operating in the Volga region of Russia, announces its preliminary, unaudited annual results for the year ended 31 December 2019.

The Group has recognised a 48% reduction in its oil, gas and condensate reserves following the discovery of unexpectedly high water levels in the main producing reservoir of the Vostochny Makarovskoye ("VM") field. The main strategic objective of the Company at this stage is to re-build its reserve and production base and re-establish a growth profile. Management believes the Company has the financial stability and resources to withstand current challenges and pursue this objective.

In spite of reduced output from VM during H2 2019, the Group's production was only slightly below that of 2018. Gross revenues were level whilst EBITDA was 6% below 2018. The reserve reduction and unsuccessful sidetracks to the VM2 and Uzen4 wells led to one-off expenses for impairment and asset write offs totalling US$10.9 million, as well as increased depletion charges. These were the main contributing factors to the loss before tax of US$10.5 million reported today.

In common with many companies in the oil industry and several economic sectors worldwide, we currently face the significant additional challenges operationally and financially set by the Covid-19 pandemic. Our immediate priority has been to modify our operations so as to protect the health of our employees, contractors and customers; and to follow all government mandated measures. To date, our production operations and markets for our products are not significantly affected, but we clearly recognise the possibility that this may happen. The impact on oil prices, exacerbated by competition between major oil producing countries in light of falling global demand for oil, is already apparent.

However, we entered this crisis in a position of financial strength, with a cash balance of US$14.1 million and no debt. Our capital expenditures are almost entirely discretionary and can be delayed or cancelled as necessary and we have taken action to reduce the fixed costs of the business. Management is determined to enable the Group to survive the current crisis and to re-build the reserves and production for the benefit of shareholders.

Further, the Board has decided to conduct a formal review of the various strategic options available to the Company to maximise value for shareholders. Accordingly, the Company has today separately announced a strategic review including formal sale process under the City Code on Takeovers and Mergers and established a special committee comprised of its independent non-executive directors to oversee this process.

FINANCIAL RESULTS FOR 2019

· Sales volumes down 2% to 4,871 boepd (2018: 4,956 boepd).

· Gross revenues flat at US$46.0 million (2018: US$45.9 million).

· Netback revenues (after export taxes and transport costs) down 3% to US$42.2 million (2018: US$43.4 million), as more condensate was exported in 2019.

· EBITDA down 6% to US$15.9 million (2018: US$16.9 million).

· EBITDA per barrel of oil equivalent sold was US$8.93 per boe (2018: US$9.36 per boe).

· Gross profit of US$9.6 million (2018: US$16.3 million) as depletion charges increased to US$14.9 million (2018: US$8.2 million).

· Net cash flow from operations of US$15.0 million (2018: US$18.3 million).

· One-off charges including impairment of US$8.3 million (2018: nil) and write off of development assets of US$2.6 million (2018: US$1.5 million), leading to an operating loss of US$9.9 million (2018: profit of US$10.3 million).

· Net cash of US$14.1 million as at 31 December 2019 (31 December 2018: US$13.5 million) after utilising US$9.6 million for capital expenditure (2018: US$2.2 million), loan repayments of US$1.7 million (2018:US$1.8 million), paying US$5.2 million in equity dividends (2018: US$4.9 million) and purchase of own shares for US$159,000 (2018: nil).

· Debt free as at 31 December 2019 (31 December 2018 borrowings of: US$1.7 million).

PRODUCTION & DEVELOPMENT

· Group average production in 2019 decreased 4.0% to 4,927 boepd (2018: 5,144 boepd).

· At the VM field unsuccessful sidetracks led to reduced output during H2 2019 and a reservoir study culminating in a 73% reduction in reserves. Production from VM and Dobrinskoye in 2019 averaged 4,500 boepd (2018: 4,537 boepd).

· At the Uzen field, drilling of slim hole wells commenced during 2019, with six wells completed by the end of the year. These, and additional slim hole wells completed more recently are to be brought into production in 2020. Oil production averaged at 427 bopd in 2019 (2018: 607 bopd).

· New reserves were discovered with a slim hole well in Upper Aptian reservoir of the Uzen field. These reserves will be quantified with appraisal drilling in 2020.

DOBRINSKOYE GAS PLANT

· Improvements in the operation of the Redox based gas sweetening enabled steady gas throughput and minimal unplanned operational downtime in 2019.

· An upgrade of the LPG extraction plant was completed in during 2019 with the installation of a turbo compressor to improve extraction rates.

DIVIDEND

· The Company paid a final dividend of US$0.065 per share for 2018 on 28 May 2019. The Board is not recommending a final dividend in respect of 2019 and does not expect to declare dividends in 2020.

COVID-19 RESPONSE

Whilst our operations to date have seen little direct operational impact from the Covid-19 pandemic, , we have focused on implementing measures to ensure the safety of our employees and contractors, the integrity of our operational facilities and to prepare the business to face potential challenges that emerge. The potential impacts are currently unknown but could include production disruption due to government restrictions or customer sales, impact on our workforce and supply chain disruption.

The Group has implemented the following actions to mitigate the risks associated with the Covid-19 pandemic:

· Majority of office staff are working from home with meetings conducted online.

· Working shifts extended for field staff to minimise travel by the workforce.

· Safe distancing guidelines and sanitising initiatives implemented across office and operating facilities.

· All business travel suspended.

· Forward purchased catering to maintain buffer stock for field canteens. Work underway to build a six month inventory of production consumables to mitigate possible lack of supply or logistics issues.

CURRENT TRADING AND OUTLOOK

· Between January and March 2020, Group production averaged 4,203 boepd, in line with management's plan. During the quarter, the Ruble has declined in value in tandem with oil prices, which has impacted the US$ equivalent for gas sales. The average sales prices for oil and condensate have declined with the international market, averaging US$36.79 per barrel in 1Q 2020 and US$26.47 in March 2020.

· In the absence of any disruptions resulting from Covid-19 or any other causes, management plans production to average close to 4,500 boepd in 2020. Achievement of these production rates depends on the successful completion of development drilling, primarily on the Uzen field, and may be impacted by delays in the execution of the drilling programme.

· Oil prices collapsed as a result of competition among major producing countries and OPEC following the reduction in demand caused by Covid-19. It is uncertain when and how rapidly oil prices may recover in the course of the year, although there has been a recent rally and forward prices are significantly higher than spot prices for Brent oil and other key marker crude oils.

· As at 31 December 2019, the Group budgeted capital expenditure of US$8.3 million for 2020, of which only US$0.6 million is currently contracted. The remaining capital investments can be delayed or cancelled as necessary to preserve the Group's liquidity.

· The Board has considered the Group's cash flow projections under various scenarios including extended period of oil prices at current levels and extended shut-ins of production for up to six months and have concluded that it remains a going concern.

Audited results will be issued pending the completion of the forensic examination, to be performed by external consultants, as noted in the Chairman's statement below, and its review by the Board of Directors and the Company's auditors KPMG.

Andrey Zozulya, Chief Executive of Volga Gas, commented:

"The financial results we are reporting today are satisfactory, in spite of the adverse operating results and the downgrade to the reserves in the VM field, and we are pleased that Volga Gas has the financial strength to withstand the additional challenges posed by the Covid-19 pandemic.

At this time, our first priority is the health and safety of all the people who work for and with Volga Gas. We are also determined to play our part in protecting the communities in which we operate.

The Group remains cash flow positive at an operational level at current oil prices, assuming no extensive disruptions, and thanks to our strong balance sheet and our ability to delay or cancel capital investment projects as necessary, the Board is confident that the Group will be able to withstand the current crisis and continue as a viable business for the long term. 

We remain positive about the potential for the Group to rebuild its reserves and production from our existing licences. We will also continue to seek value accretive opportunities, beyond our existing licence areas, building a focused exploration and production business for the long term benefit of our shareholders."

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,

Overview and Strategy

In 2019, the events of greatest impact operationally and financially for Volga Gas were at the Group's Vostochny Makarovskoye ("VM") field. As we announced in July 2019, it was found that water levels within the main producing reservoir in the VM field had risen significantly above management's expectations. An ongoing study on the reservoir was extended into a more extensive collection of data to enable a production management strategy to extract the maximum amounts of gas and condensate possible economically as well as to provide an updated estimate of the remaining economically recoverable reserves in the field. The details of the new reserve estimates and the forward plans for the VM field are covered by the Chief Executive in his Report.

The strategic challenge facing the Company at this stage is to re-build its reserve and production base and re-establish a growth profile. The Board and management have identified three key strands to achieving this:

· To maximise extraction from the VM field and extend the field's economic life with optimal reservoir management;

· To grow the Group's oil business centered on the Uzen field and exploration in the Karpenskiy licence area in which it sits; and

· New business opportunities, both to utilise the Group's gas processing infrastructure and expertise and to extend the Group's activities into new areas

I am pleased that Group's financial strength gives us the opportunity to survive the extreme challenges posed by the Covid-19 pandemic to the entire world economy and to start on the process of rebuilding the Group's assets. The Chief Executive's report outlines the actions being taken by management to deal with the challenges of the pandemic.

Performance in 2019

During 2019 the external conditions for the oil and gas industry remained generally stable although oil prices on average in 2019 were approximately 10% lower than 2018. Despite challenging geopolitics, the Ruble and the Russian domestic energy market conditions were also stable during 2019. The Group has continued to benefit from the improved operational efficiency at the Dobrinskoye gas processing plant from switching of the gas sweetening process in 2018 to a Redox-based system. This is reflected in the lower operating expense in 2019 than in 2018.

Apart from further minor improvements to the gas processing facility, a further upgrade to the project for the capture of liquid petroleum gases ("LPG") was undertaken to improve the recovery of propane and butane from the gas stream. While the LPG project as a whole will manifestly generate sufficient additional revenues to recoup the costs, the final part of the project was sanctioned before the problems with the VM field became apparent. Given the now expected curtailment of the economic life of the field, the additional investment may not be fully recouped by the extra LPG that produced during the remaining economic field life.

One of the potentially most important developments in 2019 for the Group is the application of slim hole drilling. This technique uses a light weight, truck-mounted drilling rig, of a design that was originally developed for mineral exploration. These rigs produce narrow bore holes which can used to develop the relatively shallow oil and gas deposits in the Group's licences. The key advantage is economic, as the cost of a producing slim hole well is typically one-fifth of the cost of a conventional well. Slim hole wells also provide a highly cost effective means of drilling exploratory wells, which will be part of the forward strategy of the Group.

These matters are discussed in greater detail by the Chief Executive Officer in the Operational Review.

Outlook

The Board and Management are fully committed to responding robustly to the numerous challenges posed and to start rebuilding the asset base of the company and profitably deploying the skilled operational team that has been carefully assembled.

The Board believes that Volga Gas has a stable operational capability and the financial and operational capacity to withstand the challenges posed by the Covid-19 pandemic, including potential disruption to production operations, functioning of markets and the current significant downturn in oil prices. We expect to emerge from this and to pursue our recovery and re-growth as outlined in the strategy statement above.

The Board remains ultimately committed to resuming dividend distribution, bearing in mind the requirements of the business and the need to maintain its financial strength. However, the immediate priority is to preserve and rebuild the Group's finances so as to re-establish a base of stable longer term production.

We remain determined to provide long-term value for our shareholders.

Board and Governance

Finally, I would like to update you on the Board. As previously announced, Ronald Freeman retired from the Board on 31 December 2019. Vladimir Koshcheev has also advised me of his intention to retire from the Board at the next Annual General Meeting. Similarly, Michael Calvey will be retiring by rotation and this time will not be offering himself for re-election. I and my colleagues express our warm thanks to all three of them for their contributions to the Board over many years of service. I am delighted to report the appointments of Stewart Dickson and Andrei Yakovlev as independent non-executive directors of the Company.

System of internal controls

The Board is carrying out a review of the effectiveness of the Group's internal control and risk management systems and is potentially introducing a number of measures to strengthen them. This work is ongoing.

The Audit Committee is in the process of appointing external consultants to conduct a forensic examination of the process for appointment of sales agents, and the manner in which payments to these agents are calculated. This review will start in the coming days and the results delivered to the Board as soon as practicable.

Mikhail Ivanov

Chairman

Chief Executive's Report

As discussed in the Chairman's letter, the most significant events of 2019 centered on the VM field, where the Company had to downgrade reserves in the field by 73% and decide on a production strategy to maximise the economic recovery of hydrocarbons. The background to this is covered in greater detail in the operations report and I cover the forward plan later in this Report.

When the logging in VM during H1 2019 indicated much higher than anticipated levels of gas:water contact in the reservoir, the management team decided to reduce the production rates in order to prevent further rapid rise in water encroachment. For this reason, Group total production in 2H 2019 averaged 4,220 boepd compared to 5,634 boepd in H1 2019, to average 4,927 boepd for 2019 as a whole (2018: 5,144 boepd), a 4% reduction year on year.

On a more positive note, early in 2019, management identified an opportunity to utilise slim hole well technology as an advantageous way of developing relatively shallow hydrocarbon resources. Initially using a contractor owned slim hole rig, the Company drilled a six slim hole wells in and around the Uzen oil field. This was in general a successful undertaking and provided the drilling team with valuable experience which has been put to use for the remainder of the programme. In mid-2019, the decision was taken to acquire a Company-owned slim hole rig at a cost of US$0.7 million, equivalent to approximately 18 months of rig rental. By the end of 2019, a total of six slim hole wells had been drilled and three others were in progress.

Based on the experience acquired with slim hole drilling, an extended drilling programme fully utilizing two rigs has been proposed comprising 8 new wells during 2020, 6 on Uzen and 2 on VM, and a further 20 wells during 2021-2022. In addition to the development drilling programme there are plans for seven exploratory wells to be drilled on identified structures in the Group's Karpenskiy licence area. While success with any one of these cannot be assumed, management is optimistic of being able to report a measure of success in finding new oil reserves for the Group. Equally importantly, any newly discovered oil reserves can be rapidly and cost-effectively brought into production.

Included among the eight production wells included in the slim hole drilling programme are two new wells on the VM field, which will be required to produce the identified remaining reserves in the field, and a new well on the Sobolevskoye field, a small currently non-producing field in the Group's Urozhainoye-2 licence area.

While during 2019, the most important aspects of the Group's activities relate to the sub-surface, additional works were carried out to improve the operational efficiency of the surface facilities, most especially at the Dobrinskoye gas processing plant.

The LPG unit, which was commissioned in May 2018 and has been operating since then, was upgraded with an additional investment of approximately US$2.0 million in a turbo expander which has enabled a greater level of extraction of propane and butane from the gas stream by achieving lower temperatures in the LPG extraction vessel. This upgrade was completed in November 2019 with a notable increase in LPG extraction.

There were also further improvements to the Redox-based sweetening process to improve the operational efficiency of the plant, improving the reliability of the process and reducing operating costs.

In spite of the operational challenges, lower production rates and lower oil prices than seen in 2018, the Group control costs, especially overheads. This has enabled the Group to remain cash flow positive throughout the year and to preserve its financial strength and provide some cushion to deal with the present challenges facing the Group. The Financial Review on below sets out the details.

Medium-term strategy

Management's key objective is to rebuild the Group's reserve and production base to rebuild asset value and provide a sustainable profile of profit and cash generation. The key strategic actions identified with the Board have been set out in the Chairman's letter above. The specific actions to be undertaken in 2020 are:

· Drilling of two new production wells on the VM field using slim hole drilling and to undertake production management studies to mitigate future formation water production. This is with the aim of maintaining economic gas production and maximising the extraction of the remaining reserves.

· Sustained slim hole development drilling, especially of the Albian reservoir in the Uzen field to increase oil production.

· Commence a sustained exploration drilling in the Karpenskiy licence area during 2020-2021 to test the maximum number of prospects within the remaining exploration term, with the aim of discovering material new oil reserves.

· Business development activities to seek additional gas throughput on the Dobrinskoye gas plant, including tolling of third party production; and new licence areas and ventures which can utilise the skills of the operational and management team.

Current trading and Covid-19 response

Between January and March 2020, Group production averaged 4,203 barrels of oil equivalent per day, in line with management's expectations. Based on the planned levels of plant uptime and expected results from the slim hole oil production wells, the overall production rate anticipated for the whole of 2020 is between 4,000 and 4,500 boepd.

 Whilst our operations to date have seen little direct impact from the Covid-19 pandemic, we have focused on implementing measures to ensure the safety of our employees and contractors, the integrity of our operational facilities and to prepare the business to face potential challenges that emerge. The potential impacts are currently unknown but could include production disruption due to government restrictions or customer sales, impact on our workforce and supply chain disruption. The actions implemented to mitigate the risks associated with the Covid-19 pandemic are set out in the Principal Risks and Uncertainties section. In the current environment, with significantly lower oil prices and numerous uncertainties in the global economy, management expects the Group's financial performance in 2019 to be lower than that of 2018. Nevertheless, management is confident that the Group's planned capital expenditure of US$8.3 million will be covered by operating cash flow and existing liquid resources. The Board is determined to maintain the Group's financial strength, if necessary by deferring capital expenditure, while taking the actions to rebuild the Group's asset value.

Andrey Zozulya

Chief Executive Officer

Operational Review

Operations overview

As outlined above, Group production in 2019, at an average daily rate of 4,927 boepd, was 4% lower than the 5,144 boepd achieved in 2018. Following higher production in H1 2019, in July the output from the VM field was significantly reduced following the finding of higher than anticipated levels of gas:water contact in the reservoir.

International oil prices were on average approximately 9% lower with the Urals oil price reaching an average level of US$63.71 per barrel in 2019 compared to US$69.69 per barrel in 2018. Nevertheless, the higher proportion of condensate to gas (as mentioned below) mitigated the impact of lower volumes and lower pricing on the total sales. Taking into account selling expenses, netback revenues (defined as revenues less selling expenses as shown in the Income statements) in 2019 of US$42.2 million were just 3% lower than the US$43.4 million in 2018. The fall in total sales volumes and oil prices were cushioned by a higher proportion of oil and condensate in the product mix.

Overall production costs were lower, with benefits of savings from improved operational efficiencies. On the other hand, the scheduled adjustments to the rate formulas led to higher rates of Mineral Extraction Tax. Consequently EBITDA for 2019 was 6% lower at US$15.9 million (2018: US$16.9 million).

Gas/condensate production and development

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.

Production during 2019 averaged 16.2 mmcf/d of gas and 1,507 bpd of condensate and 287 bpd of LPG (2018: 18.8 mmcf/d of gas and 1,183 bpd condensate and 223 boepd LPG), a total of 4,500 boepd (2018: 4,537 boepd). It is notable that while the overall production volumes of hydrocarbons extracted from the wells decreased from July 2019, the proportion of condensate increased such that for the year as a whole, the average total production was not materially lower on a barrel of oil equivalent basis.

The VM field has three active production wells, VM#1, VM#3 and VM#4, in the principal reservoir, the Evlano Livinskiy carbonate, and a further well in the secondary Bobrikovskiy sandstone reservoir. Smaller volumes were also derived from the Dobrinskoye #26 well which in January 2019 were revived with a successful sidetrack.

A sidetrack well that commenced drilling late in 2018 on VM#2 was unsuccessful as several attempts made during early 2019 to cut off water incursion into the well bore failed. Management subsequently undertook logging in the VM#3 which showed that the gas:water contact was higher than previously expected. The Company appointed Schlumberger Ltd to conduct a comprehensive technical evaluation and reservoir study on the VM and Dobrinskoye fields. The study was completed recently and, based on the data accumulated, a independent re-calculation of remaining reserves was carried out.

These results indicate total estimates of Proved reserves for the VM field of 3.2 million barrels of oil equivalent ("mmboe"), a downward revision of approximately 7.6 mmboe, or 70%. The preliminary Proved reserves for the Dobrinskoye field, as at 31 December 2019 are 0.4 mmboe, a downward revision of approximately 0.7 mmboe, or 64%.

Two new wells, VM#5 and VM#6 are to planned be drilled during H1 2020 on locations on the eastern flank of the field, where the recently concluded study indicates there are undepleted resources of gas and condensate that would be accessed by these wells. These wells are to be drilled with slim holes to a vertical depth of approximately 2,000 metres. While this is a greater depth than the slim hole wells drilled hitherto, management is confident of achieving its aims. The aim of this is to maintain economic levels of production to cover the fixed costs of operating the gas processing facility. On current estimates, this is considered unlikely to extend beyond mid-2022.

Management estimates production in 2020 from the VM field to be approximately 10.0 mmcfd of gas plus 1,300 bpd of condensate and 240 boepd of LPG, a total of 3,200 boepd. This rate is consistent with the strategy of reservoir management adopted after the detection of water influx in the wells. However, there is a significant risk that in event of either disruption to our ability to market condensate or a shortage of manpower to operate the gas processing plant that may be caused by the Covid-19 pandemic, production of gas and condensate may need to be curtailed during the year. While there would be a financial impact, temporary shut-downs are unlikely to have an impact on the future ability of the VM wells to produce or on the remaining recoverable reserves in the field. In addition, the effects of the pandemic may disrupt plans to drill the new VM wells and may also lead management to defer the drilling.

Gas, condensate and LPG sales

The Group has been making its gas sales directly to Gazprom since 2017 and, although there is no long term contract, the Directors expect the current arrangements to remain in place.

During 2019, the Ruble exchange rate was stable but slightly weaker than in 2018. Since the gas pricing was fixed in Ruble terms, in US Dollar terms the average gas sales realisations were slightly lower in 2019 at US$1.98/mcf (2018: US$1.99), offsetting the 4% increase in the Ruble sales price.

During 2019, the Group found it advantageous as times to export its condensate. Consequently condensate exports in 2019 were 34% of total sales (2018: 12%).

During 2019, the average condensate netback price (after accounting for export taxes and transportation costs) was US$41.75 per barrel (2018: US$43.32).

LPG commenced on a pilot basis in May 2018. As a result of production during the full year ended 31 December 2019 total sales increased by 28% to 8,803 tonnes (2018: 6,903 tonnes). However the average realisations were lower in 2019 at US$299 (2018:US$412) per tonne. Our experience is that the selling price of LPG is highly seasonal. Management hopes to increase selling flexibility in 2020 to gain an improved market position.

The impact of Covid-19 on the domestic market for condensate in the Volga region of Russia is unpredictable. We will retain a flexible policy of selling domestically or exporting as necessary. However, possible disruption to logistics beyond the control of the Group may impact marketing of both condensate and LPG, which may lead to temporary shut-downs of production.

Production costs

Average unit production costs on the gas condensate fields decreased to US$3.78 per boe in 2019 (2018: US$4.21). The decline in the Ruble, in which effectively all the costs are denominated, improved throughput rates during 1H 2019 which reduced the impact of the fixed cost element of the operating expenses and benefits further operational efficiencies all contributed.

Gas processing plant

Since June 2017, the plant has been operating entirely with Redox-based gas sweetening. In this time, the process has been progressively optimised and the efficiency of the process improved. During 2019 the plant operated with expected uptime, with temporary closures only for routine maintenance and in periods when Gazprom was undertaking maintenance on its gas transmission lines.

Since May 2018, the LPG unit has been operational at the gas plant and has been providing an additional high value product stream from gas that was either previously flared or sold with natural gas a lower value. During 2019, a turbo expander was added to the LPG unit, enabling the system to operate a lower temperature and thereby capturing a greater proportion of the butane and propane in the gas stream.

The physical capacity of the plant is currently significantly greater than well output. As the plant is on a fairly open expansive site, it is possible to operate it while enabling personnel to maintain a safe distance between them. As the majority of staff live locally to the plant, travel restrictions should not have a material impact on the ability of the plant to operate. The Group has established changes to the work patterns, including to the catering facilities on site, to preserve the health of our workers.

Oil production and development

The Group's oil production is derived from the Uzen field. During 2019 production averaged 427 bopd (2018: 607 bopd). Up to and including 2019, the Uzen field has been producing oil from a cretaceous Aptian reservoir at a depth of approximately 1,000 metres. This is now at a late stage of maturity of production. The original mature wells produced at an average rate of 422 bopd in 2019 (2018: 595 bopd).

Early in 2019 the Group drilled a sidetrack to the Uzen#4 well into an undeveloped pool in the Albian reservoir. After a series of production tests, it was concluded that the pool into which the well was drilled was charged primarily with gas rather than oil. This small gas accumulation is not of significant commercial potential - although the gas can be utilised for in field fuel requirements. Consequently, the Group has decided to write off the cost of this well.

The majority of remaining reserves in the Uzen field are in the shallower Albian reservoir. The initial development of this reservoir with conventional horizontal wells was found to be economically marginal. For this reason, management sought a low cost drilling alternative and opted for slim hole drilling. This method uses a light, truck-mounted drilling rig that hitherto has been used primarily for mineral exploration drilling. With suitable adaptation and the use of appropriate tubing and tools, the Company undertook an extended trial of this method. After an initial six wells drilled with a rented rig, management decided to purchase a Company-owned rig, with higher specifications.

By the end of 2019 a total of 6 slim hole oil wells had been drilled, with a further 3 in progress. By 29 February a total of 10 wells have been drilled, with an eleventh in progress. Following installation of production tubing and or artificial lift mechanisms, the new wells are progressively being brought into production.

One of the slim hole wells drilled in 2019 discovered oil in a previously unevaluated geological layer, the Upper Aptian, at a depth of approximately 900 metres. As a newly identified resource, Volga Gas is required to prepare a drilling project, drill at least one appraisal well, calculate the reserves and submit development plans for approval by the State Reserves Committee. The normal timeline for this approval process is approximately one year.

As with condensate sales, oil sales may be disrupted by the effects of the Covid-19 pandemic. Production operations on the Uzen field are not manpower intensive and not critically dependent on external supplies. The Group has implemented changes to ensure the health of personnel on the field. Drilling operations, on the other hand, utilise more personnel on site and rely on the availability of consumables, such as drill pipe and drilling mud. While the Group has implemented enhanced health and safety processes on drill sites, the operations may be disrupted by illness, travel restrictions and supply constraints of consumables.

Exploration

During 2019, the Group's exploration activity was confined to technical studies principally on prospects in the Karpenskiy block, on which 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. With the acquisition of slim hole drilling rigs and capability, the Group now has a highly cost effective manner of evaluating its exploration prospects for the remaining two year period of its exploration rights in the Karpenskiy licence area. During 2020, a total of seven exploratory wells have been identified for drilling in the Karpenskiy licence area.

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.

The comments of the potential impact of Covid-19 on development drilling clearly apply equally to exploration drilling.

Oil, gas and condensate reserves as of 1 January 2020

During 2019, the Company appointed Schlumberger Ltd to conduct a comprehensive technical evaluation and reservoir study on the VM field. The study was completed in December 2019 and a re-calculation of remaining reserves in the fields was carried out by independent reserve engineers Panterra. The results presented to the Company in February. As announced on 27 January 2019, there is a significant reduction in the estimated remaining reserves in the VM field as a result of this work. Separately, a re-assessment of the reserves in the Dobrinskoye field was carried out and a reduction in remaining reserves estimates was indicated there as well.

At the Uzen field, as mentioned above there were two events in 2019 which may have an impact on reserve estimates on the Uzen field: the Uzen #4 sidetrack than encountered mainly gas rather than oil; and the discovery of oil in the Upper Aptian reservoir with one of the slim hole wells. While further appraisal drilling is required for an accurate determination of the Upper Aptian reserves, management believes it realistic, if not conservative, to assume no overall revision to oil reserves.

The changes to oil, gas, condensate and LPG reserves between 1 January 2019 and 31 December 2019 are summarised in the following table.

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 2019 for gas, condensate and LPG held by GNS were independently assessed in an updated study conducted by OOO Panterra dated 7 February 2020. The full reserve report is available on the Company's website: www.volgagas.com.

3. There was an updated geological study by Panterra based on the results of the 2019 drilling activities which concluded there were no material net revision to oil reserves.

4. 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.

5. 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.

Andrey Zozulya

Chief Executive Officer

Financial Review

Results for the year

In 2019, the Group generated US$46.0 million in turnover (2018: US$45.9 million) from the sale of 729,147 barrels of crude oil and condensate (2018: 649,541 barrels), 8,803 tonnes of LPG (2018: 6,904 tonnes) and 5,674 million cubic feet of natural gas (2018: 6,471 million cubic feet).

During 2019, 34% by volume of condensate sales were exported (2018: 12%). In 2019 as in 2018 all oil sales were in the domestic market.

The gas sales price during 2019 averaged US$1.98 per thousand cubic feet (2018: US$1.99 per thousand cubic feet), the movement in the Ruble/US Dollar exchange rate which offset the increase in the Ruble selling prices. In 2019, as in 2018, the Group's gas sales were direct to Gazprom.

In 2019, the total cost of production decreased to US$7.2 million (2018: US$8.3 million), driven mainly by cost savings from chemicals used for gas sweetening and improved operational efficiency at the gas processing plant. Unit field operating costs were lower at US$4.07 per boe (2018: US$4.61 per boe), for similar reasons.

Production-based taxes increased to US$14.3 million (2018: US$13.2 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 2019. MET paid in 2019 represented 33.8% of netback revenues, defined as revenues less selling expenses as shown in the Income statements (2018: 30.4% of netback revenues), reflecting a greater proportion of oil and condensate relative to gas in the oil equivalent sales volumes. Higher rates of MET apply to oil and condensate relative to gas.

The Depletion, Depreciation and Amortisation ("DD&A") charge in 2019 was US$14.9 million (2018: US$8.2 million) reflecting the higher unit DD&A rate applied to comparable production volumes.

As a consequence principally of higher DD&A, production activities generated a gross profit of US$9.6 million in 2019 (2018: US$16.1 million).

Operating and administrative expenses in 2019 were US$4.8 million (2018: US$4.9 million).

The Group experienced a 6% decrease in EBITDA to US$15.9 million (2018: US$16.9 million).

There were no significant exploration and evaluation expenses in 2019 (2018: nil) or other provisions (2018: nil). However, as a result of the revision to reserves in the VM and Dobrinskoye fields, the Group recorded an asset impairment charge of US$8.3 million mainly against the PP&E associated with those fields. In addition, there was a US$2.6 million write off of development assets in 2019 (2018: US$1.5 million), primarily as a result of unsuccessful development drilling operations on sidetracks to the VM#2 and the Uzen #4 wells. Consequently, the Group made an operating loss of US$9.9 million in 2019 (2018: operating profit of US$10.3 million).

Including net interest income of US$0.3 million (2018: US$0.4 million) and other net losses of US$0.9 million (2018: net losses of US$0.2 million) the Group recognised a loss before tax of US$10.5 million (2018: profit before tax of US$10.6 million).

The net loss after tax was US$10.0 million (2018: net profit after tax US$8.4 million) after a current tax charge of US$2.2 million (2018: US$2.2 million) and a deferred tax credit of US$2.7 million (2018: deferred tax credit of US$0.1 million).

For the year ending 31 December 2019, the Group recorded a currency retranslation gain of US$6.1 million (2018: expense of US$11.8 million) in its other comprehensive income, relating to the movements of the Ruble against the US Dollar.

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 decreased by 18% US$15.0 million (2018: US$18.3 million). Net working capital movements contributed cash inflow of US$1.1 million in 2019 (2018: net outflow of US$0.7 million). Included in cash flow from operations was the receipt during 2018 was a sum of US$3.1 million (2019: nil) being a court awarded settlement of a legal dispute. During 2019 there were payments of profit tax of US$2.4 million (2018: US$1.8 million).

With increased capital expenditures in 2019, the net outflow from investing activities was US$9.6 million (2018: US$2.3 million).

Cash outflow from financing activities was US$7.2 million in 2019 (2018: US$6.7 million), comprising equity dividend payments of US$5.2 million (2018: US$4.9 million), loan repayments of US$1.8 million (2018: US$1.8 million) and a net sum of US$159,000 (20128: nil) spent on purchasing the Company's own shares which are held in treasury.

After a positive adjustment of US$0.7 million for the exchange rate effects on cash and cash equivalents (2018: negative adjustment of US$2.7 million), there was a net decrease in cash by US$1.1 million (2018: net increase of US$8.6 million), taking the year end cash balance to US$14.1 million (2018:15.2 million).

Dividend

In May 2019 the Company paid a final dividend of US$0.065 per ordinary share. No interim dividend was declared during 2019 (2018: interim dividend of US$0.06 per Ordinary share, totaling US$4.9 million). The Directors do not propose a final dividend in respect of 2019.

Capital expenditure

During 2019 expenditure of US$9.4 million was capitalized (2018: US$2.8 million), of which US$9.0 million was added to PP&E in development and producing assets (2018: US$2.6 million) and US$0.4 million on exploration and evaluation (2018: US$0.2 million).

The main capital expenditure in 2019 comprised the costs of drilling of slim hole wells of US$3.4 million, installation of a turbo expander at the LPG plant of US$2.0 million, drilling of well #4 sidetrack on Uzen field of US$1.2 million, drilling of well #2 sidetrack on VM field of US$0.6 million, the acquisition of a slim hold drilling rig of US$0.6 million.

Balance sheet and financing

As at 31 December 2019, the Group held cash and bank deposits of US$14.1 million (2018: US$15.2 million). All of the Group's cash balances are held in bank accounts in the UK and Russia. Approximately 68% (2018: 61%) of the Group's cash is held in US Dollars and 32% (2018: 38%) held in Russian Rubles.

In February 2019, the remaining balance of a bank facility, which was utilised to fund purchases of equipment for the LPG project, was repaid in full. There were no other finance loans or leases outstanding either in 2019 or 2018.

As at 31 December 2019, the Group's intangible assets were US$3.4 million (2018: US$3.3 million). Property, plant and equipment decreased to US$34.0 million (2018: US$45.1 million), reflecting higher depreciation charges, asset write offs and asset impairments as outlined above. The carrying values of the Group's assets relating to its main cash-generating units have been subject to impairment testing. The impairment tests, including sensitivity analysis around the central economic assumptions and taking into account the reduction in oil and gas reserves are detailed in note 4(b) to the accounts. Based on this analysis, the Directors have decided to take an impairment charge of US$8.3 million in the year to 31 December 2019 (2018: nil).

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 for the foreseeable future to maintain capital expenditure within the level of operating cash flow and to maintain an adequate level of liquidity to meet all of the Group's commitments as and when they arise.

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 operational and financial 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. The additional specific risks to which the Group is exposed as a result of the Covid-19 pandemic are detailed separately.

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 would 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.

In particular, the recent and sudden collapse in international oil prices triggered by the Covid-19 pandemic have a material impact on the Group's short term revenue and profitability outlook. The Directors have examined the impact of current low oil prices in preparing the financial statements:

· In assessment of the Group as a going concern should oil prices remain at US$25 per barrel for an extended period.

· Impairment testing. A significant drop in oil prices were considered in the sensitivity analysis conducted in relation to impairment testing.

Market risks

The Group's revenues generated from oil and condensate production have typically been from sales to local domestic customers. There have been periods when the local market has been unable to purchase condensate, causing temporary suspension of production and loss of revenues. The Group has access to export channels for its condensate into regional export markets to mitigate this risk. Gas sales are currently made to Gazprom. While the arrangement is formalised annually rather than as a long term contract, the Directors believe the risk of renewal is low as the region in which the Group operates is reliant on external gas supplies. 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, to a lesser extent, 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 being changed over a five-year period from 2019. It is not certain 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. In relation to the exploration activities, 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.

In July 2019, as detailed in the Operations Review, management commissioned an extensive reservoir study on the VM field which concluded with an updated reserve evaluation of the VM and Dobrinskoye fields completed in February 2020. The reserve report, delivered to and adopted by management on 7 February 2020, resulted in a downward revision by approximately 48% to the Group's Proved Reserves as at 31 December 2019. Management also commissioned an updated geological resource estimate on the Uzen oil field, completed in March 2020. 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. The Group's reserve statement is shown in the Operational Review. The impact of the reserve revision in 2019 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 and to trigger an impairment of the net book value of Group's Property Plant and Equipment. These impacts are reflected in the Group's financial statements for the year ended 31 December 2019.

The Group's estimated reserves include substantial volumes that are expected to be produced from wells that have yet to be drilled:

On the VM and Dobrinskoye fields: 2.0 mmboe of reserves are expected to be extracted from existing wells in 2020-2021, while with the drilling of the new VM5 and VM6 wells an additional 1.5 mmboe of reserves are recovered from VM5 and VM6 and the production profile extended to mid-2023. Management's expectations have been formed on the basis of independent studies by Schlumberger and Panterra. Should the drilling of new wells be unsuccessful, the incremental reserves may not be extracted. This scenario was considered in sensitivity analysis in impairment testing. See note 4a.

On the Uzen field, 75% of the reserves are expected to be recovered from new wells from a multi-year slim hole drilling programme.

If the costs of drilling these wells, of the results of these wells differ significantly from expectations, there may be further changes in the future estimates of reserves and to the value in use of the related cash generating units. These may impact both the future profitability and the balance sheet carrying values of the Group's property, plant and equipment. Such scenarios are considered in the impairment testing process.

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. The Group has established a rigorous risk identification and reporting system throughout its operations as a key risk mitigation activity.

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 actions 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 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 and lack of transparency 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 2019, the Group had US$14.1 million (2018: US$15.2 million) of cash and cash equivalents, of which US$4.8 million was held in bank accounts in Russia (2018: $13.8 million). As at 31 December 2019, there was no bank debt (2018: US$1.7 million), the balance of bank debt having been repaid in January 2019. 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 2019 the Group had budgeted capital expenditures of US$8.3 million, comprising primarily expenditures on drilling production wells on the Group's proven fields but also including up to US$1.0 million of exploration expenditure. There were approximately US$1.0 million of accounts payable relating to capital expenditures and other expenses incurred in the year ended 31 December 2019 (2018: US$1.1 million). The Group's cash flow projections have been tested for the ability to withstand an extended period of oil prices at US$30 per barrel.

The Board considers that the Group will have sufficient liquidity to meet its obligations and to weather an extended period of low oil prices. 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. However, with its asset bsse already in production, this risk would not impede its ability to continue as a going concern.

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 and the Group's existing cash reserves will be sufficient to sustain the Group's operations and committed capital investment for the foreseeable future. The Group 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.

Covid 19

The Directors believe the Group, may be materially impacted by several factors that arise as a result of the Covid 19 pandemic. The following table sets out the specific business risk issues identified by the Group, the potential impact and risk mitigation action plans enacted by the Group. Where possible, the scale of the exposure is indicated along with the probability. However, the ultimate exposure and scale of impact depends on many factors such as the scale and duration of the pandemic, which are presently unknown. While the full range of possible effects are unknown, the Directors considered the several severe adverse scenarios and are satisfied that the Group has adequate resources to continue as going concern. For details refer to Note 2.1.

Other risks/Brexit

The Company is not significantly commercially exposed to the outcome of the future trade negotiations between the UK and EU following the departure of the UK from the EU.

· 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 or the EU.

· 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.

· Regulations: There are no specific regulations which could potentially have significant impact on the Company arising from 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 2019

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 2019

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 3.

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; the financial position of the Group, its cash flows, liquidity position and borrowing facilities are described in the Financial Review. 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.

Going Concern

Having reviewed the future cash flow forecasts of the Group in the light of the reductions in oil and gas reserves, the recent developments in the international oil prices and markets, 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 12 months from the approval of the financial statements and thus continue to adopt the going concern basis of accounting in preparing the annual financial statements.

In reaching this conclusion, the Directors have reviewed cash flow projections using current spot and futures oil prices in the period 2020-2022 and operational assumptions on production, operating and capital costs in line with those used for impairment testing (see Note 4). The Directors have also considered the sensitivity of cash flow forecasts under a variety of scenarios that have arisen and may arise as a result of the Covid-19 pandemic and the economic impact of government measures taken to deal with the outbreak in various countries in addition to risk factors that are specific to the Group's operations. Included in these are:

· Extended oil price weakness with the Urals oil price declining to average US$20 per barrel in 2020 and US$30 per barrel in 2021;

· Disruption arising from Covid-19 that leads to a period of shut-in for the Group's entire production of varying durations, up to 6 months at the extreme, combined with the above mentioned lower oil prices;

· Unsuccessful outcomes from the drilling of the VM5 and VM6 wells;

· A lower case outturn for slim hole development drilling on the Uzen field.

The Directors recognise that the long term viability of the Group depends on successful development of oil reserves in the Uzen field and on the discovery of new oil and gas reserves to replace those that will be produced in the short and medium term. If these activities are unsuccessful for a sustained period, it may be necessary to reduce the ongoing overheads of the Group and may reduce the Group's future ability to continue as going concern.

1.2 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.

1.3 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, 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.

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.

1.4 Foreign currency translation

(a) Functional and presentation currency

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

The functional currency of the Group's subsidiaries that are incorporated in the Russian Federation is the Russian Rouble ("RUR"). It is 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 2019 were:

· GBP 1: US$1.3108 (2018: 1.2708)

· EUR 1: US$1.2101 (2018: 1.1438)

· US$ 1: RUR61.9057 (2018: 69.4706)

1.5 Oil and gas assets

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

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

(a) Exploration and evaluation assets

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

1.6 Other business and corporate assets

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

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

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

1.7 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.

1.8 Revenue recognition

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 5.

1.9 Prepayments

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

1.10 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 2019, 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$57,797 (2018: US$49,885) higher/lower, mainly as a result of foreign exchange gains/losses on translation of RUR-denominated trade payables and financial assets. At 31 December 2019, 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 US$30,658 (2018: nil) higher/lower, mainly as a result of foreign exchange gains/losses on translation of EUR denominated interest charges and financial liabilities. At 31 December 2019, 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$3,150 (2018: US$13,303) 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$2.2 million (2018: US$2.5 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$1.2 million higher or lower (2018: $1.6 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$15,587,000 and US$ US$17,009,000 at 31 December 2019 and 2018 respectively.

The Group's principal financial assets are cash and trade receivables. Trade receivables relate to one customer Gazprom Mezhregiongas Volgograd. This customer has been transacting with the Group since 2017. To date this customer's balance has not been ever written off and is 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 receivables 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 was repaid in full.

(d) Liquidity risk

The remaining contractual maturities as at 31 December 2019 and 31 December 2018 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 2020 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 determines 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, known as "GNS" and the Uzen oil field is a separate CGU, known as "PGK".

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 1 December 2019 to 31 January 2020, a Urals oil price of US$63 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. Russian export taxes are being phased out over a five-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 actual commercial experience since May 2018, when production commenced LPG sales prices have on average been similar to those for condensate. The models assume the LNG sales price is 10% lower per tonne than condensate.

· Gas sales price of RUR 4,289 per mcm excluding VAT and net of transportation costs.

· 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 Panterra as at 31 December 2019, in relation to the VM and Dobrinskoye fields. In respect of the Uzen field, the reserves were estimated by management and supported by an independent geological review of the impact of the results of wells drilled during 2019 that was produced in March 2020. A further evaluation of reserves in Uzen will be conducted during 2020, to include incremental reserves discovered in the course of 2019 during development drilling as detailed in the Operations Report. Meanwhile, management considers that the after adjusting for subsequent production, the Uzen reserves estimates remain in line with internal estimates.

· Capital expenditures required to deliver the above production profiles and to maintain the production assets throughout the field life. Total development capital expenditure assumed for the period 2020-2024 is approximately US$14.2 million, primarily on drilling of development wells, with future capital expenditure beyond that time of up to US$0.2-1.0 million per annum. The calculation in use excludes and positive contribution from successful exploratory drilling or other improvements to the assets.

· Cost assumptions are based on current experience and expectations and are broadly in line with unit costs experienced in the year ended 31 December 2019. The costs included in the analysis include all field operating and production costs and allocated overheads of the operating entities.

· 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 10% per annum is utilised in the models.

· An exchange rate reflecting the average levels pertaining during the period 1 December 2019 to 31 January 2020 of RUR67 to US$1.00 is assumed.

In addition to the base case, a number of sensitivity cases have been carried out:

· Varying gas prices by 10%,

· Varying operating expenditure by 10%,

· Varying capital expenditure by 20%,

· Varying reserves by 20% and

· Using a 12% real discount rate.

· A lower oil price scenario using flat Urals prices of US$25.00 per barrel for 2020, US$35.00 for 2021 and US$50.00 for 2022 onwards and an exchange rate of RUR 85 to US$1.00 for 2020, RUR 75 for 2021 and RUR 70 for 2022 onwards was conducted.

· As an further sensitivity scenario relating to the VM field a further set of cases were conducted on the GNS CGU on the basis that the two new wells on the field, VM#5 and VM#6 were unsuccessful.

· "Covid-19 scenario". An additional sensitivity based on assuming an extreme 6 month shut-in of all production, combined with the lower oil price assumptions detaild in the price sensitivity above, was conducted. In this scenario, all production and capital expenditure is assumed suspended for 6 months, while the CGUs carry the full fixed operating and G&A costs during shut-in.

The calculated value in use of the CGUs have been compared to the net book values of the PP&E associated with the CGUs. The table below summarises the results of this analysis, indicating the level of impairment relected in the Base Case and the potential additional impairments that may arise from each of the sensitivity cases described above:

Based on the above analysis, the book value of the GNS assets is clearly impaired. Given the relatively short remaining field life and the fact that the operating and capital costs are not especially high, the cost sensitivities are not major, while the oil price sensitivities are significantly more material. The value in use, additionally, is significantly dependent on the reserve sensitivities - especially in relation to the recognised risk attached to the outcomes of VM#5 and VM#6. However, while recognising the sensitivity to this risk factor, management does not believe that there is a basis for expecting the new wells to be unsuccessful.

Therefore, the Directors believe an impairment of RUR 375m or approximately US$8.3 million is indicated and have decided to include a charge of this amount in the financial statements for the year ended 31 December 2019.

For the PGK assets, the value in use, under the base case scenarios show a moderate level of headroom above the carrying value of the assets. However, the analysis indicates that a very small reduction in the Uzen field reserves could lead to asset impairment. The 20% reserve downside case suggests a significant reduction in value in use. However, management considers that in event of lower than expected success with development wells, a modification to development plans involving a reduction in future capital expenditure would be implemented. This may mitigate the impact suggested by the single variable sensitivity analysis. Therefore the directors consider that while there is risk of substantial future impairment, no impairment is currently indicated for the PGK assets.

The "Covid-19 shut-in" scenario, while having an impact on the NPV calculations carried out above, would most likely be reflected in the results of operations rather than a future asset impairment, in the absence of unforeseen damage to reservoir productivity arising from an extended period of shut-in.

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 CGUs.

 (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 20% 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 Dobrinskoye and Vostochny Makarovskoye fields as at 31 December 2019, was prepared in accordance with reserve definitions set by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers ("SPE"). The catalyst for this revision was the indication of a significantly higher than anticipated level of gas:water contact in the main reservoir of the VM field. Management considered these revised estimates to be reasonable and adopted them as the Group's reserves.

Independent reserves estimates of the Sobolevskoye and Uzenskoye, as at 31 December 2017, were prepared in accordance with reserve definitions set by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers ("SPE"). The reserve estimate as at 31 December 2019 is accordingly only adjusted for the volumes produced in the two years to 31 December 2019. An independent geological review by Panterra Group, based on the updated data provided from 2019 drilling activity on the Uzen field, supports management's current estimates.

4. Revenue from contracts with customers

The Group generates revenue primarily from sales of oil, gas, gas condensate and LPG. 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:

 (b) Selling expenses: 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) Write-off of development assets - During the year ended 31 December 2019, the Group wrote off assets of US$2,608,000 (2018: US$1,513,000) of capitalised costs, primarily relating to unsuccessful drilling operations on two development wells. The write off in 2018 related to the subject of a legal dispute with a drilling contractor in which the Group received a court settlement totalling US$3,120,000. This settlement was recognised as other operating income in 2018.

6. Other gains and losses - Group

7. Basic and diluted profit per share - Group

Profit per share is calculated by dividing the profit attributable to equity holders of the Company by the weighted average number of ordinary and diluted shares in issue during the year.

Since 1 January 2018 there have been no options outstanding. On 17 April 2019, the Company purchased 450,000 of its own Ordinary shares, which were held in treasury. On 4 July 2019, 250,652 treasury shares were transferred to Andrey Zozulya in settlement of his bonus award. The number of treasury shares was therefore reduced to 199,348. For the year ended 31 December 2019, the weighted average number of shares in issue, less treasury shares, was 80,823,327 (2018: 81,017,800). As at 31 December 2019, the total voting rights, being the number of shares in issue less treasury shares was 80,818,452 (2018: 81,017,800).

8. Intangible assets - Group

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.

9. Property, plant and equipment - Group

Movements in property, plant and equipment for the year ended 31 December 2019 are as follows:

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

10. Cash and cash equivalents

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

11. Inventories - Group

Inventory recognised as cost of sales in the year amounted to US$2,526,000 (2018: US$2,474,000 ). In the year to 31 December 2019 there was a US$65,000 reversal of previous write-down of inventories to net realisable value (2018: write down of US$378,000). This is included in operating and administrative expenses.

12. Trade and 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.

13. 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.