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| Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
|---|---|---|---|---|---|
| Volga Gas Plc | LSE:VGAS | London | Ordinary Share | GB00B1VN4809 | ORD 1P |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 23.50 | 22.00 | 25.00 | 0.00 | 01:00:00 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| 0 | 0 | N/A | 0 |
From May 2019 to May 2024
TIDMVGAS
RNS Number : 8026K
Volga Gas PLC
13 April 2018
13 April 2018
VOLGA GAS PLC
Preliminary results for the year ended 31 December 2017
Volga Gas plc ("Volga Gas", the "Group" or the "Company"), the oil and gas exploration and production group operating in the Volga region of Russia, is pleased to announce its preliminary, unaudited annual results for the year ended 31 December 2017.
During 2017, management's principal objectives were to implement significant improvements to the key production operations, in order to enhance their longer term performance and sustainable profitability - notably the switch to Redox based gas sweetening at the Dobrinskoye gas processing plant ("GPU") and the construction of the new plant to capture liquid petroleum gases ("LPG") from the gas and condensate stream.
As reported in the interim statement in October 2017 and the subsequent monthly production reports issued by the Company, during the implementation of Redox processing, it has been necessary to reduce the throughput of gas at the GPU with a resultant impact on production and sales volumes, especially in the second half of the year. Consequently, production volumes were 24% lower in 2017 than in 2016 on a barrel of oil equivalent ("boe") basis. However, thanks to stronger oil prices, a stable Russian Ruble and cost reductions, EBITDA and cash flow were relatively stable.
FINANCIAL RESULTS FOR 2017
-- Sales volumes down 28.3% to 4,677 boepd (2016: 6,523 boepd) -- Gross revenues down 5.3% to US$37.1 million (2016: US$39.4 million).
-- Netback revenues (after export taxes and transport costs) down 1.5% to US$34.8 million (2016: US$35.4 million).
-- EBITDA down 9.1% to US$8.8 million (2016: US$9.6 million). -- EBITDA per barrel of oil equivalent sold up 26.7% to US$5.13 per boe (2016: US$4.05 per boe) -- Profit before tax of US$168,000 (2016: US$1.2 million)
-- Operating cash flow before working capital movements of US$9.1 million (2016: US$10.4million), in line with EBITDA.
-- Total cash of US$8.6 million as at 31 December 2017 (31 December 2016: US$19.7 million) after utilising US$12.6 million for capital expenditure (2016: US$5.0 million) and paying US$5.0 million in equity dividends (2016: nil). Total borrowings, comprising bank debt, at 31 December 2017 were unchanged at US$4.0 million (2016: US$4.0 million).
PRODUCTION & DEVELOPMENT
-- Group average production in 2017 decreased 24.0% to 4,948 boepd (2016: 6,507 boepd).
-- Production from VM and Dobrinskoye fields was 25.1% lower at 4,346 boepd in 2017 (2016: 5,801 boepd) as the gas plant throughput was reduced during implementation of Redox based gas sweetening.
-- During late 2017 and early 2018 the presence of formation water in certain of the production wells on VM was detected.
-- Oil production from the Uzen field averaged at 545 bopd (2016: 708 bopd) as the mature producing wells continued to decline.
-- During 2017, a horizontal oil well, Uzen 101 was drilled, successfully tested and put on production during December 2017. This well extracts oil from the previously undeveloped shallower Albian reservoir in the Uzen field.
DOBRINSKOYE GAS PLANT
-- Implemented Redox based gas sweetening in June 2017, resulting in significant savings in chemicals costs and disposal of waste materials. During implementation, processing throughput was reduced as the process was optimised.
-- Construction of the LPG extraction plant was commenced during 2017 and is now close to completion. Test production is to commence in April 2018.
RESERVES UPDATE
Subsequent to the 2017 year-end, the Company commissioned a new independent reserve report by OOO Geostream Assets Management ("Geostream") following the recently observed presence of increased formation water during gas production from certain of the production wells on the VM field. The report, dated 12 April 2018, has resulted in a reduction, compared to the 2016 reserves as adjusted for production in 2017, of 27% in the Proved and of 28% in the Proved plus probable reserve numbers for the Group's oil and gas reserves.
Although the estimate of original hydrocarbons in place is unchanged, the presence of formation water during gas production has led Geostream to apply a more conservative calculation of ultimately recoverable reserves from the VM field.
Accordingly this reduction in reserves has been reflected in the financial results, primarily through a significant increase in the depletion, depreciation and amortisation charge for the year ended 31 December 2017. However, management estimates that given the former headroom over the carrying value of the assets the reserve decrease is not expected to lead to asset impairment.
Reserve as at Oil & Condensate Gas LPG Total 31 December 2017 (mmbbl) (bcf) (tonnes '000) (mmboe) ---------------------- ----------------- ------- --------------- --------- Proved reserves 9.824 57.3 148 21.125 Proved plus probable reserves 11.123 77.6 205 26.466 Revision as% of the 2016 reserves adjusted for 2017 production Proved reserves (5%) (37%) (47%) (27%) Proved plus probable reserves (3%) (38%) (44%) (28%)
Notes:
1. Volga Gas (through its wholly owned subsidiaries PGK and GNS) is the operator and has a 100% interest in four licences to explore for and produce oil, gas and condensate in the Volga region.
2. The reserve estimates as at 31 December 2016 were independently assessed by OOO Geostream Assets Management. The estimates at 31 December 2017 are results of an updated study conducted by OOO Geostream Assets Management dated 12 April 2018. The full reserve report is available on the Company's website: www.volgagas.com.
3. The reserve estimates were prepared in metric units: tonnes for oil, condensate and LPG and standard cubic metres for gas. The conversion ratios from tonnes to barrels applied in the table above were 7.833 barrels per tonne of oil, 8.75 barrels per tonne of condensate and 11.75 barrels per tonne of LPG. One cubic metre equates to 35.3 cubic feet and one barrel of oil equivalent is given by 6,000 standard cubic feet of gas.
4. The above reserve estimates, prepared in accordance with the PRMS reserve definitions prepared by the Oil and Gas Reserves Committee of the SPE, have been reviewed and verified by Mr Andrey Zozulya, Director and Chief Executive Officer of Volga Gas plc, for the purposes of the Guidance Note for Mining, Oil and Gas companies issued by the London Stock Exchange in June 2009. Mr Zozulya holds a degree in Geophysics and Engineering from the Groznensky Oil & Gas Institute and is a member of the Society of Petroleum Engineers.
DIVID POLICY
-- The Board regards the distribution policy to be of paramount importance to shareholders and is accordingly planning, in addition to the existing policy of distributing 50% of net income, to recommend future payments to reflect the free cash generation of the group.
-- Meanwhile the Board considers it prudent to defer a decision on the dividend until the incremental cash flow from the investments undertaken in 2017 begin to be realised. This will be reviewed at the interim results stage in September 2018.
CURRENT TRADING AND OUTLOOK
-- Between January and March 2018, Group production averaged 4,084 boepd, in line with management's plan given the anticipated higher levels of planned maintenance downtime in the period.
-- For the coming months, management expects to maintain an average daily production of gas and condensate in the region of 3,800 boepd, leading to Group production of approximately 4,500 boepd, excluding incremental production from LPG.
-- Commercial sales of LPG are planned to start during Q2 2018 and expected to add approximately 400 boepd to sales volumes.
-- Oil production between January and March 2018 averaged 804 bopd, with increasing volumes from the Uzen well 101. In this period, ground conditions have permitted normal trucking of oil form the fields. When the thaw arrives, there may - as experienced in previous years - be a period of approximately two weeks when oil transportation is disrupted.
-- Oil prices and the Russian Ruble have been relatively stable during the first three months of 2018.
-- As at 31 December 2017, the Group budgeted capital expenditure of US$5.9 million, of which the significant items were US$1.4 million for completion of the LPG project and US$3.2 million for drilling of sidetrack wells and other development activities. These sums, the majority of which are discretionary are less than the anticipated levels of operating cash flow.
Andrey Zozulya, Chief Executive of Volga Gas, commented:
"We are pleased to have delivered on the two key projects - Redox gas sweetening and LPG - that are expected to enhance the profitability of our gas and condensate production in the medium and long term. Management looks forward to achieving the targets to improve the profitability and sustainability of the business for the longer term and to delivering returns to our shareholders.
"Clearly it is disappointing to report a decrease in the Group's recoverable reserves. Management is looking into technical and operational solutions including conducting well interventions on the VM field, workovers and reperforations of the well bores to mitigate future formation water production and restore maximum gas production and the extraction of reserves in place. We will provide further updates as this work progresses.
"We remain excited about the Group's assets and remain positive about the potential for production from our fields and the potential to discover additional fields in our licences. We will also continue to seek value accretive opportunities, beyond our existing licence areas, building a focused exploration and production business."
For additional information please contact:
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Volga Gas plc
+7 (903) 385 9889
Andrey Zozulya, Chief Executive Officer +7 (905) 381 4377
Vadim Son, Chief Financial Officer +44 (0)7824 884
Tony Alves, Investor Relations Consultant 342
+44 (0)20 3470
S.P. Angel Corporate Finance LLP 0470
Richard Redmayne, Richard Morrison, Richard
Hail
+44 (0)20 3727
FTI Consulting 1000
Edward Westropp, Alex Beagley
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, 6(th) 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
PRMS Petroleum Resources Management System represents
a system for defining reserves and resources that
was developed by an international group of reserves
evaluation experts and endorsed by the World Petroleum
Council, the American Association of Petroleum
Geologists, the Society of Petroleum Evaluation
Engineers, and the Society of Exploration Geophysicists.
Probable Reserves Probable Reserves are those additional Reserves
that are less likely to be recovered than Proved
Reserves but more certain to be recovered than
Possible Reserves. It is equally likely that actual
remaining quantities recovered will be greater
than or less than the sum of the estimated Proved
plus Probable Reserves (2P). In this context, when
probabilistic methods are used, there should be
at least a 50% probability that the actual quantities
recovered will equal or exceed the 2P estimate.
Proved Reserves Proved Reserves are those quantities of petroleum
which, by analysis of geoscience and engineering
data, can be estimated with reasonable certainty
to be commercially recoverable, from a given date
forward, from known reservoirs and under defined
economic conditions, operating methods, and government
regulations. If deterministic methods are used,
the term reasonable certainty is intended to express
a high degree of confidence that the quantities
will be recovered. If probabilistic methods are
used, there should be at least a 90% probability
that the quantities actually recovered will equal
or exceed the estimate. Often referred to as 1P,
also as "Proven."
Reserves Reserves are those quantities of petroleum anticipated
to be commercially recoverable by application of
development projects to known accumulations from
a given date forward under defined conditions.
Reserves must further satisfy four criteria: they
must be discovered, recoverable, commercial and
remaining (as of the evaluation date) based on
the development project(s) applied. Reserves are
further categorised in accordance with the level
of certainty associated with the estimates and
may be sub-classified based on project maturity
and/or characterized by development and production
status.
SPE Society of Petroleum Engineers
Chairman's Statement
Dear Shareholder,
During 2017 conditions for the oil and gas industry worldwide and for Russia generally have been more stable than in the recent past. This stability has enabled Volga Gas to undertake important steps to enhance its operations materially, the most important of which was switching the gas sweetening process utilised at the Dobrinskoye gas processing plant, the Group's principal production facility, to a Redox-based system. This has reduced the chemical costs of the operation and has eliminated the need to dispose of bulky spent processing chemicals. During the implementation of this process and whilst the operational team optimizes the management of the new process, the plant throughput has had to be reduced. However, with the improved oil and gas market conditions, this has not had as material an impact on the Group's revenues in 2017 as may otherwise have occurred.
The change to a Redox gas sweetening process was achieved with only modest capital expenditure as minimal modifications to the existing plant were required. During 2017, the main focus of the capital investment was in two projects that are expected to provide incremental revenues and cash flow to the Group: the construction of a plant at the gas processing facility to capture for sale the liquid petroleum gases ("LPG") - propane and butane - that are currently vented and flared; and the drilling of a new horizontal oil well to access the hitherto undeveloped reserves in the Uzen oil field located in the Group's Karpenskiy licence area. The LPG project is expected to commence producing and selling product from April 2018. When it is fully operational the LPG plant could add up to 400 barrels of oil equivalent per day of incremental sales volumes. These projects are discussed in greater detail by the Chief Executive in the Operational Review below.
Given the constraints to gas and condensate production experienced in 2017, the Board is pleased to report that revenues have been broadly maintained at US$37.1 million (2016: US$39.4 million), EBITDA at US$8.8 million (2016: US$9.6 million) and operating cash flow before working capital movements at US$9.0 million (2016: US$10.4 million). This has enabled the Group to undertake an increased capital expenditure programme during 2017 and, in spite of some overruns in the costs of the Uzen horizontal well, to end the year with healthy cash balances and remain in a positive net cash position after taking into account borrowings. This is in addition to paying US$5.0 million in dividends to shareholders in 2017 (2016: nil).
Unfortunately, Volga Gas has recently experienced higher formation water content at certain production wells at Vostochny Makarovskoye ("VM") and so the board thought it appropriate to commission an updated independent reserves report and prudent to adopt its findings in full. This report, dated 12 April 2018, has resulted in a 27% reduction in the Proved reserves and a 28% reduction in the Proved and Probable reserves of oil, gas and condensate and we are actively looking into technical and operational solutions to mitigate the impact of the reserves reduction. The reserves reduction is caused by a re-calculation of recovery rates from the VM and Dobrinskoye gas fields, rather than any changes to the geological model or estimates of original hydrocarbons in place. This has had a material impact in reducing the operating profits of the Group to US$0.1 million (2016: US$2.51 million), due to an increase in the depletion charge to US$8.6 million (2016: US$5.0 million). Further details of the impact of the reduction of the reserves are set out in the Operating and Financial reports between pages 5 and 11 below.
In spite of the reduction in reserves, the Group still holds significant, fully developed, reserves in its three principal fields. These reserves form the basis of sustainable production with growth potential in the near term. These assets provide a platform for the Group to grow in the future, through successful exploration and by selective value accretive acquisitions. The Board believes that Volga Gas has a stable foundation and the financial and operational capability to develop and extend these assets to provide long-term value for our shareholders.
The Board remains committed to a policy of enhanced dividend distribution and is planning to modify its dividend policy towards higher rates of distribution, having in mind the requirements of the business and the need to maintain its financial strength. Within these constraints, the Board would consider distributing up to 75% of its free cash flow as dividends. For the time being however, the Board considers it prudent to defer a decision on the dividend level until the incremental cash flow from the investments undertaken in 2017 begin to be realised. A further decision will be taken by the interim results stage in September 2018.
While the immediate outlook for the oil industry remains broadly positive, the finances of the Group will continue to be conservatively managed. Capital investment commitments will continue to be at a modest and focused on enhancing the profits from the gas and condensate production and on optimizing the production from the reserves of the company.
Mikhail Ivanov
Chairman
Chief Executive's Report
The principal objective for Volga Gas in 2017 was to effect a transformation in the technology used to process the gas and condensate at the Dobrinskoye gas plant, from which the Group derives the overwhelming majority of its production, revenue and profits. During 2016 and early 2017, after extensive investigations and pilot tests, management concluded that a switch to Redox-based sweetening would be most advantageous - not only for reduced cost but also for the elimination of waste material that required disposal. This also had the advantage that it could be implemented with minimal modifications to the existing plant, saving significantly on capital expenditure that other alternatives would require.
In May 2017, we commenced the switch to Redox processing and from June 2017 onwards all of the gas processed at Dobrinskoye was with Redox. Although the change was achieved at low capital cost, in the first months after implementation, the plant throughput was kept a low levels while the process management was optimized. Throughput at the gas plant was gradually increased and in December 2017 was averaged 533,000 m(3) per day (18.8 mmcf/d). However, the period of lower throughput at the gas plant was primarily responsible for an overall reduction in group production, being 24% lower than 2016.
Offsetting the reduction in volumes in 2017, oil prices and the Russian Ruble both recovered steadily through the year and consequently the impact of lower sales volumes on the financial performance of the group was less than may have been otherwise. This is discussed in greater detail in the Financial Report below.
In addition to the switch to Redox gas sweetening, the two major projects undertaken by Volga Gas during 2017 were the construction of an LPG unit at Dobrinskoye and the drilling of the horizontal well Uzen #101 on the Uzen oil field in our Karpenskiy licence. These projects were the main use of the capital investment undertaken by Volga Gas in 2017 and are expected to contribute materially to future revenues and profits. I will cover these projects in greater detail below.
Reserves update
Subsequent to the 2017 year-end, the Company commissioned a new independent reserve report by OOO Geostream Assets Management ("Geostream") as, late in 2017, the presence of increased formation water was observed during gas production from certain of the production wells on the VM field. The report, dated 12 April 2018, has resulted in a reduction of 27% in the Proved and of 28% in the Proved plus probable reserve numbers for the Group's oil and gas reserves. Although the estimate of original hydrocarbons in place is unchanged, the presence of formation water during gas production has led Geostream to apply a more conservative calculation of ultimately recoverable reserves from the VM field.
Management considers the new reserve estimates to be consistent with the currently available field data and, accordingly, has adopted the revised reserve estimates as the Group's oil, gas and condensate reserves for the 2017 year-end accounts. The Group's reserve statement is shown in the Operational Review on pages 7 and 8. The impact of the reserve revision has been to increase the depletion, depreciation and amortisation charge of the Group compared to 2016 with consequent reductions in the profit and net book value of the Group's assets. While the reserve revisions have not triggered any impairment charges, subsequent reserve evaluations may or may not lead to further revisions which may or may not impair the assets. Following the revised reserve estimates that have been adopted, we are actively looking into technical and operational solutions to mitigate the impact of the reserves reductions and to maximise gas production through the Dobrinskoye gas plant.
2018 objectives and medium term strategy
Management has the following key objectives in 2018:
-- To increase the efficiency and processing capacity at the gas plant using Redox gas sweetening from the rate of 533,000 m(3) per day achieved at the end of 2017.
-- Having nearly completed construction of the LPG plant, to commence production and optimize the marketing of the product.
-- To complete the reservoir and technical studies on the Vostochny Makarovskoye ("VM") field and to commence actions including workovers and reperforations of the well bores to mitigate future formation water production thereby restoring maximum gas production and the extraction of reserves in place.
-- Optimise the production of oil from the new horizontal well Uzen #101 and to manage the more mature oil wells in the field.
Current trading and outlook
Between January and March 2018, Group production averaged 4,084 barrels of oil equivalent per day, in line with management's plan, given the anticipated higher levels of planned maintenance downtime in the period. For the coming months, management expects to maintain an average daily production of gas and condensate in the region of 3,800 boepd resulting in Group production of approximately 4,500 boe per day, excluding incremental volumes from the LPG project, which when the project is fully operational is expected to add a further 400 boe per day.
International oil prices strengthened at the start of 2018 and have remained relatively stable. Although it is a minor part of the Group's output, oil production has increased as a result of additional volumes from the horizontal well Uzen #101 which has more than offset the natural decline in the mature oil wells.
In the current environment, and at current production rates to which may be added additional sales of LPG, management expects the Group's financial performance in 2018 to improve on that of 2017. Meanwhile, new capital expenditure commitments remain within projected cash generation, permitting a resumption of a sustainable distribution policy for shareholders.
Andrey Zozulya
Chief Executive Officer
Operational Review
Operations overview
As outlined above, Group production in 2017, at an average daily rate of 4,948 boepd, was 24% lower than the 6,507 boepd achieved in 2016. The principal reason for this was the planned reduction of gas processing plant throughput necessary as the Redox-based gas sweetening process was implemented and optimized over a period of several months. There was also some decline in the mature production wells in the Uzen oil field and the increased presence of formation water in certain of the production wells at VM in late 2017.
The impact on revenues was partly offset by a continued recovery in oil prices through the year and the Ruble stabilising at higher levels. As a result of the lower proportion of export sales in 2017, taking into account selling expenses, netback revenues (defined as Revenues less Selling Expenses as shown in the Income Statements) in 2017 were US$34.8 million, only marginally lower than the US$35.4 million in 2016.
The benefits of savings from the lower process chemicals costs were offset by higher rates of Mineral Extraction Tax arising from higher oil prices and the scheduled adjustments to the rate formulas and by increases in administrative expenses. As a consequence EBITDA for 2017 was US$8.8 million (2016: US$9.6 million).
Besides the implementation of Redox-based processing at the Dobrinskoye gas plant, the key operational activities in 2017 were construction of the LPG plant and, in the separate oil production business, the drilling of new horizontal wells on the Uzen field.
Gas/condensate production
The Dobrinskoye and VM fields are managed as a single business unit. Production from the fields is processed at the gas plant located next to the Dobrinskoye field, extracting the condensate and processing the gas to pipeline standards before input into Gazprom's regional pipeline system via an inlet located at the plant. The VM field was developed with wells drilled by Volga Gas, while the Dobrinskoye wells were acquired from previous licensees.
By the end of 2016, development drilling on the VM field was essentially completed, with a total of four wells in the principal reservoir, the Evlano Livinskiy carbonate, and a further well in the secondary Bobrikovskiy sandstone reservoir.
Production during 2017 averaged 19.1 mmcf/d of gas and 1,163 bpd of condensate (2016: 25.5 mmcf/d of gas and 1,557 bpd condensate) an overall decrease of 25% in equivalent barrels of oil terms. As outlined above, this was principally a result of the decision to operate the gas processing plant at lower throughput rates as the Redox processing was implemented and optimized. Between June 2017 and December 2017, the daily throughput increased steadily as discussed below and production increased accordingly.
Between January 2017 and April 2017, while the gas was being sweetened with the old Sulfanox process, production was generally running at close to the gas plant's maximum physical capacity and averaged 30.5 mmcf/d of gas and 1,730 bpd of condensate. However, during late 2017 and early 2018 the presence of formation water in certain of the production wells on VM was detected. Consequently management commissioned a new reserve report. The report, date 12 April 2018, concluded that as a result of more conservative calculation of ultimate recovery rates, the company should recognise a significant reduction in reserves, mainly in the VM field.
Management is looking into technical and operational solutions to mitigate the impact of the reserves reductions including conducting well interventions on the VM field, workovers and reperforations of the well bores. On Dobrinskoye, which is a more mature gas field, there are also plans to drill a sidetrack on well #26 to develop a likely undepleted portion of the reservoir.
The Proven and Probable reserves and the revisions adopted in full for the 2017 year-end results are detailed in the table on page 8.
Gas/condensate sales
Historically, the Group's gas was sold to Trans Nafta under contract at a fixed Ruble contract. However, from December 2016, gas sales have been made directly to Gazprom. This has resulted in an increase in the net realisations although the Group now pays a transit tariff for delivery via the Gazprom pipeline network to the point of sale.
In US dollar terms, however, the stronger Ruble as well as an increase in the Ruble selling price led to the average gas sales realisations rising 36% in 2017 to US$2.06/mcf (2016: US$1.51).
Since November 2015, we have been utilizing export channels for condensate as an alternative to domestic sales in periods of low domestic demand. Domestic market conditions in 2017 were generally more favourable and consequently condensate exports declined significantly and ceased altogether from the end of March 2017. In total, approximately 15% of condensate sales were exported during 2017, compared to 48% of the total condensate sales in 2016.
During 2017 the average condensate netback price (after accounting for export taxes and transportation costs) increased 38% to US$34.37 per barrel (2016: US$24.83).
Average unit production costs on the gas-condensate fields increased moderately to US$5.39 per boe in 2017 (2016: US$5.33). The recovery in the Ruble, in which effectively all the costs are denominated and the lower throughput rates in the second half of 2017, increased the impact of the fixed cost element of the operating expenses offset the benefits of lower chemical costs associated with the switch to Redox.
Gas processing plant
The Dobrinskoye gas processing plant was originally designed and constructed to utilise a Sulfanox based gas sweetening process, which had the benefit of low capital cost but carried high chemical usage and generated substantial volumes of waste requiring careful disposal. The plant was designed with a maximum throughput capacity of one million m(3) /day (35.3 mmcf/d).
During 2016, a number of alternatives were tested and by the end of 2016, management decided that a switch to a Redox-based sweetening process would be optimal and requiring only minor modifications to the existing plant equipment. Between April and June 2017, industrial scale testing of the Redox process was undertaken while the modifications were carried out. In June the plant was switched over entirely to Redox-based processing.
During the initial months of the new process, between June 2017 and August 2017, the plant throughput was kept at relatively low levels as the process management was optimised. Throughput increased gradually through the remainder of 2017, from the average rate of 213,000 m(3) /day (7.5 mmcf/d) in June 2017 to reach 533,000 m(3) /day (18.8 mmcf/d) in December 2017 slightly above management's short term throughput target. In addition, during November 2017, inefficient operations of the system pumps had caused up to 40% of the processed gas being below pipeline specification. This issue has been dealt with and since December 2017 all of the processed gas is available for sale.
Based on the experience of operating the Redox process to date, management identified the need to add two further oxidizing vessels to the current plant configuration. Having recently completed this, management expects improvements in efficiency, reduced operational downtime and higher effective operating capacity.
The other key development at the gas plant in 2017 was the construction of a new unit for the capture, storage and sale of LPG. LPGs, primarily comprising propane and butane, are currently either included in the sales gas stream or flared. The LPG project will provide an additional product stream which is expected to increase total sales volumes by approximately 400 boe per day and to enhance profitability.
Although construction was largely accomplished before the end of 2017 as planned, delays in delivery of certain items of equipment and to regulatory clearance, completion of the project was delayed by approximately three months. As of March 2018, the LPG project is commencing the commissioning process and should start production during the second quarter of 2018.
In spite of the delays to the project, the LPG project is expected to be completed at a total capital cost of US$5.5 million.
Oil production and development
Since 2009, the Uzen field has been producing oil from a cretaceous Aptian reservoir at a depth of approximately 1,000 metres. As the oil was produced, the oil-water contact in the reservoir rose and the wells at the edge of the field were shut in as water cut increased. By the start of 2017, production was derived from three active wells - down from a peak of five in 2010. With careful management, production has been continued albeit at declining rates. The existing mature wells produced at an average rate of 595 bopd in 2017 (2016: 708 bopd).
The principal development activity of 2017 on the Uzen field was on the proved undeveloped reserves in the shallower Albian reservoir, using a horizontal well. Drilling of the new horizontal well #101 commenced on 27 April 2017. Although mainly being drilled to develop the proved but currently undeveloped Albian reservoir in the Uzen field, the well was initially sidetracked to investigate potential unproven structures. While one possible target was dry, a second small oil accumulation was encountered, providing only a minor increment to Group reserves.
Drilling operations on the horizontal section of well #101 were concluded as anticipated in July 2017 having completed a horizontal section of total length of 627 metres. Logging while drilling indicated a total productive zone in the well of 506 metres, exhibiting average porosity of 32% and oil saturation of 68%. Between October 2017 and December 2017, well #101 was intermittently flow tested. Following the installation of a flow line from the well site to the main Uzen field facilities in December 2017, well #101 has been put on continuous production. Between January and March 2018, well #101 has been producing at an average rate of approximately 300 bopd.
As a result of the extra sidetracks drilled and additional precautions taken to deliver a stable and secure production well, the costs of drilling well #101 increased to approximately US$7.1 million compared to a budget cost of US$3.8 million.
Following a revised conversion from tonnes to barrels, as the oil contained in the Albian reservoir has slightly higher density than the oil in the Aptian reservoir, there is a modest restatement in the Uzen oil reserves as expressed in barrels. There is no change in the tonnage of reserves.
Exploration
During 2017, as a result of the decision to focus on income generating investments, exploration activity was confined to internal technical studies.
Nevertheless, the Group has identified a number of exploration targets in the Karpenskiy Licence Area at shallow horizons of between 1,000 and 2,000 metres depth. These provide low cost opportunities to add potentially material oil reserves. While management recognises the potential of these prospects, the immediate priority is to maximise the value and cash generation from proven reserves.
The Group has fulfilled all its licence commitments on the Karpenskiy Licence Area and further drilling in the area is discretionary. Nevertheless future development of the oil potential in the Group's licences is a key element of management's medium-term strategy.
Oil, gas and condensate reserves as of 1 January 2018
In February 2018 Volga Gas commissioned an updated reserve report of the Group's oil, gas and condensate reserves. Management considers the new reserve estimates contained in this report, dated 12 April 2018, to be a reasonable reflection of the field data currently available, and accordingly they have been adopted by the Company as a fair statement of reserves.
The following table shows the Proven and Probable reserves as at 31 December 2017 and changes from previous estimates.
Oil, gas and condensate reserves
Oil & Condensate Gas LPG Total
(tonnes)
(mmbbl) (bcf) (000) (mmboe)
-------------------------------- ----------------- ------- ---------- ---------
As at 31 December 2016
Proved reserves 10.951 98.5 277 30.619
Proved plus probable reserves 12.153 131.5 367 38.405
-------------------------------- ----------------- ------- ---------- ---------
Production: 1 January -31
December 2017 0.667 7.0 - 1.831
Revisions:
Proved reserves (0.460) (34.2) (129) (7.663)
Proved plus probable reserves (0.363) (46.9) (162) (10.108)
As at 31 December 2017
Proved reserves 9.824 57.3 148 21.125
Proved plus probable reserves 11.123 77.6 205 26.466
Revision as % of 2016 reserves
less 2017 production
Proved reserves (5%) (37%) (47%) (27%)
Proved plus probable reserves (3%) (38%) (44%) (28%)
-------------------------------- ----------------- ------- ---------- ---------
Notes:
1. Volga Gas (through its wholly owned subsidiaries PGK and GNS) is the operator and has a 100% interest in four licences to explore for and produce oil, gas and condensate in the Volga region.
2. The reserve estimates as at 31 December 2016 were independently assessed by OOO Geostream Assets Management. The estimates at 31 December 2017 are results of an updated study conducted by OOO Geostream Assets Management dated 12 April 2018. The full reserve report is available on the Company's website: www.volgagas.com.
3. The reserve estimates were prepared in metric units: tonnes for oil, condensate and LPG and standard cubic metres for gas. The conversion ratios from tonnes to barrels applied in the table above were 7.833 barrels per tonne of oil, 8.75 barrels per tonne of condensate and 11.75 barrels per tonne of LPG. One cubic metre equates to 35.3 cubic feet and one barrel of oil equivalent is given by 6,000 standard cubic feet of gas.
4. The above reserve estimates, prepared in accordance with the PRMS reserve definitions prepared by the Oil and Gas Reserves Committee of the SPE, have been reviewed and verified by Mr Andrey Zozulya, Director and Chief Executive Officer of Volga Gas plc, for the purposes of the Guidance Note for Mining, Oil and Gas companies issued by the London Stock Exchange in June 2009. Mr Zozulya holds a degree in Geophysics and Engineering from the Groznensky Oil & Gas Institute and is a member of the Society of Petroleum Engineers.
Financial Review
Results for the year
In 2017, the Group generated US$37.1 million in turnover (2016: US$39.4 million) from the sale of 644,506 barrels of crude oil and condensate (2016: 837,837 barrels) and 6,378 million cubic feet of natural gas (2016: 9,210 million cubic feet).
The average price realised for liquids sold in the domestic market was the equivalent of US$35.49 per barrel (2016: US$30.59 per barrel). During 2017 approximately 15% of condensate sales were to export customers (2016: 48%). As a consequence selling expense such an export taxes and transportation costs fell substantially in 2017 to of US$2.2 million (2016: US$ 4.1 million). For domestic sales the selling price for liquids is effectively a wellhead netback price. The average netback price for liquids sales, calculated by deducting selling expenses from revenue attributed to oil and condensate sales, in 2017 was US$35.80 (2016: US$25.70).
The gas sales price during 2017 averaged US$2.06 per thousand cubic feet (2016: US$1.51 per thousand cubic feet), the increase being attributable to higher Ruble selling prices as well as the movement in the Ruble/US dollar exchange rate. The average sales price of gas in Rubles increased in 2017 by 10.8% compared to 2016 (no increase in 2016 over 2015). In December 2016 the Company commenced sales directly to Gazprom which was partly responsible for the increase in realised price. Production activities generated a gross profit of US$8.2 million in 2017 (2016: US$13.1 million).
In 2017, the total cost of production decreased to US$9.3 million (2016: US$11.0 million), with variable costs driven by lower production volumes, some Ruble inflation and the effect of the recovery in the Ruble on our predominantly Ruble denominated costs. Unit field operating costs were steady at US$3.74 per boe (2016: US$3.95 per boe), partly as a result of cost efficiencies, offset by fixed costs shared among lower volumes. Production based taxes were US$10.9 million (2016: US$10.3 million) reflecting the impact of higher oil prices and Ruble exchange rates on Mineral Extraction Tax ("MET") rates as well as the impact of further formula changes that came into effect on 1 January 2017. This was partly offset by lower production volumes. MET paid in 2017 represented 31.4% of netback revenues (2016: 29.0% of netback revenues).
Operating and administrative expenses in 2017 were US$5.8 million (2016: US$4.5 million), reflecting the stronger Ruble as well as certain one-off expenses.
The Group experienced a 9% reduction in EBITDA (defined in Operational and financial summary on page 11 as operating profit before non-cash charges, including exploration expense, depletion and depreciation) to US$8.8 million (2016: US$9.6 million).
The unit rate of Depletion, Depreciation and Amortisation ("DD&A") increased to US$5.02 per boe (2016: US$2.12 per boe) as a result of both of the reduction in reserves in the VM and Dobrinskoye fields and higher than anticipated expenditures on the Uzen horizontal well as well as the strength of the Ruble in which the depletion pool is recorded. This was offset by the 24% decrease in production. The DD&A charge in 2017 was US$8.6 million (2016: US$5.0 million) with consequent reductions in profit and net book value of the Group assets.
With no significant exploration and evaluation expenses of in 2017 (2016: US$0.3 million) and other provisions (2016: provision of US$1.8 million for the write off of development assets), the Group recorded an operating profit for 2017 of US$113,000 (2016: US$2.5 million).
Including net interest income of US$0.2 million (2016: US$0.2 million) and other net losses of US$142,000 (2016: net loss of US$0.8 million) the Group recognised a profit before tax of US$168,000 (2016: US$1.9 million) and reported net profit after tax of US$330,000 (2016: US$1.2 million) after a current tax charge of US$243,000 and a deferred tax credit of US$405,000 (2016: deferred tax charge of US$0.7 million).
Profitability by product
While the Group operates as a single business segment as described in Note 2.3 to the accounts on page 35, management estimates the relative profitability, which for this purpose is defined to be Gross profit less Selling Expenses, by product to be as follows:
2017 2016
US$ 000 Oil Gas & Condensate Oil Gas & Condensate
------------- ----------------- ------------- -----------------
Revenue 8,075 28,991 7,523 31,889
MET (3,816) (7,120) (3,064) (7,191)
Depreciation (967) (7,613) (480) (4,557)
Other Cost of sales (1,067) (8,253) (1,254) (9,714)
Selling expenses (189) (2,032) (221) (3,831)
------------- ----------------- ------------- -----------------
Gross profit net of selling
expenses 2,036 3,973 2,504 6,596
============= ================= ============= =================
Cash flow
Group cash flow from operating activities was US$6.3 million (2016: US$13.3 million). Net working capital movements contributed cash outflow of US$2.3 million in 2017 (2016: net inflow of US$2.9 million), which included movements in accounts payable of US$2.9 million (2016: cash inflow of US$3.8 million from export customer prepayments). Included in net cash flow for 2017 were payments of profit tax of US$0.5 million (2016: US$2,000). With higher capital expenditures in 2017, the net outflow from investing activities was US$12.6 million (2016: US$5.0 million). With dividend payments of US$5.0 million in 2017 (2016: nil), net cash outflow flow from financing activities was US$5.2 million (2016: inflow of US$4.0 million from debt drawdown).
Dividend
In July 2014, the Board announced the adoption of a policy to distribute approximately 50% of consolidated net profit after tax as a cash dividend. In 2017 the Company paid a dividend of US$0.007 per ordinary Share in respect of 2016 and in addition a special dividend of US$0.055 per ordinary share. In light of the significant capital investment in 2017 and in the interests of prudence, the Board will defer any decision on further distribution until the interim results stage when the impact of the new projects on financial performance will be clearer. However, the Board is considering a policy of basing future dividends on cash generation as well as earnings and, subject to the requirements of the Group, of distributing up to 75% of free cash flow.
Capital expenditure
During 2017 capital expenditure of US$12.4 million was incurred (2016: US$4.2 million), of which US$12.3 million was incurred on development and producing assets (2016: US$3.9 million) and US$0.1 million on exploration and evaluation (2016: US$0.3 million). Capital expenditure in 2017 comprised drilling and workovers on the Uzen oil field, construction of the LPG plant and minor upgrades to the gas processing plant.
Balance sheet and financing
As at 31 December 2017, the Group held cash and bank deposits of US$8.6 million (2016: US$19.7 million). All of the Group's cash balances are held in bank accounts in the UK and Russia. Approximately 48% (2016: 64%) of the Group's cash is held in US Dollars and 50% (2016: 34%) held in Russian Rubles.
In December 2016, the Group drew down from a RUR 240 million (US$4.0 million) of bank facility, which was utilised to fund purchases of equipment for the LPG project. Total debt as at 31 December 2017 was US$4.0 million (2016: US$4.0 million). Repayments of the loan by monthly amortization commenced in December 2017. As at 31 December 2017, there was a technical breach of certain loan covenants. Management is confident of receiving a waiver of this breach from the lender, but pending receipt of this waiver, the entire loan is classified as current.
As at 31 December 2017, the Group's intangible assets were US$3.8 million (2016: US$3.5 million). Property, plant and equipment, increased to US$62.3 million (2016: US$55.9 million), reflecting capital investment incurred in 2017 as well as the impact of foreign exchange adjustments, offset by higher depletion. The carrying values of the Group's assets relating to its main cash generating units have been subject to impairment testing. The result of the impairment tests, including sensitivity analysis around the central economic assumptions and taking into account the reduction in oil and gas reserves, as detailed in Note 4(b) to the Accounts, showed no present requirement for impairment.
For the year ending 31 December 2017, the Group recorded a currency retranslation income of US$3.5 million (2016: income of US$10.5 million) in its Other comprehensive income, relating to the movement of the Ruble against the US Dollar.
The Group's committed capital expenditures are less than expected cash flow from operations and cash-on-hand and such expenditures can be managed in light of the volatility in international oil prices and the Ruble. The Group may consider additional debt facilities to fund the longer-term development of its existing licences and operational facilities as appropriate.
The Group's financial statements are presented on a going concern basis, as outlined in note 2.1 to the Accounts.
Five year financial and operational summary
Sales volumes 2017 2016 2015 2014 2013
------------------------------- --------- ---------- ---------- ---------- ----------
Oil & condensate (barrels
'000) 644 828 439 604 547
Gas (mcf) 6,378 9,320 4,545 5,671 3,128
Total (boe '000) 1,707 2,381 1,196 1,549 1,069
Operating Results (US$ 2017 2016 2015 2014 2013
000)
------------------------------- --------- ---------- ---------- ---------- ----------
Oil and condensate sales 23,952 25,380 11,041 27,220 26,067
Gas sales 13,114 14,032 6,786 12,203 8,554
--------- ---------- ---------- ---------- ----------
Revenue 37,066 39,412 17,827 39,423 34,621
Field operating costs (6,379) (9,367) (6,016) (7,805) (5,946)
Production based taxes (10,936) (10,255) (5,877) (8,344) (8,095)
Depreciation (8,580) (5,037) (2,345) (4,656) (2,611)
Other production expenses (2,941) (1,601) (1,352) (1,709) (1,799)
--------- ---------- ---------- ---------- ----------
Cost of sales (28,836) (26,260) (15,589) (22,514) (18,451)
Gross profit 8,229 13,152 2,238 16,909 16,170
Selling expenses (2,221) (4,052) (319) - -
Exploration expense - (265) (635) - (2,519)
Write-off of development
assets (65) (1,798) (2,950) - (1,439)
Operating, administrative
& other expenses (5,831) (4,526) (3,377) (4,157) (4,029)
--------- ---------- ---------- ---------- ----------
Operating (loss)/profit 113 2,511 (5,043) 12,752 8,183
Net realisation 2017 2016 2015 2014 2013
------------------------------- --------- ---------- ---------- ---------- ----------
Oil & condensate (US$/barrel) 37.19 30.65 25.16 45.07 47.63
Gas (US$/mcf) 2.06 1.51 1.49 2.15 2.73
Operating data (US$/boe) 2017 2016 2015 2014 2013
------------------------------- --------- ---------- ---------- ---------- ----------
Production and selling
costs 3.74 3.93 5.03 5.04 5.56
Production based taxes 6.40 4.31 4.91 5.39 7.58
Depletion, depreciation
and other 5.03 2.12 1.98 3.01 2.44
EBITDA calculation (US$ 2017 2015 2014 2013
000) 2016
------------------------------- --------- ---------- ---------- ---------- ----------
Operating profit/(loss) 113 2,511 (5,043) 12,752 8,183
Exploration expense - 265 635 - 2,519
DD&A 8,645 6,857 5,319 4,656 4,050
--------- ---------- ---------- ---------- ----------
EBITDA 8,758 9,633 911 17,408 14,752
EBITDA per boe 5.13 4.05 0.76 11.24 13.81
Netback realisation for oil and condensate is calculated by deducting Selling expenses from Oil, gas and condensate sales.
Principal Risks and Uncertainties
The Group is subject to various risks relating to political, economic, legal, social, industry, business and financial conditions. The following risk factors, which are not exhaustive, are particularly relevant to the Group's business activities:
Volatility of oil prices
The supply, demand and prices for oil are influenced by factors beyond the Group's control. These factors include global and regional demand and supply, exchange rates, interest and inflation rates and political events. A significant prolonged decline in oil and gas prices could impact the profitability of the Group's activities.
All of the Group's revenues and cash flows come from the sale of oil, gas and condensate. If sales prices should fall below and remain below the Group's cost of production for any sustained period, the Group may experience losses and may be forced to curtail or suspend some or all of the Group's production, at the time such conditions exist. In addition, the Group would also have to assess the economic impact of low oil and gas prices on its ability to recover any losses the Group may incur during that period and on the Group's ability to maintain adequate reserves.
The Group does not currently hedge its crude oil production to reduce its exposure to oil price volatility as the structure of taxes applied to oil and condensate production in Russia effectively reduce the exposure to international market prices for oil. In addition, the Ruble exchange rate has tended to move with the oil price, reducing the overall volatility of oil prices when translated into Russian Rubles.
Market risks
The Group's revenues generated from oil and condensate production have typically been from sales to local domestic customers. There have been periods when the local market has been unable to purchase condensate, causing temporary suspension of production and loss of revenues. Since November 2015, the Group has developed export channels for its condensate into regional export markets to mitigate this risk. Gas sales are made to Gazprom. The region in which the Group operates is reliant on external gas supplies. Consequently the risk of insufficient demand for the Group's gas is considered low. Gas sales have generally been conducted as expected, subject to occasional constraints during pipeline maintenance operations.
Oil and gas production taxes
The Group's sales generated from oil and gas production are subject to Mineral Extraction Taxes ("MET"), which form a material proportion of the total costs of sales. The rates of these taxes are subject to changes by the Russian government, which relies heavily on such taxes for its revenues. Changes to rate formulas which came into effect during 2015 and in 2016 materially increased the rates on crude oil, condensate and natural gas. With oil prices recovering from recent lows, MET rates have increased in line with current formulas. As of 2019, the Russian government is planning trials of a profit-based oil and gas taxation regime to replace the production-based MET. At present the impact on the Group's operations of any such change of tax regime is unknown.
Exploration and reserve risks
Whilst the Group will seek to apply the latest technology to assess exploration licences, the exploration for, and development of, hydrocarbons involves a high degree of risk. These risks include the uncertainty that the Group will discover sufficient commercially exploitable oil or gas resources in unproven areas of its licences. Unsuccessful exploration efforts may result in impairment to the balance sheet value of exploration assets. However, the Group's current plans involve limited expenditure in exploration related activities.
In February 2018, the Group commissioned an updated reserve evaluation based on reporting standards set by the Society of Petroleum Engineers. The reserve report, delivered to and adopted by management on 12 April 2018, resulted in a downward revision by approximately 27% to the Group's reserves as at 31 December 2017. Management considers the new reserve estimate to be in line with the currently available field data and accordingly has chosen to adopt the preliminary estimates as the statement of the Group's oil, gas and condensate reserves. The Group's reserve statement is shown in the Operational Review on pages 7 and 8. The impact of the reserve revision has been to increase the depletion, depreciation and amortisation charge of the group with consequent reductions in the profit and net book value of the Group's assets. While the reserve revisions do not appear to have triggered an impairment subsequent reserve evaluations may lead to further revisions which may impair the assets. Furthermore, if the results of producing the Group's fields are significantly different to expectations, there may be changes in the future estimates of reserves. These may impact both the future profitability and the balance sheet carrying values of the Group's Property, Plant and Equipment.
Environmental risk
The oil and gas industry is subject to environmental hazards, such as oil spills, gas leaks, ruptures and discharges of petroleum products and hazardous substances, including waste materials generated by the sweetening process formerly in use at the Dobrinskoye gas processing plant. These environmental hazards could expose the Group to material liabilities for property damages, personal injuries, or other environmental harm, including costs of investigating and remediating contaminated properties.
The Group is subject to stringent environmental laws in Russia with regards to its oil and gas operations. Failure to comply with such laws and regulations could subject the Group to material administrative, civil, or criminal penalties or other liabilities. Additionally, compliance with these laws may, from time to time, result in increased costs to the Group's operations, impact production, or increase the costs of potential acquisitions.
The Group liaises closely with the Federal Service of Environmental, Technological and Nuclear Resources of the Saratov and Volgograd Oblasts on potential environmental impact of its operations and conducts environmental studies both as required by, and in addition to, its licence obligations to mitigate any specific risk. The Group's operations are regularly subject to independent environmental audit. The Group did not incur any material costs relating to the compliance with environmental laws during the period.
Risk of operating oil and gas properties
The oil and gas business involves certain operating hazards, such as well blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and releases of toxic substances. Any of these operating hazards could cause serious injuries, fatalities, or property damage, which could expose the Group to liabilities. The settlement of these liabilities could materially impact the funds available for the exploration and development of the Group's oil and gas properties. The Group maintains insurance against many potential losses and liabilities arising from its operations in accordance with customary industry practices, but the Group's insurance coverage cannot protect it against all operational risks.
Foreign currency risk
The Group's capital expenditures and operating costs are predominantly in Russian Rubles ("RUR") while a minority of administrative expense is in US Dollars, Euros and Pounds Sterling. Revenues are predominantly received in RUR so the operating profitability is not materially exposed to moderate short-term exchange rate movements. The functional currency of the Group's operating subsidiaries is the RUR and the Group's assets and liabilities are predominantly RUR denominated. As the Group's presentational currency is the US Dollar, fluctuations in the exchange rate of the RUR against the US Dollar impact the Group's financial statements.
Business in Russia
Amongst the risks that face the Group in conducting business and operations in Russia are:
-- Economic instability, including in other countries or the global economy that could lead to consequences such as hyperinflation, currency fluctuations and a decline in per capita income in the Russian economy.
-- Governmental and political instability that could disrupt, delay or curtail economic and regulatory reform, increase centralised authority or result in nationalisations.
-- Social instability from any ethnic, religious, historical or other divisions that could lead to a rise in nationalism, social and political disturbances or conflict.
-- Uncertainties in the developing legal and regulatory environment, including, but not limited to, conflicting laws, decrees and regulations applicable to the oil and gas industry and foreign investment.
-- Unlawful or arbitrary action against the Group and its interests by the regulatory authorities, including the suspension or revocation of their oil or gas contracts, licences or permits or preferential treatment of their competitors.
-- Lack of independence and experience of the judiciary, difficulty in enforcing court or arbitration decisions and governmental discretion in enforcing claims.
-- Unexpected changes to the federal and local tax systems.
-- Laws restricting foreign investment in the oil and gas industry.
-- The imposition of sanctions upon certain entities in Russia.
The Group's operations and financial management have not to date been impacted directly by any sanctions.
Legal systems
Russia, and other countries in which the Group may transact business in the future, have or may have legal systems that are less well developed than those in the United Kingdom. This could result in risks such as:
-- Potential difficulties in obtaining effective legal redress in the court of such jurisdictions, whether in respect of a breach of contract, law or regulation, including an ownership dispute.
-- A higher degree of discretion on the part of governmental authorities.
-- The lack of judicial or administrative guidance on interpreting applicable rules and regulations.
-- Inconsistencies or conflicts between and within various laws, regulations, decrees, orders and resolutions.
-- Relative inexperience of the judiciary and courts in such matters.
In certain jurisdictions, the commitment of local business people, government officials and agencies and the judicial system to abide by legal requirements and negotiated agreements may be more uncertain, creating particular concerns with respect to licences and agreements for business. These may be susceptible to revision or cancellation and legal redress may be uncertain or delayed. There can be no assurance that joint ventures, licences, licence applications or other legal arrangements will not be adversely affected by the jurisdictions in which the Group operates.
Liquidity risk
At 31 December 2017 the Group had US$8.6 million (2016: US$19.7 million) of cash and cash equivalents of which US$7.9 million was held in bank accounts in Russia (2016: $6.1 million). As at 31 December 2017, total bank debt was US$4.0 million (2016: US$4.0 million). The Group has fully drawn on the debt facilities available as at 31 December 2017 and 31 December 2016. 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 2017 the Group has budgeted capital expenditures US$5.9 million of which the significant items are US$1.4 million for completion of the LPG project and US$3.2 million is for drilling of sidetrack wells and other development activities. There were approximately US$1.6 million of accounts payable relating to capital expenditures and other expenses incurred in the year ended 31 December 2017 (2016: US$4.8 million).
The Board considers that the Group will have sufficient liquidity to meet its obligations. All current and planned capital expenditures are discretionary and may be deferred or cancelled in the light of the Group's cash generation and liquidity position.
Through its ordinary course activities, the Group is exposed to legal, operational and development risk that could delay growth in its cash generation from operations or may require additional capital investment that could place increased burden on the Group's available financial resources.
Capital risk
The Group manages capital to ensure that it is able to continue as a going concern whilst maximising the return to shareholders. The Group is not subject to any externally imposed capital requirements. The Board regularly monitors the future capital requirements of the Group, particularly in respect of its ongoing development programme. Management expects that the cash generated by the operating fields will be sufficient to sustain the Group's operations and committed capital investment for the foreseeable future and has a policy of maintaining a minimum level of liquidity to cover forward obligations. Further short-term debt facilities may be arranged to provide financial headroom for future development activities.
Bribery
The Company is subject to numerous requirements and standards including the UK Bribery Act. In addition the Group is subject to anti-bribery and anti-corruption laws and regulations in all jurisdictions in which it operates. Failure to comply with regulations and requirements, such as failure to implement adequate systems to prevent bribery and corruption, could result in prosecution, fines or penalties imposed on the Company or its officers or suspension of operations. The Group's mitigation measures include compliance related activities, training, monitoring, risk management, due diligence and regular review of policies and procedures. We prohibit bribery and corruption in any form by all employees and by those working for or connected with the business. Employees are expected to report actual, attempted or suspected bribery or other issues related to compliance to their line managers or through our confidential reporting process, which is available to all staff as well as third parties
Fraud
The Group has been exposed to fraudulent transfers of funds from its bank accounts and is at various times at risk to attempted fraud. . The Group has established enhanced protections of its information technology infrastructure, operational systems and procedures against fraudulent activities.
Abbreviated Financial Statements
for the year ended 31 December 2017
Group Income Statement
(presented in US$ 000)
Year ended 31 December Notes 2017 2016
CONTINUING OPERATIONS
Revenue 4 37,066 39,412
Cost of sales 5 (28,836) (26,260)
-------------- ----------------
Gross profit 8,230 13,152
Selling expenses 5(a) (2,221) (4,052)
Operating and administrative expenses 5 (5,831) (4,525)
Exploration and evaluation expense - - (265)
Write off of development assets (65) (1,798)
-------------- ----------------
Operating profit 113 2,511
Interest income 197 183
Interest expense - (3)
Other losses - net 6 (142) (763)
-------------- ----------------
Profit for the year before tax 168 1,928
Current income tax (243) (2)
Deferred income tax 405 (739)
-------------- ----------------
Profit for the year before non-controlling
interests 330 1,187
Attributable to:
The owners of the parent Company 330 1,187
============== ================
Basic and diluted profitper share
(in US dollars) 10 0.0041 0.0146
Weighted average number of shares
outstanding 81,017,800 81,017,800
Group Statement of Comprehensive Income
(presented in US$ 000)
Year ended 31 December 2017 2016
Profit for the year attributable to equity
shareholders of the Company 330 1,187
Other comprehensive income:
Items that are or may be reclassified subsequently
to profit or loss
Currency translation differences 3,452 10,495
Reversal of share grant reserve 5,233 -
-------------- -------
Total comprehensive income for the
year 9,015 11,682
Attributable to:
The owners of the parent Company 9,015 11,682
============== =======
Group Balance Sheet
(presented in US$ 000)
At 31 December Notes 2017 2016
ASSETS
Non-current assets
Intangible assets 7 3,756 3,460
Property, plant and equipment 8 62,329 55,908
Other non-current assets - 4
Deferred tax assets 1,618 1,536
-------------- --------------
Total non-current assets 67,703 60,908
Current assets
Cash and cash equivalents 9 8,617 19,718
Inventories 10 1,228 981
Other receivables 11 2,529 3,007
-------------- --------------
Total current assets 12,374 23,706
Total assets 80,077 84,614
============== ==============
EQUITY AND LIABILITIES
Equity
Share capital 1,485 1,485
Other reserves (77,403) (75,622)
Accumulated profits 141,787 141,224
-------------- --------------
Equity attributable to the shareholders
of the parent 65,869 67,087
Non-current liabilities
Asset retirement obligation 184 175
Deferred tax liabilities 3,202 3,429
Bank loans 13 - 3,802
-------------- --------------
Total non-current liabilities 3,386 7,406
Current liabilities
Trade and other payables 12 6,818 9,963
Current portion of bank loans 13 4,004 158
-------------- --------------
Total current liabilities 10,822 10,121
Total equity and liabilities 80,077 84,614
============== ==============
Group Cash Flow Statement
(presented in US$ 000)
Year ended 31 December Notes 2017 2016
Profit for the year before tax 168 1,928
Adjustments to profit before tax:
Depreciation of property, plant and
equipment 8 8,647 5,060
Exploration and evaluation expense - 265
Write off of development assets 272 1,749
Provision for obsolete inventory 115 536
Other net non-cash operating gains 5(b) (646) -
Foreign exchange differences 586 892
--------- -----------------
Operating cash flow prior to working
capital 9,142 10,430
Working capital changes
Decrease/(increase) in trade and other
receivables 901 (1,091)
(Decrease)/increase in payables (2,880) 3,745
(Increase)/decrease in inventory (308) 201
--------- -----------------
Cash flow from operations 6,855 13,285
Income tax paid (509) (2)
Net cash flow generated from operating
activities 6,346 13,283
--------- -----------------
Cash flows from investing activities
Expenditure on exploration and evaluation 7 (112) (499)
Purchase of property, plant and equipment 8 (12,440) (4,534)
--------- -----------------
Net cash used in investing activities (12,552) (5,033)
--------- -----------------
Cash flows from financing activities
Equity dividends paid (5,000) -
Bank loans (repaid)/drawn (165) 3,947
--------- -----------------
Net cash (used in)/provided by financing
activities (5,165) 3,947
--------- -----------------
Effect of exchange rate changes on cash
and cash equivalents 270 752
Net (decrease)/increase in cash and
cash equivalents (11,101) 12,949
Cash and cash equivalents at beginning
of the year 9 19,718 6,769
Cash and cash equivalents at end of
the year 9 8,617 19,718
========= =================
Group Statement of Changes in Shareholders' Equity
(presented in US$ 000)
Share Currency Share Accumulated Total
Capital Translation Grant Profit Equity
Reserves Reserve
Opening equity at 1
Jan 2017 1,485 (80,855) 5,233 141,224 67,087
Profit for the year - - - 330 330
Reversal of share grant
reserve - - (5,233) 5,233 -
--------- ------------- --------- ----------------- ----------
Currency translation
differences - 3,452 - - 3,452
--------- ------------- --------- ----------------- ----------
Total comprehensive
income - 3,452 (5,233) 5,563 3,782
Transactions with owners
Equity dividends paid - - - (5,000) (5,000)
--------- ------------- --------- ----------------- ----------
Total transactions with
owners - - - (5,000) (5,000)
--------- ------------- --------- ----------------- ----------
Closing equity at 31
Decr 2017 1,485 (77,403) - 141,787 65,869
========= ============= ========= ================= ==========
Opening equity at 1
Jan 2016 1,485 (91,350) 5,233 140,037 67,724
Profit for the year - - - 1,187 1,187
Currency translation
differences - 10,495 - - 10,495
--------- ------------- --------- ----------------- ----------
Total comprehensive
income - 10,495 - 1,187 11,682
--------- ------------- --------- ----------------- ----------
Transactions with owners
Total transactions with - - - - -
owners
--------- ------------- --------- ----------------- ----------
Closing equity at 31
Decr 2016 1,485 (80,855) 5,233 141,224 67,087
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Notes to the Abbreviated Financial Statements
for the year ended 31 December 2017
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 set out in the Strategic Report in pages 2 to 12; the financial position of the Group, its cash flows, liquidity position and borrowing facilities are described in the Financial Review on pages 9 to 11. 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 2.
Having reviewed the future cash flow forecasts of the Group in the light of the reductions in oil and gas reserves and in consideration of the current financial condition of the Group, the directors have concluded that the Group will continue to have sufficient funds in order to meet its obligations as they fall due for at least the foreseeable future and thus continue to adopt the going concern basis of accounting in preparing the annual financial statements.
1.2 Adopted IFRS not yet applied
The following Adopted IFRSs have been issued but have not been applied by the Group in these financial statements. Their adoption is not expected to have a material effect on the financial statements unless otherwise indicated:
-- IFRS 9 Financial Instruments (effective date 1 January 2018)
-- IFRS 9 replaces the guidance in IAS 39 Financial Instruments: Recognition and Measurement on the classification and measurement of financial assets and financial liabilities, impairment of financial assets, and on hedge accounting.
-- IFRS 9 contains a new classification and measurement approach for financial assets that reflects the business model in which assets are managed and their cash flow characteristics. IFRS 9 also introduced a new impairment model with a forward-looking expected credit loss (ECL) model.
Based on the assessment, the Group does not expect the application of IFRS 9 to have a significant impact on its financial statements, other than the disclosure impact which the Group is finalising.
-- IFRS15 Revenue from Contracts with Customers (effective date 1 January 2018)
-- IFRS 15 replaces the guidance in IAS 11 Construction Contracts and IAS 18 Revenue. IFRS 15 provides a single model for accounting for revenue arising from contracts with customers, focusing on the identification and satisfaction of performance obligations.
The Group does not expect the application of IFRS 15 to have a significant impact on its financial statements.
-- IFRS 16 Leases (effective date 1 January 2019)
IFRS 16 replaces existing leases guidance in IAS 17 Leases, IFRIC 4 Determining whether an Arrangement contains a Lease, SIC-15 Operating Leases, and SIC-27 Evaluating the Substance of Transactions Involving the Legal Form of a Lease. Based on the assessment and lease contract review, the impact of implementation of the standard will be limited to leases of administrative buildings and offices. As such, the Group does not expect the application of IFRS 16 to have significant impact on its financial statements.
-- Annual Improvements to IFRS Standards 2014-2016 Cycle (date 1 January 2018);
-- Amendments to IFRS 2: Classification and Measurement of Share-based Payment Transactions (effective date 1 January 2018).
The Group is yet to assess the full impact of these new amendments and annual improvements but does not expect them to have a material impact on the financial statements.
-- Amendments to IAS 12: Recognition of Deferred Tax Assets for Unrealised Losses (effective date 1 January 2017);
-- Amendments to IAS 7: Disclosure Initiative (effective date 1 January 2017).
These amendments were adopted by the Group in the year, and do not have a material impact on its financial statements.
1.3 Consolidation
(a) Subsidiaries
The consolidated financial statements include the financial statements of the Company and its subsidiaries. Subsidiaries are entities controlled by the Group. The Group controls an entity when it is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. In assessing control, the Group takes into consideration potential voting rights that are currently exercisable. The acquisition date is the date on which control is transferred to the acquirer. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases. Losses applicable to the non-controlling interests in a subsidiary are allocated to the non-controlling interests even if doing so causes the non-controlling interests to have a deficit balance.
Investments in subsidiaries are accounted for at cost less impairment. Cost is adjusted to reflect changes in consideration arising from contingent consideration amendments. Cost also includes direct attributable costs of investment.
Inter-company transactions, balances and unrealised gains on transactions between Group companies are eliminated; unrealised losses are also eliminated unless the cost cannot be recovered.
The Company and its subsidiaries outside the Russian Federation maintain their financial statements in accordance with IFRSs as adopted by the EU. The Russian subsidiaries of the Group maintain their statutory accounting records in accordance with the Regulations on Accounting and Reporting of the Russian Federation. The consolidated financial statements are based on these statutory accounting records, appropriately adjusted and reclassified for fair presentation in accordance with International Financial Reporting Standards as adopted by the EU.
A list of the Company's subsidiaries is provided in Note 21.
1.4 Segment reporting
Segmental reporting follows the Group's internal reporting structure.
Operating segments are defined as components of the Group where separate financial information is available and reported regularly to the chief operating decision maker ("CODM"), which is determined to be the Board of Directors of the Company. The Board of Directors decides how to allocate resources and assesses operational and financial performance using the information provided.
The CODM receives monthly IFRS based financial information for the Group and its development and production entities. There were two development and production entities during both 2016 and 2017. These entities both engage in upstream production, gathering and sale of hydrocarbons, with common operational management and control. Management has determined that the operations of these production and development entities are sufficiently homogenous (all are concerned with upstream oil and gas development and production activities) for these to be aggregated for the purpose of IFRS 8, "Operating Segments". Common economic drivers for the operations are international oil prices, export and Mineral Extraction Taxes and the costs of drilling, completing and operating wells and production facilities. The Group has other entities that engage as either head office or in a corporate capacity or as holding companies. Management has concluded that due to application of the aggregation criteria that separate financial information for segments is not required.
No geographic segmental information is presented as all of the companies operating activities are based within a localised area of the Russian Federation.
Management has determined therefore that the operations of the Group comprise one class of business, being oil and gas exploration, development and production and the Group operates in only one geographic area - the Volga region of the Russian Federation.
The Group's gas sales, representing a substantial proportion of revenues are made to a single customer. Details are provided in Note 3.1 (b).
1.5 Foreign currency translation
(a) Functional and presentation currency
Items included in the financial statements of each of the Group's entities are measured using the currency of the primary economic environment in which the entity operates ("the functional currency"). The consolidated financial statements are presented in US Dollars, which is the Company's functional and the Group's presentation currency.
The functional currency of the Group's subsidiaries that are incorporated in the Russian Federation is the Russian Rouble ("RUR"). It is the Management's view that the RUR best reflects the financial results of its Cyprus subsidiaries because they are dependent on entities based in Russia that operate in an RUR environment in order to recover their investments. As a result, the functional currency of the subsidiaries continues to be the RUR.
(b) Transactions and balances
Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the income statement.
Foreign exchange gains and losses that relate to cash and cash equivalents, borrowings and other foreign exchange gains and losses are presented in the income statement within "Other gains and losses".
(c) Group companies
The results and financial position of all the Group entities (none of which has the currency of a hyper-inflationary economy) that have a functional currency different from the presentation currency are translated into the presentation currency as follows:
(i) assets and liabilities for each balance sheet item presented are translated at the closing rate at the date of that balance sheet;
(ii) income and expenses for each income statement are translated at average exchange rates (unless this average is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the rate on the dates of the transactions); and
(iii) all resulting exchange differences are recognised in other comprehensive income.
The major exchange rates used for the revaluation of the closing balance sheet at 31 December 2017 were:
-- GBP 1.3485: US$ (2016: 1.233) -- EUR 1.1956: US$ (2016: 1.052) -- US$ 1:57.6002 RUR. (2016: 60.657)
1.6 Oil and gas assets
The Company and its subsidiaries apply the successful efforts method of accounting for Exploration and Evaluation ("E&E") costs, in accordance with IFRS 6 "Exploration for and Evaluation of Mineral Resources". Costs are accumulated on a field-by-field basis.
Capital expenditure is recognised as property, plant and equipment or intangible assets in the financial statements according to the nature of the expenditure and the stage of development of the associated field, i.e. exploration, development, production.
(a) Exploration and evaluation assets
Costs directly associated with an exploration well, including certain geological and geophysical costs, and exploration and property leasehold acquisition costs, are capitalised as intangible assets until the determination of reserves is evaluated. If it is determined that a commercial discovery has not been achieved, these costs are charged to expense after the conclusion of appraisal activities. Exploration costs such as geological and geophysical that are not directly related to an exploration well are expensed as incurred.
Once commercial reserves are found, exploration and evaluation assets are tested for impairment and transferred to development assets. No depreciation or amortisation is charged during the exploration and evaluation phase.
(b) Development assets
Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells into commercially proven reserves, is capitalised within property, plant and equipment. When development is completed on a specific field, it is transferred to producing assets as part of property, plant and equipment. No depreciation or amortisation is charged during the development phase.
(c) Oil and gas production assets
Production assets are accumulated generally on a field by field basis and represent the cost of developing the commercial reserves discovered and bringing them into production together with E&E expenditures incurred in finding commercial reserves and transferred from the intangible E&E assets as described above.
The cost of production assets also includes the cost of acquisitions and purchases of such assets, directly attributable overheads, finance costs capitalised and the cost of recognising provisions for future restoration and decommissioning.
Where major and identifiable parts of the production assets have different useful lives, they are accounted for as separate items of property, plant and equipment. Costs of minor repairs and maintenance are expensed as incurred.
(d) Depreciation/amortisation
Oil and gas properties are depreciated or amortised using the unit-of-production method. Unit-of-production rates are based on proved reserves, which are oil, gas and other mineral reserves estimated to be recovered from existing facilities using current operating methods. Oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the field storage tank.
(e) Impairment - exploration and evaluation assets
Exploration and evaluation assets are tested for impairment prior to reclassification to development tangible assets, or whenever facts and circumstances indicate that an impairment condition may exist. An impairment loss is recognised for the amount by which the exploration and evaluation assets' carrying amount exceeds their recoverable amount. The recoverable amount is the higher of the exploration and evaluation assets' fair value less costs to sell and their value in use. For the purposes of assessing impairment, the exploration and evaluation assets subject to testing are grouped with existing cash-generating units of production fields that are located in the same geographical region.
(f) Impairment - proved oil and gas production properties
Proven oil and gas properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset's carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset's fair value less costs to sell and value in use. The cash generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped together where the cash flows of each field are interdependent, for instance where surface infrastructure is used by one or more field in order to process production for sale.
(g) Decommissioning
Provision is made for the cost of decommissioning assets at the time when the obligation to decommission arises. Such provision represents the estimated discounted liability (the discount rate used currently being at 10% per annum) for costs which are expected to be incurred in removing production facilities and site restoration at the end of the producing life of each field. A corresponding item of property, plant and equipment is also created at an amount equal to the provision. This is subsequently depreciated as part of the capital costs of the production facilities. Any change in the present value of the estimated expenditure attributable to changes in the estimates of the cash flow or the current estimate of the discount rate used are reflected as an adjustment to the provision and the property, plant and equipment. The unwinding of the discount is recognised as a finance cost.
1.7 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:
Machinery and equipment 6-10 years Office equipment in excess of US$5,000 3-4 years Vehicles and other 2-7 years
Depreciation methods, useful lives and residual values are reviewed at each balance sheet date.
1.8 Financial assets
The Group classifies its financial assets in the following categories:
(a) Financial assets at fair value through profit or loss
Financial assets at fair value through profit or loss are financial assets held for trading. This category comprises derivatives unless they are effective hedging instruments. The Group had no financial assets in this class as at 31 December 2016 or 31 December 2015.
(b) Loans and receivables
Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. This category comprises trade and other receivables, term bank deposits and cash and cash equivalents in balance sheet.
1.9 Inventories
Crude oil inventories are stated at the lower of cost of production and net realisable value. Materials and supplies inventories are recorded at average cost and are carried at amounts which do not exceed the expected recoverable amount from use in the normal course of business. Cost comprises direct materials and, where applicable, direct labour plus attributable overheads based on a normal level of activity and other costs associated in bringing inventories to their present location and condition.
1.10 Trade and other receivables
Trade and other receivables are recorded initially at fair value and subsequently measured at amortised cost using the effective interest method, less provision for impairment. A provision for impairment of trade receivables is established when there is objective evidence that the Group will not be able to collect all amounts due according to the original terms of the receivables. The amount of the provision is the difference between the asset's carrying amount and the present value of estimated future cash flows, discounted at the original effective interest rate.
1.11 Cash and cash equivalents
Cash and cash equivalents include cash in hand, and deposits held at call with banks.
1.12 Share capital
Ordinary shares are classified as equity.
Incremental costs directly attributable to the issue of new shares or options are shown in equity as a deduction, net of tax, from the proceeds.
1.13 Trade payables
Trade payables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method.
1.14 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.
1.15 Employee benefits
(a) Share-based compensation
The fair value of the employee services received in exchange for the grant of the options is recognised as an expense. The total amount to be expensed over the vesting period is determined by reference to the fair value of the options granted, excluding the impact of any non-market vesting conditions (for example, profitability and sales growth targets). Non-market vesting conditions are included in assumptions about the number of options that are expected to vest. The option plan currently in place for certain of the directors is an equity settled share option plan.
The Company measures the equity instruments granted to employees at the fair value at grant date. The fair value of fully-vested shares is expensed immediately. The fair value of shares with vesting requirements is estimated using the Black-Scholes option pricing model. This value is recognised as an expense over the vesting period on a straight-line basis. The estimate is revised, as necessary, if subsequent information indicates that the number of equity instruments expected to vest differs from previous estimates.
(b) Social obligations
Wages, salaries, contributions to the Russian Federation state pension and social insurance funds, paid annual leave, sick leave and bonuses are accrued in the year in which the associated services are rendered by the employees of the Group.
1.16 Revenue recognition
Revenue comprises the fair value of the consideration received or receivable for the sale of oil and gas in the ordinary course of the Group's activities. Revenue is shown net of value added tax, returns, rebates and discounts and after eliminating sales within the Group. Revenue from the sale of oil or gas is recognised when the oil/gas is delivered to customers and title has transferred. In 2016 and 2017 , the Group's revenue related to sales of crude oil and condensate collected directly by or delivered to customers and gas sales made at the entry to the gas distribution system.
1.17 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.
1.18 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 2017, 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$220,000 (2016: US$476,000) higher/lower, mainly as a result of foreign exchange gains/losses on translation of RUR denominated trade payables and financial assets. At 31 December 2017, 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$600 (2016: US$1,000) higher/lower, mainly as a result of foreign exchange gains/losses on translation of EUR denominated interest charges and financial liabilities. At 31 December 2017, 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$6,000 (2016: US$7,000) higher/lower, mainly as a result of foreign exchange gains/losses on translation of GBP denominated trade payables and financial assets.
If the US Dollar had weakened/strengthened by 5% against the RUR with all other variables held constant, shareholders equity would have been US$3.3 million (2015: US$2.9 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.
(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$1.5 million higher or lower (2016: $2.7 million).
(iii) Cash flow and fair value interest rate risk
As the Group currently has no significant interest-bearing assets and liabilities, the Group's income and operating cash flows are substantially independent of changes in market interest rates.
(b) Credit risk
The Group's maximum credit risk exposure is the fair value of each class of assets, presented in note 3.1(a)(i) of US$8,617,000 and US$ US$19,718,000 at 31 December 2017 and 2016 respectively.
The Group's principal financial asset is cash and credit risk arises from cash and cash equivalents and deposits with banks and financial institutions. It is the Group's policy to monitor the financial standing of these assets on an ongoing basis. Bank balances are held with reputable and established financial institutions.
The Group's oil and condensate sales are normally undertaken on a prepaid basis and accordingly the Group has no trade receivables and consequently no credit risk associated with the related trade receivables. Gas sales accounting for 35.4% of Group revenues in 2017 (2016: 35.6%) were made to Gazprom (2016: to Trans Nafta). As at 31 December 2017 there were trade receivables of US$1.3 million (31 December 2016: US$2.0 million) relating to gas sales. As at 31 December 2017 there was no provision for bad debts (2016: nil).
(c) Liquidity risk
Cash flow forecasting is performed by Group finance. Group finance monitors rolling forecasts of the Group's liquidity requirements to ensure it has sufficient cash to meet operational needs. The Group believes it has sufficient liquidity headroom to fund its currently planned exploration and development activities.
The Group expects to fund its capital investments, as well as its administrative and operating expenses, through 2016 using a combination of cash generated from its oil and gas production activities, existing working capital and, when appropriate, medium-term bank borrowings. If the Group is unsuccessful in generating enough liquidity to fund its expenditures, the Group's ability to execute its long-term growth strategy could be significantly affected. The Group may need to raise additional equity or debt finance as appropriate to fund investments beyond its current commitments.
(d) Capital risk 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, benefits from an interest rate subsidy provided by the regional Government. Further short-term debt facilities may be arranged to provide financial headroom for future development activities.
2.2 Fair value estimation
The Group has no financial assets and liabilities that are required to be measured at fair value.
3. Critical accounting estimates and judgements
The Group makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below.
a) Carrying value of fixed assets, intangible assets and impairment
Fixed assets and intangible assets are assessed for impairment when events and circumstances indicate that an impairment condition may exist. The carrying value of fixed assets and intangible assets are evaluated by reference to their value in use and primarily looks to the present value of management's best estimate of the cash flows expected to be generated from the asset. In identifying cash flows management firstly determine the cash generating unit or group of assets that give rise to the cash flows. The cash generating unit ("CGU") is the lowest level of asset at which independent cash flows can be generated. For this purpose the directors consider the Group to have two CGUs: the VM and Dobrinskoye fields with the Dobrinskoye gas processing plant are treated as a single CGU, and the Uzen oil field is a separate CGU.
The estimation of forecast cash flows involves the application of a number of significant judgements and estimates to a number of variables including production volumes, commodity prices, operating costs, capital investment, hydrocarbon reserves estimates and discount rates. Key assumptions and estimates in the impairment models relate to:
-- International oil prices: flat real prices reflecting the actual levels pertaining at 31 December 2017 - Urals oil price of US$65 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 current applicable official rates and a price differential of $5 per barrel to reflect transportation costs. Based on commercial studies conducted during 2016 and 2017, LPG is expected to achieve a premium per tonne over condensate whereas the models assume price parity.
-- Gas sales price of RUR 4,025 per mcm excluding VAT.
-- Production profiles based on remaining reserves in the Proved category and approved field development plans. For the purposes of impairment testing, the level of reserves used those recently provided to the Group by the independent consultancy Geostream.
-- While it has been included in the production profile, the LPG production has not yet been established although it is expected to commence in April 2018.
-- Capital expenditures required to deliver the above production profiles and to maintain the production assets throughout the field life. Total development capital expenditure assumed is US$5 million with future maintenance capital expenditure of up to US$2 million per annum. The principal items being the completion of the LPG plant and sidetracks to two gas/condensate wells.
-- Cost assumptions are based on current experience and expectations and are broadly in line with unit costs experienced in the year ended 31 December 2017, including an annual estimated cost saving of US$4.0 million from the successful implementation of Redox-based gas sweetening.
-- Export and mineral extraction taxes reflect rates set by current legislation.
-- The model reflects real terms cash flows with no inflationary escalation of revenues or costs.
-- A real discount rate of 12% per annum is utilised in the models. -- An exchange rate of RUR57 to US$1.00 is assumed.
Under the base case assumptions, the value in use of each CGU was shown to be in excess of its respective carrying value.
In addition to the base case a number of sensitivity cases have been carried out: varying oil and gas prices by 10%, varying operating expenditure by 10%, varying capital expenditure by 20%, varying reserves by 10% and using a 15% real discount rate. In aggregate the sensitivities yielded net present values in excess of carrying values for the CGUs, in all of these cases, the net present value under the sensitivities remained above the carrying value of individual CGUs.
Under the base case economic assumptions as outlined above, the reserves at the VM and Dobrinskoye fields would need to drop by a further 26% below the level as at 31 December 2017, and the Uzen oil field reserves would need to drop by 19% below current levels for the value in use to reach the respective carrying value.
A further sensitivity in which LPG was excluded from the production profile brought the Value in Use down to approximately US$1.5 million, or 2.9% below the level of the carrying value of the VM and Dobrinskoye CGU under the base case assumptions and up to US$8.6 million or 16.6% below the carrying value under the various sensitivity cases outlined above. However, the impairment testing model is based on the existing and approved plans and forecasts in which LPG is one of the drivers of future cash flows. Presently the LPG project is commencing the commissioning process and there is no indication that it will not be operating as expected, though the various sensitivities affecting LPG streams were considered.
Accordingly as at 31 December 2017, based on the Group's impairment testing of the property, plant and equipment related to each CGU management concluded that no clear impairment was indicated. However, should there be material adverse changes to the assumptions used in future impairment tests, or should there be further reductions in reserve estimates, there may be impairment of one of both of the CGU's.
(b) Estimation of oil and gas reserves
Estimates of oil and gas reserves are inherently subjective and subject to periodic revision. In addition, the results of drilling and other exploration or development or production activity will often provide additional information regarding the Group's reserve base that may result in increases or decreases to reserve volumes. Such revisions to reserves can be significant and are not predictable with any degree of certainty. Management considers the estimation of reserves to represent a significant judgement in the context of the financial statements as reserve volumes are used as the basis for assessing the useful life of oil and gas assets, applying depreciation to oil and gas assets and in assessing the carrying value of oil and gas assets. Decreases in reserve estimates can lead to significant impairment of oil and gas assets where revisions (positive or negative) can have a significant effect on depreciation rates from period to period. Variation of 10% from the base level of reserves is among the sensitivity tests carried out in impairment testing as described in Note 4(a) above.
An independent assessment of the reserves and net present value of future net revenues ("NPV") attributable to the Group's fields, Dobrinskoye, Vostochny Makarovskoye, Sobolevskoye and Uzenskoye, as at 31 December 2016, was prepared in accordance with reserve definitions set by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers ("SPE"). In February 2018, the Group commissioned an update to this report as, late in 2017, the presence of increased formation water was observed during gas production from certain of the production wells on the VM field. The results delivered to management imply a negative revision to reserves of approximately 27% below the level of reserves as at 31 December 2016 as adjusted for production during 2017. The catalyst for this revision was a re-calculation of recovery factors following the recent detection of the presence of formation water in certain of the wells in the VM field. Management considers these revised estimates to be reasonable and is adopting them as the Group's reserves. As outlined above, management considers that for the time being, no clear impairment is indicated, although further downward revisions may necessitate impairment charges in the future.
4. Revenue
Year ended 31 December 2017 2016
US$ 000 US$ 000
Oil 8,075 7,523
Condensate 15,877 17,857
Gas 13,114 14,032
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Total revenues 37,066 39,412
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5. Cost of sales and administrative expenses - Group
Cost of sales and administrative expenses are as follows:
Year ended 31 December 2017 2016
US$ 000 US$ 000
Production expenses 9,320 10,968
Mineral extraction taxes 10,936 10,255
Depletion, depreciation and amortisation 8,580 5,037
----------------------- --------------------
Cost of Sales 28,836 26,260
======================= ====================
Total expenses are analysed as follows:
Year ended 31 December 2017 2016
US$ 000 US$ 000
Sales related expenses (a) 2,221 4,052
Field operating expenses (b) 6,379 9,367
Mineral extraction tax 10,936 10,255
Depreciation & amortization 8,613 5,059
Exploration & evaluation - 265
Write off of development assets 65 1,798
Inventory write off (c) 191 529
Salaries & staff benefits 6,103 3,177
Directors' emoluments and other benefits 698 645
Audit fees 293 314
Taxes other than payroll and mineral
extraction 47 38
Legal & consulting 551 291
Other 856 1,110
----------------------- --------------------
Total 36,953 36,900
======================= ====================
(a) Selling expense: comprise pipeline transit costs and fees related to gas sales as well as export taxes and costs associated with delivering gas condensate sales to export customers.
(b) Field operating expenses: In the year ended 31 December 2017, a provision for the cost of waste removal was reversed, leading to a credit of US$1,009,000 partly offset by other accrued expenses resulting in a net non-cash operating gain of US$646,000 (2016: nil). This amounts shown as field operating expenses above are net of this sum.
(c) Inventory write-off: In the years ended 31 December 2017 and 31 December 2016, certain obsolete and unused items of production equipment were transferred from producing assets to inventory and then written off.
6. Other gains and losses - Group
Year ended 31 December 2017 2016
US$ 000 US$ 000
-------- --------
Foreign exchange loss) (586) ( 892)
Gain from settlement of legal dispute 300 -
Other gains 144 129
-------- --------
Total other gains and losses (142) ( 763)
======== ========
7. Intangible assets
Intangible assets represent exploration and evaluation assets such as licences, studies and exploratory drilling, which are stated at historical cost, less any impairment charges or write-offs.
Work in progress: Exploration Total
exploration and
and evaluation evaluation
At 1 January 2017 140 3,320 3,460
Additions - 112 112
Write offs and impairments - (1) (1)
At 31 December 2017 140 3,431 3,571
Exchange adjustments 7 178 185
------------------ ------------- -------------
At 31 December 2017 147 3,609 3,756
================== ============= =============
Work in progress: Exploration Total
exploration and
and evaluation evaluation
At 1 January 2016 117 2,750 2,867
Additions - 254 254
Write offs and impairments - (240) (240)
At 31 December 2016 117 2,764 2,881
Exchange adjustments 23 556 579
------------------ ------------- -------------
At 31 December 2016 140 3,320 3,460
================== ============= =============
8. Property, plant and equipment
Movements in property, plant and equipment, for the year ended 31 December 2016 are as follows:
Cost Development Land & Producing Other Total
assets buildings assets
US$ 000 US$ 000 US$ 000 US$ 000 US$ 000
At 1 January 2017 3,559 780 68,179 598 73,116
Additions 12,332 - - - 12,332
Transfers (9,375) 6 9,175 194 -
Write-offs and impairments (257) (8) (91) (78) (434)
Exchange adjustments 224 42 3,730 33 4,029
------------ ----------- ---------- -------- ---------
At 31 December 2017 6,483 820 80,993 747 89,043
Accumulated depreciation
At 1 January 2017 - - (16,619) (589) (17,208)
Adjustment for assets
written off - - 83 78 161
Depreciation - (41) (8,413) (194) (8,648)
Exchange adjustments - (1) (985) (33) (1,019)
------------ ----------- ---------- -------- ---------
At 31 December 2017 - (42) (25,934) (738) (26,714)
------------ ----------- ---------- -------- ---------
Net Book Value
At 31 December 2017 6,483 778 55,059 9 62,329
============ =========== ========== ======== =========
Movements in property, plant and equipment, for the year ended 31 December 2016 are as follows:
Cost Development Land Producing Other Total
assets & buildings assets
US$ 000 US$ 000 US$ 000 US$ 000 US$ 000
At 1 January 2016 1,137 650 55,879 498 58,164
Additions 2,341 - 1,564 - 3,905
Write-offs and impairments (57) - (917) - (974)
Transfers (294) - 294 - -
Exchange adjustments 432 130 11,359 100 12,021
-------------------- --------------- ------------- ------------- ------------
At 31 December 2016 3,559 780 68,179 598 73,116
Accumulated depreciation
At 1 January 2016 - - (9,399) (475) (9,874)
Adjustment for assets
written off - - 195 15 210
Depreciation - - (5,028) (32) (5,060)
Exchange adjustments - - (2,387) (97) (2,484)
-------------------- --------------- ------------- ------------- ------------
At 31 December 2016 - - (16,619) (589) (17,208)
-------------------- --------------- ------------- ------------- ------------
Net book value
At 31 December 2016 3,559 780 51,560 9 55,908
==================== =============== ============= ============= ============
9. Cash and cash equivalents - Group and Company
An analysis of Group cash and cash equivalents by bank and currency is presented in the table below:
At 31 December 2017 2016
--------------- --------------
Bank Currency US$ 000 US$ 000
United Kingdom
Barclays Bank PLC USD 665 3,479
Barclays Bank PLC GBP 97 148
Russian Federation
Unicreditbank RUR - 82
Unicreditbank USD - 131
ZAO Raiffeisenbank RUR 4,337 6,628
ZAO Raiffeisenbank USD 3,513 9,200
ZAO Raiffeisenbank EUR - 13
Other banks and cash
on hand RUR 5 37
Total cash and cash equivalents 8,617 19,718
=============== ==============
10. Inventories
At 31 December 2017 2016
US$ 000 US$ 000
Production consumables and
spare parts 787 796
Crude oil inventory 441 185
-------- ------------
Total inventories 1,228 981
======== ============
11. Other receivables
At 31 December 2017 2016
US$ 000 US$ 000
VAT receivable 300 154
Prepayments 278 725
Trade receivables 1,260 2,067
Other accounts receivable 691 61
------------- --------------
Total other receivables 2,529 3,007
============= ==============
Prepayments are to contractors and relate to initial advances made in respect of drilling, construction and other projects. Trade receivables relate to sales of gas and condensate. The receivables were settled on schedule subsequent to the balance sheet date.
12. Trade and other payables
At 31 December 2017 2016
US$ 000 US$ 000
-------- --------
Trade payables 1,571 4,738
Taxes other than profit
tax 2,366 2,266
Customer advances 2,597 2,836
Other payables 284 123
-------- --------
Total 6,818 9,963
======== ========
The maturity of the Group's and the Company's financial liabilities are all between zero to three months. Customer advances are prepayments for oil and condensate sales, normally one month in advance of delivery.
13. Bank loan
At 31 December 2017 2016
US$ 000 US$ 000
Non-current liabilities
Secured bank-loan - 3,802
Current liabilities
Current portion of secured
bank loan 4,004 158
-------- --------
Total Bank Loan 4,004 3,960
======== ========
In December 2016, one of the Group's operating subsidiaries received bank loan in total amount of RUR 240 million (US$3.96 million), which was utilised to fund purchases of equipment for the LPG project and should be fully repaid by 2019 (repayments are scheduled as follows - in 2018: US$2.0 million; 2019: US$2.0 million). As at 31 December 2017, there was a technical breach of certain loan covenants. Management expects to receive a waiver of this breach from the lender, but pending receipt of this waiver, the entire loan is classified as current. Interest is charged at a fixed rate of 11.45% per annum. The Bank loan as at 31 December 2016 has been secured by charges over the shares of the Group's Russian operating subsidiaries as detailed in Note 21 below.
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR FKNDBNBKKQQD
(END) Dow Jones Newswires
April 13, 2018 02:18 ET (06:18 GMT)
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