Ruspetro Regulatory News (RPO)

Ruspetro plc

16 April 2015

Ruspetro plc ("Ruspetro" or the "Company")

Preliminary Unaudited Results for the Year Ended 31 December 2014

London, 16 April 2015: Ruspetro plc (LSE: RPO), an independent oil and gas development and production company with assets in the Western Siberia region of the Russian Federation, announces today its results for the full year ended 31 December 2014, and an update on its operations to date.

Financial Highlights

ü Revenues of US$55.1m (down 31% Y-o-Y) due primarily to a 26% decline in liquids production, and a 9% decline in the realized oil price Y-o-Y.

ü Full year EBITDA (1) of US$9.5m vs. US$13.0m in 2013, driven mostly by the decline in production, and oil price, partially offset by Mineral Extraction Tax ("MET") relief from September 2013. EBITDA per barrel of liquids was US$7.4 in both 2013 and 2014.

ü Strengthened our partnership with Glencore by extending our export prepayment facility in March 2014 and entering into two domestic facilities in May 2014 and October 2014.

ü Net loss of US$262.9m vs. net loss of US$74.2m in 2013, driven mostly by the foreign exchange loss on US dollar denominated loans to the Group's Russian subsidiaries (US$202.4m). After eliminating the effect of foreign exchange losses from both years, 2014 loss was US$60.5m against US$48.6m in 2013. Secured a US$100.0m development facility and US$44.7m working capital facility from Otkritie to fund a refocused appraisal and development programme.

ü Net debt decreased by US$152.3m from US$387.4m at the beginning of the year to US$235.1m end 2014.

Operational Highlights

ü Oil production in 2014 averaged 3,523 bopd, a 14% decrease compared to 2013. In January 2014, suspended production of gas and condensate in the Palyanovo field primarily to conserve gas while we engage in discussions to commercialise these gas reserves.

ü The production performance of the Group's first two horizontal wells was encouraging (ten day flow tests averaged 1,350 and 900 bopd for wells 214 and 251, respectively)

o Spudded our first multiple fractured horizontal well (214) (MFHW) in April 2014.

o in our second well (251), introduced for the first time in Russia innovative completion technology customized to our geological environment.

ü Successful focus on safety in our operations including implementation of the EMEX system to manage HSE performance. One minor lost time injury in 2014.

ü Extended the subsoil license for the Vostochno-Inginsky block until 2034.

Post Period End

Since the end of 2014, two MFHW (wells 212 and 216) have been drilled. Both encountered extensive sands (642m net oil sand within a horizontal section of 1149m in well 212, and 516m net oil sand within a horizontal section of 961m in well 216). These will be completed using our flexible fracturing system which allows us to optimise the location and size of the hydraulic fractures to the sand distribution encountered in the well. These two wells will come on stream in April/May 2015, respectively.

John Conlin, Chief Executive Officer, commented:

"Despite the challenging business environment 2014 has been a year of important progress for Ruspetro. We have successfully introduced a new approach to fracturing our new generation horizontal wells. We have also introduced other key technologies to extract maximum insight into the subsurface, and hence de-risk our development programme in the future. Towards the end of the year we transformed our balance sheet and put in place a credit facility to fund our development activities. Given the current low and volatile oil price environment, this will be used cautiously to fund a modest appraisal and development programme in 2015, as the springboard for an accelerated push in the medium term."

Enquiries:

Ruspetro plc

John Conlin, Chief Executive Officer +44 (0) 2078 877624

Alexander Betsky, Finance Director +44 (0) 2078 877624

Finlay Thomson, Investor Relations +44 (0) 7976 248471

FTI Consulting

Ben Brewerton, George Parker +44 (0) 2037 271000

About Ruspetro

Ruspetro plc is an independent oil & gas development and production company, listed on the premium segment of the London Stock Exchange (LSE: RPO). The Company's operations are located on three contiguous licence blocks in the middle of the Krasnoleninsk Arch in Western Siberia. Ruspetro assets include proved and probable (2P) reserves of over 2.0 bnboe.

Glossary

 bopd - barrels of oil per day

Chairman's Statement

In 2014, for a small exploration and production company operating with a technically challenging portfolio, the business environment in Russia could hardly have been more difficult.

In the middle of the year, ambiguity about the impact of sanctions on the business forced Ruspetro into both clarifications and contingency arrangements to ensure that operations were not hampered. In due course, that uncertainty was clarified and our technology has been cleared for use.

Thereafter, what started as a modest decline in the oil price to below US$100 per barrel in the third quarter became a headlong plunge, coupled with a slump in the value of the ruble. While some stability has emerged in recent months in both the oil price and ruble/dollar exchange rate, the credibility of forecasters has gone, and we expect to live with both volatility and uncertainty for the medium term.

This macro-economic business context makes the transformational restructuring transaction that we competed in December all the more remarkable. Our liabilities (including debt and put option obligations) were reduced by US$218.8 million, while we raised US$52.3 million of new equity, and arranged loan facilities of up to US$144.7 million, in aggregate, for development and working capital.

More important perhaps than the numbers is the relationship now established between Ruspetro and Bank Otkritie Financial Corporation ("Otkritie"), currently the largest private bank in Russia by assets. Otkritie and Sergey Gordeev are now our main lender and largest shareholder, respectively, and we are delighted that Sergey has joined our Board.

Successfully raising substantial development funds is a major milestone for the Company, and while the fall in oil prices impacted our revenues, the weakening of the ruble has driven down our dollar cost base such that we can drill economically attractive production wells at current oil prices. Nevertheless, given the extended period of low and volatile oil prices, the Board has decided that a cautious capital expenditure programme and a cautious use of loan facilities in 2015 is in the best interests of the Company, and that the capital invested should focus on maturing development opportunities for the medium term. This philosophy is outlined below in the CEO's review.

It remains unclear how the oil and gas industry in Russia will respond in the medium term. A material reduction in activity seems unlikely given the dollar-equivalent cost reduction that all operators will experience. However, we can expect some opportunities to drive costs down further as service providers manage cash flow.

Our focus is on positioning Ruspetro for the medium term: understanding our reservoirs, managing risk, applying the right mix of technologies, enhancing our reputation as an innovative company and creating value from every well that we drill. In the medium term, this is expected to build substantial shareholder value.

When 2014 started, there was a strong sense of optimism in Russia, particularly given the Winter Olympics in February. The dramatic events since, including ruble devaluation and unexpected crash in oil prices, have caused anxiety, and their consequences remain to be seen. However, within Ruspetro, we have made substantial progress in the way that we operate and think. We have rebuilt our technical core and our technical credibility. On behalf of the Board, I would like to thank all our staff for their efforts under difficult circumstances and in particular welcome to the team those who have come on board in the last 12 months.

I would also like to thank our new partners for the confidence they have shown in joining the Ruspetro project. We welcome them as shareholders and in particular welcome Sergey Gordeev to the Board. We have a highly experienced team of non-executive directors on the Board and I would like to thank them for their invaluable input and challenge. Lastly, I thank our shareholders for their support as we have navigated our way through difficult macroeconomic conditions affecting the oil industry. The course we have set should position Ruspetro to make significant progress in 2015.

CEO's Review

The working environment in which Ruspetro staff and our contractors operate is particularly challenging. Since joining Ruspetro, it has been one of my top priorities to build upon and enhance our health, safety and environmental ("HSE") awareness and performance.

In 2014, we appointed a HSE director to oversee our HSE practices, improve policies and ensure that we approach HSE issues in the most direct and effective manner. In addition, we successfully implemented the EMEX platform as a tool to log, monitor and action HSE improvements across all operational areas. I am pleased to report only one minor lost-time incident in 2014 relating to a slip and fall. Our aim is to continue our positive HSE momentum in the coming year.

Achievements in 2014

In April 2014, we introduced multiple fractured horizontal wells into our operations. Initially this was rather simplistically conceived as a way of connecting the discontinuous sands that, with hindsight, had contributed to the poor outcome of the vertical well development programme in 2012-13.

However, by the second well, we had introduced a radical change in fraccing and completion thinking, abandoning the standard Western Siberian approach of a small number of large fracs, and moving to a concept based on a larger number of smaller fracs tuned to the sand distribution seen in the well. This required us to source technology proven in North America but hitherto unused in Russia.

Similarly, we have introduced a number of other internationally established technologies to ensure that we maximise the insight from these early wells. These include geo-steering in the horizontal sections to assess sand continuity, and the use of tracers to assess the effectiveness of the fracs in each well. This knowledge has been embodied in the design of the wells that are to be drilled and completed by the second quarter of 2015.

While I am impressed by the progress that we have made with our first two horizontal wells and the follow-up in early 2015, the reality is that we are still developing our understanding of the geology and in particular the possible play types in our acreage. Our efforts at geological characterisation in the last year have been hampered by a chronic geological data shortage resulting from missed data collection opportunities in the first frantic development campaign in 2012-13. Furthermore, we are only just beginning to capitalise on the seismic contribution to unlocking our reserves. The bottom line is that that we have an immature resource base outside the core area.

Given this blunt assessment, the Board has endorsed a strategy starting in the second half of 2015 of an appraisal campaign designed to mature between 25 and 75 development wells. This programme, which includes both vertical and horizontal wells, will underpin a resumption of our development well campaign in 2016, when we believe oil prices may have partly rebounded.

This strategy will have two key additional benefits:

· With an inventory of de-risked development wells, we will be able to plan and deliver a sustainable improvement in drilling and completion performance by driving learning, leveraging the market for services, and improving our operating practices.

· It will provide a sound basis for the generation of a coherent facilities plan based on a more realistic view of our future production levels and precisely where in our acreage they are being generated.

Palyanovo

In January 2014, we suspended production of gas and condensate in the Palyanovo field, primarily to conserve gas while we evaluated further options to commercialise the gas reserves. Discussions are progressing with an international counterparty in this regard. In the meantime, we are taking the opportunity of the suspension of production to collect key sub-surface data with a view to updating the gas field development plan in 2015. During 2015, we will also update our Russian reserves for the Palyanovo licence ahead of its planned renewal by the year-end.

Aims for 2015

Our objectives for 2015 are to:

· Increase oil production by squeezing our existing stock of oil production wells and improving water-flood effectiveness in the core Pottymsko Inginsky ("PI") area.

· Complete our horizontal development well rollout in the area of pad 23b.

· Initiate an appraisal campaign to build an inventory of mature development locations. Four areas are currently targeted in this campaign.

· Mature our development toolkit (technology, design, cost, execution). For example: the application of geosteering, seismic visualisation, novel well designs, optimised completion technology, rig strategies, etc.

· Implement fit-for-purpose infrastructure enhancements to support the programme.

· Radically improve our understanding of the gas reserves and production potential of Palyanovo.

Costs and cash management

The restructuring transaction, while transformational for the longer term, was highly complex and inevitably time-consuming. Nevertheless, we were able to make a start with our horizontal well programme, using oil pre-payment facilities and an additional loan from Limolines Transport Limited ("Limolines"), one of our main shareholders.

These early wells represent the evolution of our development thinking and technology application. Perhaps as importantly, they have driven a fundamental rebuild in our drilling services contracting strategy and allowed us to deliver a highly competitive benchmark well cost for the future.

Despite the availability of new funds, a lower oil price is our reality. We will continue with a highly disciplined approach to managing our cash. As we have successfully done with our drilling costs, we will continue our drive to reduce to the greatest extent possible dollar-denominated services, and perhaps capitalise on the assumed slowdown in Russia to look for keen bids for any new capital expenditure.

Operational Review

Production

The Group's total liquid production in 2014 averaged 3,541 boepd, down 26% from the 4,797 boepd in 2013. Average oil production was 3,523 boepd, 14% lower than the 4,082 boepd in 2013. Average condensate production from the Group's Palyanovsky licence area declined from 1,352 boepd in the first quarter of 2013 to 330 boepd in the fourth quarter, down 75%, leading to the decision to suspend production in February 2014 to conserve gas for future commercialisation. The Group's oil production in the fourth quarter of 2014 averaged 3,580 bopd, down 7% from 3,854 boepd in the third quarter.

In 2014, the Group initiated a horizontal drilling campaign based on multi-stage fractured horizontal production wells. Three horizontal wells were spudded in 2014 as part of this campaign (wells 214, 251 and 212), two of which were successfully completed within 2014 (wells 214 and 251).

The Group began drilling its first horizontal well, number 214, in April. The pilot well encountered 19 metres of oil-bearing sands. Three large fractures were placed in the well's 600-metre horizontal section and the well came online at the beginning of July as planned. The 10-day flow test yielded 1,350 barrels of oil per day (bopd) using an electrical submersible pump. By the end of 2014, the well was producing at 615 bopd, as expected.

The Group's second horizontal well, number 251, was spudded in June and a pilot well was drilled as planned. This well encountered eight metres of net oil sand, which was at the low end of expectations. Two sidetracks were thereafter required to overcome challenging hole conditions prior to entering the horizontal section. In this well, the Group employed, for the first time in Russia, a completion system designed and implemented by NCS Energy Services, an independent technology and services company specialising in multistage completions (NCS Mongoose completion system). The system allows for a larger number of customised fractures to be placed along the horizontal wellbore than the completion technology previously available in the country and used for completion of well 214. It also allows for greater fracturing speed and flexibility than the completion system previously used by the Group, as the process eliminates the need for perforation and the plugging of each section and enables multiple sequential fracture operations. Eight fractures were successfully placed along the 890-metre horizontal section of the wellbore, precisely targeting the reservoir intervals of interest. The planned installation of an electrical submersible pump was completed in October. A 10-day flow test for this well averaged 900 bopd at approximately 25% watercut.

The Group's third horizontal well, number 212, was designed to have a 1,000-metre horizontal section with 12 fractures. It was spudded on 17 December and is expected to be completed in the second quarter of 2015.

The production performance of the Group's first horizontal wells is encouraging. Equally exciting is the introduction of innovative yet proven completion technologies into the Group's operations, which we believe will make a positive contribution to value creation for our shareholders.

Reservoir management and waterflood

As at the end of 2014, the Group had a stock of 34 producing wells and seven injector wells. During the year, a comprehensive review of the response to the waterflood programme was carried out as part of the ongoing reservoir management plan in the producing field. One producing well was converted to a water injection well in the first half of 2014, giving a total of seven active injector wells in the main production area of the field.

Out of 24 producing wells subject to waterflooding, nine producing wells show consistently increasing oil production rates in response to pressure support. A comprehensive tracer campaign has been initiated to assist in further optimisation of the waterflood.

The Group's subsurface team set about expanding and refining the waterflood programme such that crude oil production towards the end of the year stabilised. The waterflood was more compartmentalised than had been originally envisaged, in line with the findings from our 3D-seismic reprocessing.

In 2014, the Group continued to interpret the 3D seismic data that covers 42% of the field. The results showed structural and stratigraphic compartmentalisation in our main area of production. This poses challenges for an effective waterflood programme and demonstrates why production results from vertical wells can vary drastically over quite small distances. These findings add to our knowledge of the field and enable us to be more confident about selecting drilling locations and appropriate well technologies going forward.

Resource potential

DeGolyer & MacNaughton ("D&M") conducted a reserve audit for the Group as at 30 June 2014, based on the horizontal well development programme for the first time. Proved reserves were 258 million barrels of oil equivalent (boe), up 15% from the previous estimate of 225 million boe. Mid-year 2014 proved plus probable reserves were 2.0 billion boe, up 6% from the 2013 year-end estimate of 1.9 billion boe. Of these reserves, natural gas comprises 51 million boe of proved reserves and 201 million boe of proved and probable reserves.

The Group has 5.9 million barrels of proved developed oil and condensate reserves. This compares to 12.7 million barrels as at 31 December 2013. The decrease is primarily attributable to the reclassification of condensate reserves from proved developed to proved undeveloped in the Palyanovo licence area. D&M estimated contingent resources in the Bazhenov oil shale formation at 3.5 billion boe in place.

In line with industry best practices, the Group has decided to change the independent reserves auditor from D&M to another international auditing firm. The selection is expected to be made in the first half of 2015, followed by a full-year report by the end of 2015.

Macro-environment in 2014

From a macro-environment perspective, 2014 proved a challenge in several respects. First, Russia experienced a turbulent year due to the geopolitical crisis in Ukraine, as the economic sanctions targeted against Russia have been imposed on certain individuals, financial institutions, state-controlled companies, technologies and equipment in the financial, defence and energy sectors. Second, the crude oil price, though averaging almost US$100 per barrel in 2014, compared with US$109 in 2013, dropped dramatically in the fourth quarter of 2014. Having peaked in June 2014 at US$115, the Brent crude oil price had dropped to US$57 by the year-end, due to slower growth in major oil-consuming countries, soaring production of hard-to-extract crude oil in the US and Canada, and OPEC's decision to maintain production levels.

At the same time, the difficult macro-environment brought some significant operational benefits through the devaluation of the Russian ruble, functional currency of the Group's operating companies. With oil and gas production generating the majority of hard-currency revenues of Russian companies and the government, the decline in the oil price weakened the ruble exchange rate from 32 to the US dollar on 1 January 2014 to a low of 67 on 16 December 2014. While the ruble/dollar exchange rate averaged 35.4 during the nine months ending 30 September 2014, it plummeted in the fourth quarter, paralleling the slump in the Brent price. The ruble's dramatic fall has cushioned the Group's exposure to the oil price decline, as it is estimated that 90% of its operating expenses, 80% of capital expenditures and 40% of SG&A in 2015 are denominated in rubles. The effect of this devaluation is expected to bring significant savings in 2015 in terms of operating costs, CAPEX and, to a lesser extent, SG&A.

Sales and marketing

The Group's total production in 2014 was some 1.3 million boe, or an average of 3,541 boepd. In 2014, the Group exported 448 thousand boe and sold 854 thousand boe of crude oil and 7 thousand boe of condensate on the domestic market, compared with 261 thousand boe, 1.2 million boe and 258 thousand boe in 2013, respectively. All export volumes were delivered under the Glencore export prepayment facility and 49% of domestic volumes were delivered to Energo Resours, a subsidiary of Glencore, under both domestic prepayment facilities signed in 2014.

In 2014, export sales revenue was US$40.8 million (US$18.8 million after export duty), domestic crude oil revenue was US$35.0 million, and condensate revenue was US$0.3 million. In 2013, export sales revenue was US$27.4 million (US$13.3 million after export duty), domestic crude oil revenue was US$54.0 million, and condensate revenue was US$11.3 million.

Export deliveries were contracted to Glencore via the Transneft pipeline system and freight terminal in Primorsk: 80% of domestic sales volumes were delivered via pipeline (compared with 60% in 2013) and 20% by rail and truck (compared with 40% in 2013).

Financial Review

Financial summary

Revenues were US$55.1 million in 2014, compared with US$79.8 million in 2013, while earnings before interest, tax, depreciation and amortisation ("EBITDA") were US$9.5 million, compared with US$13.0 million. The drop in revenues was primarily driven by a 14% reduction in average oil production, a 9% fall in the average oil price, and the termination of condensate sales.

The drop in EBITDA was primarily driven by the 14% decline in crude oil production, a loss of gross margin from the cessation of condensate sales and a 9% fall in the average oil price. The effect was offset by a substantial saving from reduced MET following changes in tax legislation in relation to tight oil reservoirs available to the Group since September 2013.

Cost of sales

The cost of sales, including depreciation and production-related taxes was US$51.7 million in 2014, compared with US$65.9 million in 2013. The decrease was primarily driven by a US$20 million reduction in MET due to a full year's 80% MET relief benefit conferred to the Group starting September 2013, along with a marginal benefit from the ruble depreciation towards the end of 2014, and savings of US$1 million in production services. These savings, however, were offset by a US$6.2 million increase in depletion expenses in 2014 due to temporary suspension of operations at Palyanovo, along with a US$1.1 million increase in repair and maintenance expenses and employee benefit expenses.

Selling and administrative expenses (S&A)

S&A expenses include oil transportation costs, payroll expenses, rent, professional services, property and land taxes, depreciation, IT and telephony, and other expenses.

S&A expenses in 2014 amounted to US$20.8 million, down 7% from US$22.5 million in 2013. The decrease resulted from savings, mostly in professional services, IT and telephony, travel and depreciation, offset by increases in payroll expenses (including severance) and oil transportation expenses as a result of higher export volumes year-on-year in 2014.

 Comprehensive loss for the year and foreign exchange

The Group recorded a loss of US$262.9 million for 2014, compared with US$74.2 million in 2013. The 2014 result includes a foreign-exchange loss of US$202.4 million, compared with US$25.6 million in the previous year. The Group's operating companies, whose functional currency is the Russian ruble, have borrowings in US dollars. As a result of the ruble devaluation, those borrowings in ruble terms have substantially increased, resulting in the accounting recognition of US$202.4 million in foreign-exchange losses. After deducting the foreign-exchange losses from both years, the Group's loss would have been US$60.5 million in 2014, compared with US$48.6 million in 2013.

Balance sheet

The Group's balance sheet has been transformed due to the completion of the restructuring in December 2014 along with the effects of the ruble depreciation.

The Group's restructuring comprised the following key components:

• A restructuring of the existing US$337.9 million Sberbank credit facility along with a Sberbank capital put option valued at around US$20.2 million. These were together exchanged for a new US$150 million five-year loan from Otkritie, with the conversion of the remaining US$208.1 million by Mastin Holdings Limited ("Mastin"), a company beneficially owned by Sergey Gordeev, into 25% of the Company's enlarged issued equity share capital.

• A five-year development facility of up to US$100 million was entered into with Otkritie for the purposes of financing the Group's field development.

• A five-year credit facility of up to US$44.7 million was entered into with Otkritie for general working capital purposes with drawdown available until the end of June 2016.

• The extension of shareholder loans from Makayla Investments ("Makayla") from 2015 to 2016 and Limolines from 2018 to 2020; US$5.0 million is due to be repaid to Makayla in May 2015.

• A raising of gross proceeds of £32.9 million (around US$52.3 million) from a placing and open offer. This included the offset of a US$10.7 million short-term Limolines loan against Limolines' subscription for the new shares in the placing and open offer.

As a result of the Restructuring alone, the Group's total debt decreased by US$198.6 million, current liabilities decreased by US$20.2 million, total equity increased by US$256.2 million, and total cash on hand increased by US$41.6 million before transaction-related fees. Transaction fees totalled US$ 5.7 million and the Group's net debt decreased by US$240.2 million.

The completion of the restructuring helped to reduce net debt significantly in 2014. Specifically, net debt decreased by US$152.3 million, from US$387.4 million at the beginning of 2014 to US$235.1 million at the end. Other current and non-current liabilities decreased by US$74.4 million to US$81.1 million by the year-end, from US$ 155.5 million at the end of 2013. Among other things, this reflected the conversion of the Sberbank capital put option, a decrease in deferred tax liabilities, and a decrease in trade and other payables. Despite an increase of total equity by US$ 256.2 million as part of the restructuring, the Group's total equity decreased by US$ 19.6 million in 2014, from US$95.3 million to US$75.7 million, mainly due to the magnitude of foreign-exchange losses associated with the ruble depreciation.

Cash flow

In 2014, the Group generated a net cash inflow from operating activities of US$9.0 million, resulting from positive operating cash flow of US$7.8 million and a positive cash contribution from changes in working capital of US$1.2 million. The latter resulted from the collection of receivables, as well as from the significant ruble depreciation during 2014, leading to a major decline (when expressed in US dollars) in ruble-denominated accounts payable balances.

During the year, the Group spent US$49.6 million on investment activities. This consisted of US$23.9 million on the construction of new wells, US$1.9 million on rig mobilisation and demobilisation, US$10.8 million on infrastructure-related capital expenditures, US$1.3 million on development studies, US$2.6 million on the purchase of intangible and other assets, and US$9.2 million for capital expenditures related to activities before the initiation of the Group's horizontal well development programme in 2014.

The Group received US$37.4 million (net of costs) from the issue of new shares in December 2014 through the Company's open offer and placing. It also received loan proceeds of US$10 million from Limolines in August 2014. In addition, loan proceeds from Otkritie totalling US$148.5 million (net of arrangement fees of US$1.5 million) were received in December 2014. The Group utilised these immediately, as part of the restructuring, to repay the US$150

million outstanding under the Sberbank credit facility then owned by Mastin.

Financing of Ruspetro's current operations and future development

Following the restructuring and the extension of shareholder loans, together with the additional US$100 million development facility available (subject to continuing to meet the drawdown conditions), the Group is able to continue the implementation of its horizontal well programme in the near future. The Group's focus on production is critical to its success, as the terms for its restructured debt finance require the Group to achieve certain annualised EBITDA and production covenants that will be tested quarterly from January 2016. The Group is required to monitor closely its ability to meet such covenants throughout the year, and this will depend largely on the drilling of additional horizontal wells and on foreign-exchange and oil price movements. Given the current financial position, the management considers that financial statements should be prepared on a going concern basis.

Outstanding debt obligations

Ruspetro Plc

PRELIMINARY UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

AS AT AND FOR THE YEAR ENDED 31 DECEMBER 2014

Unaudited Consolidated Statement of Profit or Loss and Other Comprehensive Income for the year ended 31 December 2014

(presented in US$ thousands, except otherwise stated)

Unaudited Consolidated Statement of Financial Position as at 31 December 2014

(presented in US$ thousands, except otherwise stated)

Unaudited Consolidated Statement of Changes in Equity for the year ended 31 December 2014

(presented in US$ thousands, except otherwise noted)

Unaudited Consolidated Statement of Cash Flows for the year ended 31 December 2014

(presented in US$ thousands, except otherwise stated)

Refer to Note 11 for the refinancing transaction that did not require the use of cash and cash equivalents and was excluded from the cash flow statement.

Notes to the Consolidated Financial Statements for the year ended 31 December 2014

(all tabular amounts are in US$ thousands unless otherwise noted)

1. Basis of preparation

These consolidated financial statements of the Group have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the EuropeanUnion. The consolidated financial statements are prepared under the historical cost convention, modified for fair values under IFRS.

The consolidated financial statements are presented in US dollars (US$) and all values are rounded to the nearest thousand unless otherwise indicated.

Sberbank credit facility restructuring

On 5 December 2014 the shareholders of the Company approved a financial restructuring (the Restructuring) at a general meeting. The restructuring included the issue of shares under an Open Offer and Placing, as well as in consideration for the capitalisation of existing indebtedness as described below.

On 9 December 2014 LLC Sberbank Capital (Sberbank Capital) transferred its creditor rights and rights under its put option to Mastin Holdings Limited (Mastin) in total amount of US$358,076 thousand. Part of the debt in the amount of US$150,000 thousand was repaid by means of a five year term credit facility received on 10 December 2014 from OJSC "Bank Otkritie Financial Corporation" (Otkritie). The remaining debt was capitalised through the issue of new ordinary shares to Mastin, which also purchased Sberbank Capital's shareholding in the Company's capital, resulting in Mastin having an aggregate 25% shareholding in the Company's enlarged issued share capital, following the Open Offer and Placing.

On 11 December 2014 the Company completed a fully underwritten Open Offer and a Placing at 10 pence per ordinary share, raising United Kingdom Sterling ("£") 32.9 million (approximately US$52.7 million) before expenses.

The Company's obligation to repay a shareholder loan from Limolines Transport Limited's (Limolines) with principal and interest amounting to US$10.7 million in February 2015 (the Limolines Loan) was off-set against Limolines' subscription for new ordinary shares in the Placing and Open Offer. Additionally, the Company undertook to pay US$5.0 million in respect of accrued interest on a shareholder loan from Makayla Investments Limited in May 2015. Total shareholder outstanding loans as at 31 December 2014 were equal to US$99.1 million.

Following the restructuring, Otkritie has commited to provide a new development facility for up to US$100.0 million as well as a new credit facility for up to US$44.7 million.

The guaranteed net proceeds of the Restructuring, comprising the initial tranche of the development facility of US$50.0 million and gross proceeds of £32.9 million (approximately US$52.7 million) from the Placing and Open Offer less costs of the Restructuring of approximately US$7.5 million, comprised approximately US$95.2 million. In addition, the Company will be able to draw down up to US$44.7 million under the Credit Facility.

The drawdown of the development facility second tranche of US$50.0 million (expected to be available from July 2015) is dependent on the Group meeting certain covenants under the development facility. Should the applicable development facility covenants not be met or the development facility second tranche is not drawn down, then the Company will only receive the guaranteed net proceeds of the Restructuring.

The completion of the Restructuring occurred on 11 December 2014 with the admission of 536,310,294 new ordinary shares to listing on the premium segment of the Official List of the UK Listing Authority and to trading on the London Stock Exchange's main market for listed securities (the Admission). In addition, the Company issued 420,242 new ordinary shares in lieu of salary to certain current and former Directors. Following the Admission, and as at the date of these financial statements, the Company's issued share capital comprises 870,112,016 ordinary shares.

Going concern

These consolidated financial statements are prepared on a going concern basis.

At the reporting date the Group had net current liabilities of US$11,465 thousand, which included cash in hand of US$12,022 thousand.

The Group's continuing operations are dependent upon its ability to make further investments in field development in order to grow its hydrocarbon production and sales. In the short term, this field development is planned to involve, in particular, the drilling of a number of horizontal wells, the success of which will only be known with certainty once each well is completed. The first and the second horizontal wells were drilled and launched into production in July and October 2014 respectively. In the light of these results, the nature and extent of the Group's drilling programme may change over time, with a consequent change in investment requirements.

Accordingly, the ability of the Group to generate sufficient cash from operations may be materially affected by the results of the Group's current appraisal activity and the success of future drilling activities, as well as by a number of economic factors to which the Group's financial forecasts are particularly sensitive, such as crude oil prices, the level of inflation in Russia, and foreign exchange rates.

The Group finances its exploration and development activities using a combination of cash in hand, operating cash flow generated mainly from the sale of crude oil production, prepayments from forward oil sale agreements and additional debt or equity financing as required. As further discussed in Note 11, the credit facility obtained from Otkritie contains certain covenants which the Group needs to meet to avoid acceleration of the debt repayment schedule. The two major covenants are EBITDA and production volumes.

The projections prepared by management of the Group for the purposes of preparation of these financial statements shows that it is possible that the Group might violate its EBITDA covenant for the year ending 31 December 2015 and four consecutive quarters ending 31 March 2016. The main reason for this is a substantial decline of the oil price, which is beyond the control of the Group. To mitigate this risk, management has commenced negotiations with Otkritie to revise the covenants. The Group has also received a written confirmation that Otkritie has no intention to take any actions to accelerate repayment of the loans as a result of the possible violation of covenants for the periods referred to above. Nevertheless, while negotiations continue, management recognises that there is an uncertainty as to the Group's ability to continue as a going concern.

During the reporting period, the Group negotiated a roll-over of the US$30 million advance financing arrangement with Glencore Energy UK Ltd. (Glencore) and obtained Russian Rouble ("RUR") 750,000 thousand (US$21,646 thousand) as a forward oil sale prepayment from LLC EnergoResurs (EnergoResurs). The Group also secured further shareholder finance of US$10 million in short term funding, as announced on 26 August 2014, from Limolines, a major shareholder of the Company.

On 14 November 2014 an extension of existing shareholder loans was agreed until October 2016 and February 2020.

On the basis of the assumptions and cash flow forecasts prepared, management has assumed that the Group will continue to operate within both available and prospective facilities. Accordingly, the Group financial statements are prepared on the going concern basis and do not include any adjustments that would be required in the event that the Group were no longer able to meet its liabilities as they fall due.

2. Summary of significant accounting policies

Principles of consolidation

Subsidiaries

Subsidiaries are those entities in which the Group has an interest of more than one half of the voting rights, or otherwise has power to exercise control over their operations. Subsidiaries are consolidated from the date on which control is transferred to the Group and are no longer consolidated from the date that control ceases.

All intercompany transactions, balances and unrealised gains on transactions between Group companies are eliminated; unrealised losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Where necessary accounting policies for subsidiaries have been changed to ensure consistency with the policies adopted by the Group.

Oil and natural gas exploration, evaluation and development expenditure

Oil and gas exploration activities are accounted for in a manner similar to the successful efforts method. Costs of successful development and exploratory wells are capitalised.

Development costs

Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells, is capitalised within oil and gas properties.

Property, plant and equipment, Mineral rights and other intangibles

Oil and gas properties and other property, plant and equipment, including mineral rights are stated at cost, less accumulated depletion, depreciation and accumulated impairment losses.

The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning obligation, and for qualifying assets, borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.

Depreciation and Depletion

Oil and gas properties are depreciated on a unit-of-production basis over proved developed reserves of the field concerned, except in the case of assets whose useful life is shorter than the lifetime of the field, in which case the straight-line method is applied. Mineral rights are depleted on the unit-of-production basis over proved and probable reserves of the relevant area.

Other property, plant and equipment are generally depreciated on a straight-line basis over their estimated useful lives as follows:

Major maintenance and repairs

Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset that was separately depreciated and is now written off is replaced and it is probable that future economic benefits associated with the item will flow to the Group, the expenditure is capitalised. Where part of the asset was not separately considered as a component, the replacement value is used to estimate the carrying amount of the replaced assets which is immediately written off. Inspection costs associated with major maintenance programs are capitalised and amortised over the period to the next inspection. All other maintenance costs are expensed as incurred.

Intangible assets

Intangible assets are stated at the amount initially recognised, less accumulated amortisation and accumulated impairment losses. Intangible assets include computer software.

Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is fair value as at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortisation and any accumulated impairment losses. Amortisation is calculated on a straight line basis over their useful lives, except for mineral rights that are depleted on the unit-of-production basis as explained above.

Impairment of assets

The Group monitors internal and external indicators of impairment relating to its tangible and intangible assets.

The recoverable amounts of cash-generating units and individual assets have been determined based on the higher of value-in-use (VIU) calculations and fair values less costs to sell (FVLCS). These calculations require the use of estimates and assumptions. It is reasonably possible that the oil price assumption may change which may then impact the estimated life of the field and may then require a material adjustment to the carrying value of long-term assets.

Given the shared infrastructure and interdependency of cash flows related to the three licences the Group holds, the assets are considered to represent one Cash Generating Unit (CGU), which is the lowest level where largely independent cash flows are deemed to exist.

Share option plan

The share option plan, under which the Group has the ability to choose whether to settle it in cash or equity instruments at the discretion of the Board of Directors is accounted for as an equity settled transaction. The fair value of the options granted by the Company to employees is measured at the grant date and calculated using the Trinomial option pricing model and recognised in the consolidated financial statements as a component of equity with a corresponding amount recognised in selling, general and administrative expenses over the time share reward vest to the employee.

Modifications of the terms or conditions of the equity instruments granted in a manner that reduces the total fair value of the share-based payment arrangement or is not otherwise beneficial to the employee, are accounted for as services received in consideration for the equity instruments granted as if the modification had not occurred.

Financial instruments

A financial instrument is any contract that gives rise to financial assets or liabilities.

Financial assets within the scope of International Accounting Standard (IAS) 39 are classified as either financial assets at fair value through profit or loss, loans and receivables, held to maturity investments, or available for sale financial assets, as appropriate. When financial assets are recognised initially, they are measured at fair value, plus directly attributable transaction costs for all financial assets not carried at fair value through profit or loss.

The Group determines the classification of its financial assets at initial recognition.

Financial instruments carried on the consolidated statement of financial position include loans and receivables, cash and cash equivalent balances, borrowings, accounts payable and put and call options. The particular recognition and measurement methods adopted are disclosed in the individual policy statements associated with each item.

An obligation to acquire own shares is classified as a liability. The liability to repurchase own shares is initially recognised at the fair value of consideration payable (being the net present value of estimated redemption amount) and it is recorded as deduction of equity. Subsequent changes (revision of estimate, unwinding of discount) are recognised in profit or loss. If options are not exercised, the amount recognised as a liability is transferred to equity.

Rights to acquire own shares are classified as assets. The right to repurchase own shares is initially recognised at the fair value of consideration payable, estimated using the Black-Scholes option pricing model, and it is recorded as increase of equity. Subsequent changes (revision of estimate) are recognised in profit and loss.

Loans and receivables

Loans and receivables are non‑derivative financial assets with fixed or determinable payments that are not quoted in an active market. After initial measurement loans and receivables are subsequently carried at amortised cost using the effective interest method less any provision for impairment.

A provision for impairment is recognised when there is an objective evidence that the Group will not be able to collect all amounts due according to the original terms of the loans and receivables. The amount of provision is the difference between the assets' carrying value and the present value of the estimated future cash flows, discounted at the original effective interest rate. The change in the amount of the loan or receivable is recognised in profit or loss. Interest income is recognised in profit or loss by applying the effective interest rate.

Cash and cash equivalents

Cash and cash equivalents in the consolidated statement of financial position comprise cash at banks and on hand and short term deposits with an original maturity of three months or less.

For the purpose of the consolidated cash flow statement, cash and cash equivalents consist of cash and cash equivalents as defined above, net of outstanding bank overdrafts if any.

Borrowings and accounts payable

The Group's financial liabilities are represented by accounts payable and borrowings.

Borrowings are initially recognised at fair value of the consideration received less directly attributable transaction costs. After initial recognition, borrowings are measured at amortised cost using the effective interest method; any difference between the initial fair value of the consideration received (net of transaction costs) and the redemption amount is recognised as an adjustment to interest expense over the period of the borrowings.

A financial liability is derecognised when the obligation under the liability is discharged or cancelled or expires. Where an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability, and the difference in the respective carrying amounts is recognised in the profit or loss.

Impairment of financial assets

The Group assesses at the end of each reporting period whether there is any objective evidence that a financial asset or a group of financial assets is impaired. A financial asset or a group of financial assets is deemed to be impaired if, and only if, there is an objective evidence of impairment as a result of one or more events that has occurred after the initial recognition of the asset (an incurred 'loss event') and that loss event has an impact on the estimated future cash flows of the financial asset or the group of financial assets that can be reliably estimated. Evidence of impairment may include indications that the debtors or a group of debtors is experiencing significant financial difficulty, default or delinquency in interest or principal payments, the probability that they will enter bankruptcy or other financial reorganisation and where observable data indicate that there is a measurable decrease in the estimated future cash flows, such as changes in arrears or economic conditions that correlate with defaults.

Inventories

Inventories are stated at the lower of cost and net realisable value. Cost of inventory is determined on the weighted average basis. The cost of finished goods and work in progress comprises raw material, direct labour, other direct costs and related production overheads (based on normal operating capacity) but excludes borrowing costs. Net realisable value is the estimated selling price in the ordinary course of business, less the estimated cost of completion and selling expenses.

Provisions

General

Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. The expense relating to any provision is presented in profit or loss net of any reimbursement. If the effect of the time value of money is material, provisions are discounted using rates that reflect, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognised as finance costs.

Provision for dismantlement

Provision for dismantlement is related primarily to the conservation and abandonment of wells, removal of pipelines and other oil and gas facilities together with site restoration activities related to the Group's licence areas. When a constructive obligation to incur such costs is identified and their amount can be measured reliably, the net present value of future decommissioning and site restoration costs is capitalised within property plant and equipment with a corresponding liability. Provisions are estimated based on engineering estimates, licence and other statutory requirements and practices adopted in the industry and are discounted to net present value using discount rates reflecting adjustments for risks specific to the obligation.

Adequacy of such provisions is periodically reviewed. Changes in provisions resulting from the passage of time are reflected in profit or loss each year under finance costs. Other changes in provisions, relating to a change in the expected pattern of settlement of the obligation, changes in the discount rate or in the estimated amount of the obligation, are treated as a change in accounting estimate in the period of the change and are reflected as an adjustment to the provision and a corresponding adjustment to property, plant and equipment. If a decrease in the liability exceeds the carrying amount of the asset, the excess is recognised immediately in profit or loss.

Taxes

Income tax

The income tax expense comprises current and deferred taxes calculated based on the tax rates that have been enacted or substantively enacted at the end of the reporting period. Current and deferred taxes are charged or credited to profit or loss except where they are attributable to items which are charged or credited directly to equity, in which case the corresponding tax is also taken to equity.

Current tax is the amount expected to be paid to or recovered from the taxation authorities in respect of taxable profits or losses for the current and prior periods.

Deferred tax assets and liabilities are calculated in respect of temporary differences using the liability method. Deferred taxes provide for all temporary differences arising between the tax bases of assets and liabilities and their carrying values for financial reporting purposes, except where the deferred tax arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss.

A deferred tax asset is recognised for all deductible temporary differences and carry forward of unused tax credits and unused tax losses only to the extent that it is probable that taxable profit will be available against which the deductible temporary differences or carry forward losses can be utilised.

Unrecognised deferred tax assets are reassessed at the end of each reporting period and are recognised to the extent that it has become probable that future taxable profit will allow the deferred tax asset to be recovered.

Deferred tax assets and liabilities are offset when the Group has a legally enforceable right to set off current tax assets and liabilities, when deferred tax balances are referred to the same governmental body (i.e. federal, regional or local) and the same subject of taxation and when the Group intends to perform an offset of its current tax assets and liabilities.

Value added tax

Russian Value Added Tax ('VAT') at a standard rate of 18% is payable on the difference between output VAT on sales of goods and services and recoverable input VAT charged by suppliers. Output VAT is charged on the earliest of the dates: either the date of the shipment of goods (works, services) or the date of advance payment by the buyer. Input VAT could be recovered when purchased goods (works, services) are accounted for and other necessary requirements provided by the tax legislation are met.VAT related to sales and purchases is recognised in the consolidated balance sheet on a gross basis and disclosed separately as a current asset and liability.

Mineral extraction tax

Mineral extraction tax on hydrocarbons, including natural gas and crude oil, is due on the basis of quantities of natural resources extracted. Mineral extraction tax for crude oil is determined based on the volume produced per fixed tax rate adjusted depending on the monthly average market prices of the Urals blend and the RUR/US$ exchange rate for the preceding month. The ultimate amount of the mineral extraction tax on crude oil depends also on the depletion and geographic location of the oil field. Mineral extraction tax on gas condensate is determined based on a fixed percentage from the value of the extracted mineral resources. Mineral extraction tax is accrued as a tax on production and recorded within cost of sales.

Equity

Share capital

Ordinary shares are classified as equity. Incremental costs directly attributable to the issue of new shares and options are shown in equity as a deduction, net of tax, from the proceeds. Any excess of the fair value of shares issued or liabilities extinguishment over the par value of shares issued is recorded as share premium.

Other reserves

Other reserves include a reserve on reorganisation of the Group, the amount of share options of shareholders and an amount related to fair value of Directors' options.

Revenue recognition

Revenue is measured at the fair value of the consideration received or receivable for goods provided or services rendered less any trade discounts, VAT and similar sales-based taxes after eliminating sales within the Group.

Revenue from sale of crude oil and gas condensate is recognised when the significant risks and rewards of ownership have been transferred to the customer, the amount of revenue can be measured reliably, it is probable that the economic benefits associated with the transaction will flow to the Group and costs incurred or to be incurred in respect of this transaction can be measured reliably. If the Group agrees to transport the goods to a specified location, revenue is recognised when goods are passed to the customer at the designated location.

Other revenue is recognised in accordance with contract terms.

Interest income is accrued on a regular basis by reference to the outstanding principal amount and the applicable effective interest rate, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset's net carrying amount. Dividend income is recognised where the shareholders' right to receive a dividend payment is established.

Borrowing costs

Borrowing costs directly relating to the acquisition, construction or production of a qualifying capital project under construction are capitalised and added to the project cost during construction until such time the assets are substantially ready for their intended use i.e. when they are capable of production. Where funds are borrowed specifically to finance a project, the amount capitalised represents the actual borrowing costs incurred. Where surplus funds are available for a short term out of money borrowed specifically to finance a project, the income generated from such short term investments is also capitalised and deducted from the total capitalised borrowing cost. Where the funds used to finance a project form part of general borrowings, the amount capitalised is calculated using a weighted average of rates applicable to relevant general borrowings of the Group during the period. All other borrowing costs are recognised in the profit or loss account as finance costs in the period in which they are incurred.

Employee benefits 

Wages, salaries, contributions to the Russian Federation state pension and social insurance funds, paid annual leave and sick leave, bonuses are expensed as incurred.

Foreign currency translation

Foreign currency transactions are initially recognized in the functional currency at the exchange rate ruling at the date of transaction. Monetary assets and liabilities denominated in foreign currencies are translated at the functional currency rate of exchange in effect at the end of the reporting period.

The US dollar (US$) is the presentation currency of the Group and the functional currency of the Company. The functional currency of subsidiaries operating in the Russian Federation is the Russian Rouble (RUR). The assets and liabilities of the subsidiaries are translated into the presentation currency of the Group at the rate of exchange ruling at the end of each of the reporting periods. 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). All the resulting exchange differences are recorded in other comprehensive income.

The US$ to RUR exchange rates were 56.26 and 32.73 as at 31 December 2014 and 31 December 2013, respectively and the average rates for the year ended 31 December 2014 and 2013 were 38.47 and 31.85, respectively. The US$ to £ exchange rates were 0.64 and 0.61 as at 31 December 2014 and 31 December 2013, respectively and the average rates for the year ended 31 December 2014 and 2013 were 0.61 and 0.64, respectively. The increase in the US$ to RUR exchange rate for the year ended 31 December 2014 has resulted in a loss of US$202,410 thousand in the consolidated statement of profit or loss and other comprehensive loss and an adjustment of US$9,292 thousand in other comprehensive loss.

3. Significant accounting judgements, estimates and assumptions

In the application of the Group's accounting policies, management is required to make judgements, estimates and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources.

The estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant. Actual results may differ from these estimates. The estimates and underlying assumptions are reviewed on an on-going basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period or in the period of the revision and future periods if the revision affects both current and future periods.

The most significant areas of accounting requiring the use of the Group's management estimates and assumptions relate to oil and gas reserves; useful economic lives and residual values of property, plant and equipment; impairment of tangible assets; provisions for dismantlement; taxation and allowances.

Subsoil Licences

The Group conducts operations under exploration and production licences which require minimum levels of capital expenditure and mineral production, timely payment of taxes, provision of geological data to authorities and other such requirements. The current periods of the Group's licences expire between December 2015 and June 2034.

Regulatory authorities exercise considerable discretion in issuing and renewing licences and in monitoring licencees' compliance with licence terms. The loss of licence would be considered a material adverse event for the Group.

It is management's judgement that each of the three licences held by the Group will be renewed for the economic lives of the fields which are projected to be up to 2040 (two licences held by INGA) and 2029 (the licence held by Trans-oil). The appraised economic lives of the fields are used as the basis for reserves estimation, depletion calculation and impairment analysis. In making this assessment, management considers that the licence held by Trans-oil, which was extended for three years to December 2015, will be further extended. This further extension will be dependent on management demonstrating to the licencing authorities that associated petroleum gas produced in the course of oil production is being utilised.

Useful economic lives of property, plant and equipment and Mineral rights

Oil and gas properties and mineral rights

The Group's oil and gas properties are depleted over the respective life of the oil and gas fields using the unit-of-production method based on proved developed oil and gas reserves. Mineral rights are depleted over the respective life of the oil and gas fields using the unit-of-production method based on proved and probable oil and gas reserves.

Reserves are determined using estimates of oil in place, recovery factors and future oil prices.

When determining the life of the oil and gas field, assumptions that were valid at the time of estimation, may change when new information becomes available. The factors that could affect the estimation of the life of an oil and gas field include the following:

· Changes of proved and probable oil and gas reserves;

· Differences between actual commodity prices and commodity price assumptions used in the estimation of oil and gas reserves;

· Unforeseen operational issues; and

· Changes in capital, operating, processing and reclamation costs, discount rates and foreign exchange rates possibly adversely affecting the economic viability of oil and gas reserves.

Any of these changes could affect prospective depletion of mineral rights and oil and gas assets and their carrying value.

Other non-production assets

Property, plant and equipment other than oil and gas properties are depreciated on a straight-line basis over their useful economic lives. Management at the end of each reporting period reviews the appropriateness of the assets useful economic lives and residual values. The review is based on the current condition of the assets, the estimated period during which they will continue to bring economic benefit to the Group and their estimated residual value.

Estimation of oil and gas reserves

Unit-of-production depreciation, depletion and amortisation charges are principally measured based on Group's estimates of proved developed and proved and probable oil and gas reserves. Estimates of proved and probable reserves are also used in determination of impairment charges and reversals. Proved and probable reserves are estimated by an independent international reservoir engineers, by reference to available geological and engineering data, and only include volumes for which access to market is assured with reasonable certainty.

Information about the carrying amounts of oil and gas properties and the depreciation, depletion and amortisation charged is provided in Notes 8 and 9.

Estimates of oil and gas reserves are inherently imprecise, require the application of judgements and are subject to regular revision, either upward or downward, based on new information such as from the drilling of additional wells, observation of long-term reservoir performance under producing conditions and changes in economic factors, including product prices, contract terms or development plans. Changes to Group's estimates of proved and probable reserves affect prospectively the amounts of depreciation, depletion and amortisation charged and, consequently, the carrying amounts of mineral rights and oil and gas properties.

Were the estimated proved reserves to differ by 10% from management's estimates, the impact on depletion would be as follows:

Provision for dismantlement

The Group has a constructive obligation to recognise a provision for dismantlement for its oil and gas assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time when assets are installed. The Group performs analysis and makes estimates in order to determine the probability, timing and amount involved with probable required outflow of resources. Estimating the amounts and timing of such dismantlement costs requires significant judgement. The judgement is based on cost and engineering studies using currently available technology and is based on current environmental regulations. Provision for dismantlement is subject to change because of change in laws and regulations, and their interpretation.

Estimated dismantlement costs, for which the outflow of resources is determined to be probable, are recognised as a provision in the Group's financial statements.

Impairment of non-current assets

The Group accounts for the impairment of non-current assets in accordance with IAS 36 Impairment of Assets. Under IAS 36, the Group is required to assess the conditions that could cause assets to become impaired and to perform a recoverability test for potentially impaired assets held by the Group. These conditions include whether a significant decrease in the market value of the assets has occurred, whether changes in the Group's business plan for the assets have been made or whether a significant adverse change in the business environment has arisen.

Subsequent to the year end, the Group's shares have been trading at a level which indicate that the market capitalisation of the Group is below the carrying value of net assets. This has resulted in a review of the Group's non-current assets (Oil and Gas properties and Mineral Rights) to determine whether they are impaired as at the reporting date.

The recoverable amount was estimated using value in use approach. The models developed by the management to calculate value in use involved assumptions as to future hydrocarbon prices, taxes, production volumes, and inflation. The models also use estimates of proved developed reserves at 31 December 2014 as calculated by the management of the Group. Estimated cash flows were discounted with a risk adjusted discount rate derived as the weighted average cost of capital (WACC). For the Group's businesses the after tax nominal discount rate is estimated at 10 percent.

Based on the impairment analysis performed, management does not consider that the Group's non-current assets are impaired as at 31 December 2014.

Assumptions used in developing cash flow forecasts of the Group

Taxation

The Group is subject to income and other taxes. Significant judgement is required in determining the provision for income tax and other taxes due to complexity of the tax legislation of the Russian Federation. Deferred tax assets are recognised to the extent that it is probable that it will generate enough taxable profits to utilise deferred income tax recognised. Significant management judgement is required to determine the amount of deferred tax assets recognised, based upon the likely timing and the level of future taxable profits. Management prepares cash flow forecasts to support recoverability of deferred tax assets. Cash flow models are based on a number of assumptions relating to oil prices, operating expenses, production volumes, etc. These assumptions are consistent with those, used by independent reservoir engineers. Management also takes into account uncertainties related to future activities of the Group and going concern considerations. When significant uncertainties exist deferred tax assets arising from losses are not recognised even if recoverability of these is supported by cash flow forecasts.

Segment reporting

Management views the Group as one operating segment and uses reports for the entire Group to make strategic decisions. 98% of total revenues from external customers in 2014 and 2013 were derived from sales of crude oil and gas condensate. These sales are made to domestic and international oil traders. Although there are a limited number of these traders, the Group is not dependent on any one of them as crude oil is widely traded and there are a number of other potential buyers of this commodity. The Group's operations are entirely located in Russia.

The Company's Board of Directors evaluates performance of the entity on the basis of different measures, including total expenses, capital expenditures, operating expenses per barrel and others.

4. Adoption of the new and revised standards

At the date of approval of these consolidated financial statements the following accounting standards, amendments and interpretations were issued by the International Accounting Standards Board and IFRS Interpretations Committee in the year ended 31 December 2014 or earlier, but are not yet effective and therefore have not been applied:

(i) Not endorsed by the European Union

New standards and interpretations

· IFRS 9 - Financial Instruments (effective for annual periods on or after 1 January 2018).

· IFRS 14 - Regulatory Deferral Accounts (effective for annual periods on or after 1 January 2016).

· IFRS 15 - Revenue from Contracts with Customers (effective for annual periods on or after 1 January 2017)

5. Revenue

Other revenue includes proceeds from third parties for crude oil transportation.

For the years ended 31 December 2014 and 2013, revenue from export sales of crude oil amounted to US$18,811 thousand and US$13,306 thousand, respectively.

Revenues from certain individual customers from sales of crude oil and gas condensate approximately equalled or exceeded 10% of total Group revenue.

6. Other expenses

Other expenses mainly consist of impairment of fixed and other assets in amount of USD2,137 thousand, impairment of financial instruments in amount of USD1,285 thousand, and professional fees, incurred in connection with the cancellation of a previously proposed financial transaction by the Company, in amount of USD709 thousand.

7. Income tax

The major components of income tax expense for the years ended 31 December 2014 and 2013 were:

Loss before taxation for financial reporting purposes is reconciled to the tax calculation for the period as follows:

Differences between IFRS and statutory taxation regulations in Russia give rise to temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and their tax bases. The tax effect of the movements in these temporary differences is detailed below and is recorded at the rate of 20% for Group companies incorporated in the Russian Federation.

The movements in deferred tax assets and liabilities relates to the following:

The Group recognises deferred tax assets in respect of tax losses incurred only by INGA, because it is probable that sufficient taxable profits will be available in the future to utilise the deductible temporary difference.

The Group did not recognise deferred income tax assets of US$65,172 thousand and US$39,682 thousand, in respect of losses that can be carried forward against future taxable income amounting to US$325,861 thousand and US$198,410 thousand as at 31 December 2014 and 31 December 2013, respectively. As at 31 December 2014, losses amounting to US$29,230 thousand, US$21,578 thousand, US$15,139 thousand, US$24,009 thousand, US$25,210 thousand and US$210,695 thousand expire in 2018, 2019, 2020, 2021, 2023, 2024 respectively. As at 31 December 2013, losses amounting to US$51,087 thousand, US$36,899 thousand, US$26,559 thousand, US$41,400 thousand and US$42,465 thousand expire in 2018, 2019, 2020, 2021, 2023 respectively.

8. Property, plant and equipment

For the year ended 31 December 2014, additions to construction in progress are primarily made up of additions to production facilities, including wells, as well as additions to infrastructure. As at 31 December 2014, the construction in progress balance mainly represents production wells and oil production infrastructure not finalised (e.g. pads, electricity grids, etc.).

None of the Group's property, plant and equipment was pledged as at the reporting dates.

9. Mineral rights and other intangibles

Intangible assets of the Group are not pledged as security for liabilities and their titles are not restricted.

10. Shareholders' equity

Share capital

On 11 December 2014 on completion of the Restructuring 536,730,536 new ordinary shares were issued as follows:

· 179,061,411 new ordinary shares were issued pursuant to applications received for Open Offer and Excess shares.

· 4,298,403 new ordinary shares were taken up by the underwriting shareholders pursuant to their underwriting commitment under the Open Offer.

· 145,890,169 new ordinary shares were taken up by underwriting shareholders pursuant to the terms of the Placing.

In total 329,249,983 new ordinary shares were issued at par value of 10 pence per share, with existing shareholders being offered the right to subscribe for 0.55 new shares for each existing share held.

Mastin purchased from Sberbank Capital 10,362,632 existing ordinary shares. Including 20,115,743 new ordinary shares issued to it to set off the put obligation of the Company, a total 207,060,311 new ordinary shares were issued to Mastin resulting in it having a 25% holding in the enlarged issued ordinary share capital as at 31 December 2014.

In addition, on 17 December 2014 a further 420,242 share were issued to current and former Directors in lieu of salary for the period from 1 April 2013 to 31 March 2014.

Reflecting these transactions, the issued and paid up share capital of the Company consisted of 870,112,016 and 333,381,480 ordinary shares with a par value of GBP 0.10 each at 31 December 2014 and 2013 respectively.

11. Borrowings

Otkritie credit facilities Under the terms of the Restructuring the Group obtained a loan from Otkritie in the amount of US$150,000 thousand on 8 December 2014, pursuant to a loan agreement dated 14 November 2014. The loan is payable in November 2019, bears interest at 8% per annum and is subject to certain covenants, including EBITDA and production targets.

14 November 2014 loan agreements for US$100,000 thousand and US$44,700 thousand were entered into with Otkritie for the Group's field development and for general working capital purposes respectively. As at 31 December 2014 no facilities were drawn down under these agreements.

Sberbank credit facility On 10 December 2014 an assignment and transfer agreement was entered into between Ruspetro Russia, Ruspetro Holding Limited and Mastin. In accordance with the agreement the creditor rights in relation to the total debt in the amount of US$337,894 thousand being due to Sberbank as at 10 December 2014 was transferred to Mastin. Part of the loan in the amount of US$150,000 thousand was repaid through the corresponding credit facility provided by Otkritie in December 2014. The remaining part of the loan in the amount of US$187,894 thousand was settled by the issuance to Mastin of new ordinary shares in the Company.

Loans from shareholders of the Company The Group has a number of US$ denominated loans obtained from Shareholders of the Company. All of these loans are unsecured and the interest rate on most of these loans is Libor +10% per annum.

14 November 2014, the Group rescheduled the maturity of the main Shareholders' loans until October 2016 and February 2020 with US$5,000 thousand payable in accrued interest on 31 May 2015. These amendments did not substantially alter the terms of these original loans, and were therefore were not treated as extinguishment of an existing liability and recognition of a new liability. The present value difference arising from the renegotiation was recognised over the remaining life of these loans by adjusting the effective interest rate.

Foreign exchange losses The Group recognised a net foreign exchange loss amounting to US$196,084 thousand and US$24,694 thousand during the years ended 31 December 2014 and 2013 respectively on the US$ denominated credit facilities and outstanding accrued interest thereon.

12. Provision for dismantlement

The provision for dismantlement represents the net present value of the estimated future obligations for abandonment and site restoration costs which are expected to be incurred at the end of the production lives of the oil and gas fields which is estimated to be in 20 years from 31 December 2014.

This provision has been created based on the Group's internal estimates. Assumptions, based on the current economic environment, have been made which management believes are a reasonable basis upon which to estimate future dismantlement liability. These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual dismantlement costs will ultimately depend upon future market prices for the necessary dismantlement works required which will reflect market conditions at the relevant time. Furthermore, the timing is likely to depend on when the fields cease to produce at economically viable levels. This in turn will depend upon future oil and gas prices and future operating costs which are inherently uncertain.

13. Loss per share

Basic

Basic earnings per share are calculated by dividing the profit attributable to equity holders of the Company by the weighted average number of ordinary shares in issue during the period.

Diluted

Diluted earnings per share is calculated by adjusting the weighted average number of ordinary shares to assume conversion of all dilutive potential ordinary shares.

The Company has incurred a loss from continuing operations for the year ended 31 December 2014 and the effect of considering the exercise of the options on the Company's shares would be anti-dilutive, that is, it would reduce the loss per share.

(1)Earnings before interest, taxes, depreciation and amortization for the year ending 31 December 2014 is calculated by adding finance costs, depletion, depreciation and amortization, foreign exchange income/loss, other expenses and other operating expenses. In this calculation other expenses includes but is not limited to impairment of PPE, financial instruments and advances paid.