Ruspetro Regulatory News (RPO)

Ruspetro plc

4 April 2014

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

Preliminary Unaudited Results for the Year Ended 31 December 2013

London, 4 April 2014: Ruspetro plc (LSE: RPO) Ruspetro plc (LSE: RPO), is 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 2013 and an update on its operations to date.

Financial Highlights

· Revenues of US$79.8m (+5% Y-o-Y) on the back of stabilised production

· Full year EBITDA of US$13.0m vs. a negative EBITDA of US$6.2m in 2012(1)

· Well Head Revenue per barrel significantly enhanced by the introduction of Mineral Extraction Tax ("MET") relief for hard-to-recover reserves effective from September

· Successfully extended the maturity of its Sberbank facility to 2018; as of year-end, total debt was US$ 403m, including shareholder loans

· Cash of US$ 15.8m, improved by a one-year prepayment facility with Glencore Energy UK Ltd for US$30 million with the obligation to export 15,000 metric (approximately 1,200 bopd) tonnes of crude oil per quarter.

Operational Highlights

· Average 2013 production up 3% from 2012 at 4,797 bopd

· Successful waterflood implementation mitigated natural decline in base production

· Proved reserves of 225 mmboe (-4% Y-o-Y)

· Probable reserves of 1,662 mmboe (+4% Y-o-Y)

· Proved developed reserves of 29 mmboe (+81% Y-o-Y)

· Preparations progressing for a drilling campaign based on multi-stage fractured horizontal production wells

Corporate Highlights

· Four new members have joined our Board in 2013, adding to a strengthened, international Board with a wealth of technical experience in the region and industry

· Signed a technical partnership with Schlumberger in order to advance and execute a revised development plan

· The Board continues to evaluate a range of funding alternatives and potential strategic transactions

 John Conlin, Chief Executive Officer, commented:

"2013 has been a necessary year of reassessment for Ruspetro. During this period we have successfully restructured our debt, raised non-dilutive financing, strengthened our leadership and technical teams, and are therefore in a position to restart development drilling. Building on our technical partnership with Schlumberger, and the positive effect of the Federal MET relief on our production economics, we are confident that Ruspetro is well positioned for the future."

Enquiries

Investors / Analyst enquiriesDaniel Barcelo, Ruspetro+44 (0)207 318 1260

Twitter: @ruspetroplc

Media enquiriesFTI Consulting

Ben Brewerton; George Parker; Natalia Erikssen

+44 (0)203 727 1000

For Russian Media enquiries

Maria Shiryaevskaya ; Olga Lundquist

+7 495 795 0623

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 1.9 bnboe.

Glossary

bbl barrel

bnboe billion barrels of oil equivalent

boe barrels of oil equivalent

bopd barrels of oil per day

mmbbl million barrels

mmboe million barrels of oil equivalent

CHAIRMAN'S STATEMENT

2013 has been a year of change for Ruspetro - change in strategy, team and approach. We believe that the transformation we have undergone is for the better, but we cannot deny that it has been a difficult year. We are emerging from these changes stronger, more focused and on a better footing for the future.

Since our performance has not been as successful as initially planned, our duty to shareholders was to determine how to set Ruspetro on the right track again. We felt it was time to pause and review our operational performance and determine an effective strategy for the successful development of Ruspetro's large hydrocarbon assets. The discussions led to a number of Board changes. I was elected Chairman of the Board and will continue my active involvement in the business, both in the areas of strategy, and our engagement with Russia's fiscal and legislative framework.

In order to develop the business further, John Conlin was appointed as Chief Executive Officer by the Board in December 2013. He is not only an experienced E&P executive, but he is also a petroleum engineer. Most recently he was Chairman of Aurelian Oil & Gas, a small independent E&P company which recently merged with San Leon Energy. Prior to his move to the independent sector, he spent 28 years at Shell in various senior management and operational positions, including the role of President of Sakhalin Energy in Moscow, in the late Nineties. With his extensive experience of the industry, John has a clear strategy to lead Ruspetro through a successful development phase to production. These he articulates in his CEO report. 

The geological and operational expertise we are building in-house is complemented at Board level by significant input from a new non-executive director, Maurice Dijols. Maurice was formerly President of Schlumberger Russia and is currently a Non-Executive Director of IGSS (the largest land seismic company in Russia) and Eurasia Drilling Company (the largest drilling company in Russia). His experience in the Russian market and the practicalities of operating in Western Siberia is unrivalled, and thus he has closed a key gap in our team. 

In our commitment to the highest corporate governance standards, we have also made a number of strong appointments to the Board, appointing Kirill Androsov and Frank Monstrey as Non-Executive Directors. Mr. Monstrey's track-record in delivering production growth in Kazakhstan and Kirill's deep knowledge of the Russian energy market further strengthen our Board. The Board re-organisation along with the various committees was completed in early 2014. We are now confident we have strong leadership to support the implementation of the agreed strategy.

The team in place is now empowered to lead Ruspetro into a new phase which will reflect a different approach to geological challenge, technology application and planning. We are working to build a well-rounded and technically advanced team, and with the support of Schlumberger, to develop the capability to successfully design and execute the complex horizontal wells which we believe will unlock the potential of our substantial resources. 

Ruspetro's immediate business plan objectives are both to develop and sustain its current oil production, including through the initiation of horizontal drilling. Changes in the fiscal environment in which we operate have significantly improved our production economics. In July 2013, the Russian Government signed a law to reduce Mineral Extraction Tax (MET) with effect from 1 September 2013, which has significantly enhanced the cash flow generation from our existing oil production. This applies to oil produced from hard-to-recover reservoirs, such as our Bazhenov and Tyumen formations which have low permeability. Under this legislation, virtually all the Group's current production qualifies for an 80% reduction in MET.

These fiscal policy changes have made it realistic to consider the development of our vast shale resources in the Bazhenov formation. We believe, along with a large number of renowned global experts, that the Bazhenov could drive the new wave of investment in unconventional resources in Russia from around the world. While it is true to say that the successes in the US have not been replicated as quickly elsewhere in the world, there are practical reasons to believe that significant early progress can be anticipated in Russia. These include the scale of the resources, the advantageous geology, the significant pre-existing infrastructure in areas of low-density population, access to technical expertise and, importantly, a favourable fiscal regime.

In order to implement a sound strategy for the development of its large hydrocarbon assets, Ruspetro will begin drilling from existing financial resources, but we acknowledge additional funds will be required to implement the full development programme. Initial drilling has been facilitated by the successful restructuring during 2013 of our existing medium-term credit facility with Sberbank as well as of our shareholder loans. Additionally, the conclusion of a forward oil sale agreement with Glencore in 2013 and which has been renewed in 2014 is an important liquidity management initiative.

The continued development of Ruspetro's extensive hydrocarbon resources will be funded through a combination of reinvested cash flow and additional financial resources. The Board is also considering a range of potential strategic transactions.

While the past year has been undeniably challenging, I believe that Ruspetro emerges from it with a clear set of strategic decisions which will allow the management team in place to deliver growth. I would like to thank all Ruspetro's employees who have shown dedication through these difficult times and who have worked hard to support myself and the executive team. My consideration also goes to other Board members who have and will I am sure continue to make a sustained valuable contribution to helping Ruspetro deliver on its potential promises.

Finally and most importantly, on behalf of the Board and Management, I would like to thank all our shareholders for their continued support during what has been a challenging year for the Company. As we set out in this report, Ruspetro is now in a far better position to deliver value for all its stakeholders.

Alexander Chistyakov, Chairman Ruspetro

CHIEF EXECUTIVE'S REVIEW

Having joined the Company as an Independent Non-Executive Board member in August 2013, I had the opportunity, along with my Board colleagues, to think about the best way to take Ruspetro forward. Consequently, I welcomed the invitation to take on the role of Chief Executive Officer and look forward to implementing the revised strategy developed by the Board.

What have we learned?

2013 was the year in which reality bit hard. The very aggressive drilling campaign in 2012 and 2013 did not deliver the expected production, while consuming much of our available capital. The simple truth is that we underestimated the complexity of the development challenge in our Pottymsko Inginsky core area. We encountered a lower reservoir permeability range than expected (0.5-1.0mD), as well as greater structural complexity and more limited reservoir continuity. Along with these issues, delayed implementation of water injection caused a large pressure sink to form in the reservoir.

Our first priority has been to stabilise production from our existing wells. This has been a real success story. We have scaled up the waterflood operations by converting a number of producing wells to water injection and have seen a very positive response in terms of slowing the previous production decline.

Perhaps the most important technical decision we have made is to switch to a development concept based on multiple fractured horizontal production wells. In addition to the improved economics of these wells, they critically mitigate by their design the observed reservoir heterogeneity.

In order to further advance our understanding of the reservoir geology and develop complex horizontal wells, the Company began a search for a technical partner, and was delighted to sign a technical partnership with Schlumberger. Through this agreement, Schlumberger will provide horizontal well designs which capitalise on their world-wide experience with this technology and will support Ruspetro in the operational execution of these wells. Subject to having the necessary funding in place, we also consider to improve our subsurface understanding next winter by shooting additional 3D seismic in areas previously only covered by 2D seismic data.

We therefore believe that we understand what went wrong in the past and that we can build a profitable business to repair our balance sheet and create shareholder value.

Corporate Strategy Moving Forward

Now that we have a firm strategy in place, we are focused on delivery, and establishing a track-record which demonstrates our subsurface understanding, technical knowledge and operational capability.

Our immediate objectives are to:

· Build production in 2014 through enhanced water-flooding of the core Pottymsko Inginsky (PI) area and an initial horizontal well development of three areas adjacent to the PI core area

· Create a horizontal well development toolbox of well designs and execution strategies.

· Appraise and mature a ranked inventory of development targets for drilling post 2014, outside the core area

Drilling is due to restart in April 2014. We are in the process of positioning the rig on Pad 23b from where we can develop patterns north west of our existing producing area. Our strategy will comprise of drilling an initial series of horizontal production wells followed by a number of vertical wells designed in due course to be converted to water injectors after a period of test production.

An important characteristic of this plan is that, from this pad, we can alternate drilling between areas thereby giving us the breathing space to assess well performance in each area before a follow-up well is drilled. Secondly, keeping the rig on one pad gives us the opportunity to drive significant improvements in drilling and completion operations over the programme.

In the future, we plan to move to a multi rig development effort building on the experience of this year's horizontal well campaign. Medium term activity levels will be tuned to delivering production levels which are aimed at underwriting capital investment needs and debt servicing.

Longer Term Opportunities

Palyanovo

Our significant gas reserve base in the Palyanovo licence block is a valuable asset which we continue to assess opportunities to monetise. We have a market and are currently in discussion with potential Joint Venture partners to develop the necessary processing facilities. That being the case we closed-in the field at the beginning of 2014 to conserve gas.

Bazhenov

Russia's unconventional resource base remains an area of interest particularly following the Mineral Extraction Tax relief implemented in 2013. We are estimated to have 3.5 billion barrels of 3C oil in place across our 300,000 acres of Bazhenov shale. Given the attractive fiscal incentives, we anticipate a collaborative effort within the industry to initiate the important first steps towards commercialisation of this potential giant resource.

John Conlin, CEO Ruspetro

OPERATIONAL & FINANCIAL REVIEW

Production

Production in the year averaged 4,797 boepd, a 3% increase from average production in 2012 of 4,639 boepd. This increase was due to successful drilling activity and the implementation of water-flooding to reduce well decline rates.

In 2013, only three wells were drilled and these were completed in the first quarter: two in the gas and condensate producing area in the Palyanovo licence block and one oil well drilled to the north-west of the main producing area in the Pottymsko Inginsky licence area. This latter well, 254b, produced the highest initial flow rate of any well in the field to date. It continues to be a strong producer and produced 750 boepd in December 2013. The two wells completed in Palyanovo were not fracture completed and did not produce commercial volumes.

Fourth quarter 2013 production averaged 4,010 boepd, a decline of 31.5% compared to a 5,856 boepd average in the fourth quarter of 2012. Crude oil production averaged 3,680 boepd, a decline of only 11.5% compared to a 4,160 boepd average in the fourth quarter of 2012. The larger decrease in total production is due to reduced condensate production from our Palayanovo licence. The limited decline in crude oil production was due to new production from well 254b and improved response from our waterflood programme. Crude oil comprised 92% of production in the final quarter of 2013, compared to 71% in the fourth quarter 2012.

Reservoir Management and Waterflood

During the year the subsurface team identified falling pressure support in our main crude oil producing area in the Pottymsko-Inginsky licence area as an opportunity where effective reservoir management could stabilise and even build production without drilling. They set about expanding and refining the waterflood programme such that crude oil production towards the end of the year was stabilised. The waterflood was more compartmentalised than had been originally envisaged, in line with the findings from our 3D-seismic reprocessing. 12 wells have now shown a response to the waterflood programme and more well conversions are planned for 2014 to enhance the effectiveness of this programme further. It has been calculated that the waterflood is currently yielding 800 boepd in excess of production purely from primary depletion.

Revising the Geological Model

In 2013, only three wells were drilled and these were completed in the first quarter: two in the gas and condensate producing area in the Palyanovo licence block and one crude oil well drilled to the north-west of the main producing area in the Pottymsko Inginsky licence area. This latter crude well, 254b, produced the highest initial flow rate of any well in the field to date, a thirty date initial rate of 1,508 boepd. It continues to be a strong producer and produced 750 boepd in December 2013 with a total cumulative production of over 23 thousand barrels during the month. The two wells completed in Palyanovo were not fracture completed and did not produce commercial volumes.

As a result of the analysis of Ruspetro's performance throughout the year, it was decided that an extensive revision of the Company's geological model and overall approach to production was necessary. Greater permeability and more homogeneity within the reservoirs had been assumed for the 2012 drilling campaign and it became clear from well results during the period that this was not the case.

The field required an integrated approach to the development of the reservoir including furthering our sub-surface knowledge by re-analysing the data that was and has become available, bringing new drilling and completion techniques to the field that is likely to be more appropriate to the field's geology and more development planning for the lifecycle of the areas targeted.

In 2013, the Company began reprocessing the 3D seismic data that covers 42% of the field. The results of the reprocessing 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 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.

In parallel with this work, the Company entered into a technical partnership with Schlumberger in September 2013. A team of technical experts from Schlumberger joined the Ruspetro sub-surface team in our office and were commissioned to build a knowledge map of the field by reviewing the subsurface data, helping the Company select target areas to appraise and develop, and to design and implement a number of horizontal multistage fractured wells.

As a result of this technical partnership, the Company has now selected a number of target areas and has within those target areas several bottom hole locations to begin the appraisal and development of the reservoirs in that area.

Schlumberger in collaboration with Ruspetro's subsurface team have produced an initial ranking of subsurface areas by risk, as well as to output production forecasts for individual wells with sensitivity tables for different well lengths and fracture numbers. This will lead to more effective capital allocation within the new drilling campaign.

Resource Potential

DeGolyer & MacNaughton conducted a reserve audit for the Company as of 31 December 2013. Proved reserves were 225 million barrels oil equivalent (boe), a decrease of 4% from the year-ago estimate of 234 million boe, mainly due to a re-assessment of oil water contacts in the Vostochno-Inginsky licence area. Year end 2013 proved plus probable reserves were 1.9 billion boe, a 3% increase from 2012's estimate of 1.8 billion boe, primarily due to a removal of sales gas restrictions.

Of these reserves, natural gas comprises 34 million boe of proved reserves and 232 million boe of proved and probable reserves.

The Company has 29 million barrels of proved developed reserves. This compares to 16 million barrels as at 31 December 2012.

DeGolyer & MacNaughton estimate contingent resources in the Bazhenov oil shale formation of 3.5 billion boe in place.

Sales and Marketing

In 2013 Ruspetro produced approximately 1.75 million barrels of oil and condensate giving an average production of 4,797 boepd. Of this 85% was crude oil and 15% was condensate. Whereas the condensate is bought by a local off-taker and provided 12% of our revenues, crude oil is sold into both the domestic market and for export. Of our crude oil revenues generated in 2013, 66% were sold domestically with revenues of US$54 million and 34% of our crude oil was exported, generating revenues of US$27 million.

Overall the Company delivered 52% of its sales via the domestic pipeline network, 15% was exported by pipeline, 19% was delivered by rail as light oil and 14% of sales were condensate trucked directly from the processing facility by the off-taker.

Outlook for 2014

During this year of strategic re-evaluation, we have taken stock and evaluated our position at a technical level, determining that our strategy must revolve around increasing pressure support and economic production from our low permeability reserves. From our technical partnership with Schlumberger, to the positive effect of the Federal MET relief on our production economics, to the long term potential in our Bazhenov resources, it is clear that Ruspetro has a diverse set of opportunities from which to gain firm footing in the Russian oil industry.

Development in 2014 is aimed at maximising cash generations from operations while increasing capital efficiency. With the new 80% MET relief creating a well head revenue per barrel of crude equal to that of condensate, we have shut in our Palyanovo licence and will focus solely on our crude production in 2014 in the Pottymsko-Inginksy licence area.

With the help of Schlumberger, our technical team has identified several bottom hole locations and plan to begin drilling from Pad 23b in patterns north west of our existing producing area. Our strategy consists of drilling horizontal wells with roughly five multistage fracs each to both achieve a higher capital expenditure per barrel and to increase the probability of production per well. In acknowledging the strong effects of waterflooding historically, we also plan to drill a number of vertical wells designed to be converted to water injectors after an initial period of test production. We expect to spud the first horizontal well from this Pad in early April 2014.

Financial Summary

Revenues and EBITDA increased in 2013 over 2012 to US $79.8 million and US$13.0 million respectively due to a higher overall average production rate of 4,797 boepd, higher average oil prices, reduced operating and general expenditures and the MET relief in effect from 1 September 2013. As an illustration, at a Brent crude oil price of US$110, the 80% MET relief helped boost the Company's well head revenue by approximately 50% to US$41 per barrel in December 2013, from US$27/barrel in August 2013, the month before the MET relief became effective. Overall, well head revenue increased by 19% from 2012 and EBITDA increased from negative US$6 million in 2012 to positive US$13 million in 2013.

Further, in August 2013, the Company arranged a US$30 million 360-day pre-payment facility with Glencore Energy UK Ltd. Due, in part, to this facility the Company had a 2013 year-end cash balance of US$ 15.8 million.

Long-Term Debt Restructured

Ruspetro's principal creditor, AKB 'Sberbank' agreed to restructure its credit facility with the Company in May 2013. The restructuring extended the maturity of the facility to April 2018 and included interest payment deferrals for 2013 and 2014. The 2014 interest payment deferral was subject to covenants that have been met by the Company in 2013. The two principal shareholders with loans outstanding also extended the maturities of these loans to the Company with the debt of US$ 21 million (as of 31 December 2013) owed to Makayla Investments Limited now maturing in May 2015, extended from August 2013, and the US$ 69 million (as of 31 December 2013) owed to Limolines Transport Limited now maturing in May 2018, extended from May 2015. The Company had long-term borrowings of approximately US$403 million on 31 December 2013.

Cost of Sales

2013 cost of sales, including depreciation and production related taxes, was US$63,222 thousand and represented 79.2% of revenues as compared to the 98.1% of revenues in 2012. The decrease in the cost of sales is primarily a result of the decreased expenditures in this year of reassessment and reduced drilling.

The decreased sales related costs includes MET which was 19.5% lower than 2012, largely due to the introduction of 80% MET relief. Other sales costs decreased by 12.5% majoring to large decreases both in repairs and maintenance and in transportation services, which is due to the construction and use of our own intra field pipeline, decreasing dependency on oil-transport companies. Operating expenses excluding depreciation and MET amounted to approximately US$19,134 thousand, as compared to US$25,093 thousand in 2012.

Compared with 2012 depletion, depreciation and amortisation in 2013 increased by 3.2% to US$18,488 thousand.

Selling and Administrative Expenses ('S&A')

S&A expenses (excluding share-based payments) decreased by 12.3% to US$24,936 thousand from 2012. These expenses include oil transportation costs, payroll expenses, rent, professional services, property and land taxes, bank charges and other expenses, including costs associated with Ruspetro's status as a public company. The decrease in S&A is largely due to the reduced use of external audit and legal services and decreased lower oil transport services owing to the construction and use of our own intra field pipeline.

Comprehensive Loss for the Year

The Company recorded a loss for the year of US$74,238 thousand. This is approximately US$46,954 thousand higher than the 2012 loss of US$27,284 thousand. After translating the results to the presentation currency, which resulted in a loss of US$11,063 thousand, the total comprehensive loss for the year was US$85,301 thousand.

Cash Flow

Ruspetro ended 2012 with US$34,416 in cash. In 2013, we did not receive any proceeds from the issue of share capital nor did we pay down principal of loans and borrowings. In meeting certain covenants with Sberbank, Ruspetro's principal creditor, we were entitled to an interest payment deferral in 2013, and therefore no interest was paid during the period. In signing a forward oil sale prepayment agreement with Glencore, we received US$30,000 thousand from Glencore in August 2013. We spent US$31,755 on drilling, and US$12,351 thousand on infrastructure development during the year. After an operating cash outflow before working capital adjustments of positive US$8,105 thousand, working capital adjustments of positive US$18,808 thousand and a currency translation difference of negative US$391 thousand we ended the year with a closing cash balance of US$15,832 thousand.

Purchase of Property, Plant and Equipment ('PP&E')

The Company invested US$44,106 thousand in property, plant and equipment in 2013 representing a decrease in investment over 2012 of 58.6%. PP&E assets were US$234,203 thousand at the end of the period, an increase of 104%, whilst mineral rights and other intangibles decreased by 7.0% to US$395,533 thousand.

Financing of Ruspetro's Current Operations and Future Development

On the basis of its current financial resources and its existing external and shareholder debt financing, the Company recognises the need to raise additional funding in the short term. This will allow Ruspetro to implement the horizontal well programme in full and to generate sufficient revenues and cash flow to meet future liabilities as they fall due.

While the existing US$313.4 million facility with Sberbank is due in the end of April 2018, securing financing is essential for the continued development of the field. Therefore Ruspetro is evaluating several strategic transactions and financing alternatives, including a joint venture, farm in, merger/sale, or other capital raising alternatives.

If additional financing is not obtained, the Group may need to amend its development plan and may be unable to realise its assets and discharge its liabilities in the normal course of business. Management considers that these circumstances represent a material uncertainty that may cast doubt on the Group's ability to continue as a going concern, and have described these risks in the accounts as a material uncertainty.

Ruspetro Plc

PRELIMINARY UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

AS AT AND FOR THE YEAR ENDED 31 DECEMBER 2013

Unaudited Consolidated Statement of Comprehensive Income for the year ended 31 December 2013

(Presented in US$ thousands, except otherwise stated)

Unaudited Consolidated Statement of Financial Position for the year ended 31 December 2013

(Presented in US$ thousands, except otherwise stated)

Unaudited Consolidated Statement of Changes in Equity for the year ended 31 December 2013

(Presented in US$ thousands, except otherwise stated)

Unaudited Consolidated Statement of Cash Flows for the year ended 31 December 2013

(Presented in US$ thousands, except otherwise stated)

Ruspetro Plc

Notes to the Consolidated Condensed Financial Statements

for the year ended 31 December 2013

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

1. Basis of preparation

These consolidated financial statements of the Company, including those of its subsidiaries (the 'Group') have been prepared in accordance with International Financial Reporting Standards (IFRSs) as adopted by the European Union. The consolidated financial statements are prepared under the historical cost convention, modified for fair values under IFRS.

The results are unaudited, however we do not expect there to be any difference between the numbers presented and those within the annual report.

The financial information set out here does not constitute the Group's statutory accounts, but is derived from those accounts. The statutory accounts for the year ended 31 December 2013 will be delivered to the Registrar of Companies following the group's annual general meeting. Accounts will be dispatched to shareholders as soon as possible. The auditors opinion is unqualified, but includes an emphasis of matter relating to the material uncertainty over the Group's ability to continue as a going concern.

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

Going concern

These consolidated financial statements are prepared on a going concern basis, which presumes that the Group will be able to realize its assets and discharge its liabilities in the normal course of business in the foreseeable future.

At the reporting date the Group had net current liabilities of $40,137 thousand, which included cash in hand of $15,832 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. 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.

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, prepayment from a forward oil sale agreement, and additional debt or equity financing as required.

During 2013, management renegotiated the terms of the outstanding credit facility with Sberbank with a resulting roll up of interest accruing in 2013 and 2014 and the deferral of its capital repayment until 2018, and obtained US$30 million as a forward oil sale prepayment from Glencore. Since the year end, management has agreed with Sberbank to defer the exercise period for the outstanding put option to April 2015 at the earliest and negotiated a roll-over of the US$30 million advance financing arrangement with Glencore.

In addition to its operational requirements the Group has debt obligations falling due in April 2015 and May 2015 totaling US$56 million. To meet these obligations, in addition to the measures already taken, described above, management has commenced a number of negotiations to (1) secure further shareholder finance, (2) obtain prepayment finance in respect of domestic crude oil, (3) renegotiate the repayment terms of the shareholder loans and (4) secure a further restructuring of the Sberbank loan and deferral of the Sberbank put option. Additionally, management is continuing to develop and evaluate potential strategic and capital raising options in relation to its assets.

Management considers that there is a material uncertainty as to the realization of these potential financing transactions to meet the Group's future capital requirements. Their occurrence may also 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 outcome of these matters is a subject of material uncertainty and may give rise to significant doubt as to the ability of the Group to continue as a going concern.

However, 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

Business Combinations

The Group uses the acquisition method of accounting to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair values of the assets transferred, the liabilities incurred and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Acquisition-related costs are expensed as incurred. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. On an acquisition-by-acquisition basis, the Group recognises any non-controlling interest in the acquiree either at fair value or at the non-controlling interest's proportionate share of the acquiree's net assets.

The excess of the consideration transferred, the amount of any non-controlling interest in the acquiree and the acquisition-date fair value of any previous equity interest in the acquiree over the fair value of the Group's share of the identifiable net assets acquired is recorded as goodwill. If this is less than the fair value of the net assets of the subsidiary acquired in the case of a bargain purchase, the difference is recognised directly in profit or loss.

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 programmes 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 amortization 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 amortization and any accumulated impairment losses. Amortization 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 licenses 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 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 amortized 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 amortized 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 license 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, license 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 recognized 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.

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 (Note 17).

Non-controlling interests

Non-controlling interests ("NCI") is the equity in subsidiaries not attributable, directly or indirectly, to the Company. NCI at the end of the reporting period represents the non-controlling shareholders' portion of the carrying value of the identifiable assets and liabilities of the subsidiary. NCI are presented within equity, separately from the equity, attributable to the Company's shareholders .

The Group treats transactions with NCI as transactions with equity owners of the Group. For purchases from NCI the difference between any consideration paid and the relevant share acquired of the carrying value of net assets of the subsidiary is recorded in equity. Gains or losses on disposals to non-controlling interests are also recognised in equity.

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, value-added tax 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 recognized where the shareholders' right to receive a dividend payment is established.

Leases

Leases in which a significant portion of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Payments made under operating leases (net of any incentives received from the lessor) are charged to the income statement on a straight-line basis over the period of the lease.

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 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 32.73 and 30.37 as at 31 December 2013 and 31 December 2012, respectively and the average rates for the year ended 31 December 2013 and 2012 were 31.85 and 31.07, respectively. The US$ to GBP exchange rates were 0.61 and 0.62 as at 31 December 2013 and 31 December 2012, respectively and the average rates for the year ended 31 December 2013 and 2012 were 0.64 and 0.63, respectively. The increase in the US$ to RUR exchange rate for the year ended 31 December 2013 has resulted in a loss of US$25,586 thousand in the consolidated statement of comprehensive income and an adjustment of US$11,063 thousand in other comprehensive income (refer to Notes 13 and 14).

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.

The financial statements of the subsidiaries are prepared for the same reporting year as the Company, using consistent accounting policies.

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 recognized 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 licenses 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 licenses expire between June 2014 and June 2017.

Regulatory authorities exercise considerable discretion in issuing and renewing licenses and in monitoring licensees' compliance with license 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 licenses held by the Group will be renewed for the economic lives of the fields which are projected to be up to 2040 (two licenses held by INGA) and 2029 (the license 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 consider that the license held by Trans-oil, which was extended for three years to December 2015, will be further extended. This further extension will be depended on management demonstrating to licensing 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 amortization 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.

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 amortization 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 recognize 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 indicates that the market capitalization 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.

If there are indications of loss in value, the recoverable amount is estimated. The recoverable amount is the higher of the assets FVLCS, or its VIU. Management consider that an appropriate approach to determining FVLCS is by discounting the post-tax cash flows expected to be generated by the oil and gas assets, net of associated selling costs, taking into account those assumptions that market participants would use in estimating fair value. The VIU is a discounted cash flow calculation based on continued use of the assets in its present condition, excluding potential exploitation of improvement or expansion potential.

The determination of the recoverable amount for both the FVLCS and the VIU involves assumptions as to future hydrocarbon prices, taxes, production volumes, and inflation. The models also use estimates of proved developed for VIU and proved and probable reserves for FVLCS as developed by the independent Reservoir Engineers, DeGolyer and MacNaughton. Estimated cash flows are 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 our estimation of fair value less cost of sale, management do not consider that the Group's non-current assets are impaired as at 31 December 2013.

Assumption 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 2013 and 2012 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 2013, 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 (postponed).

.

Management expects that the adoption of these accounting standards in future periods will not have a material effect on the financial statements of the Group.

5. Revenue

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

For the years ended 31 December 2013 and 2012, revenue from export sales of crude oil amounted to US$13,306 thousand and US$16,877 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 / income

Other operating income in 2012 arouse in connection with the settlement of debt owed to Makayla Investments Limited.

For a better presentation of the economic nature the expenses of maintenance the temporary idle wells, which in 2012 were presented in the cost of sales amounting to US$1,045 thousand, in 2013 are presented in other operating expenses. For comparability, these costs in 2012 were also restated from the cost of sales to other operating expenses.

Other operating expenses mainly include expenses incurred in the process of Board of directors restructuring.

Other expenses include professional fees, incurred in connection with the Company's cancelled previously proposed bond issue.

7. Income tax

The major components of income tax expense for the years ended 31 December 2013 and 2012 are:

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 recognised previously unrecognised deferred tax assets in respect of tax loss incurred by INGA, because it is probable that sufficient taxable profit to utilise the deductible temporary difference will be available in the future.

The Group did not recognise deferred income tax assets of US$39,682 thousand and US$37,180 thousand, in respect of losses that can be carried forward against future taxable income amounting to US$198,410 thousand and US$185,899 thousand as at 31 December 2013 and 31 December 2012, 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. As at 31 December 2012 losses amounting to US$70,031 thousand, US$43,020 thousand, US$28,990 thousand and US$43,858 thousand expire in 2018, 2019, 2020, 2021 respectively.

8. Property, plant and equipment

For the year ended 31 December 2013, 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 2013, the construction in progress balance mainly represents production wells and oil production infrastructure not finalized (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. Borrowings

Sberbank credit facility On 24 May 2013, the terms of Sberbank's credit facility were amended whereby, inter alia, repayment of a portion of accrued interest and its principal were deferred until April 2018. Payment of part of the accrued interest will be deferred until 25 May 2015 if the Group complies with certain covenants (principally an agreed EBITDA level). The Group was in compliance with covenants at 31 December 2013. The Group paid an agreement amendment fee of US$1,000 thousand for the amendment of the agreement, which is amortized over the remaining term of the facility, with the unamortized part of the fee netted with the credit facility. These amendments did not substantially alter the terms of the original credit facility, and were therefore were not treated as extinguishment of an existing liability and recognition of a new liability. The present valuedifference arising from the renegotiation was recognised over the remaining life of the instrument by adjusting the effective interest rate.

The Group recognised a net foreign exchange loss amounting to US$21,979 thousand and a net foreign exchange gain amounting to US$19,512 thousand during the years ended 31 December 2013 and 2012 respectively on the Sberbank credit facility and outstanding accrued interest which is denominated in US$.

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

On 6 June 2013 and 2 October 2013, the Group rescheduled the maturity of the main Shareholders' loans until May 2015 and May 2018 respectively. 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 the instrument by adjusting the effective interest rate.

11. 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 2013.

This provision has been created based on the Group's internal estimates. Assumptions, based on the current economic environment, have been made which management believe 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.

12. 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 2013 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 2013 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 expenses incurred in the process of Board of directors restructuring, penalties of late payments to suppliers and gain on disposal of assets.