Ruspetro Regulatory News (RPO)

14 APRIL 2016

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

Preliminary Results Announcement

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 its Preliminary Results for the year ended 31 December 2015.

Corporate

· Intention to seek shareholder approval to cancel the listing of the Company's ordinary shares from the premium segment of the Official List and re-register the Company as a private limited company announced (see separate statement issued today at 07.00am)

Operations - Maturing a technical solution for the development of our assets

· Comprehensive internal hydrocarbon resource review completed. Revised 2P oil reserves of 108 mmbbl, 2C oil resources of 223 mmbbl. Appraisal campaign initiated to convert contingent resources into 2P reserves

· Encouraging performance from horizontal well 210, which was drilled and completed at a cost of US$5.4 million. Drilling and fracturing services contracts put in place to underpin a future horizontal well cost target of approximately US$4 million

· Average oil production increased by 13% year on year to 3,989 bpd in 2015. Cash production operating costs reduced from US$16/bbl to US$12/bbl

· Following an international tender, two modern mobile hydraulic rigs sourced and commissioned in the field

· Extended reach drilling combined with a portfolio of fracturing technologies successfully field tested

Financial - Positive Operating Cash Flow before working capital adjustments despite the Low Oil Price Environment

· 2015 Revenues of US$43.9 million, versus US$55.1 million in 2014. EBITDA of US$2.6 million, versus US$9.6 million in 2014

· US$63.8 million undrawn facility available as at the date of this release

· Met the production covenant required to access the second US$50 million tranche of development funds

· Revised Loan Covenants agreed with our primary lenders following a decision to slow the pace of development drilling in response to the sustained weakness in oil prices

· Net debt increased by US$64.8 million to US$299.9 million at period end

· Net loss of US$99.1 million vs. net loss of US$262.9 million in 2014, with exchange rate related losses contributing to a significant extent in both years

· Group current netback per barrel after Mineral Extraction Tax (MET) is US$19 at a Brent price of US$40 due to the favourable tax regime applicable to the Group's tight oil reserves

Outlook - Demonstrating an Economically Attractive Growth Proposition

· Intention to double production levels in 2016

· Implement low cost and flexible appraisal campaign to increase 2P reserves

· Establish a benchmark cost for a horizontal development well with 10-15 fractures below US$4 million

· Establish a material production stream from the UK1 (Abalak formation) capitalising on its zero % MET fiscal regime

· Continue drive to lower cash production operating costs

· Continue tight management of cash and obtain the required refinancing of trade finance lines, in the normal course of business

John Conlin, Chief Executive Officer of Ruspetro plc, Commented: 

"Improved geological insight coupled with the application of proven well technologies has, over a programme of only four wells, led to our most prolific horizontal development well to date. More importantly, this has been delivered at previously unachievable cost, which we can already anticipate to lower significantly. We remain convinced that understanding the geology of the field is the key to smart investment in building production.

"Following a comprehensive review of our sub-surface data and field performance, we have completed the first in-house assessment of our reserves and resources. The headline reserves numbers are significantly lower than those previously provided by external consultants and reserves' auditors. The resources remain substantial but reinforce the need for appraisal to mature areas for future development. This has been initiated with very encouraging early results.

"In 2015, we have established the technical and cost building blocks for a sustainable operating business in a low cost environment. However, given our balance sheet and development capital requirements, this in itself will not guarantee the long-term sustainability of the business. Today therefore, you will also see the announcement concerning the Company's proposed delisting and re-registration as a private limited company. This will give the Group the flexibility to source funding that is not available in the public equity markets, using the asset base and production potential of the Group as valuation benchmarks rather than the market capitalisation of the listed entity. Based on the achievements of the last two years, and despite the current harsh macro-environment, we remain positive for the long term prospects of the Group."

RESOURCES

Approach and methodology

Ruspetro's internal reserves and resources assessment is the result of a thorough re-examination of all our sub-surface geological data and a fresh look at the available seismic data, which has recently been re-processed. All our historical well test and well performance data has also been re-examined and integrated into our models.

Our estimates of Proven and Probable (2P) Reserves and 2C Contingent Resources have been prepared in accordance with Petroleum Resource Management System guidelines endorsed by the Society of Petroleum Engineers. We have rebuilt our resource base with a bottom up technical analysis, incorporating a rigorous probabilistic approach combined with a modular project appraisal and development plan.

The Results

Oil and Associated Gas

The 30 June 2014 external reserve audit estimated 2P Oil and Associated Gas Reserves to be 1727.3 mmbbl and 1171.0 Bcf respectively.

The current in-house estimates of 2P Oil and Associated Gas Reserves are 107.9 mmbbl and 152.4 Bcf respectively, and at the 2C level, Oil and Associated Gas Resources are estimated to be 223.3 mmbbl and 301.5 Bcf respectively.

Clearly, the Company now has a radically different view of the Group's reserves and resources. Previous external reserve audits assumed a region-wide deeper oil-water contact, which was neither supported by wireline interpretation nor by existing production performance. Our variable oil-water contact interpretation combined with the low structural dip has caused us to materially reduce the oil initially in place when compared to previous external reserve audits. Our geological framework is also somewhat more complex than previously assessed.

The Company notes that for the 20 year period up to 2035 the Company's combined estimate of 2P Oil Reserves and 2C Oil Resources (331 mmbbl) is comparable to the GKZ estimate of C1+C2 recoverable oil reserves (435 mmbbl).

While the Group's resources are still substantial enough to build a sizeable EP business, the reality is that a relatively modest fraction of our resource base is now considered mature for development. This is the main rationale for the dedicated appraisal campaign which has been initiated. Early results are encouraging both in terms of reserve maturation and in the validation of the geological concepts we are pursuing.

Non-associated Gas (Palyanovo Licence)

For the gas reservoir within the Palyanovo licence, the 30 June 2014 external reserves audit estimated 2P Non Associated Gas and Condensate Reserves to be 341.0 Bcf and 18.8 mmbbl respectively.

The current in-house estimate of 2P Non Associated Gas and Condensate Reserves is 8.3 Bcf and 0.3 mmbbl respectively and at the 2C level, the Non Associated Gas and Condensate Resources are estimated to be 10 Bcf and 0.5 mmbbl respectively.

The pressure data obtained following the field shut-in early in 2014 provide highly reliable material balance based estimates of the connected gas in place and recoverable gas reserves. Previous estimates were based on unrealistic geo-cellular models with a significantly greater areal extension of the producible gas volume.

These non-associated gas reserves are too small for stand-alone development. Our focus for the future will be to commercialise our associated gas reserves and where it is economically viable, to tie-in the Palyanovo gas on an incremental basis.

Resources Summary

ENQUIRIES:

Ruspetro plc

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

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

Dominic Manley, Investor Relations +44 (0) 207318 1630

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 Krasnoleninsky Arch in Western Siberia.  

CHAIRMAN'S STATEMENT

Shareholders will also see today's announcement regarding the Company's intention to seek Shareholder approval to cancel the listing of the Company's ordinary shares from the premium segment of the Official List and re-register the Company as a private limited company.

Since completing the refinancing and restructuring at the end of 2014, we have embarked on a programme to reduce our operating, administrative and capital costs whilst setting in train an ambitious appraisal and development programme that will enable us to build production from current levels. Our focus is on excellent geological understanding of our assets and the application of well technologies proven elsewhere in the world but not as yet widely applied in Western Siberia.

Despite a 13% increase in production from 3,523 bpd in 2014 to 3,989 bpd in 2015, our revenues have declined from US$55.1 million in 2014 to US$43.8 million in 2015 due to the 46% decline in average price of Brent in 2015 compared to 2014. While we were able to achieve a modest EBITDA for the year of US$2.6 million, this is clearly not sufficient to cover the levels of capital investment required, interest payments on loans outstanding and loan repayments due in the future. Our net debt position increased from US$235.1 million at the start of 2015 to US$299.9 million by the end of the year. The Board, therefore, has considered at length the strategic question of how best to raise the substantial funds necessary to bring the business to the point where it is generating sufficient free cash flow to meet its financial commitments and yield a return for shareholders.

The Board are of the considered view that the funding necessary to achieve our objectives is currently not available in the public equity markets for Ruspetro, given the current sector sentiment and strained geopolitical environment in which it operates. We believe that as a private limited company, Ruspetro will have better prospects of achieving this goal because the principal valuation points that will be used by potential investors in a private company will be the Group's asset base, production and future production potential rather than the low benchmark of the market capitalisation of the listed entity. Furthermore, not having a listing enables us to open discussions with a group of investors who are able to take a longer term view of the Company's prospects and those of the oil and gas sector.

In our view, among the many factors affecting our view of the sustained lack of public equity market sentiment for the Company's publicly listed shares, is the fact that we have not been able to restore the Group's free float above the UKLA's 25% threshold for a premium listed company for well over a year. If the resolutions are carried at the General Meeting and we enter this next phase in the development of the Group we look forward to engaging with all our shareholders and stakeholders to ensure that there is transparency as to our plans and our results.

As a private limited company, if the resolutions are carried at the General Meeting, we will reduce our Board from its current eight members to a Board of six that will include one Independent Non-Executive Director and the current Chief Executive Officer. I will continue to serve as Chairman of the new Board.CEO'S STATEMENT

2015 has been a year in which we have positioned the Company for future profitable growth. With regard to technology implementation, project execution capability both surface and sub-surface, and critically in the current oil price environment, in the dramatic reduction in our projected well costs, we now have a compelling and credible economic development plan for our assets. In a separate section to this report shareholders will see some very impressive examples of our technology driven approach.

During the year, we have built on the 2014 horizontal drilling campaign. In the first half of the year, we drilled and completed two further horizontal multi-stage fractured wells and one deviated well. Bringing these wells online allowed production to reach a level of 6,237 bpd at the end of May. The production performance of the second of the two horizontal wells (well 210) is particularly encouraging, with cumulative oil production after 10 months of 245,000 bbl, while the capital cost of the well was US$5.4 million - approximately half the cost of the first horizontal well completed by the Group in 2014.

The work that the sub-surface team carried out in 2015 confirmed that a relatively modest fraction of our resource base was mature for development. This had a major impact on our development thinking in that a structured appraisal campaign was required, not just to mature reserves, but to define those areas of the field where profitable development wells could be drilled. Central to our revised strategy was the need for drilling units with the potential for faster rig moves to provide the necessary flexibility to respond nimbly to appraisal results.

The Board therefore made the conscious decision to delay the re-start of drilling until we were able to carry out an international tender for suitable rigs. Drilling re-started in late 2015 using two modern hydraulically driven rigs - one light rig for the appraisal programme and a heavier rig for our horizontal development wells. In parallel, we capitalised on the softer services market to introduce innovative, performance based contracting strategies for drilling and completion/fracturing services. These initiatives underpin our expectation to drill and complete a horizontal development well with 10-15 fractures for less than US$4 million.

In the current campaign thus far, we have drilled two multi-fractured horizontal wells (wells 191 and 192) and three deviated appraisal wells (wells 200, 201 and well 411). The two horizontal wells had record horizontal sections and encountered extensive sands (531m net oil sand within a horizontal section of 1269m in well 191, and 435m net oil sand within a horizontal section of 1100m in well 192). These wells are being 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 wells. These two production wells are expected to come on stream in May 2016.

The three appraisal wells have successfully proved our "channel concept" (channel-like distribution of oil-bearing sands), and have given us the confidence to proceed with planning for a horizontal well development campaign on pads 20 and 41. Encouragingly, new low cost benchmarks are being established as each rig moves up the learning curve.

Due to the decision to reduce drilling activity levels in the second half of 2015 in response to the sustained low oil price (as compared to the business plan put forward at the time of the restructuring at a time of high oil prices), the Company and its Lenders recognised that the existing loan covenants could not realistically be met. These were successfully revised such that the Company now has production only covenants for its three credit facilities with its primary lender.

In 2015, we have built a robust business with positive production operating cash flows at current oil prices; however, this in itself will not guarantee the long-term sustainability of the business. The Group is not currently able to generate sufficient cash flow to cover capital investment, or interest and capital repayments on its outstanding borrowings, and it continues to draw down on the debt facilities available to it. Net debt increased from US$235.1 million at the start of 2015 to US$299.9 million by the end of the year.

The Group's future is conditional on securing additional development funding coupled with successful refinancing of its principal debt facilities on maturity albeit that the timing and level depend on the development scenario adopted and the oil price environment.

This is the primary rationale for the delisting decision, although there are other cost and management focus benefits. This is considered to give the Group the flexibility to source funding that is not available in the public equity markets, using the asset base and production potential of the Group as valuation benchmarks rather than the market capitalisation of the listed entity.

We will remain committed to high standards of corporate governance and communication with our shareholders. If the resolutions are carried at the general meeting, as anticipated, I look forward to this next chapter in the Company's history, during which, I believe, we can build value in the business for all of our shareholders.

I would like to end by congratulating all our staff and contractors for contributing to a year when we had no lost time incidents. This is a tremendous achievement given the challenging environment in Western Siberia and in a year when our activity levels have increased significantly from 2014.

Strategy in Action

Geological Insight is the key to our business

Our geology is complex, permeabilities are low and opportunities have been missed in the past to collect key data. Nevertheless we have made significant progress. We have gone right back to basics and have now completed a comprehensive re-assessment of all available data. This included detailed reservoir re-correlation, seismic mapping (stratigraphy, channels) and a full fluid contact and petrophysical review, which culminated in the construction of a field-wide integrated geo-cellular model.

Making more use of our 3D Data

Importantly, we believed that we could extract more insight from the existing 3D data sets. This was evidenced by the recent re-processing of the legacy merged 3D seismic surveys, which has already delivered very valuable input to well placement. We are also designing and planning new 3D seismic in order to cover the Southern portion of the Pottymsko-Inginsky (PI) licence area and enable further appraisal and development works.

Integrated Teamwork

Using state-of-the-art software the Ruspetro team has defined new workflows aiming at integrating all available subsurface data (well, core, seismic, and production test data) with the regional geological framework. This immediately paid off by highlighting several prospective appraisal and development drilling targets. As an example, well 210H was planned to test a stratigraphic play located very near older unsuccessful wells. Careful integration of advanced seismic attributes and well data not only provided an explanation for the offset well results but also defined a possible upside stratigraphic play. Well 210H was drilled in H1 2015 to exploit this, and encountered approximately 750m of net oil sand along the 1050m horizontal section.

Horizontal appraisal to reduce hydrocarbon finding costs

Well 210H was drilled in the Northwestern part of the PI licence area to test a candidate stratigraphic play located in the vicinity of marginal wells. Instead of setting the production casing shoe to the top of the main reservoir target, the decision was made to continue to drill and extend this section until the minimum economic pay would be encountered within a maximum 250m MD section extension. Should the well not have encountered this minimum pay within this extended interval, it would then have been sidetracked to a fallback development target located in a diametrically opposite direction to the primary target. This fallback option is only possible by having a sidetrack kick-off point shallow up near the surface casing. However 210H encountered the targeted pay and was successfully completed and stimulated. This drilling and completion strategy is the key enabler to de-risked appraisal.

Driving down the well costs

We continue introducing technology proven elsewhere into our well construction operations both in drilling and completion, with the objective of simplifying well designs while extending our development reach. New elements introduced for the first time include:

· 4 inch high torque connection drill pipe for the long horizontal sections

· Combination of premium connection casing and rotating liner hanger technology to enhance liner placement and cementation

· Ultra-long (5700m) 2 inch coil tubing for our fracture plans

Central to our strategy has been the introduction of modern hydraulically driven rigs with the potential for faster rig moves to provide greater flexibility to the drilling plan. Our current fleet comprises one light rig for the appraisal programme and a heavier rig for our horizontal development wells. Furthermore, we have capitalised on the softer services market to introduce innovative, performance based contracting strategies for drilling and completion/fracturing services.

The result of this suite of initiatives is a set of benchmark cost targets which in themselves allow us to plan positively even at the prevailing low oil price.

Maturing the Horizontal well Development Concept

Optimising our horizontal well design concept has been a key driver for the business in 2015 to ensure maximum productivity and ultimate total recovery from wells drilled. The key design parameters for the new wells such as the length, orientation, hydraulic fracture density and size are continuously scrutinised to suit our emerging geological insights. Major achievements in 2015 included:

· Developing a suite of technologies comprising both coiled tubing and conventional "plug and perf" solutions.

· Refining our fracture designs and introducing more, much smaller fractures to optimise oil productivity in our thin oil rims

· Refining the relationship between initial well production performance and ultimate recovery

Fit for Purpose Infrastructure

In parallel with the evolution of our sub-surface thinking, we have completed a rigorous review of in-field infrastructure and initiated a number of small but important projects both to redress shortcomings and to prepare for the future. These include:

· A mix of mobile and permanent pad based test separating systems

· Network connection between our produced and injection water systems

· Oil export line

 In addition we have two critical growth projects in progress:

· A CPF expansion

· A 6kV overhead power line and substation

Similarly, but to a lesser extent compared to our sub-surface innovation due to the prevailing legislation, we are challenging hard the conventional Western Siberian approach to design and contracting. As an example we have radically reduced civil engineering costs by introducing regional competition. We have also restructured and enhanced our procurement and contracting processes to ensure transparency and rigour in our assessments of tenders. We have increased our flexibility to respond to appraisal-driven changes to the drilling sequence by putting in place framework contracts for construction; pre-ordering standard materials, and committing early to standard development pad design to obtain approvals in time.

Financial Review

Revenues

Revenues were US$43.9 million in 2015, compared with US$55.1 million in 2014. The drop in revenues was primarily driven by a 46% reduction in the average realised oil price, partially offset by a 13% increase in liquids production.

Cost of sales

The cost of sales, including depreciation and production-related taxes was US$53.9 million in 2015, compared with US$52.7 million in 2014. The increase was driven by various factors, primarily a 13% increase in liquids production for the period, and a US$3.6 million increase in Mineral Extraction Tax ("MET") as a result of the "tax manoeuvre" (an increase of MET with simultaneous decrease of export duty). The additional volumes produced, as well as the production-related reduction in the volume of proved developed reserves, drove a US$1.6 million rise in depletion expense as well as the production-related reduction in the volume of proved developed reserves in 2015. Offsetting the above increases to cost of sales were a US$4.0 million reduction in production-related operating expenses and direct payroll expenses, partially achieved due to the devaluation of the Russian Ruble against the US Dollar.

Selling and administrative expenses (S&A)

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

S&A expenses in 2015 amounted to US$15.6 million, down 21% from US$19.8 million in 2014. The decrease resulted from savings, mostly in payroll expenses, professional services, and rent. Almost all of the above combined savings have been achieved due to the 59% devaluation of the Russian Ruble from the previous period.

EBITDA

EBITDA was US$2.6 million in 2015, compared with US$9.6 million in the previous year. The drop in EBITDA was primarily driven by lower netback (revenues from oil sales less export duty less transportation expenses) which was a result of the 46% decline in the average realised oil price, and, to a lesser extent, an increase in MET. These effects were offset by additional contributions to gross profit from a 13% increase in liquids production, a lower export duty, due to the falling trend of oil prices (as well as the tax manoeuvre as described above), and lower production-related operating and S&A expenses, partially achieved through the devaluation of the Russian Ruble.

Comprehensive loss for the year and foreign exchange

The Group recorded a loss of US$99.1 million for 2015, compared with US$262.9 million in 2014. The 2015 result includes a foreign-exchange loss of US$57.2 million, compared with US$202.4 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$51.3 million in foreign exchange losses. After deducting the foreign-exchange losses from both years, the Group's loss would have been US$41.9 million in 2015, compared with US$60.5 million in 2014.

Balance sheet

Non-current assets have decreased by US$61.1 million, largely explained by the devaluation of the Russian Ruble (contributing to US$85.0 million), partially offset by capital expenditure of US$41.9 million incurred during the period.

Total equity has fallen by US$115.7 million from US$75.7 million to negative US$40.0 million as at 31 December 2015. The movement in total equity was a result mostly of foreign exchange losses as a result of the devaluation in the Russian Ruble.

In December 2015, the Group signed a loan addendum with Otkritie which excluded EBITDA covenants, and reset the production covenants to the Group's revised four year development plan. On 15 January 2016, the Group signed an identical addendum with Trust Bank as with Otkritie, resetting its production covenants and removing EBITDA covenants.

Borrowings have increased from the prior year by US$60.3 million to US$307.4 million, reflecting US$59.6 million drawn down of the Group's existing bank facilities with Otkritie and Trust Bank and US$5.3 million net increase of interest accrued on shareholders loans, partly offset by principal repayments of US$3.7 million and US$0.9 million related to the payment and amortisation of the arrangement fees for Otkritie and Trust Bank facilities.

The Group's current liabilities increased by US$13.3 million primarily due to the reclassification of an existing shareholder loan from Makayla Investments Limited ("Makayla") in the amount of US$20.4 million. This was a long-term liability in the prior period at the previous reporting date. In April 2016 the Group concluded an addendum to the Makayla loan agreement rescheduling the principal and accrued interest repayments into two parts, US$3.1 million in October 2016 and US$20.3 million in May 2017.

The Group paid down accrued interest on the Makayla shareholder loan in the amount of US$5.0 million and decreased its trade and other payables by US$2.7 million mostly due to a decrease of the Group's prepayment facility with Glencore. Within current liabilities between 31 December 2014 and 31 December 2015 there was a US$2.0 million net decrease in prepayments to Glencore as a result of the Group's new US$22.5 million export facility, drawn down in May 2015. US$13.8 million is classified as trade and other payables, and has been offset by the full repayment of three prepayment facilities with Glencore and Energo Resurs LLC, (a Russian company affiliated with Glencore), in the amount of US$14.8 million during the first half of 2015.

Cash flow

In 2015, the Group generated a net cash outflow from operating activities of US$4.7 million, resulting from a negative cash contribution from changes in working capital of US$6.1 million (mostly from a decrease in trade and other payables of US$4.6 million), offset by a positive net cash flow contribution from operating activities of US$1.4 million.

During the period, the Group spent US$35.2 million on investment activities. This consisted of US$20.0 million spent on the construction of new wells, US$10.5 million on infrastructure-related capital expenditures, US$1.9 million on development studies, US$1.6 million on the purchase of intangible and other assets and US$1.2 million in capitalised staff costs.

The Group received loan proceeds of US$59.6 million from Otkritie and Trust, repaid US$3.7 million in principal and paid US$14.3 million in interest. Additionally, the Group repaid US$5.0 million of accrued interest on a shareholder loan.

Cash balances at the end of the period were US$7.5 million compared to US$12.0 million at the end of 2014.

Financing of Ruspetro's current operations and future development

Following the Group's financial restructuring, the Group is able to continue the implementation of its horizontal well programme in the near future. The restructuring was achieved in December of 2014, along with the satisfaction of the 30 June 2015 production covenants, which was a condition for the Group to draw down the second US$50.0 million of its US$100.0 million development facility from Otkritie (subject to continuing to meet the drawdown conditions), along with the planned raising in 2016 of additional trade finance lines from its partners.

Under recent addendae signed in December 2015 and January 2016, the Group must achieve certain annualised production targets that will be tested quarterly from April 2016. The current projections prepared by management for the purposes of preparation of these preliminary unaudited condensed consolidated financial statements show that the Group will not breach its covenants within one year of publishing these preliminary unaudited condensed consolidated financial statements.

Furthermore, in April 2016 the Group signed an additional agreement with Makayla delaying the Group's obligation to repay the loan and accrued interest owed to Makayla from October 2016 until May 2017, with a partial repayment of US$3.1 million due in October 2016, so long as the Group's covenants with Otkritie and Trust Bank are not be breached.

As at the date of this document, the Group has US$63.8 million of undrawn facilities available and is confident that it will, during the course of 2016, secure further domestic and export trade financing lines necessary to fully finance its development programme in the near term. The outcome of such negotiations cannot be certain and, therefore, the directors recognise that this represents a material uncertainty which may cast significant doubt over the Group's ability to continue as a going concern.

Taking into account all considerations relevant to the Group's financial position, management considers it appropriate that the Group's preliminary unaudited condensed consolidated financial statements should be prepared on a going concern basis.

Ruspetro plc

Preliminary Unaudited Condensed Consolidated Financial Statements

As at and for the year ended 31 December 2015

Preliminary Unaudited Consolidated Statement of Profit or Loss and Other Comprehensive Income for the year ended 31 December 2015

(presented in US$ thousands, except otherwise stated)

Preliminary Unaudited Consolidated Statement of Financial Position as at 31 December 2015

(presented in US$ thousands, except otherwise stated)

Preliminary Unaudited Consolidated Statement of Changes in Equity for the year ended 31 December 2015

(presented in US$ thousands, except otherwise noted)

Preliminary Unaudited Consolidated Statement of Cash Flows for the year ended 31 December 2015

(presented in US$ thousands, except otherwise stated)

Notes to the Preliminary Unaudited Condensed Consolidated Financial Statements for the year ended 31 December 2015

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

1. Basis of preparation

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

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

Going concern

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

At 31 December 2015 the Group reported net current liabilities of US$31,651 thousand (2014: US$11,465 thousand), which included cash in bank of US$7,511 thousand (2014: US$12,022 thousand). The Group had negative operating cash flow of US$4,664 thousand in the reporting period (2014: positive operating cash flow of US$3,310 thousand).

The Group's continuing operations are dependent, in particular, 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.

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.

In particular, the Group attained a level of production in the six-months period ended 30 June 2015 required under the terms of its credit facilities with Public Joint-Stock Company "Bank Otkritie Financial Corporation" ("Otkritie") in order to enable it to access the second US$50 million of its US$100 million Development Facility with Otkritie.

In addition, during the reporting period, the Group negotiated the US$22.5 million advance financing arrangement with Glencore Energy UK Ltd. ("Glencore"). Prepayments from forward oil sale agreements are one of the main sources of working capital. The renewal of such prepayments occurs regularly under normal course of business, but cannot be certain and, therefore, the directors recognise that this represents a material uncertainty which may cast significant doubt over the Group's ability 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 preliminary unaudited condensed consolidated 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 investees, including structured entities, that the Group controls because the Group (i) has power to direct the relevant activities of the investees that significantly affect their returns, (ii) has exposure, or rights, to variable returns from its involvement with the investees, and (iii) has the ability to use its power over the investees to affect the amount of the investor's returns. 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 depleted 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 depreciation 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.

Operating leases

Where the Group is a lessee in a lease which does not transfer substantially all the risks and rewards incidental to ownership from the lessor to the Group, the total lease payments are charged to profit or loss for the year on a straight-line basis over the lease term. The lease term is the non-cancellable period for which the lessee has contracted to lease the asset together with any further terms for which the lessee has the option to continue to lease the asset, with or without further payment, when at the inception of the lease it is reasonably certain that the lessee will exercise the option.

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 options. The particular recognition and measurement methods adopted are disclosed in the individual policy statements associated with each item.

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 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 statement of financial position on a gross basis and disclosed separately as a current asset and liability.

Mineral extraction tax

Mineral extraction tax ("MET") 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 Russian ruble (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.

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 recognised 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$ 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 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 RUR72.88 and RUR56.26 as at 31 December 2015 and 31 December 2014, respectively and the average exchange rates for the year ended 31 December 2015 and 2014 were RUR61.29 and RUR38.47, respectively. The US$ to pounds sterling (£) exchange rates were £0.68 and £0.64 as at 31 December 2015 and 31 December 2014, respectively and the average exchange rates for the year ended 31 December 2015 and 2014 were £0.65 and £0.61, respectively. The increase in the US$ to RUR exchange rate for the year ended 31 December 2015 has resulted in a loss of US$57,221 thousand in the preliminary unaudited consolidated statement of profit or loss and other comprehensive loss and an adjustment of US$16,558 thousand in other comprehensive loss (refer to Notes 8 and 9).

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 ongoing 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 June 2017 and December 2165.

The Russian regulatory authorities exercise considerable discretion in issuing and renewing licences and in monitoring licensees' 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. 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 INGA will be further extended.

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 (Note 8). 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 (Note 9).

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 (Note 8). At the end of each reporting period management 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 the 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 the 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 the 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 (Note 12). 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 preliminary unaudited condensed consolidated 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 the value in use approach. The models developed by 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 2015 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 pre-tax nominal discount rate is estimated at 15.2 percent (2014: 13.2 percent).

Based on the impairment analysis performed, management does not consider that the Group's non-current assets are impaired as at 31 December 2015.

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. 99% of total revenues from external customers in 2015 were derived from sales of crude oil and gas condensate (2014: 98%). 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 preliminary unaudited condensed 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 2015 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 (amended in July 2014 and effective for annual periods beginning on or after 1 January 2018).

· IFRS 14 - Regulatory Deferral Accounts (issued in January 2014 and effective for annual periods beginning on or after 1 January 2016).

· IFRS 15 - Revenue from Contracts with Customers (issued in May 2014 and effective for annual periods beginning on or after 1 January 2018).

· IFRS 16 - Leases (issued in January 2016 and effective for annual periods beginning on or after 1 January 2019).

Amendments

· Amendments to IFRS 10, IFRS 12 and IAS 28 - Investment entities: Applying the Consolidation Exception (issued in December 2014 and effective for annual periods beginning on or after 1 January 2016).

· Amendments to IFRS 10 and IAS 28 - Sale or Contribution of Assets between an Investor and its Associate or Joint Venture (issued on 11 September 2014 and effective for annual periods beginning on or after 1 January 2016).

· Amendments to IAS 12 - Recognition of Deferred Tax Assets for Unrealised Losses (issued in January 2016 and effective for annual periods beginning on or after 1 January 2017).

· Amendments to IAS 7 - Disclosure Initiative (issued on 29 January 2016 and effective for annual periods beginning on or after 1 January 2017).

(ii) Endorsed by the European Union

Amendments

· Amendments to IAS 19 - Defined benefit plans: Employee Contributions (issued in November 2013 and effective for annual periods beginning 1 July 2014).

· Annual Improvements to IFRSs 2012-2013 Cycle (issued in December 2013 and effective for annual periods beginning on or after 1 July 2014).

· Amendments to IFRS 11 - Accounting for Acquisitions of Interests in Joint Operations (issued on 6 May 2014 and effective for the periods beginning on or after 1 January 2016).

· Amendments to IAS 16 and IAS 38 - Clarification of Acceptable Methods of Depreciation and Amortisation (issued on 12 May 2014 and effective for the periods beginning on or after 1 January 2016).

· Amendments to IAS 27 - Equity Method in Separate Financial Statements (issued on 12 August 2014 and effective for annual periods beginning 1 January 2016).

· Annual Improvements to IFRSs 2014 (issued on 25 September 2014 and effective for annual periods beginning on or after 1 January 2016).

· Amendments to IAS 1 - Disclosure Initiative (issued in December 2014 and effective for annual periods beginning on or after 1 January 2016).

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 2015 and 2014, revenue from export sales of crude oil amounted to US$12,618 thousand and US$18,811 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, net

Other expenses, net, mainly consist of an insurance claim settlement received and an impairment charge of other assets. In 2015 the Group received an insurance claim settlement in total amount of US$1,800 thousand relating to an incident with damage to insured property during well construction. Impairment of financial instruments was recognised in total amount of US$1,869 thousand.

In 2014 other expenses mainly consisted of impairment of fixed and other assets in amount of US$2,137 thousand, impairment of financial instruments in amount of US$1,285 thousand, and professional fees, incurred in connection with the cancellation of a previously proposed financial transaction by the Company, in amount of US$709 thousand.

7. Income tax

The major components of income tax benefit for the years ended 31 December 2015 and 2014 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 relate 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$53,946 thousand and US$65,172 thousand, in respect of losses that can be carried forward against future taxable income for ten years from the year of losses recognition, amounting to US$269,879 thousand and US$325,861 thousand as at 31 December 2015 and 31 December 2014, respectively.

The Group did not recognise deferred income tax assets in respect of losses that can be carried forward without limiting the year of expiration against future taxable income amounting to US$14,567 thousand and US$21,514 thousand as at 31 December 2015 and 31 December 2014.

8. Property, plant and equipment

For the years ended 31 December 2015 and 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 2015 and 2014, the construction in progress balance mainly represents production wells and oil production infrastructure not finalised (e.g. pads, electricity grids, etc.).

The Group's property, plant and equipment in total amount of US$7,841 was pledged under the credit facility agreements with Otkritie as at 31 December 2015 (31 December 2014: nil).

For a better presentation of their nature, several items of fixed assets, similar to those items of fixed assets classified as other property, plant and equipment in 2014 with cost of US$2,966 thousand and US$1,725 thousand as at 1 January 2014 and 31 December 2014 respectively, were classified as oil and gas properties. For comparability, the depreciation of these items for 2014 in total amount of US$999 thousand was restated and reallocated from administrative expenses to cost of sales (Note 8 and Note 9).

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

Issued and paid up share capital of the Company as at 31 December 2015 and 2014 consisted of 870,112,016 ordinary shares with a par value of £0.10 each.

11. Borrowings

Otkritie credit facilities The loan facility from Otkritie in the amount of US$150,000 thousand obtained and drawn down in full in December 2014, pursuant to a loan agreement dated 14 November 2014, is repayable in November 2019, bears interest at 8% per annum and is subject to certain covenants, including production targets. In December 2015 an addendum to the credit facility agreements was concluded whereby the applicable covenants were modified and provided solely for reduced production targets.

14 November 2014 credit facility 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 2015, facilities in total amount of US$24,400 thousand out of US$100,000 thousand and US$21,344 thousand out of US$44,700 thousand were drawn down under these agreements, respectively (31 December 2014: nil).

Trust credit facility On 17 November 2015 the Group entered into a credit facility agreement with Public Joint-Stock Company "National Bank Trust" (Trust), a bank affiliated with Otkritie, for the amount of US$25,600 thousand. This relates to utilisation of the funding available under the first US$50,000 thousand tranche of the Development Facility with Otkritie. As at 31 December 2015, total amount of US$13,841 thousand was drawn down under this facility.

On 15 January 2016 an addendum to the credit facility with Trust was concluded, whereby the applicable covenants were modified and provided solely for reduced production targets.

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. Certain loans of an amount US$303 thousand have matured by 31 December 2015 and 2014 and are presented as current liabilities.

In May 2015 interest in total amount of US$5,000 thousand was repaid under the one of the Shareholders' loan agreements. 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$57,221 thousand and US$202,410 thousand during the years ended 31 December 2015 and 2014 respectively, out of which US$51,322 thousand and US$196,084 thousand relate to the US$ denominated credit facilities and outstanding accrued interest for the years ended 31 December 2015 and 2014 respectively.

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 23 years from 31 December 2015.

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 loss 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 2015 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.

14. Earnings before interest, taxes, depreciation and amortisation (EBITDA)

Earnings before interest, taxes, depreciation and amortisation for the year ending 31 December 2015 is calculated by adding finance costs, depletion, depreciation and amortisation, 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.