Interim Results for 6M 2013

Exillon Energy plc

Interim results for the first six months of 2013

27 August 2013

27 August 2013 - Exillon Energy plc (EXI.LN), a London Premium listed independent oil producer with assets in two oil-rich regions of Russia, Timan-Pechora ("Exillon TP") and West Siberia ("Exillon WS"), today issues its interim results for the first six months to 30 June 2013.

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"During the first half of 2013 we delivered a dramatic increase in reserves (increasing 2P reserves by 96%), and continued strong financial performance (an 83% increase in EBITDA). Our production increased 35% over the same period in 2012, and 9% over the second half of 2012."

Financials

Our EBITDA increased 83% year-on-year, from US$15.6 million to US$28.6 million, while we posted a net profit of US$7.9 million compared to a US$1.7 million net loss in the first half of 2012.

We had US$72.9 million of cash and cash equivalents as at 30 June 2013. Net debt position was US$27.3 million. As of 23 August 2013 our cash and cash equivalents had increased to US$97.8 million and our net debt was therefore US$3.3 million.

Reserves

As announced in March 2013, our total proved ("1P") reserves increased by 56% to 196 million barrels, our total proved plus probable ("2P") reserves increased by 96% to 520 million barrels and our total proved plus probable plus possible ("3P") reserves increased by 121% to 882 million barrels.

Production

Oil production increased 35% from 2.1 million to 2.83 million barrels equivalent to an increase from 11,539 bpd to 15,621 bpd compared to H1 2012, and 9% from 2.6 million to 2.83 million compared to H2 2012.

We publish quarterly production data, and therefore have already announced details of our production for the period. For reference we summarise below the monthly data published during the six month period. Also disclosed is our production data for July:

Primarily because of the reduction in our drilling programme for 2013 in Exillon TP, we have revised our production expectations for December 2013. We now expect production to reach between 18,000 and 19,000 bpd, once the ongoing upgrade to our oil processing facility is completed. Further details are given later in this statement.

Dear Shareholders,

Our strategy is to deliver a balance of growth in production, EBITDA and reserves. During the first half of 2013 we delivered a dramatic increase in reserves (increasing 2P reserves by 96%), and continued strong financial performance (an 83% increase in EBITDA). Our production increased 35% over the same period in 2012, and 9% over the second half of 2012.

Drilling and Production - Exillon WS

Production at Exillon WS is currently constrained by an oil processing capacity bottleneck. This currently caps daily production at 1,600 tonnes (approximately 12,500 barrels) per day. We have continued to complete additional wells and therefore we have "behind pipe" capacity. A second stage of the oil processing facility is expected to be completed in November 2013, at which point we estimate that production in Exillon WS is likely to increase by approximately 2,000 bpd.

During the period we drilled, completed and announced 8 wells in Exillon WS. These were announced on 13 June and 18 July. We have recently drilled, and are currently completing and testing, four more wells in EWS. These are wells 71, 73, 80, 92 and we expect to announce results shortly. In addition we are currently drilling Wells 74 and 93.

Drilling and Production - Exillon TP

Exillon TP has had mixed drilling results this year. Some of the wells discovered thick oil saturated net pay formations confirming or exceeding our geological model. However flow rate results from these wells were lower than expected because of a lack of natural fractures.

We are now working with an international project institute to reinterpret our existing seismic data in order to adjust our drilling programme to better target highly fractured zones. We believe that this additional analysis is necessary to extract the greatest value from Exillon TP, and we will therefore pause our current drilling programme until these studies have been completed.

During the period we drilled, completed and announced 3 wells in Exillon TP. These were announced on 18 July. We do not now intend to complete the 4 additional wells that had been planned for the 2013 drilling programme in TP (2 each from Pads 2 and 3). As a result we do not expect any further production growth in ETP in 2013.

Drilling and Production - 2013 drilling results (all previously announced)

This year in EWS we have previously announced via RNS the results of EWS I - 70, EWS I - 64, EWS I - 65, EWS I - 66, EWS I - 90, EWS I - 201, EWS I - 91, EWS I - 72. In Exillon TP we announced Well North ETP VI - 3, Well ETP VI - 2 and Well ETP IV - 5002.

EWS I - 70

Well EWS I - 70 was drilled on the northern extension of the East EWS I field. The well was spudded on the 4th May 2013 and drilled and cemented in 13 days. The well encountered the Jurassic P reservoir at 1,871 metres, confirming 17.8 metres of effective vertical net oil pay.

The well flowed oil naturally to the surface with a flow rate of 499 bbl/day on an 8 mm choke. The well was drilled vertically from Pad 7, and is now connected to our existing production facilities.

 EWS I - 64

Well EWS I - 64 was drilled on the north-west extension of the EWS I field. The well was spudded on the 1st February 2013 and drilled and cemented in 29 days. The well encountered the Jurassic P reservoir at 1,862 metres, confirming 2.7 metres of effective vertical net oil pay.

Upon perforation the well flowed 220 bbl/day, of which 44 bbl/day was oil. The well was drilled 1.1 km to the north-west of Pad 6. Due to the fact that the well is located lower than any other well on the structure it has been converted to water injection for the purposes of maintaining reservoir pressure.

EWS I - 65

Well EWS I - 65 was drilled on the north-west extension of the EWS I field. The well was spudded on the 3rd March 2013 and drilled and cemented in 25 days. The well encountered the Jurassic P reservoir at 1,858 metres, confirming 8.6 metres of effective vertical net oil pay and 14.2 metres of net pay along the well bore.

The well is currently operated with a submersible pump flowing at 156 bbl/day, of which 85 bbl/day is oil. Going forward we will seek to minimize water cut in the production from this well. The well was drilled 1.6 km to the north-west of Pad 6, and is now connected to our existing production facilities.

EWS I - 66

Well EWS I - 66 was drilled on the north-west extension of the EWS I field. The well was spudded on the 30th March 2013 and drilled and cemented in 14 days. The well encountered the Jurassic P reservoir at 1,852 metres, confirming 10.5 metres of effective vertical net oil pay and 18.2 metres of net pay along the well bore.

The well is currently operated with a submersible pump flowing at 574 bbl/day, of which 551 bbl/day is oil. The well was drilled 1.0 km to the north-east of Pad 6, and is now connected to our existing production facilities. Well 6 is the last planned well from Pad 6.

Appraisal well EWS I - 90

Appraisal well EWS I - 90 was designed to test the north-east extension of the EWS I field. The structure was previously tested with well EWS I - 61, but due to a long deviation of well EWS I - 61, the structure was not tested for flow rates.

The well was spudded on the 13th April 2013 and drilled and cemented in 34 days. 18.4 metres of core was collected, which is represented by mudstones, gravel conglomerates, and sandstones. The core exhibits signs of hydrocarbon saturation. During a test the well has produced only a film of oil due to low permeability of the producing horizon.

We will assess the core data for methods of producing from this reservoir. Two additional wells have been previously planned for drilling in this part of the field in 2013. No further drilling will be completed in this area of the field prior to the completion of petrophysical studies.

The well was drilled 0.7 km to the south-east of Pad 9, and has been converted to a water source well.

EWS I - 91

Well EWS I - 91 was drilled on the central part of the north-west extension of the EWS I field. The well was spudded on the 18th May 2013 and drilled and cemented in 20 days. The well encountered the Jurassic P reservoir at 1,856 meters, confirming 4.3 meters of effective vertical net oil pay and 7.2 meters of net pay along the well bore.

The well is currently operating with a submersible pump flowing oil at 377 bbl/day. The well was drilled 1.2 km to the north-west of Pad 9, and is now connected to our existing production facilities.

EWS I - 72

Well EWS I - 72 was drilled on the margin of the northern extension of the East EWS I field. The well was designed to test the productivity of the margin of the field which represents a transitional zone between collector quality sands and non-collector.

The well was spudded on the 8th June 2013 and drilled and cemented in 18 days. The well encountered the Jurassic P reservoir at 1,876 meters, confirming 4.3 meters of effective vertical net oil pay.

The well is currently operating with a submersible pump flowing oil at 94 bbl/day. The well was drilled 0.6 km to the north of Pad 7.

Appraisal well North ETP VI - 3

Appraisal well North ETP VI - 3 was designed to test northern extension of the North ETP VI field.

The well was spudded on 27 March 2013 and drilled and cemented in 84 days. The well encountered Lower Silurian reservoir at 3,175 metres, confirming 12.2 metres of absolute effective net oil pay.

The well is currently being tested with natural oil rates to surface ranging from 488 bbl/day on an 18 mm choke to 92 bbl/day on a 6 mm choke. The well was drilled vertically from Pad 3, and is now connected to existing production facilities.

Exploration well ETP VI - 2

Exploration well ETP VI - 2 was drilled on the southern tip of the ETP VI structure. The well was spudded on 29 April 2013 and drilled and cemented in 70 days.

45.5 meters of core were collected, which is represented by low permeability carbonates with no signs of hydrocarbon saturation. During a test the well did not produce oil.

We will re-assess the geological model of the area and intend to conduct a fracture survey. Two additional wells have been previously planned for drilling in this part of the field in 2013. No further drilling will be completed in this area of the field prior to the completion of the fracture survey.

Well ETP IV - 5002

Well ETP IV - 5002 was spudded on 12 February 2013 and drilled and cemented in 64 days on the northern part of the ETP IV field. The well encountered Lower Silurian reservoir at 3,272 metres, confirming 15.6 metres of absolute effective net oil pay. In addition, the well encountered Domanic reservoir at 3,245 metres, confirming 5.7 metres of absolute effective net oil. Due to the angled trajectory of the well bore, this well exposed 25.4 metres of effective net oil pay.

The well is currently operating with a submersible pump flowing oil at 8 bbl/day. To increase the flow rate from this well we will consider conducting an acid hydrofrack in the upcoming winter season.

The well was drilled 0.9 km to the north-west of Pad 5, and is now connected to existing production facilities. Well ETP IV - 5002 is the last planned well from Pad 5.

Infrastructure

In order to improve our profitability we have continued to enhance and complete significant items of infrastructure. In ETP our 25 km gas pipeline (for associated gas) is now operational, and the parallel 25 km oil pipeline is complete and expected to be operational by the end of 2013.

In EWS our 40 km intra-field pipeline was completed on time and on budget, doubling its capacity. Our oil treatment facility on our main EWS I field is operating at full capacity, and is currently being expanded from a capacity of 1,600 tonnes (approximately 12,500 bpd) to 3,000 tonnes (approximately 23,400 bpd). We expect this upgrade to be completed later this year.

We are finalising our plans in EWS to utilize our associated gas. This is necessary in order to fulfil our licence obligations and to avoid flaring penalties. In order to accomplish this in a cost effective manner we are actively considering a project to extract lighter fractions from our oil. We currently produce oil that is lighter (and therefore more valuable) than Urals blend. However most of our sales in EWS are currently blended via the Transneft network and we lose the value of this quality premium. Extracting lighter fractions will allow us to monetise some of this quality premium at the same time as increasing power consumption and thereby gas utilisation. Once implemented these plans could lead to a material increase in EBITDA per bbl. Overall capex for this project is within our existing budget for gas utilisation projects.

Capital expenditure during the period was approximately US$ 66.1 million (45% of which was in ETP and 55% in EWS). Of this total, US$17.7 million was attributable to drilling, US$47.6 million to infrastructure and US$0.8 million to seismic data acquisition and interpretation.

Financial Performance

During the first six months of 2013 our oil production increased by 35% from 2.1 million barrels to 2.83 million barrels. This was equivalent to average production for the 6 months of 15,621 bpd, and also an increase of 11% over the 14,089 bpd for the second 6 months of 2012.

During the reporting period, our revenue increased 15% from US$140.0 million to US$161.6 million. Our netback (which we define as revenue less Mineral Extraction Tax, Export Duty and Transneft charges) rose 30% from US$44.5 million to US$57.7 million.

EBITDA increased 83% from US$15.6 million in H1 2012 to US$28.6 million in H1 2013, whilst net profit grew from US$1.7 million of net loss to US$7.9 million of net profit. The growth in EBITDA and net profit was a result of continuing investment in our surface infrastructure and our increased production.

EBITDA was equivalent to US$10.2 per barrel compared to US$7.6 per barrel in H1 2012. However this was lower than achieved in H2 2012 mainly because of lower netbacks. The main driver for these lower netbacks was the declining trend in the price of Urals during the period.

Our balance sheet remains strong with US$72.9 million of cash and cash equivalents as at 30 June 2013. As at 30 June 2013, debt was US$100.2 million, so our net debt position was US$27.3 million. As of yesterday our cash and cash equivalents had increased to US$97.8 million and our net debt was therefore US$3.3 million.

Exillon's strategy is to deliver to our shareholders a balance of growth in production, reserves and profitability. We will continue to adapt the geographical balance of our investment programme between ETP and EWS, as well as the pace of this programme, to deliver these goals.

Mark Martin

Chief Executive Officer

FINANCIAL REVIEW

The interim condensed consolidated financial information of Exillon Energy plc for the six month period ended 30 June 2013 has been prepared in accordance with IAS 34 "Interim Financial Statements". The condensed consolidated financial information and notes on pages 9 through to 27 should be read in conjunction with this review which has been included to assist in the understanding of the Group's financial position at 30 June 2013.

Summary

EBITDA for the six months ended 30 June 2013 increased by 83% to US$28.6 million compared to US$15.6 million for the six months ended 30 June 2012.

Net profit for the period, which includes depreciation costs, foreign exchange loss and share-based compensation, amounted to US$7.9 million compared to net loss of US$1.7 million for the six months ended 30 June 2012.

Revenue

Our revenue for the six months ended 30 June 2013 increased by 15% year-on-year, reaching US$161.6 million (2012: US$140.0 million), of which US$67.6 million or 42% came from export sales of crude oil and US$94.0 million or 58% came from domestic sales of crude oil. This increase in revenue is attributable to:

· An increase in production leading to a 36% increase in sale volumes from 2,063,842 bbl in 2012 to 2,811,932 bbl; and

· A change in average commodity prices: we achieved an average oil price of US$97.5/bbl (2012: US$106.9/bbl) for export sales and US$44.4/bbl (2012: US$43.8/bbl) for domestic sales.

Currently our netback for domestic sales is higher than the one for export sales because of the fluctuations in oil prices. Our total netback for domestic and export sales increased by 30% from US$44.5 million to US$57.7 million year-on-year.

Operating Results

Operating costs excluding depreciation, depletion and amortisation increased to US$76.6 million (2012: US$58.4 million) following an increase in production of 35% to 2,827,312 bbl (2012: 2,100,162 bbl). The difference between the production volumes and sales volumes is due to the change in the oil inventory balance during the year. The increase in production costs is mainly related to the growth of mineral extraction tax from US$45.0 million in 2012 to US$60.3 million in 2013, as a result of higher production volumes and increased tax rate. Another cost driver was the increased gas flaring penalties.

Depreciation, depletion and amortisation costs primarily relate to the depreciation of proven and probable reserves and other production and non-production assets. These costs totalled US$11.2 million (2012: US$8.2 million). The increase in DD&A costs is driven by higher production volumes and by bringing into operation infield facilities once their construction was completed.

Selling expenses for the six months ended 30 June 2013 of US$46.15 million (2012: US$55.7 million) is comprised of export duties of US$35.4 million (2012: US$44.1 million), transportation services of US$10.73 million (2012: US$10.8 million) and other selling expenses of US$0.02 million (2012: US$0.8 million). Transportation services include services provided by Transneft and transportation services from oil field to oil filling station. In 2013, the export duty rate fluctuated within the range from US$359.3 per tonne to US$420.6 per tonne following the changes in crude oil prices. Export duty is reviewed by the Russian government on a monthly basis and is based on a formula that takes into account the average Urals price prevailing in the market between the 15th of the previous month and 14 th--- of the month of delivering the crude.

Administrative expenses (excluding share-based compensation expenses, depreciation and amortisation) totalled US$10.7 million (2012: US$10.5 million). In 2013, savings were achieved in salary and related taxes, business trip and office rent expenses with increase in consulting services.

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In 2013, interest income increased to US$1.8 million (2012: US$1.6 million) resulting from surplus cash being held on short-term deposits and VTB credit-linked deposits.

It should be noted that - in accordance with IFRS - a foreign exchange loss of US$3.8 million has been included in our net profit arising from the revaluation of foreign currency monetary items (cash and cash equivalents, accounts receivable and payable, other assets) using the closing rate at the reporting date. A larger foreign exchange loss of US$35.5 million has been applied directly to the consolidated statement of financial position as the part of translation reserve.

As a result of the above, the Group reported a net profit after tax of US$7.9 million compared to a loss of US$1.7 million for the six months ended 30 June 2012.

Financial position

We ended the period with US$72.9 million of cash and cash equivalents (31 December 2012: US$121.0 million) and outstanding borrowings of US$100.2 million.

The increase in the property, plant and equipment has been driven by extensive drilling of wells, the construction of 40 km pipeline from infield oil processing facility to oil filling station and other field developments in Exillon WS; successfully completed construction of two 25 km pipelines for transportation of oil and gas to the refinery and drilling of wells at Exillon TP. This was offset by a translation difference due to the depreciation of the Russian Rouble against the US Dollar at the reporting date.

Principal risks and uncertainties

The principal risks and uncertainties affecting the business activities of the Group are set out on pages 18 to 19 of the Directors' Report section of the Annual Report for the year ended 31 December 2012, a copy of which is available on the Company's website at www.exillonenergy.com. The Board continually assesses and monitors the key risks of the business. The principal risks and uncertainties that could have a material impact on the Group's performance over the remainder of the financial year have not changed from those which are set out in the Group's 2012 Annual Report.

Directors

A full list of Directors is maintained on the Group's website: exillonenergy.com.

Related parties

Related party transactions are given in note 23.

Statement of directors' responsibilities

The Directors of the Company hereby confirm that to the best of their knowledge:

(a) the condensed consolidated interim financial statements have been prepared in accordance with IAS 34 and give a true and fair view of the assets, liabilities, financial position and profit and loss of the Group as required by DTR 4.2.10(4); and

(b) the interim management report includes a fair review of the information required by DTR 4.2.7 (being an indication of important events that have occurred during the first six months of the financial year and their impact on the condensed set of financial statements; and a description of the principal risks and uncertainties for the remaining six months of the year) and DTR 4.2.8 (being related party transactions that have taken place in the first six months of the current financial year and that have materially affected the financial position or performance of the entity during that period).

On behalf of the board of directors of Exillon Energy plc.

Mark Martin

Chief Executive Officer

 Disclaimer

This statement may contain forward-looking statements concerning the financial condition and results of operations of the Group. Forward-looking statements are statements of future expectations that are based on the management's current expectations and assumptions and involve known and unknown risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied in these statements. No assurances can be given as to future results, levels of activity and achievements and actual results, levels of activity and achievements may differ materially from those expressed or implied by any forward-looking statements contained in this report. The Company does not undertake any obligation to update publicly or revise any forward-looking statement as a result of new information, future events or other information.

INDEPENDENT REVIEW REPORT TO EXILLON ENERGY PLC

Introduction

We have been engaged by the Exillon Energy PLC (the "Company") to review the condensed consolidated set of financial statements in the half-yearly financial report for the six months ended 30 June 2013 which comprises the interim consolidated statement of comprehensive income, interim consolidated statement of financial position, interim consolidated statement of changes in equity, interim consolidated statement of cash flows and the related notes 1 to 24. We have read the other information contained in the half yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed consolidated set of financial statements.

This report is made solely to the company in accordance with guidance contained in International Standard on Review Engagements 2410 (UK and Ireland) "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Auditing Practices Board. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our work, for this report, or for the conclusions we have formed.

Directors' Responsibilities

The half-yearly financial report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure and Transparency Rules of the United Kingdom's Financial Conduct Authority.

As disclosed in note 2, the annual consolidated financial statements of the company are prepared in accordance with IFRS. The condensed consolidated set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34, "Interim Financial Reporting".

Our Responsibility

Our responsibility is to express to the Company a conclusion on the interim condensed consolidated set of financial statements in the half-yearly financial report based on our review.

Scope of Review

We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410, "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Auditing Practices Board for use in the United Kingdom. A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK and Ireland) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the interim condensed consolidated set of financial statements in the half-yearly financial report for the six months ended 30 June 2013 is not prepared, in all material respects, in accordance with International Accounting Standard 34 and the Disclosure and Transparency Rules of the United Kingdom's Financial Conduct Authority.

Ernst & Young LLC

Chartered Accountants

Douglas

Isle of Man

23 August 2013

Interim Consolidated Statement of Comprehensive Income

* Unused vacation accrual of $219 thousand was reclassified from changes in working capital to operating cash flow before working capital changes to provide consistency with the presentation for the six months 2013.

 Notes to Interim Condensed Consolidated Financial Statements (Unaudiated)

1. Background

The principal activity of Exillon Energy plc (the "Company" or the "Parent") and its subsidiaries (together "the Group") is exploration, development and production of oil. The Group's production facilities are based in the Republic of Komi and the Khanty-Mansiysk Region of the Russian Federation. The Group's structure is provided in Note 24.

Exillon Energy plc is a public limited company which is listed on the London Stock Exchange and is incorporated and domiciled in the Isle of Man. The Company was formed on 27 March 2008. Its registered address is Fort Anne, South Quay, Douglas, Isle of Man, IM1 5PD.

As at 30 June 2013, the largest shareholder has 30.2% (2012: 30.2%) in the Company's outstanding issued share capital.

The Group's operations are conducted primarily through its operating segments, Exillon TP and Exillon WS.

2. basis of preparation

This condensed consolidated interim financial information for the six months ended 30 June 2013 has been prepared in accordance with International Accounting Standard ("IAS") 34, "Interim financial reporting". The condensed consolidated interim financial information should be read in conjunction with the annual financial statements for the year ended 31 December 2012, which have been prepared in accordance with International Financial Reporting Standards ("IFRSs"). The operations carried out by the Group are not subjected to the seasonality or cyclicality factors.

3. going concern

The Group's business activities, together with the factors likely to affect its future development, performance and position including financial risk factors are set out on page 7. In carrying out their assessment, the Directors have considered the Group's budget, the cash flow forecasts, trading estimates, contractual arrangements, committed financing and exposure to contingent liabilities. The Directors believe that the Group's forecasts and projections, taking account of reasonably possible changes in trading performance, show that the Group is adequately financed and the Group therefore continues to adopt the going concern basis in preparing its consolidated interim financial statements.

4. ACCOUNTING POLICIES

Accounting policies - the accounting policies applied are consistent with those of the annual consolidated financial statements for the year ended 31 December 2012, except for the adoption of new standards and interpretations effective as of 1 January 2013:

· IAS 1 Presentation of Items of Other Comprehensive Income - Amendments to IAS 1 (effective on or after 1 January 2013)

The amendments to IAS 1 change the grouping of items presented in other comprehensive income (OCI). Items that could be reclassified to profit or loss at a future point in time (for example, net gain on hedge of net investment, exchange differences on translation of foreign operations, net movement on cash flow hedges and net loss or gain on available-for-sale financial assets) would be presented separately from items that will never be reclassified (for example, actuarial gains and losses on defined benefit plans and revaluation of land and buildings). The amendment affects presentation only and has no impact on the Groups financial position or performance.

· IAS 19 Employee Benefits (effective on or after 1 January 2013)

The revised standard has no impact on the Group's financial position or performance.

· IAS 28 Investments in Associates and Joint Ventures (effective on or after 1 January 2013)

The revised standard has no impact on the Group's financial position or performance.

· IFRS 1 Government Loans - Amendment to IFRS 1 (effective on or after 1 January 2013)

The amendment has no impact on the Group's financial position or performance.

· IFRS 7 Disclosures - Offsetting Financial Assets and Financial Liabilities - Amendment to IFRS 7 (effective on or after 1 January 2013)

These amendments have no impact on the Group's financial position or performance.

· IFRS 10 Consolidated financial statements (effective 1 January 2013)

IFRS 10 replaces the portion of IAS 27 Consolidated and Separate Financial Statements that addresses the accounting for consolidated financial statements. It also addresses the issues raised in SIC-12 Consolidation - Special Purpose Entities.

IFRS 10 establishes a single control model that applies to all entities including special purpose entities. The changes introduced by IFRS 10 will require management to exercise significant judgment to determine which entities are controlled and therefore are required to be consolidated by a parent, compared with the requirements that were in IAS 27. The new standard has no impact on the currently held investments of the Group.

· IFRS 11 Joint Arrangements (effective 1 January 2013)

The new standard has no impact on the Group's financial position or performance.

· IFRS 12 Disclosure if Interests in Other entities (effective 1 January 2013)

The amendment affects presentation only and has no impact on the Groups financial position or performance.

· IFRS 13 Fair value measurement (effective 1 January 2013)

IFRS 13 establishes a single source of guidance under IFRS for all fair value measurements. IFRS 13 does not change when an entity is required to use fair value, but rather provides guidance on how to measure fair value under IFRS when fair value is required or permitted. The application of IFRS 13 has not impacted the fair value measurements carried out by the Group.

During the six months ended 30 June 2013 the Group has not early adopted any other standard, interpretation or amendment that has been issued but is not yet effective.

Annual Improvements May 2012

These improvements have no impact on the Group, but include:

· IFRS 1 First-time Adoption of International Financial Reporting Standards

This improvement clarifies that an entity that stopped applying IFRS in the past and chooses, or is required, to apply IFRS, has the option to re-apply IFRS 1. If IFRS 1 is not re-applied, an entity must retrospectively restate its financial statements as if it had never stopped applying IFRS.

· IAS 1 Presentation of Financial Statements

This improvement clarifies the difference between voluntary additional comparative information and the minimum required comparative information. Generally, the minimum required comparative information is the previous period.

· IAS 16 Property Plant and Equipment

This improvement clarifies that major spare parts and servicing equipment that meet the definition of property, plant and equipment are not inventory.

· IAS 32 Financial Instruments, Presentation

This improvement clarifies that income taxes arising from distributions to equity holders are accounted for in accordance with IAS 12 Income Taxes.

· IAS 34 Interim Financial Reporting

The amendment aligns the disclosure requirements for total segment assets with total segment liabilities in interim financial statements. This clarification also ensures that interim disclosures are aligned with annual disclosures.

These improvements are effective for annual periods beginning on or after 1 January 2013.

Critical accounting judgements and key sources of estimation uncertainty:

The preparation of interim financial statements requires management to make judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets and liabilities, income and expense. Actual results may differ from these estimates.

In preparing these condensed consolidated interim financial statements, the significant judgements made by management in applying the Group's accounting policies and the key sources of estimation uncertainty were the same as those that applied to the consolidated financial statements for the year ended 31 December 2012.

5. OPERATING SEGMENTS

Management has determined the operating segments based on the reports reviewed by Directors that are used to make strategic decisions, who are deemed to be the chief operating decision maker ("CODM").

Since 2013 Exillon Energy plc manages its business as two operating segments, Exillon TP and Exillon WS. In November 2012 all assets from Regional Resources, which represented the third operating segment in 2012, were transferred to other companies of the Group registered in Russian Federation. After that on 22 November 2012 the Company sold its ownership shares in Regional Resources to a third party with an insignificant gain. The trading role of Regional Resources was taken over by the companies of Exillon TP and Exillon WS to the extent of crude oil produced by the corresponding segment.

· Exillon TP: upstream business based in the Timan-Pechora basin in the Komi Republic in the Russian Federation. The revenue is derived from extraction and sale of crude oil.

· Exillon WS: upstream business based in Western Siberia in the Russian Federation. The revenue is derived from extraction and sale of crude oil.

Segmental information for the Group for the six months ended 30 June 2013 is presented below:

Segmental information for the Group for the six months ended 30 June 2012 is presented below:

The transfer prices between operating segments are on an arm's length basis in a manner similar to transactions with third parties.

Unallocated category represents costs of corporate companies that are managed at the Group level.

Management assesses performance of the operating segments based on EBITDA which is calculated as follows: operating result plus depletion and depreciation, plus/minus foreign exchange gains/(losses) and plus/minus other significant one-off income/(expenses). Other significant one-off items for the six months ended 30 June 2013 included a loss of $19 thousand arising on the disposal of equipment and $190 thousand of fair value adjustment of loan issued (Note 21 and 23). The measure also excludes the effects of equity-settled share-based payments. Starting from 2012 year loss on disposal of property, plant and equipment is excluded from the EBITDA calculation and prior period information has been changed accordingly.

Net back is defined as revenue less direct and indirect government taxation. The indicator calculated as revenue less Mineral Extraction Tax, Export Duty and Transneft transportation services.

Reconciliation of operating profit/(loss) to EBITDA for the six months ended 30 June 2013 is presented below:

Reconciliation of operating profit/(loss) to EBITDA for the six months ended 30 June 2012 is presented below:

6. revenue

7. cost of sales

8. selling expenses

9. administrative expenses

10. earnings per share

Basic earnings per share ("EPS") is calculated by dividing net profit/(loss) for the year attributable to ordinary equity shareholders of the Group by the weighted average number of ordinary shares outstanding during the period.

The following reflects the income and adjusted share data used in the EPS computations:

11. Property, plant and equipment

Decommissioning costs of $8,681 thousand and $7,360 thousand were included within oil and gas properties as of 30 June 2013 and 31 December 2012, respectively.

Cumulative capitalized borrowing costs of $13,773thousand and $10,609 thousand were included within oil and gas properties as of 30 June 2013 and 31 December 2012, respectively. Total borrowing costs incurred during the six months ended 30 June 2013 period amounted to $3,164 thousand and were capitalized in full.

Exploration and evaluation assets as of 30 June 2013 and 31 December 2012 comprise the ETP VI licence acquired in February 2010 and the ETP VII licence acquired in December 2011. Construction in progress relates to the construction of in-field infrastructure and drilling of oil wells commenced in 2012.

12. Inventories

13. trade and other receivables

In determining the recoverability of a trade receivable, the Group considers any change in the credit quality of the trade receivable from the date credit was initially granted up to the reporting date. The concentration of credit risk is limited due to the customer base. Accordingly, the management of the Group believes that there is no further credit provision required in excess of the allowance for doubtful debts.

14. other assets

15. SHORT-TERM LOANS ISSUED

In September - November 2012 the Group has signed a number of preliminary agreements to process the acquisition of subsoil licences and certain other non-current assets of VenlockNeft LLC ("Venlock") for a total consideration of $2,719 thousand. Completion of the transaction is subject for certain actions and approvals and is planned for 2013.

As a part of Venlock acquisition process in 2012 year the Group issued a loan to a third party of $2,719 thousand maturing in December 2013.

16. provision for decommissioning

In accordance with the licence agreements the Group is liable for site restoration, clean up and abandonment of the wells upon completion of their production cycle. The provision for future site restoration relates to obligations to restore the oilfields after use. All of these costs are expected to be incurred at the end of the life of wells between 2027 and 2038. They depend on the estimated lives of the wells, the scale of any possible contamination and the timing and extent of corrective actions.

The unwinding of the discount related to future site restoration and abandonment reserve is included within finance costs. The management believes that this estimate of the future liability is appropriate to the size of the fields.

17. trade and other payables

18. borrowings

There is no material difference between the carrying amount and fair value of borrowings.

Credit Suisse - On 10 September 2010, the Group agreed a loan facility of $50 million with a term of 3.5 years. Interest is charged at LIBOR plus 7%.

The first repayment of principal was made in January 2012 in compliance with the repayment schedule.

In March 2012 the existing loan facility was replaced by a $100 million loan facility with a term of 5 years. The loan bears an interest rate at LIBOR plus 6% and is repayable in equal quarterly installments beginning from March 2014. The interest is payable quarterly with the first payment made in June 2012.

Unamortised borrowing costs of $1,514 thousand incurred in relation to the previous loan facility of $50 million were written off to the statement of comprehensive income in March 2012.

Borrowing costs of $2,160 thousand directly attributable to the extension of loan facility were immediately recognised in the statement of comprehensive income in 2012.

The loan is secured by a pledge of the 100% shares of certain Group's subsidiaries (Note 24): Ucatex Oil LLC, Kayumneft CJSC, Nem Oil CJSC, Komi Resources CJSC, Ucatex Ugra LLC, Actionbrook Limited, Claybrook Limited, Diamondbridge Limited, Lanarch Limited, Halescope Limited, Vitalaction Limited, Corewell Limited, Touchscope Limited, Silo Holdings Limited and Exillon Finance Limited.

The loan is also secured with future revenue under export contracts and cash balances from a bank account opened in CJSC Bank Credit Suisse (Moscow).

19. Share capital

The amount of share capital available for issue at the date of these consolidated financial statements and the issued share capital of the Company are as follows: