EXI.L Regulatory News (EXI)

Exillon Energy plc

Interim results for the first six months of 2017

1 September 2017 - Exillon Energy plc ("Exillon", the "Company" or the "Group") (EXI.LN), a London Premium listed independent oil producer with assets in two oil-rich regions of Russia, Timan-Pechora ("Exillon TP" or "ETP") and West Siberia ("Exillon WS" or "EWS"), today issues its interim results for the first six months to 30 June 2017.

Highlights

• Net profit decreased by 12% to US$19.6 million (US$22.3 million in 1H 2016)

• EBITDA decreased by 9% to US$34.6 million (US$38.1 million in 1H 2016)

• EBITDA per barrel increased by 23% to US$17.4 per barrel (US$14.2 per barrel in 1H 2016)

• Production decreased by 25%, with the average production for 1H 2017 equivalent to 11,118 bpd

Production

Our oil production decreased by 25% from 2.69 million to 2.01 million barrels equivalent to a decrease from 14,807 bpd to 11,118 bpd compared to 1H 2016, and 14% from 2.33 million to 2.01 million barrels equivalent to a decrease from 12,652 bpd to 11,118 bpd compared to 2H 2016.

The decrease in our production is reflecting natural production decline curve due to the natural depletion; although this did not result in any impairment of oil and gas properties.

We publish monthly production data, and, therefore, have already announced details of our production for the period. For reference the monthly data published during the six month period of 2017 is summarised below.

Dear Shareholders,

The first six months of 2017 were reasonably successful for Exillon. Continuous volatility of oil prices and production decline affected our ability to generate the recurring growth of financial results for the period, although we still delivered robust financial performance with positive EBITDA and net profit.

Financial Position and Performance

Our EBITDA decreased by 9% from US$38.1 million to US$34.6 million, with a net profit of US$19.6 million (compared to a net profit of US$22.3 million in 1H 2016). Although our revenue slightly increased from US$64.1 million to US$64.4 million, our netback (which we define as revenue less mineral extraction tax, export duty and Transneft charges) decreased by 5% from US$52.4 million to US$50.0 million. The growth in our revenue was primarily a consequence of higher average oil prices during 1H 2017 as compared to 1H 2016, reflecting the movements in global oil prices. This was offset by a decrease in our sales volumes, resulting from the decline in our production. Rising average oil prices led to a simultaneous significant increase in mineral extraction tax, despite the ongoing application of certain tax exemptions by Exillon TP and Exillon WS, with a corresponding decrease in our netback.

Our EBITDA after allocation of central costs was equivalent to US$17.4 per barrel compared to US$14.2 per barrel in 1H 2016 and US$14.0 per barrel in 2H 2016. The indicator was significantly improved, despite the decrease in absolute values of the indicators mentioned above. While our netback decreased by 5%, netback per barrel was equivalent to US$25.2 per barrel compared to US$19.5 per barrel in 1H 2016 and US$22.0 per barrel in 2H 2016. This improvement was driven by appreciation of the Russian Rouble, which enhanced the US dollar equivalent of netback and EBITDA, and by higher average prices achieved in 1H 2017 as compared to 2016.

76% of our oil production was from Exillon WS and 24% from Exillon TP. EBITDA per barrel on an operating level (before central costs) was US$21.2 per barrel in Exillon WS (1H 2016: US$16.2 per barrel) and US$5.7 per barrel in Exillon TP (1H 2016: US$7.3 per barrel). The spread in EBITDA per barrel is growing wider between operating segments due to mineral extraction tax exemption applied by Exillon WS.

Our financial position remains strong with US$43.5 million of cash and cash equivalents as at 30 June 2017 (31 December 2016: US$146.5 million). In March 2017, a term loan of US$100.0 million, which we took out in March 2012, was fully repaid. In April 2017, we entered into new facility agreements for an aggregate principal amount of up to US$206 million. As at 30 June 2017, the outstanding debt amounted to US$124.6 million. Our net debt position was US$81.1 million (31 December 2016: outstanding debt of US$7.7 million and net cash position of US$138.8 million).

As of 1 September 2017 our cash and cash equivalents increased to US$45.1 million resulting in a net debt position of US$79.5 million.

Capital expenditure during the period was US$232.6 million (1H 2016: US$4.8 million), 91% of which was incurred in Exillon WS and 9% in Exillon TP (1H 2016: 84% in Exillon WS and 16% in Exillon TP). Of this total, US$2.7 million was attributable to drilling, US$5.2 million to infrastructure and US$224.7 to advance payments for property, plant and equipment (1H 2016: US$2.0 million was attributable to drilling, US$2.7 million to infrastructure and US$0.1 million to seismic data acquisition and interpretation). In 1H 2017, advance payments for property, plant and equipment were made in relation to drilling of wells and construction of infield infrastructure under the Group's investment program for the years 2017-2021, which was approved by the Board of Directors.

Drilling Update

During the period we drilled one production and one exploratory oil well. The drilling was carried out only at Exillon WS and the drilling results were successful for both wells.

Dmitry Margelov

Chief Executive Officer

FINANCIAL REVIEW

The interim condensed consolidated financial information of Exillon Energy plc for the six month period ended 30 June 2017 has been prepared in accordance with IAS 34 "Interim Financial Statements". The condensed consolidated financial information and the relevant notes 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 2017 and financial performance for the six months then ended.

Revenue

Our revenue for the six months ended 30 June 2017 increased by 0.5% compared to the same period in 2016, reaching US$64.4 million (1H 2016: US$64.1 million), of which 100% came from domestic sales of crude oil (1H 2016: US$14.1 million or 22% came from export sales of crude oil and US$50.0 million or 78% came from domestic sales of crude oil). This change in revenue is attributable to:

· a decrease in production leading to a 26% decrease in sales volumes from 2,683,413 bbl in 1H 2016 to 1,987,146 bbl in 1H 2017;

· an increase in average commodity prices: we achieved an average oil price of US$32.4 / bbl for domestic sales (1H 2016: US$22.8 / bbl). During 1H 2016 we achieved an average oil price of US$28.9 / bbl for export sales; and

· Russian Rouble appreciation, which increased the US dollar equivalent of our revenue. The effective average exchange rate was 70.2583 Russian Roubles to one US dollar (Rouble/US$) in 1H 2016 and 57.9862 Rouble/US$ in 1H 2017.

Operating Results

Cost of sales excluding depreciation and depletion expenses increased to US$23.0 million (1H 2016: US$16.6 million), despite the decrease in production by 25% to 2,012,360 bbl (1H 2016: 2,694,875 bbl). The difference between the production volumes and sales volumes is due to the change in the oil inventory balance during the period. The major increase occurred in mineral extraction tax from US$7.1 million in 1H 2016 to US$13.6 million in 1H 2017. It was a combined result of:

· both operating segments: substantial increase in average crude oil prices used in the calculation of the tax, the increase of the base tax rate from 857 Russian Roubles per tonne of crude oil in 2016 to 919 Russian Roubles per tonne in 2017 and Russian Rouble appreciation, which increased the US dollar equivalent of mineral extraction tax;

· Exillon WS: during both periods Exillon WS applied a 0% mineral extraction tax rate to the oil produced from a certain oil reservoir, which includes oil production from the majority of oil wells located at EWS I and EWS II oil fields. The tax exemption for this oil reservoir was introduced by Russian legislation in the second half of 2015 with an effective date from 1 January 2015 (Note 7). In 1H 2017, a 0% tax rate was applied to 1,140,512 bbl or 74% of crude oil produced by Exillon WS out of the total production of 1,534,306 bbl (1H 2016: a 0% tax rate was applied to 1,766,814 bbl or 84% of crude oil produced by Exillon WS out of the total production of 2,102,145 bbl). As a result, in Exillon WS the tax was accrued for 393,794 bbl of crude oil in 1H 2017 as compared to 335,331 bbl 1H 2016, which also contributed to the increase in mineral extraction tax. In 1H 2017, Exillon WS applied a reducing factor to the mineral extraction tax rate, which reflects the specific characteristics of the remaining oil production from the EWS II oil field (Note 7). This partially offset the increase in mineral extraction tax from higher taxable production volumes in Exillon WS;

· Exillon TP: during both periods Exillon TP applied decreasing factors to the base mineral extraction tax rate, which reflect the specific characteristics of oil production from the ETP V and ETP VI oil fields (Note 7). This tax exemption had a similar effect for both periods, while the decrease in Exillon TP production partially offset general increasing factors mentioned above.

Depreciation and depletion costs ("DD&A") primarily relate to the depreciation of proved and probable reserves and other production and non-production assets. These costs amounted to US$8.7 million in 1H 2017 compared to US$8.9 million in 1H 2016. The decrease in DD&A costs was driven by lower production volumes, which was offset by DD&A charge on the additions to property, plant and equipment and Russian Rouble appreciation, since most of DD&A costs are nominated in Russian Roubles.

Selling expenses in 1H 2017 amounted to US$3.1 million (1H 2016: US$7.5 million) and comprised of transportation services of US$2.5 million and services of Transneft crude oil metering system of US$0.6 million (1H 2016: export duties of US$3.0 million, transportation services of US$3.7 million and services of Transneft crude oil metering system of US$0.8 million). The major decrease related to export duty as a result of change in our sales mix. Transportation services included services provided by Transneft and trucking services from the infield oil filling stations to oil terminals at Transneft. In 1H 2016, transportation services provided by Transneft of US$1.6 million related to export sales of crude oil. While in 1H 2017, transportation services provided by Transneft of US$0.7 million related to domestic sales of crude oil in Exillon TP for the period from January to April 2017. During 1H 2016 and the period from May to June 2017 domestic customers of both operating segments have been paying directly to Transneft for its transportation services. Exillon TP used Transneft crude oil metering system services at a cost of US$0.6 million in 1H 2017 as compared to US$0.8 million in 1H 2016. The decrease is a result of reduced production volumes. The decrease in Russian Rouble nominated trucking services to Transneft from US$2.1 million in 1H 2016 to US$1.8 million in 1H 2017 is a result of lower production volumes partially offset by the appreciation of the Russian Rouble against US dollar.

Administrative expenses in 1H 2017 (excluding depreciation and amortisation) amounted to US$3.9 million in comparison to US$2.8 million in 1H 2016, with the main increase attributable to consulting services.

In 1H 2017 interest income amounted to US$4.3 million (1H 2016: US$0.8 million) resulting from surplus cash being held on short-term bank deposits and purchase of short-term interest-bearing bank bills of exchange.

It should be noted that in accordance with IFRS a foreign exchange loss of US$3.3 million (1H 2016: US$2.1 million) has been included in our net profit arising from the revaluation of foreign currency monetary items (cash and cash equivalents, accounts receivable and payable, other monetary assets) using the closing rate at the reporting date. The foreign exchange loss recognised in 1H 2016 was a result of the exchange rate decrease from 72.8827 Rouble/US$ as of 31 December 2015 to 64.2575 Rouble/US$ as of 30 June 2016. During 1H 2016 the foreign exchange loss arising on US dollar denominated cash held by Russian subsidiaries was offset by foreign exchange gain attributable to the intercompany loan, which is expected to be settled to fund repayments of the Group's external debt and is not considered to be as permanent as equity (Note 4). The foreign exchange loss in 1H 2017 was mostly attributable to US dollar nominated cash and cash equivalents held by Russian subsidiaries and was a consequence of the exchange rate decrease from 60.6569 Rouble/US$ as of 31 December 2016 to 59.0855 Rouble/US$ as of 30 June 2017. During both periods the exchange rate experienced substantial volatility: in 1H 2016 it fluctuated between the highest rate of 83.5913 Rouble/US$ achieved on 22 January 2016 and the lowest rate of 63.7162 Rouble/US$ achieved on 23 June 2016; while in 1H 2017 the highest rate of 60.6569 Rouble/US$ was achieved on 01 January 2017 and the lowest rate of 55.8453 Rouble/US$ was achieved on 26 April 2017. A foreign exchange gain of US$10.6 million (1H 2016: gain of US$41.2 million) has been recognised in other comprehensive income as part of the translation reserve.

As a result of the above, net profit for the first six months of 2017, which includes depreciation costs and foreign exchange translation effects, amounted to US$19.6 million compared to net profit of US$22.3 million for the six months ended 30 June 2016.

Financial position

We ended the period with US$43.5 million of cash and cash equivalents and outstanding borrowings of US$124.6 million (31 December 2016: US$146.5 million and US$7.7 million, respectively). In March 2017 the loan principal of US$7.7 million has been repaid in compliance with the repayment schedule, being the last principal payment under a term loan of US$100.0 million, which we took out in March 2012. In April 2017, we entered into new facility agreements and received US$125.0 million. As at 30 June 2017, the entire outstanding borrowings relate to the long-term portion of the loan principal. According to the repayment schedule it will be repaid beyond 12 months after the reporting date.

The additions to the property, plant and equipment of US$232.7 million included US$0.1 million of capitalised interest, US$224.7 million of advance payments for property, plant and equipment with the remaining amount attributable to the drilling of oil wells and further development of infield infrastructure in Exillon WS and Exillon TP. This was partially offset by depreciation and depletion of US$8.7 million, while the positive effect was enhanced by the translation difference of US$9.0 million, due to the appreciation 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 21 to 24 of the Directors' Report section of the Annual Report for the year ended 31 December 2016, 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 that were set out in the Group's 2016 Annual Report.

For reference we summarise below the principal risks and uncertainties:

· substantial and/or extended decline in the prices for crude oil;

· fluctuations in currency exchange rates materially and adversely affecting our financial results and condition;

· continued high levels of inflation in Russia;

· potential significant capital expenditures that may be required to increase production levels and overall efficiency, and any inability to finance these and other expenditures;

· suspension, restriction, termination or lack of extension to our exploration and production licences issued by the Russian authorities;

· potential claims and liabilities under environmental, health, safety and other laws and regulations;

· under-development of the Russian legal system and Russian legislation creating an uncertain environment for investment and business activity;

· potential tax audits by the Russian tax authorities, resulting in additional tax liabilities;

· frequent changes to Russian tax law and practice;

· operational risks of drilling and the introduction of new technology, leading to losses and failure to achieve planned production targets;

· drilling, exploration and production risks and hazards which may prevent us from realising profits resulting in substantial losses;

· poor condition of Russian physical infrastructure leading to disruption of normal business activity;

· third party provision of some services, including transportation services;

· transportation of produced crude oil via a single pipeline system operated by an external provider - Transneft;

· variable weather conditions at our oil fields which may limit the production during certain times of the year;

· intense competition within the oil industry and adverse effects by global economic conditions;

· forced liquidation of some companies in the Group as a result of negative net assets;

· social, political and economic instability in the Russian Federation leading to a potential material adverse effect on operations, financial conditions and prospects;

· crime and corruption hindering the Company's ability to conduct business effectively leading to a material adverse effect on our financial condition and results of operations;

· dependence on senior management personnel and on maintaining a highly qualified skilled workforce;

· failure to manage the Company's growth or to execute or integrate acquisitions;

· changes in the foreign policy of the Russian government and changes in its key global relationships leading to an adverse effect on the Russian political and economic environment in general;

· potential difficulties in enforcing court decisions and the discretion of governmental authorities to file and join claims and enforce court decisions preventing the Group or investors from obtaining effective redress in court proceedings;

· foreign and court judgments not being recognised and enforceable against the Group's Russian subsidiaries;

· increased presence of the Russian state within the private sector as a consequence of the international financial crisis and the resulting downturn in Russian economy. Expropriation or nationalisation of any of the Group's or subsidiaries' assets without fair compensation, leading to a material adverse effect on the Group's business, prospects, financial condition and results of operations;

· shareholder liability under Russian legislation leading to the Company becoming liable for the obligations of its Russian subsidiaries.

Directors

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

Related parties

Related party transactions are disclosed in Note 21.

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

(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.

Dmitry Margelov

Chief Executive Officer

Disclaimer

This document 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 2017 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 22. 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 International Financial Reporting Standards. 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 condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2017 is not prepared, in all material respects, in accordance with International Accounting Standard 34 as adopted by the European Union and the Disclosure and Transparency Rules of the United Kingdom's Financial Conduct Authority.

Ernst & Young LLP

London

1 September 2017

INTERIM consolidated statement of comprehensive income

INTERIM consolidated statement of changes in equity

Total interest paid during the six months ended 30 June 2017 comprised $685 thousand (the six months ended 30 June 2016: $1,286 thousand).

notes to INTERIM condensed consolidated financial statements (UNAUDITED)

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 22.

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 current registered address is First Names House, Victoria Road, Douglas, Isle of Man, IM2 4DF. (Before 01 August 2017 the registered address was Fort Anne, South Quay, Douglas, Isle of Man, IM1 5PD).

As at 30 June 2017, the largest shareholder has an interest of 29.99% (2016: 29.99%) 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 2017 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 2016, which have been prepared in accordance with International Financial Reporting Standards ("IFRSs"). The operations carried out by the Group are not subject to seasonality or cyclical factors.

3. going concern

The principal risks and uncertainties, which are likely to affect the Group's future development, performance and position including financial risk factors are set out in paragraph "Principal risks and uncertainties" above. The Group's forecasts and projections, taking account of reasonable changes in trading performance (including oil price), show that the Group can operate with its current cash holding. The assessment was performed with consideration of Group's business, budget, cash flow forecast, trading estimates, contractual arrangements, committed financing and exposure to contingent liabilities, financial covenant calculation and the principal risks and uncertainties.

Having considered the above matters, the Directors have a reasonable expectation that the Group has adequate resources to continue operational existence and meet its liabilities as they fall due for the foreseeable future, being at least 12 months from the date of approval of the condensed consolidated interim financial statements. For this reason the Directors continue to adopt the going concern basis of accounting in preparing the 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 2016.

During the six months ended 30 June 2017 the Group has not early adopted any other standard, interpretation or amendment that has been issued but is not yet effective:

· IFRS 15 Revenue from Contracts with Customers (effective on or after 1 January 2018)

The new standard removes inconsistencies and weaknesses in existing revenue recognition standards by providing clear principles for revenue recognition in a robust framework; provides a single revenue recognition model which will improve comparability over a range of industries, companies and geographical boundaries; and simplifies the preparation of financial statements by reducing the number of requirements to which preparers must refer. The Group plans to adopt the new standard on the required effective date. The Group performed a preliminary assessment of IFRS 15, which is subject to changes arising from a more detailed ongoing analysis. Crude oil is sold only on its own in separately identified contracts with customers, with no bundled package of goods and/or services. Contracts with customers in which crude oil sale is the only performance obligation are not expected to have any significant impact on the Group. The Group expects the revenue recognition to occur at a point in time when control of the asset is transferred to the customer, generally on delivery of the goods. This is consistent with the Group's existing accounting policy for revenues.

Critical accounting judgments 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 2016, except for the change in certain major assumptions used in estimation of decommissioning costs:

Decommissioning costs

Provision for decommissioning represents the present value of decommissioning costs relating to the Russian Federation oil and gas interests, which are expected to be incurred in a time period between 2025 and 2038. These provisions have been created based on the Group's internal estimates. Assumptions, based on the current economic environment, have been made which management believe are a reasonable basis upon which to estimate the future liability. Those estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning works required which will reflect market conditions at the relevant time. Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce at economically viable rates. This in turn will depend upon future oil and gas prices, which are inherently uncertain.

Major assumptions used in estimation of decommissioning costs are set out below:

Exillon TP:

· as at 30 June 2017, undiscounted value of estimated future cash outflows is estimated at $6,133 thousand (31 December 2016: $5,951 thousand);

· expected timing of future cash outflows - the majority of the expenditure is expected to take place in a range between 2026 and 2038 (2016: between 2026 and 2038);

· discount rate (based on long-term maturity Russian government bonds) - 8% per annum (2016: 9%);

· inflation rate (based on the external analysts' forecasts) - 4% per annum (2016: 4-7%).

If the discount rate had increased by 1% to 9% at 30 June 2017, the decommissioning liability would have been $441 thousand lower (31 December 2016: $406 thousand lower).

Exillon WS:

· as at 30 June 2017, undiscounted value of estimated future cash outflows is estimated at $11,584 thousand (31 December 2016: $11,161 thousand);

· expected timing of future cash outflows - the majority of the expenditure is expected to take place in 2025 (2016: 2025);

· discount rate (based on long-term maturity Russian government bonds) - 8% per annum (2016: 9%);

· inflation rate (based on the external analysts' forecasts) - 4% per annum (2016: 4-7%).

If the discount rate had increased by 1% to 9% at 30 June 2017, the decommissioning liability would have been $600 thousand lower (31 December 2016: $606 thousand lower).

Estimation of oil and gas reserves

Oil and gas reserves are key elements in the Group's investment decision-making process. They are also an important element in testing for impairment. Changes in oil and gas reserves, particularly proved and probable reserves, will affect unit-of-production depreciation charges in the consolidated statement of comprehensive income.

Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. Estimates of oil and gas reserves are inherently imprecise, require the application of judgement and are subject to future revision. Accordingly, financial and accounting measures (such as depletion charges and provision for decommissioning) that are based on proved and probable reserves are also subject to change.

Proved reserves are estimated by reference to available reservoir and well information. All proved reserves estimates are subject to revision, either upward or downward, based on new information, such as from development drilling and production activities or from changes in economic factors, including product prices, contract terms or development plans. In general, changes in the technical maturity of hydrocarbon reserves resulting from new information becoming available from development and production activities have tended to be the most significant cause of annual revisions.

In general, estimates of reserves for undeveloped or partially developed fields are subject to greater uncertainty over their future life than estimates of reserves for fields that are substantially developed and being depleted. As a field goes into production, the amount of proved reserves will be subject to future revision once additional information becomes available through, for example, the drilling of additional wells or the observation of long-term reservoir performance under producing conditions. As those fields are further developed, new information may lead to revisions.

Changes to the Group's estimates of proved and probable reserves also affect the amount of depletion recorded in the Group's consolidated financial statements for property, plant and equipment related to oil and gas production activities. A reduction in proved and probable reserves will increase depletion charges (assuming constant production) and reduce profit.

Proved and probable reserve estimates of the Group as of 30 June 2016 were based on the reports prepared by Miller and Lents Ltd, independent engineering consultants, adjusted by production for the second half of 2016 and the six months ended 30 June 2017.

As at 30 June 2017, the net carrying amount of oil and gas properties and related cost of production licence was $298,858 thousand (31 December 2016: $296,163 thousand).

Taxation

The Group is subject to income tax and other taxes. Significant judgment is required in determining the provision for income tax and other taxes due to the complexity of the tax legislation incorporated in the Russian Federation. There are many transactions and calculations for which the ultimate tax determination is uncertain. The Group recognises liabilities for anticipated tax audit matters based on estimates on whether additional tax will be due. Where the final tax outcome is different from the amounts that were initially recorded, such differences will impact the amount of tax and tax provisions in the period in which such determination is made.

Net investment in foreign operations

Loans issued to foreign subsidiaries, the settlement of which is neither planned nor likely to occur in the foreseeable future, form part of the Group's net investment in those subsidiaries. In 2014 the Group transferred $43.0 million from Exillon Finance LLC to Kayumneft JSC through an intercompany loan. The Group did not consider that repayment of this intercompany loan was likely to occur in the foreseeable future. The intercompany loan formed a part of the Group's net investment in Kayumneft JSC. Foreign exchange differences on the intercompany loan and the corresponding tax effect were recognised in other comprehensive income.

In light of continued decline in oil prices and significant weakening of Russian Rouble leading to the decrease in the Group's profits, in June 2015 management reassessed the judgement and determined that this intercompany loan was expected to be settled to fund repayments of the Group's external debt. During the six months ended 30 June 2017, a foreign exchange gain of $198 thousand on the intercompany loan has been recognized in profit or loss (30 June 2016: a foreign exchange gain of $4,046 thousand). The relevant Group's external debt has been fully repaid in March 2017.

Impairment

The carrying value of the Group's assets can be significantly affected by change in oil prices. The drastic drop in oil price during the last quarter of 2014 and its continuous volatility thereafter have indicated potential impairment of oil and gas properties. The detailed impairment review analysis was made as of 31 December 2016. For this assessment, oil and gas assets were grouped into cash-generating units (being the Group's oil fields), while other property, plant and equipment assets were allocated to oil fields according to their reserve share in the total portfolio. The recoverable amount for each cash-generating unit was determined based on the future cash flows to be obtained from the proved and probable reserves of the relevant oil field discounted to their present value. The projection of cash flows was made for the period covering 2035, being the expected period to extract currently estimated reserves. With reference to the analysis performed, management was able to conclude that in each cash-generating unit the recoverable amount (based on fair value less costs of disposal) exceeds the carrying amount of the related assets, and therefore there is no impairment to be recognised as of 30 June 2017 (31 December 2016: nil).

5. OPERATING SEGMENTS

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

Exillon Energy plc manages its business through two operating segments, Exillon TP and Exillon WS.

· 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.

No operating segments have been aggregated to form the above reportable operating segments.

Segmental information for the Group for the six months ended 30 June 2017 is presented below:

Segmental information for the Group for the six months ended 30 June 2016 is presented below:

The selling prices between operating segments are on an arm's length basis in a manner similar to transactions with third parties. There were no intersegment revenues during the six months ended 30 June 2016 and 2017.

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).

Net back is defined as revenue less direct and indirect government taxation. The indicator is calculated as revenue mineral extraction tax, export duty and Transneft transportation services.

Reconciliation of profit/(loss) before income tax to EBITDA for the six months ended 30 June 2017 is presented below:

Reconciliation of profit before income tax to EBITDA for the six months ended 30 June 2016 is presented below:

During the six months ended 30 June 2017 the Group earned revenues each exceeding 10% of the Group's revenues from four major customers: $14,879 thousand (attributable to domestic sales reported by Exillon TP), $8,477 thousand, $8,540 thousand and $9,437 thousand (attributable to domestic sales reported by Exillon WS).

During the six months ended 30 June 2016 the Group earned revenues each exceeding 10% of the Group's revenues from three major customers: $13,204 thousand (attributable to domestic sales reported by Exillon TP), $14,077 thousand and $20,111 thousand (attributable to export and domestic sales reported by Exillon WS, respectively).

6. revenue

7. cost of sales

During the six months ended 30 June 2016 and 2017, Exillon WS applied 0% mineral extraction tax rate to the oil produced from a certain oil reservoir, which includes oil production from the majority of oil wells located at the EWS I and EWS II oil fields. The tax exemption for this oil reservoir was introduced in the second part of 2015 (with effective date from 1 January 2015). The tax exemption amounted to $18,999 thousand for the first six months of 2017 and $16,695 thousand for the first six months of 2016. During the six months ended 30 June 2017, Exillon WS applied a reducing factor to the mineral extraction tax rate, which reflects the specific characteristics of the remaining oil production from the EWS II oil field. The tax exemption amounted to $609 thousand for the first six months of 2017.

During the six months ended 30 June 2016 and 2017, Exillon TP applied reducing factors to the mineral extraction tax rate, which reflect the specific characteristics of oil production from the ETP V and ETP VI oil fields. The tax exemption amounted to $689 thousand for the first six months of 2017 and $418 thousand for the first six months of 2016.

8. selling expenses

9. administrative expenses

10. earnings per share

Basic earnings per share ("EPS") is calculated by dividing net profit for the period attributable to ordinary equity shareholders of the Company 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 $7,116 thousand and $6,942 thousand were included within oil and gas properties as of 30 June 2017 and 31 December 2016, respectively. Change in estimates relates to the change in the assumptions used in estimation of decommissioning costs (Note 4).

Cumulative capitalized borrowing costs of $19,918 thousand and $19,808 thousand were included within oil and gas properties as of 30 June 2017 and 31 December 2016, respectively. Total borrowing costs incurred during the six months ended 30 June 2017 period amounted to $741 thousand, of which $110 thousand were capitalised (31 December 2016: total borrowing costs amounted to $1,727 thousand of which $541 thousand was capitalised). There is no tax relief related to the capitalised borrowing costs.

Exploration and evaluation assets as of 30 June 2017 and 31 December 2016 comprise the ETP VII licence acquired in December 2011. Construction in progress relates to the construction of infield infrastructure and drilling of oil wells commenced in 2016 and 2017.

Additions to construction in progress include $224,741 thousand of advances issued for the capital construction. All types of expenses (such as well drilling, construction and development of infield infrastructure) to be incurred are capitalised in accordance with the Group accounting policy.

Advance payments for property, plant and equipment include $128,208 thousand of advances paid and refunded during the six months ended 30 June 2017. In January-February 2017 the Company made advance payments for a total amount of $97,774 thousand in relation to a potential purchase of office buildings. The remaining amount of $30,434 thousand relates to advance payments for the drilling of oil wells and further development of infield infrastructure. The transactions did not proceed and consequently are not reflected in additions to property, plant and equipment. The amount of $134,470 thousand was refunded in full in March 2017. The difference of $6,262 thousand between amounts of advance payments and refunds relates to translation gain that is part of other comprehensive income.

Advance payments for property, plant and equipment of $13,135 thousand paid in the period were agreed to be refunded prior to 30 June 2017. These amounts are shown as other receivables (Note 13) rather than additions to property, plant and equipment, but are included in investing cash flows. The refund was received after 30 June 2017 and will be shown as a reduction to investing cash flows in the second half of the year.

In 2015, the Group purchased an aircraft for $10,600 thousand, which was subsequently leased to an unrelated third party for a period of ten years at a monthly lease payment of $130 thousand; with the retained right to use the aircraft for the Company's needs on commercial payment terms.

Minimum lease payments were as follows:

12. Inventories

Inventories included no obsolete or slow-moving items as of 30 June 2017 (31 December 2016: nil).

13. trade and other receivables

Trade receivables are non-interest bearing. 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. Accordingly, the management of the Group believes that there is no further credit provision required in excess of the allowance for doubtful debts.

As at 30 June 2017, other receivables included $13,135 thousand of advance payment for property, plant and equipment, which was made during the six months ended 30 June 2017 and refunded in July 2017, due to the amendments in construction contract (Note 11).

14. other assets

15. 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 2025 and 2038 (Note 4). 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.

16. trade and other payables

Trade and other payables are non-interest bearing. As at 30 June 2017, advances of $7,525 thousand (31 December 2016: $9,815 thousand) relate to the receipts from customers for sales in July 2017 (31 December 2016: January 2017).

17. borrowings

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

Gazprombank JSC - On 7 April 2017, Kayumneft JSC entered into facility agreements for an aggregate principal amount of up to $206,000 thousand, nominated in US dollars and repayable in full on 28 September 2018. During the six months ended 30 June 2017, Kayumneft JSC received $125,000 thousand. The facility agreements provide an interest rate at LIBOR plus 5.3%. The interest is payable monthly with the first payment made in April 2017.

As at 30 June 2017, the outstanding balance of $124,561 thousand was recognized net of the unamortized amounts of borrowing costs of $439 thousand. The amortisation of borrowing costs for the first six months of 2017 was $76 thousand. The undrawn facilities amounted to $81,000 thousand and available until March 2018.

Under the terms of the facility agreements, the Group is subject to two financial covenants and a number of general covenants. The financial covenants will be tested for the year ended 31 December 2017.

Exillon Energy plc and its subsidiaries guarantee and secure the obligations of Kayumneft JSC under the facility agreements. The facility agreements are secured by a pledge of the 100% shares of certain Group's subsidiaries (Note 22): Komi Resources CJSC, Nem Oil CJSC, Aslador Oil CJSC, Kayumneft JSC, Ucatex Ugra LLC, Ucatex Oil LLC and Setera LLC.

Credit Suisse - On 14 March 2017 the principal of $7,692 thousand has been repaid in compliance with the repayment schedule, being the last principal payment under this loan facility.

18. Share capital

The issued share capital of the Company at the date of these consolidated financial statements is as follows:

The total number of allotted ordinary shares is 161,510,911 with a par value of $0.0000125 each. As of 30 June 2017 shares issued include 1,195,702 shares (31 December 2016: 1,195,702 shares), which are not paid and held by the Employee Benefit Trust within the Group for further allocation to employees. There were no new share awards granted to employees during the six months ended 30 June 2017.

19. Risk management

The Group's activities expose it to a variety of financial risks: market risk (including foreign currency risk and interest rate risk), credit risk and liquidity risk.

The interim condensed consolidated financial statements do not include all financial risk management information and disclosures required in the annual financial statements, and should be read in conjunction with the Group's annual financial statements as at 31 December 2016.

Major categories of financial instruments - The Group has various financial assets such as trade and other accounts receivable, cash and cash equivalents and interest receivable on bank deposits. The Group's principal financial liabilities comprise borrowings, trade and other accounts payable, advances received and salary payable.

The major part of cash is held on short-term and long-term deposits placed in financial institutions incorporated in the Russian Federation, which provide premium deposit rates. The financial ability of financial institutions and overall market circumstances are continuously monitored by management based on the information provided by independent rating agencies or other publicly available financial information.

As of 30 June 2017, cash and cash equivalents amounted to $43,139 thousand were held in one financial institution (31 December 2016: cash and cash equivalents of $146,346 thousand and the interest receivable of $195 thousand).

On 28 July 2017, the Central Bank of Russia has withdrawn Bank Ugra's licence. As of that date, outstanding amount of cash held in Bank Ugra was $848 thousand. Currently the major part of cash is held in other financial institutions incorporated in the Russian Federation.

As of 30 June 2017, US dollars account for approximately 4% of cash and cash equivalents with the remaining 96% held in Russian Roubles (31 December 2016: US dollars account for approximately 21% of our cash with the remaining 79% held in Russian Roubles).

Foreign currency risk - new loan facility agreements are nominated in US dollars and were taken out by a Russian Rouble functional currency subsidiary (Note 17). Consequently, these loan facilities are exposed to foreign currency risk, which can adversely impact the consolidated financial results of the Group. The Group does not use any derivatives to manage foreign currency risk exposure, although there is a detailed budgeting and cash forecasting process in place to help ensure that the Group has adequate cash available to meet its payment obligations under the facility agreements.