EXI.L Regulatory News (EXI)

Exillon Energy plc

Preliminary unaudited results for the year ended 31 December 2012

8 March 2013

Exillon Energy plc ("Exillon") (EXI.LN), a London listed independent oil producer with assets in two oil-rich regions of northern Russia, Timan-Pechora ("Exillon TP") and West Siberia ("Exillon WS"), today issues its preliminary unaudited results for the year ended 31 December 2012.

From the Chief Executive

·; Production up 45%, exceeding 16,000 bpd in December

·; EBITDA up 136% to US$46.1 million (up from US$19.5 million in 2011)

·; Net profit of US$12.1 million (up from a net loss of US$10.4 million in 2011) 

·; Completed oil treatment and power generation facilities in both Exillon TP and Exillon WS

·; Commissioned own entry point into Transneft pipeline network in Exillon WS increasing EBITDA per barrel in H2 2012

Mark Martin, Chief Executive, said:

"Exillon made excellent operational and financial progress during a very busy 2012. Our drilling programme delivered annual production growth of 45%, and we also expect soon to announce an updated reserves report. We have completed a number of one off infrastructure projects in ETP and EWS which have materially increased our profitability per barrel.

Financially, we have a strong balance sheet with US$127.9 million of cash (as of yesterday), EBITDA up over 130% and a move into net profit. We will accelerate our development strategy in 2013 and realise further value for shareholders through ongoing growth in production, EBITDA and reserves."

Dear Shareholders,

Exillon has enjoyed a very successful 2012, increasing oil production by 45% from 3.24 million to 4.69 million barrels. In order to build on this success in 2013 we intend to accelerate our drilling plans, targeting six new wells in 2013 in ETP from two well pads, and approximately fifteen new wells in EWS from four well pads.

Financial Performance

Our EBITDA increased 136% from US$19.5 million to US$46.1 million, with a net profit of US$12.1 million (compared to a net loss of US$10.4 million in 2011). Our revenue increased from US$203.0 million to US$301.9 million and netback (which we define as revenue less Mineral Extraction Tax, Export Duty and Transneft charges) rose 63% from US$63.6 million to US$103.5 million.

This strong growth in EBITDA was a result of our continuing investment in surface infrastructure, our ongoing drilling programme and slightly higher oil prices. During 2012 we completed our oil treatment and power generation facilities in both Exillon TP and Exillon WS, and in July we commissioned our own entry point into the Transneft pipeline network in Exillon WS. The completion of this entry point improved our EBITDA per barrel in the second half of 2012. It is also an important part of our strategy of owning our own infrastructure and controlling our sales routes.

For the full year 2012 our EBITDA was equivalent to US$9.9 / bbl compared to US$6.1 / bbl in 2011. EBITDA per barrel in H2 2012 was US$11.8 / bbl compared to US$7.5/ bbl in H1 2012. This continuing growth was a function of both the improvements to our infrastructure and to economies of scale as production increased.

75% of our oil production in 2012 was from Exillon WS and 25% from Exillon TP. Both units were profitable in 2012 although Exillon WS is currently larger and enjoys greater economies of scale than Exillon TP. EBITDA per barrel on an operating level (before central costs) was US$13.2 / bbl in Exillon WS (2011: US$9.3 / bbl) and US$9.5 / bbl in Exillon TP (2011: US$7.3 / bbl).

Our balance sheet remains strong with US$121.0 million of cash and cash equivalents as at 31 December 2012. We have a term loan from Credit Suisse of US$100 million which matures in 2017. This is our only debt. As at 31 December 2012 debt was US$100.2 million, so our net cash position at year end was US$20.8 million.

As at 7th March 2013 our cash balance had increased to US$127.9 million.

Operational Excellence

We have seen excellent results from our drilling programme this year. The greatest success was in Exillon WS from Pad 5 in the North East of our EWS I field. The high natural flow rates, achieved without any well stimulation, demonstrate that the newly developed areas of this reservoir are thick and of high quality. Pad 7, which is adjacent to Pad 5, will be developed during 2013.

All of our new wells are now being drilled at a 60 degree angle, exposing double the net pay compared to vertical wells. During the year our completion and cementing procedures were improved, and we have substantially increased our water injection rates to sustain the productivity of our fields.

Investor Relations and Corporate

To reinforce our investor relations efforts we appointed Investec to act as joint broker alongside Mirabaud. We also listed our shares on the Warsaw Stock Exchange to broaden the range of investors who are able to buy Exillon.

We have canvassed the views of our major investors about disclosure of production data and the consensus was that monthly disclosure was excessive. We will therefore publish quarterly production data in 2013.

During 2012 we also made progress in controlling our central overhead costs. For example we have reduced our financial audit costs by 23%.

Acquisitions and Reserves

We made two acquisitions in 2012, both in Timan Pechora. In January we announced the acquisition of the ETP VII licence which increased our contiguous licence area to 344km2. In September - November 2012 we have 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 US$2.7 million.  This will add a further 1,075 km² of prospective areas, more than quadrupling the total area of Exillon TP to 1,419 km². We will continue to consider contiguous acquisitions in both Exillon WS and Exillon TP if and when these become available.

Our strategy is to invest in the development of our oil fields in order to increase 1) production 2) EBITDA and 3) reserves. In 2012 our oil production grew 45% and our EBITDA grew 136%. The third component of our strategy will be assessed by the independent reserves audit of our assets. This is currently under preparation by Miller & Lents in Houston, and we expect to release it shortly.

Mark Martin

Chief Executive Officer

OPERATIONAL REVIEW

Drilling

In 2012 we drilled 16 wells (twelve producers and four water injection wells). Details of this drilling programme were announced throughout 2012 via RNS, and all announcements can be found on www.exillonenergy.com.

Exillon TP

Exillon TP produced 1,185,557 bbl and generating revenue of US$51.9 million.

We successfully completed an oil processing facility and power generation facilities.

Exillon WS

Exillon WS produced 3,507,045 bbl and generated revenue of US$250.0 million.

In February 2010, we began construction of a Transneft oil terminal, which was successfully completed in 2012 and commissioned in July 2012.

Financial

US dollars account for approximately 83% of our cash with the remaining 17% held in Russian Roubles.

Capital expenditure for the period was US$86.5 million (2011: US$97.3 million). Of total capital expenditure, US$30.7 million was attributable to drilling (2011: US$22.9 million), US$45.7 million to infrastructure (2011: US$66.7 million), and US$10.1 million to seismic data acquisition and interpretation (2011: US$6.4 million). The infrastructure spend included completion of Exillon's own entry point into the Transneft pipeline network, completion of an oil treatment and power generation facilities in both Exillon TP and Exillon WS, construction of infield camps, roads and pipelines.

FINANCIAL REVIEW

The Consolidated Financial Information and notes which follow should be read in conjunction with this review which has been included to assist in the understanding of our financial position as at 31 December 2012.

Summary

We maintained a strong financial position in 2012 due to rising production levels, improved efficiency and replacement of our existing loan facility.

EBITDA increased by 136% from US$19.5 million in 2011 to US$46.1 million in 2012.

Net profit for the year, which includes depreciation costs, foreign exchange translation effects, loss on write-off of non-current assets and share based compensation costs amounted to US$12.1 million compared to net loss of US$10.4 million in 2011.

Revenue

Our revenue for the year ended 31 December 2012 increased by 49% year-on-year, reaching US$301.9 million (2011: US$203.0 million), of which US$166.0 million or 55% came from export sales of crude oil and US$135.9 million or 45% came from domestic sales of crude oil. This increase in revenue is attributable to:

·; An increase in production leading to a 47% increase in sales from 3,170,715 bbl in 2011 to 4,651,049 bbl; and

·; An increase in average commodity prices: we achieved an average oil price of US$105/bbl (2011: US$102 / bbl) for export sales and US$44 / bbl (2011: US$41 / bbl) for domestic sales.

Operating Results

Operating costs excluding depreciation, depletion and amortisation increased to US$127.6 million (2011: US$80.4 million) following an increase in production of 45% to 4,692,602 bbl (2011: 3,242,503 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$64.5 million in 2011 to US$99.8 million in 2012, as a result of both higher production volumes and increased average commodity prices in 2012 used in the calculation of the tax. Another cost driver leading to the growth in other taxes incurred was the increased rates of gas flaring penalties introduced in 2012.

Depreciation and depletion costs primarily relate to the depreciation of proved and probable reserves and other production and non-production assets. In 2012, these costs totalled US$20.5 million (2011: US$13.8 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 2012 of US$106.8 million (2011: US$84.1 million) is comprised of export duties of US$83.8 million (2011: US$65.6 million), transportation services of US$22.0 million (2011: US$16.9 million) and other selling expenses of US$1.0 million (2011: US$1.6 million). Transportation services include services provided by Transneft and transportation services from oil field to oil filling station. In 2012, the export duty rate fluctuated within the range from US$336.6 per tonne to US$460.7 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 and 15th of the two months prior to the month of delivering the crude.

Administrative expenses (excluding share-based compensation expenses, share issuance costs and depreciation and amortisation) totalled US$20.8 million (2011: US$18.6 million). In 2012, an increase in headcount led to an ensuing increase in salaries, while savings were achieved in business trip and office rent expenses.

In 2012, interest income increased to US$2.9 million (2011: US$1.3 million) resulting from surplus cash being held on short-term deposits and VTB credit-linked deposits.

In 2012, income tax expense of US$5.4 million (2011: US$2.9 million) comprised an income tax charge of US$6.9 million (2011: US$2.5 million) and a deferred tax credit of US$1.5 million (2011: deferred tax charge of US$0.4 million). The basic corporate income tax rate in the Russian Federation is 20%. The reduced rate of 17% was applied to Exillon WS in 2012 in compliance with local tax legislation (2011: 16%).

It should be noted that - in accordance with IFRS - a foreign exchange gain of US$3.4 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 gain of US$24.8 million has been applied directly to the consolidated statement of financial position as the part of translation reserve.

As a result of the above, we reported a profit after tax of US$12.1 million compared to a loss of US$10.4 million for the year ended 31 December 2011.

Financial Position

In February 2012 we received proceeds of US$14.3 million comprising the nominal value and accrued interest in relation to Eurobonds issued by EBRD.

In March 2012 we replaced our existing US$50 million loan facility with a US$100 million facility with a LIBOR plus 6% interest rate and a term of 5 years. The previous loan had an interest rate of LIBOR plus 7% and a term of 3.5 years.

We ended the period in a strong financial position with US$121.0 million of cash and cash equivalents (2011: US$117.6 million) with outstanding borrowings of US$100.2 million (2011: US$49.0 million), equivalent to a net cash position of US$20.8 million (2011: US$68.6 million).

The increase in the cost of property, plant and equipment has been driven by the drilling of wells and further development of field infrastructure in Exillon WS and the launch of drilling and extensive field development in Exillon TP.

Cash Flow

Net cash generated from operating activities in 2012 amounted to US$36.1 million, compared to a US$32.4 million inflow in 2011. Operating cash flow before working capital changes amounted to the inflow of US$46.8 million in 2012 compared to the inflow of US$19.4 million in 2011. The increase is driven by higher production and sales volumes. It was also positively affected by payment terms for tax payments to the Russian Government, offset by the timing gap for taxes receivable; a decrease in trade and other receivables due to the implementation of a prepayment scheme dealing with customers and an increase in interest income received from holding our cash surplus on deposits. The negative impact relates to the decrease in trade and other payables following payments to contractors for drilling work and the construction of infield infrastructure, an increase in inventory balances and an increase in income tax paid due to the further expansion of our operations in 2012.

Capital expenditure during the year was US$86.5 million (2011: US$97.3 million), including the drilling of wells and the development of infield infrastructure. During the year, we paid US$5.9 million of loan interest (2011: US$3.7 million), which was capitalised in full (2011: US$2.7 million). 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 US$2.7 million.

Cash flow from financing activities was US$47.3 million (2011: US$145.1 million). The inflow of US$49.8 million relates to the net proceeds from increasing the loan facility. The outflow of US$2.5 million represents the repayment of the loan principal amount before we replaced the loan facility.

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (UNAUDITED)

CONSOLIDATED STATEMENT OF FINANCIAL POSITION (UNAUDITED)

The financial statements were authorised for issue by the board of directors on 7 March 2013.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (UNAUDITED)

CONSOLIDATED STATEMENT OF CASH FLOW (UNAUDITED)

* Unused vacation accrual of $216 thousand and bad debt expense of $195 thousand were reclassified from changes in working capital to operating cash flow before working capital changes to provide consistency with the presentation for the year ended 2012.

NOTES TO THE 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 31.

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.

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

2. basis of preparation

The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRSs") issued by the International Accounting Standards Board ("IASB") and the Listing Rules of the United Kingdom's Financial Services Authority ("FSA"). These standards are subject to interpretations issued from time to time by the International Financial Reporting Interpretation Committee ("IFRIC"). These consolidated financial statements have been prepared on a historical cost basis, modified for fair values where required under IFRS.

The preparation of the financial statements requires the use of certain critical accounting estimates. It also necessitates management to exercise its judgement in the process of applying the Group's accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the financial statements are disclosed in Note 5.

Note 30 to the financial statements include the Group's objectives, policies and processes for managing its capital, its financial risk management objectives and its exposure to credit risk and liquidity risk.

The Group believes that it has sufficient financial resources to manage its business risks successfully despite the current uncertain economic outlook. The Company's forecasts and projections, taking account reasonable changes in trading performance (including oil price), show that the Company can operate with its current cash holding.

The Directors have a reasonable expectation that the Group has adequate resources to continue operational existence for the foreseeable future. Thus they continue to adopt the going concern basis of accounting in preparing the annual financial statements.

3. adoption of new and revised standards

Standards, amendments and interpretations to existing standards that are not effective yet and have not been early adopted by the Group: 

·; 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 Group's financial position or performance.

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

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

·; IAS 32 Offsetting Financial Assets and Financial Liabilities - Amendments to IAS 32(effective on or after 1 January 2014)

These amendments clarify the meaning of "currently has a legally enforceable right to set-off". The amendments also clarify the application of the IAS 32 offsetting criteria to settlement systems (such as central clearing house systems) which apply gross settlement mechanisms that are not simultaneous. These amendments are not expected to impact the Group's financial position or performance.

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

The amendments will have 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 require an entity to disclose information about rights to set-off and related arrangements. The disclosures would provide users with information that is useful in evaluating the effect of netting arrangements on an entity's financial position. The new disclosures are required for all recognized financial instruments that are set off in accordance with IAS 32 Financial Instruments: Presentation. The disclosures also apply to recognized financial instruments that are subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are set off in accordance with IAS 32. These amendments will have no impact the Group's financial position or performance.

·; IFRS 9 Financial instruments (effective on or after 1 January 2015)

IFRS 9, as issued, reflects the first phase of the IASB's work on the replacement of IAS 39 and applies to classification and measurement of financial assets and financial liabilities as defined in IAS 39. The standard was initially effective for annual periods beginning on or after 1 January 2013, but Amendments to IFRS 9 Mandatory Effective Date of IFRS 9 and Transition Disclosures, issued in December 2011, moved the mandatory effective date to 1 January 2015. In subsequent phases, the IASB will address hedge accounting and impairment of financial assets. The adoption of the first phase of IFRS 9 will have an effect on the classification and measurement of the Group's financial assets, but will not have an impact on classification and measurements of financial liabilities. The Group will quantify the effect in conjunction with the other phases, when the final standard including all phases is issued.

·; 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. Based on the preliminary analyses performed, IFRS 10 is not expected to have any impact on the currently held investments of the Group.

·; IFRS 11 Joint Arrangements (effective 1 January 2013)

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

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

IFRS 12 includes all of the disclosures that were previously in IAS 27 related to consolidated financial statements, as well as all of the disclosures that were previously included in IAS 31 and IAS 28. These disclosures relate to an entity's interests in subsidiaries, joint arrangements, associates and structured entities. A number of new disclosures are also required. The new standard will have no impact on the Group's 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 Group is currently assessing the impact that this standard will have on the financial position and performance, but based on the preliminary analyses, no material impact is expected.

During the year ended 31 December2012 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 will not have an 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.

The accounting policies adopted are consistent with those of the previous financial year, except for the

following amendments to IFRS effective as of 1 January 2012:

·; IAS 1 Presentation of Items of Other Comprehensive Income - Amendments to IAS 1 (Effective on or after 1 July 2012)

·; IAS 12 Income Taxes (Amendment) - Deferred Taxes: Recovery of Underlying Assets;

·; IFRS 1 First-Time Adoption of International Financial Reporting Standards (Amendment) - Severe Hyperinflation and Removal of Fixed Dates for First-Time Adopters IFRS 7 Financial Instruments: Disclosures (Amendments);

·; IFRS 7 Financial Instruments: Disclosures - Enhanced Derecognition Disclosure Requirements.

The adoption of the standards or interpretations is described below:

IAS 12 Income Taxes (Amendment) - Deferred Taxes: Recovery of Underlying Assets

The amendment clarified the determination of deferred tax on investment property measured at fair value and introduces a rebuttable presumption that deferred tax on investment property measured using the fair value model in IAS 40 should be determined on the basis that its carrying amount will be recovered through sale. The amendment is effective for annual periods beginning on or after 1 January 2012. The amendment had no effect on the Group's financial position, performance or its disclosures.

IFRS 1 First-Time Adoption of International Financial Reporting Standards (Amendment) - Severe Hyperinflation and Removal of Fixed Dates for First-Time Adopters

The amendment had no effect on the Group's financial position, performance or its disclosures.

IFRS 7 Financial Instruments: Disclosures - Enhanced Derecognition Disclosure Requirements

The amendment requires additional disclosure about financial assets that have been transferred but not

derecognised to enable the user of the Group's financial statements to understand the relationship with those assets that have not been derecognised and their associated liabilities. In addition, the amendment requires disclosures about the entity's continuing involvement in derecognised assets to enable the users to evaluate the nature of, and risks associated with, such involvement. The amendment is effective for annual periods beginning on or after 1 July 2011. The Group does not have any assets with these characteristics so there had been no effect on the presentation of its financial statements.

4. SIGNIFICANT ACCOUNTING POLICIES

Basis of consolidation - The Group's consolidated financial statements incorporate the financial statements of the Company and its subsidiaries. Control comprises the power to govern the financial and operating policies of the investee so as to obtain benefit from its activities and is achieved through direct and indirect ownership of voting rights; currently exercisable or convertible potential voting rights; or by way of contractual agreement. Subsidiaries are consolidated from the date on which control is transferred to the Group and are de-consolidated from the date that control ceases.

Inter-company transactions, balances and unrealised gains and losses on transactions between group companies are eliminated. Accounting policies of subsidiaries have been changed where necessary to ensure consistency with the policies adopted by the Group.

Segmental reporting - Operating segments are reported in a manner consistent with the internal reporting provided to the directors of the Company. The chief operating decision-maker, who is responsible for making strategic decisions, allocating resources and assessing performance of the operating segments, has been identified as the Board.

Functional and presentation currencies - The items included in these consolidated financial statements relating to the Group companies are measured using their functional currency that is the currency in the main environment in which they operate. These consolidated financial statements are presented in US dollars or $, which is the Exillon Energy plc functional and presentation currency. The functional currency of the Group's trading and oil extracting subsidiaries is the Russian Rouble and for the other companies it is the US dollar.

Foreign currency translation - Transactions in foreign currencies are initially recorded in the functional currency at the rate ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated to the functional currency at the rate of exchange ruling at the reporting date. All differences are taken to the statement of comprehensive income.

Loans issued to the foreign subsidiaries, the settlement of which is neither planned nor likely to occur in the foreseeable future, form part of the Company's net investment in those subsidiaries. They do not include trade receivables or trade payables. In the consolidated financial statements exchange differences arising on those loans are recognised initially in other comprehensive income and reclassified from equity to profit or loss on disposal of the net investment.

On consolidation, assets and liabilities denominated in foreign currencies are translated into US dollars at closing rates of exchange. Results of operations and cash flows of subsidiaries are translated into US dollars at average rates of exchange. The Group uses average monthly rates published by Central Bank of the Russian Federation to translate trading results denominated in Roubles into US dollars. Differences resulting from the retranslation of the opening net assets and the results for the year are taken to reserves.

The Group used the following exchange rates of one Rouble to one US dollar:

The exchange rate of UAE Dirham (AED) to US dollar has been held constant for the last several years at a rate of 3.675 AED for one US dollar.

Business combinations - The Group uses the acquisition method to account for business combinations. The consideration transferred for an acquisition of a subsidiary is the fair values of the assets transferred, the liabilities incurred and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Acquisition-related costs are expensed as incurred. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date.

Property, plant and equipment - The Group uses the cost model by which items of property, plant and equipment are stated at historical purchase cost less accumulated depreciation and impairment.

a) Historical cost

Historical cost of property, plant and equipment items includes their acquisition cost, all the costs directly related to bringing the assets to the location and condition ready for their intended use and any costs of dismantling and removing the item or restoring the site on which it is located.

Staff costs and other operating expenses incurred in the construction of the asset are also capitalised.

The costs of expansion, modernisation or improvements leading to increased productivity, capacity or efficiency or to a lengthening of the useful lives of the assets are capitalised.

Current repair, upkeep and maintenance expenses are recognised in the consolidated statement of comprehensive income as incurred. Furthermore, certain of the Group's facilities require periodic reviews. In this respect, a portion of the items requiring replacement is recognised specifically and is depreciated over the period until the next reviewis carried out.

Property, plant and equipment also include investments relating to oil and gas exploration, development and production activities.

Exploration and evaluation assets

Exploration and evaluation assets are measured at cost less provision for impairment, where required.

The Group recognises oil and gas exploration and evaluation activities using successful efforts accounting, whereby the accounting treatment of the various costs incurred is as follows:

(i) The costs incurred in the acquisition of new interests in areas with proved and unproved reserves including exploration licence acquisition costs, are capitalised as incurred to the account "Exploration and Evaluation Assets" of the field concerned.

(ii) Exploration costs (geological and geophysical expenditures, expenditures associated with the maintenance of unproved reserves and other expenditures relating to the exploration activity), excluding exploratory drilling expenditures, are expensed as incurred.

(iii) Administrative expenses (office rent, office cars, administrative personnel, etc.) that are not directly attributable to the exploration and evaluation activities are expensed as incurred.

(iv) Exploratory drilling costs are capitalised to the account "Exploration and Evaluation Assets" of the field concerned, pending determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort. If the well does not demonstrate potential economic oil and gas quantities, the well costs are expensed as a dry hole and are reported in exploration expenses. It is not unusual to have exploration wells carried in the statement of financial position for several years while additional appraisal drilling and seismic work on the potential oil and gas field is performed or while the optimum development plans and timing are established.

(v) The Group classifies exploration and evaluation assets as tangible assets since its tangible element (underlying reserves) is significant and exploration and evaluation assets represent an integral part of the underlying reserves.

(vi) Activities preceding the acquisition of oil and gas properties are defined aspre-exploration (or pre-licence). All pre-exploration expenditures are recognised as an expense in the consolidated statement of comprehensive income when incurred and include project feasibility studies, surface mapping and appraisal activities, as well as other overhead costs related to pre-exploration activities.

An exploration and evaluation asset is no longer classified as such when the technical feasibility and commercial viability of extracting a mineral resource is proved. Once commercial reserves are found, exploration and evaluation assets are transferred to account "Oil and Gas Properties" and depleted using the unit-of-production method as described in paragraph b) Depreciation and depletion below.

Development costs

Expenditures related to the development of hydrocarbons are not recognised as exploration and evaluation assets but as oil and gas properties.

Development costs include the cost of development wells to produce proved reserves, the cost of production facilities (such as flow lines, separators, oil treatment facilities, heaters, storage tanks, improved recovery systems and gas processing facilities), borrowing costs and other costs necessary to obtain access to proved and probable reserves.

b) Depreciation and depletion

Property, plant and equipment related to oil and gas production activities are depreciated using the unit-of-production method as described below, except in the case of assets whose useful life is shorter than the lifetime of the field (roads, pipelines, pumps, etc.), in which case the straight-line method is applied. Exploration and evaluation assets are only depreciated when the field is in production.

(i) Producing wells, well pads and other producing items are depleted over Proved and Probable (2P) reserves on a field-by-field basis.

(ii) Capitalised future decommissioning costs are depleted over Proved and Probable reserves (2P).

(iii) Other development costs that cannot be attributed to particular producing units are allocated to cost centres of related oil fields based on their reserve share in the total portfolio. Such costs are depleted over Proved and Probable (2P) reserves on a field-by-field basis.

Since 2P reserves assume future development costs to access proved undeveloped and probable reserves, an adjustment is made to the depreciation base to reflect the effect of future development costs.

Property, plant and equipment, other than those described above, are depreciated using the straight-line method on the basis of the acquisition cost of the assets less their estimated residual value, over the years of estimated useful life of the assets, as follows:

The residual values and useful lives of these assets are reviewed annually. Depreciation and depletion starts when the assets become available for use.

Impairment of assets - Assets that are subject to amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the purposes of assessing impairment, assets are grouped into cash-generating units as they generate cash flows which are independent from other units.

Recoverable amount is the higher of fair value less costs to sell and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax risk adjusted discount rate.

If the recoverable amount of an asset (or a cash-generating unit) is estimated to be less than its carrying amount, the carrying amount of the asset (or the cash-generating unit) is reduced to its recoverable amount, and an impairment loss is recognised in the consolidated statement of comprehensive income.

The basis for future depreciation or amortisation will take into account the reduction in the value of the asset as a result of any accumulated impairment losses.

When an impairment loss subsequently reverses, the carrying amount of the asset (or the cash-generating unit) is increased to the revised estimate of its recoverable amount, so that the increased carrying amount does not exceed the carrying amount that would have been determined in case no impairment loss had been recognised for the asset (or the cash-generating unit) in prior years. A reversal of an impairment loss is recognised in the consolidated statement of comprehensive income. The reversal is capped at the value that the asset would have been held at had it continued to be depreciated. An impairment loss recognised for goodwill can not be reversed in a subsequent period.

Impairment of oil and gas properties

For oil and gas properties, assets are tested for impairment whenever facts and circumstances indicate potential impairment. Impairment reviews compare the carrying amount of an asset with its recoverable amount. Recoverable amount is the higher of value in use and fair value less costs to sell. As the company is in the development phase, recoverable amount is based on fair value less costs to sell with the reference to market participant assumptions of the future cash flows to be obtained from the proved and probable reserves.

Recognition and measurement of financial instruments - The Group recognises financial assets and liabilities in its statement of financial position when it becomes a party to the contractual obligation of the instrument.

Financial assets and liabilities are initially recognised at fair value. The accounting policies for subsequent re-measurement of these items are disclosed in the respective accounting policies set out below.

Cash and cash equivalents - Cash and cash equivalents comprise cash in hand, current balances with banks and similar institutions; and short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and have a maturity of three months or less from the date of acquisition.

Financial instruments - Eurobonds are non-derivative financial assets with fixed coupon receipts. The financial instrument is measured at amortised cost using the effective interest method, less any impairment. Interest income is recognised by applying the effective interest rate.

Effective interest method

The effective interest method is a method of calculating the amortised cost of a financial asset or a financial liability and of allocating interest income over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash receipts (including all fees on points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the financial instrument, or, where appropriate, a shorter period, to the net carrying amount on initial recognition.

Trade and other receivables- Trade and other receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method, less provision for impairment.

The primary factors that the Group considers when determining whether a receivable is impaired is its overdue status. The following other principal criteria are also used to determine that there is objective evidence that an impairment loss has occurred:

·; any portion of the receivable is overdue and the late payment cannot be attributed to a delay caused by the settlement systems;

·; the counterparty experiences a significant financial difficulty as evidenced by its financial information that the Group obtains;

·; the counterparty considers bankruptcy or a financial reorganisation;

·; there is adverse change in the payment status of the counterparty as a result of changes in the national or local economic conditions that impact the counterparty.

Inventories- Inventories are stated at the lower of cost and net realisable value. Cost is determined by the weighted average method and comprises direct purchase costs, cost of production, transportation and custom clearance costs.

Trade and other payables - Trade and other payables are carried at payment or settlement amounts. Where the time value of money is material, payables are initially recognised at fair value and subsequently carried at amortised cost using the effective interest rate.

Borrowings - Borrowings are initially recognised at fair value, being the fair value of the proceeds received net of issue costs associated with the borrowing. After initial recognition, interest bearing loans and borrowings are subsequently measured at amortised costs using the effective interest method.  

Operating leases - Where the Group is a lessee in a lease which does not transfer substantially all the risks and rewards incidental to ownership from the lessor to the Group, the total lease payments are recognised on a straight-line basis over the period of the lease and charged to the consolidated statement of comprehensive income.

Provisions and contingencies - Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the Group expects some or all of a provision to be reimbursed, for example, under an insurance contract, the reimbursement is recognised as a separate asset, but only when the reimbursement is virtually certain. The expense relating to any provision is presented in the statement of comprehensive income net of any reimbursement. If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax discount rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognised as finance cost. Any change in the amount recognised for environmental and litigation and other provisions arising through changes in discount rates is included within finance cost.

A contingent liability is disclosed where the existence of an obligation will only be confirmed by future events or where the amount of the obligation cannot be measured with reasonable reliability. Contingent assets are not recognised, but are disclosed where an inflow of economic benefits is probable.

Provision for decommissioning - Provision for decommissioning is recognised only to the extent of the expected costs needed to remediate the actual damage made to the environment. A corresponding amount equivalent to the provision is also recognised as part of the cost of the related property, plant and equipment. The amount recognised is the estimated cost of decommissioning, discounted to its net present value, and is reassessed each year in accordance with local conditions and requirements. Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision, and a corresponding adjustment to property, plant and equipment. The unwinding of the discount on the decommissioning provision is included as a finance cost.

Income taxes - Income tax expense represents the sum of the tax currently payable and deferred tax. The Group provides for taxes based on the tax accounts maintained and prepared in accordance with the tax regulations of the Russian Federation.

The tax currently payable is based on the taxable profits for the period. Taxable profit differs from net profit as reported in the statement of comprehensive income because it excludes items of income or expense that are taxable or deductible in other periods and it further excludes items that are never taxable or deductible. The Group's liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the reporting date.

Deferred income tax is recognised, using the balance sheet liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the consolidated financial statements. Deferred income tax is determined using tax rates (and laws) that have been enacted or substantially enacted by the reporting date and are expected to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled.

Deferred income tax assets are recognised only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilised.

Deferred income tax is provided on arising temporary differences, except where the timing of the reversal of the temporary difference is controlled by the Group and it is probable that the temporary difference will not reverse in the foreseeable future.

Tax relating to items recognised directly in equity is recognised in equity and not in the statement of comprehensive income.

Pensions and post-employment benefits - Wages, salaries, mandatory defined contributions to the state pension and social insurance funds, paid annual leave and sick leave, bonuses, and non-monetary benefits are accrued in the year in which the associated services are rendered by the employees of the Group.

Share based payments - The fair value of the employee services received in exchange for the grant of the share awards is recognised as an expense over the vesting period of the award, with a corresponding increase in equity. The total amount to be expensed over the vesting period is determined by reference to the fair value of the share awards at the date of grant, excluding the impact of non-market vesting conditions. Non-market vesting conditions are included in assumptions about the number of options that are expected to vest. At the end of reporting period, the Company revises its estimates of the number of options that are expected to vest. The impact of the revision of the original estimates is recognised in profit or loss with a corresponding entry to equity.

Share capital - Ordinary shares are classified as equity. The difference between the nominal value of the shares and the issue price is recorded as share premium.

Share issuance costs - Costs that are directly attributable to the issue of new shares such as broker commissions, settlement fees, legal and other expenses are deducted from equity. Costs that related jointly to more than one transaction are allocated between the share premium account and statement of comprehensive income in proportion to the number of new shares issued compared to the existing number of shares. The costs allocated to the listing of existing shares are expensed in profit or loss.

Advances and prepayments - Advances and prepayments are carried at cost less provision for impairment. An advance or prepayment is classified as construction in progress when the goods or services relating to the advance or prepayment are expected to be obtained after one year, or when the advance or prepayment relates to an asset which will itself be classified as non-current upon initial recognition. Advances or prepayments to acquire assets are transferred to the carrying amount of the asset once the Group has obtained control of the asset and it is probable that future economic benefits associated with the asset will flow to the Group. Other advances and prepayments are written off to profit or loss when the expenses relating to the advances or prepayments are incurred. If there is an indication that the assets, goods or services relating to an advance or prepayment will not be received, the carrying value of the advance or prepayment is written down accordingly and a corresponding impairment loss is recognised in the consolidated statement of comprehensive income.

Revenue recognition - Revenues from sales of goods are recognised at the point of transfer of risks and rewards of ownership of the goods, normally when the crude oil is shipped. If the Group agrees to transport goods to a specified location, revenue is recognised when the goods are passed to the customer at the destination point. Sales are shown net of VAT and discounts.

Revenues are measured at the fair value of the consideration received or receivable. Interest income is recognised on a time-proportion basis using the effective interest method.

5. Critical accounting judgements and key sources of estimation uncertainty

The preparation of the financial statements in conformity with IFRS requires management to make estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Details of the Group's significant accounting judgments and critical accounting estimates are set out below:

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 after 2027. 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 31 December 2012, undiscounted value of estimated future cash outflows is estimated at$3,564 thousand (2011: $1,679 thousand);

·; Expected timing of future cash outflows - the majority of the expenditure is expected to take place in a range between 2027 and 2038 (2011: between 2027 and 2038);

·; Discount rate -8% per annum (2011: 10%);

·; Inflation rate - 3-7% per annum (2011: 5%).

If the discount rate had increased by 1% to 9% at 31 December 2012, the decommissioning liability would have been $236thousand lower (2011: $115 thousand lower).

Exillon WS:

·; As at 31 December 2012, undiscounted value of estimated future cash outflows is estimated at$14,653 thousand (2011: $8,465 thousand);

·; Expected timing of future cash outflows - the majority of the expenditure is expected to take place in a range between 2027 and 2038 (2011: between 2027 and 2038);

·; Discount rate -8% per annum (2011: 10%);

·; Inflation rate - 3-7% per annum (2011: 5%).

If the discount rate had increased by 1% to 9% at 31 December 2012, the decommissioning liability would have been $976 thousand lower (2011: $577 thousand lower).

Estimation of oil and gas reserves

In 2011 the Group extended the expiration date of subsoil licences ETP I and ETP IV from 2013 to June 2036 and December 2038, respectively. There were no license extensions in 2012 year.

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 depreciation and amortisation 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 depreciation and amortisation charges (assuming constant production) and reduce income.

Proved and Probable reserve estimates of the Group as of 1 November 2011were based on the reports prepared by Miller and Lents Ltd, independent engineering consultants.

As at 31 December 2012, the net carrying amount of oil and gas properties and related cost of production licence was $496,606thousand (2011: $421,388thousand).

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. Deferred tax assets are recognised for all unused tax losses to the extent that it is probable that taxable profit will be available against which the losses can be utilised. Significant management judgment is required to determine the amount of deferred tax assets that can be recognised, based upon the likely timing and the level of future taxable profits together with future tax planning strategies (Note 28).

6. segmental analysis

Management has determined the operating segments based on the reports reviewed by the 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 as three operating segments, Exillon WS, Exillon TP andRegional Resources.

·; 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.

·; Regional Resources: oil trading company based in Moscow in the Russian Federation.

Segmental information for the Group for the year ended 31 December 2012 is presented below:

Segmental information for the Group for the year ended 31 December 2011 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). In 2012, other significant one-off itemsincluded a lossof $1,062 thousand arising on the write-off of capitalised workover of oil wells. The measure also excludes the effects of equity-settled share-based payments.

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 year ended 31 December 2012 is presented below:

Reconciliation of operating (loss)/profit to EBITDA for the year ended 31 December 2011 is presented below:

Activities by geographical areas

The Group derives its revenue from export and domestic sales with the allocation of revenue on the basis of the customer's location:

In 2012, the Group earned revenues each exceeding 10% of Group's revenues from three major customers of $166,000 thousand (attributable to export sales), $51,634 thousand and $31,319thousand (both attributable to domestic sales), reported by Exillon WS and Exillon TP segments.

In 2011, the Group earned revenues each exceeding 10% of Group's revenues from four major customers of $95,284 thousand and $27,630 thousand (both attributable to export sales) and $25,780 thousand and $25,362 thousand (both attributable to domestic sales), reported by Exillon WS and Exillon TP segments.

As at 31 December 2012 and 2011, non-current assets located outside the Russian Federation were insignificant.

7. cost of sales

8. selling expenses

9. administrative expenses

10. other INCOME/(eXPENSE)

The Company received the penalties from its suppliers as a result of theirnon-compliance with contractual terms.

11. auditors' remuneration

During the year, the Group obtained the following services from the Group's auditor as detailed below:

12. Employee costs

The average number of full time equivalent employees (including directors) during the year was as follows:

13. finance income

14. finance cost