Exillon Energy: Interim Results of 2013, Production Up 35%
Exillon Energy plc, a London Premium listed independent oil producer with assets in two oil-rich regions of Russia, Timan-Pechora and West Siberia, today issues its interim results for the first six months to 30 June 2013.
“During the first half of 2013 we delivered a dramatic increase in reserves (increasing 2P reserves by 96%), and continued strong financial performance (an 83% increase in EBITDA). Our production increased 35% over the same period in 2012, and 9% over the second half of 2012.”
Financials
Our EBITDA increased 83% year-on-year, from US$15.6 million to US$28.6 million, while we posted a net profit of US$7.9 million compared to a US$1.7 million net loss in the first half of 2012.
We had US$72.9 million of cash and cash equivalents as at 30 June 2013. Net debt position was US$27.3 million. As of 23 August 2013 our cash and cash equivalents had increased to US$97.8 million and our net debt was therefore US$3.3 million.
Reserves
As announced in March 2013, our total proved (“1P”) reserves increased by 56% to 196 million barrels, our total proved plus probable (“2P”) reserves increased by 96% to 520 million barrels and our total proved plus probable plus possible (“3P”) reserves increased by 121% to 882 million barrels.
Production
Oil production increased 35% from 2.1 million to 2.83 million barrels equivalent to an increase from 11,539 bpd to 15,621 bpd compared to H1 2012, and 9% from 2.6 million to 2.83 million compared to H2 2012.
Primarily because of the reduction in our drilling programme for 2013 in Exillon TP, we have revised our production expectations for December 2013. We now expect production to reach between 18,000 and 19,000 bpd, once the ongoing upgrade to our oil processing facility is completed. Further details are given later in this statement.
Our strategy is to deliver a balance of growth in production, EBITDA and reserves. During the first half of 2013 we delivered a dramatic increase in reserves (increasing 2P reserves by 96%), and continued strong financial performance (an 83% increase in EBITDA). Our production increased 35% over the same period in 2012, and 9% over the second half of 2012.
Drilling and Production – Exillon WS
Production at Exillon WS is currently constrained by an oil processing capacity bottleneck. This currently caps daily production at 1,600 tonnes (approximately 12,500 barrels) per day. We have continued to complete additional wells and therefore we have “behind pipe” capacity. A second stage of the oil processing facility is expected to be completed in November 2013, at which point we estimate that production in Exillon WS is likely to increase by approximately 2,000 bpd.
During the period we drilled, completed and announced 8 wells in Exillon WS. These were announced on 13 June and 18 July. We have recently drilled, and are currently completing and testing, four more wells in EWS. These are wells 71, 73, 80, 92 and we expect to announce results shortly. In addition we are currently drilling Wells 74 and 93.
Drilling and Production – Exillon TP
Exillon TP has had mixed drilling results this year. Some of the wells discovered thick oil saturated net pay formations confirming or exceeding our geological model. However flow rate results from these wells were lower than expected because of a lack of natural fractures.
We are now working with an international project institute to reinterpret our existing seismic data in order to adjust our drilling programme to better target highly fractured zones. We believe that this additional analysis is necessary to extract the greatest value from Exillon TP, and we will therefore pause our current drilling programme until these studies have been completed.
During the period we drilled, completed and announced 3 wells in Exillon TP. These were announced on 18 July. We do not now intend to complete the 4 additional wells that had been planned for the 2013 drilling programme in TP (2 each from Pads 2 and 3). As a result we do not expect any further production growth in ETP in 2013.
Drilling and Production – 2013 drilling results (all previously announced)
This year in EWS we have previously announced via RNS the results of EWS I – 70, EWS I – 64, EWS I – 65, EWS I – 66, EWS I – 90, EWS I – 201, EWS I – 91, EWS I – 72. In Exillon TP we announced Well North ETP VI – 3, Well ETP VI – 2 and Well ETP IV – 5002.
EWS I – 70
Well EWS I – 70 was drilled on the northern extension of the East EWS I field. The well was spudded on the 4th May 2013 and drilled and cemented in 13 days. The well encountered the Jurassic P reservoir at 1,871 metres, confirming 17.8 metres of effective vertical net oil pay.
The well flowed oil naturally to the surface with a flow rate of 499 bbl/day on an 8 mm choke. The well was drilled vertically from Pad 7, and is now connected to our existing production facilities.
EWS I – 64
Well EWS I – 64 was drilled on the north-west extension of the EWS I field. The well was spudded on the 1st February 2013 and drilled and cemented in 29 days. The well encountered the Jurassic P reservoir at 1,862 metres, confirming 2.7 metres of effective vertical net oil pay.
Upon perforation the well flowed 220 bbl/day, of which 44 bbl/day was oil. The well was drilled 1.1 km to the north-west of Pad 6. Due to the fact that the well is located lower than any other well on the structure it has been converted to water injection for the purposes of maintaining reservoir pressure.
EWS I – 65
Well EWS I – 65 was drilled on the north-west extension of the EWS I field. The well was spudded on the 3rd March 2013 and drilled and cemented in 25 days. The well encountered the Jurassic P reservoir at 1,858 metres, confirming 8.6 metres of effective vertical net oil pay and 14.2 metres of net pay along the well bore.
The well is currently operated with a submersible pump flowing at 156 bbl/day, of which 85 bbl/day is oil. Going forward we will seek to minimize water cut in the production from this well. The well was drilled 1.6 km to the north-west of Pad 6, and is now connected to our existing production facilities.
EWS I – 66
Well EWS I – 66 was drilled on the north-west extension of the EWS I field. The well was spudded on the 30th March 2013 and drilled and cemented in 14 days. The well encountered the Jurassic P reservoir at 1,852 metres, confirming 10.5 metres of effective vertical net oil pay and 18.2 metres of net pay along the well bore.
The well is currently operated with a submersible pump flowing at 574 bbl/day, of which 551 bbl/day is oil. The well was drilled 1.0 km to the north-east of Pad 6, and is now connected to our existing production facilities. Well 6 is the last planned well from Pad 6.
Appraisal well EWS I – 90
Appraisal well EWS I – 90 was designed to test the north-east extension of the EWS I field. The structure was previously tested with well EWS I – 61, but due to a long deviation of well EWS I – 61, the structure was not tested for flow rates.
The well was spudded on the 13th April 2013 and drilled and cemented in 34 days. 18.4 metres of core was collected, which is represented by mudstones, gravel conglomerates, and sandstones. The core exhibits signs of hydrocarbon saturation. During a test the well has produced only a film of oil due to low permeability of the producing horizon.
We will assess the core data for methods of producing from this reservoir. Two additional wells have been previously planned for drilling in this part of the field in 2013. No further drilling will be completed in this area of the field prior to the completion of petrophysical studies.
The well was drilled 0.7 km to the south-east of Pad 9, and has been converted to a water source well.
EWS I – 91
Well EWS I – 91 was drilled on the central part of the north-west extension of the EWS I field. The well was spudded on the 18th May 2013 and drilled and cemented in 20 days. The well encountered the Jurassic P reservoir at 1,856 meters, confirming 4.3 meters of effective vertical net oil pay and 7.2 meters of net pay along the well bore.
The well is currently operating with a submersible pump flowing oil at 377 bbl/day. The well was drilled 1.2 km to the north-west of Pad 9, and is now connected to our existing production facilities.
EWS I – 72
Well EWS I – 72 was drilled on the margin of the northern extension of the East EWS I field. The well was designed to test the productivity of the margin of the field which represents a transitional zone between collector quality sands and non-collector.
The well was spudded on the 8th June 2013 and drilled and cemented in 18 days. The well encountered the Jurassic P reservoir at 1,876 meters, confirming 4.3 meters of effective vertical net oil pay.
The well is currently operating with a submersible pump flowing oil at 94 bbl/day. The well was drilled 0.6 km to the north of Pad 7.
Appraisal well North ETP VI – 3
Appraisal well North ETP VI – 3 was designed to test northern extension of the North ETP VI field.
The well was spudded on 27 March 2013 and drilled and cemented in 84 days. The well encountered Lower Silurian reservoir at 3,175 metres, confirming 12.2 metres of absolute effective net oil pay.
The well is currently being tested with natural oil rates to surface ranging from 488 bbl/day on an 18 mm choke to 92 bbl/day on a 6 mm choke. The well was drilled vertically from Pad 3, and is now connected to existing production facilities.
Exploration well ETP VI – 2
Exploration well ETP VI – 2 was drilled on the southern tip of the ETP VI structure. The well was spudded on 29 April 2013 and drilled and cemented in 70 days.
45.5 meters of core were collected, which is represented by low permeability carbonates with no signs of hydrocarbon saturation. During a test the well did not produce oil.
We will re-assess the geological model of the area and intend to conduct a fracture survey. Two additional wells have been previously planned for drilling in this part of the field in 2013. No further drilling will be completed in this area of the field prior to the completion of the fracture survey.
Well ETP IV – 5002
Well ETP IV – 5002 was spudded on 12 February 2013 and drilled and cemented in 64 days on the northern part of the ETP IV field. The well encountered Lower Silurian reservoir at 3,272 metres, confirming 15.6 metres of absolute effective net oil pay. In addition, the well encountered Domanic reservoir at 3,245 metres, confirming 5.7 metres of absolute effective net oil. Due to the angled trajectory of the well bore, this well exposed 25.4 metres of effective net oil pay.
The well is currently operating with a submersible pump flowing oil at 8 bbl/day. To increase the flow rate from this well we will consider conducting an acid hydrofrack in the upcoming winter season.
The well was drilled 0.9 km to the north-west of Pad 5, and is now connected to existing production facilities. Well ETP IV – 5002 is the last planned well from Pad 5.
Infrastructure
In order to improve our profitability we have continued to enhance and complete significant items of infrastructure. In ETP our 25 km gas pipeline (for associated gas) is now operational, and the parallel 25 km oil pipeline is complete and expected to be operational by the end of 2013.
In EWS our 40 km intra-field pipeline was completed on time and on budget, doubling its capacity. Our oil treatment facility on our main EWS I field is operating at full capacity, and is currently being expanded from a capacity of 1,600 tonnes (approximately 12,500 bpd) to 3,000 tonnes (approximately 23,400 bpd). We expect this upgrade to be completed later this year.
We are finalising our plans in EWS to utilize our associated gas. This is necessary in order to fulfil our licence obligations and to avoid flaring penalties. In order to accomplish this in a cost effective manner we are actively considering a project to extract lighter fractions from our oil. We currently produce oil that is lighter (and therefore more valuable) than Urals blend. However most of our sales in EWS are currently blended via the Transneft network and we lose the value of this quality premium. Extracting lighter fractions will allow us to monetise some of this quality premium at the same time as increasing power consumption and thereby gas utilisation. Once implemented these plans could lead to a material increase in EBITDA per bbl. Overall capex for this project is within our existing budget for gas utilisation projects.
Capital expenditure during the period was approximately US$ 66.1 million (45% of which was in ETP and 55% in EWS). Of this total, US$17.7 million was attributable to drilling, US$47.6 million to infrastructure and US$0.8 million to seismic data acquisition and interpretation.
Financial Performance
During the first six months of 2013 our oil production increased by 35% from 2.1 million barrels to 2.83 million barrels. This was equivalent to average production for the 6 months of 15,621 bpd, and also an increase of 11% over the 14,089 bpd for the second 6 months of 2012.
During the reporting period, our revenue increased 15% from US$140.0 million to US$161.6 million. Our netback (which we define as revenue less Mineral Extraction Tax, Export Duty and Transneft charges) rose 30% from US$44.5 million to US$57.7 million.
EBITDA increased 83% from US$15.6 million in H1 2012 to US$28.6 million in H1 2013, whilst net profit grew from US$1.7 million of net loss to US$7.9 million of net profit. The growth in EBITDA and net profit was a result of continuing investment in our surface infrastructure and our increased production.
EBITDA was equivalent to US$10.2 per barrel compared to US$7.6 per barrel in H1 2012. However this was lower than achieved in H2 2012 mainly because of lower netbacks. The main driver for these lower netbacks was the declining trend in the price of Urals during the period.
Our balance sheet remains strong with US$72.9 million of cash and cash equivalents as at 30 June 2013. As at 30 June 2013, debt was US$100.2 million, so our net debt position was US$27.3 million. As of yesterday our cash and cash equivalents had increased to US$97.8 million and our net debt was therefore US$3.3 million.
Exillon’s strategy is to deliver to our shareholders a balance of growth in production, reserves and profitability. We will continue to adapt the geographical balance of our investment programme between ETP and EWS, as well as the pace of this programme, to deliver these goals.
Mark Martin
Chief Executive Officer
FINANCIAL REVIEW
The interim condensed consolidated financial information of Exillon Energy plc for the six month period ended 30 June 2013 has been prepared in accordance with IAS 34 “Interim Financial Statements”. The condensed consolidated financial information and notes on pages 9 through to 27 should be read in conjunction with this review which has been included to assist in the understanding of the Group’s financial position at 30 June 2013.
Summary
EBITDA for the six months ended 30 June 2013 increased by 83% to US$28.6 million compared to US$15.6 million for the six months ended 30 June 2012.
Net profit for the period, which includes depreciation costs, foreign exchange loss and share-based compensation, amounted to US$7.9 million compared to net loss of US$1.7 million for the six months ended 30 June 2012.
Revenue
Our revenue for the six months ended 30 June 2013 increased by 15% year-on-year, reaching US$161.6 million (2012: US$140.0 million), of which US$67.6 million or 42% came from export sales of crude oil and US$94.0 million or 58% came from domestic sales of crude oil. This increase in revenue is attributable to:
· An increase in production leading to a 36% increase in sale volumes from 2,063,842 bbl in 2012 to 2,811,932 bbl; and
· A change in average commodity prices: we achieved an average oil price of US$97.5/bbl (2012: US$106.9/bbl) for export sales and US$44.4/bbl (2012: US$43.8/bbl) for domestic sales.
Currently our netback for domestic sales is higher than the one for export sales because of the fluctuations in oil prices. Our total netback for domestic and export sales increased by 30% from US$44.5 million to US$57.7 million year-on-year.
Operating Results
Operating costs excluding depreciation, depletion and amortisation increased to US$76.6 million (2012: US$58.4 million) following an increase in production of 35% to 2,827,312 bbl (2012: 2,100,162 bbl). The difference between the production volumes and sales volumes is due to the change in the oil inventory balance during the year. The increase in production costs is mainly related to the growth of mineral extraction tax from US$45.0 million in 2012 to US$60.3 million in 2013, as a result of higher production volumes and increased tax rate. Another cost driver was the increased gas flaring penalties.
Depreciation, depletion and amortisation costs primarily relate to the depreciation of proven and probable reserves and other production and non-production assets. These costs totalled US$11.2 million (2012: US$8.2 million). The increase in DD&A costs is driven by higher production volumes and by bringing into operation infield facilities once their construction was completed.
Selling expenses for the six months ended 30 June 2013 of US$46.15 million (2012: US$55.7 million) is comprised of export duties of US$35.4 million (2012: US$44.1 million), transportation services of US$10.73 million (2012: US$10.8 million) and other selling expenses of US$0.02 million (2012: US$0.8 million). Transportation services include services provided by Transneft and transportation services from oil field to oil filling station. In 2013, the export duty rate fluctuated within the range from US$359.3 per tonne to US$420.6 per tonne following the changes in crude oil prices. Export duty is reviewed by the Russian government on a monthly basis and is based on a formula that takes into account the average Urals price prevailing in the market between the 15th of the previous month and 14 th— of the month of delivering the crude.
Administrative expenses (excluding share-based compensation expenses, depreciation and amortisation) totalled US$10.7 million (2012: US$10.5 million). In 2013, savings were achieved in salary and related taxes, business trip and office rent expenses with increase in consulting services.
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In 2013, interest income increased to US$1.8 million (2012: US$1.6 million) resulting from surplus cash being held on short-term deposits and VTB credit-linked deposits.
It should be noted that – in accordance with IFRS – a foreign exchange loss of US$3.8 million has been included in our net profit arising from the revaluation of foreign currency monetary items (cash and cash equivalents, accounts receivable and payable, other assets) using the closing rate at the reporting date. A larger foreign exchange loss of US$35.5 million has been applied directly to the consolidated statement of financial position as the part of translation reserve.
As a result of the above, the Group reported a net profit after tax of US$7.9 million compared to a loss of US$1.7 million for the six months ended 30 June 2012.
Financial position
We ended the period with US$72.9 million of cash and cash equivalents (31 December 2012: US$121.0 million) and outstanding borrowings of US$100.2 million.
The increase in the property, plant and equipment has been driven by extensive drilling of wells, the construction of 40 km pipeline from infield oil processing facility to oil filling station and other field developments in Exillon WS; successfully completed construction of two 25 km pipelines for transportation of oil and gas to the refinery and drilling of wells at Exillon TP. This was offset by a translation difference due to the depreciation of the Russian Rouble against the US Dollar at the reporting date.
Principal risks and uncertainties
The principal risks and uncertainties affecting the business activities of the Group are set out on pages 18 to 19 of the Directors’ Report section of the Annual Report for the year ended 31 December 2012, a copy of which is available on the Company’s website at www.exillonenergy.com. The Board continually assesses and monitors the key risks of the business. The principal risks and uncertainties that could have a material impact on the Group’s performance over the remainder of the financial year have not changed from those which are set out in the Group’s 2012 Annual Report.
Directors
A full list of Directors is maintained on the Group’s website: exillonenergy.com.
Related parties
Related party transactions are given in note 23.
Statement of directors’ responsibilities
The Directors of the Company hereby confirm that to the best of their knowledge:
(a) the condensed consolidated interim financial statements have been prepared in accordance with IAS 34 and give a true and fair view of the assets, liabilities, financial position and profit and loss of the Group as required by DTR 4.2.10(4); and
(b) the interim management report includes a fair review of the information required by DTR 4.2.7 (being an indication of important events that have occurred during the first six months of the financial year and their impact on the condensed set of financial statements; and a description of the principal risks and uncertainties for the remaining six months of the year) and DTR 4.2.8 (being related party transactions that have taken place in the first six months of the current financial year and that have materially affected the financial position or performance of the entity during that period).
On behalf of the board of directors of Exillon Energy plc.
Mark Martin
Chief Executive Officer
Disclaimer
This statement may contain forward-looking statements concerning the financial condition and results of operations of the Group. Forward-looking statements are statements of future expectations that are based on the management’s current expectations and assumptions and involve known and unknown risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied in these statements. No assurances can be given as to future results, levels of activity and achievements and actual results, levels of activity and achievements may differ materially from those expressed or implied by any forward-looking statements contained in this report. The Company does not undertake any obligation to update publicly or revise any forward-looking statement as a result of new information, future events or other information.
INDEPENDENT REVIEW REPORT TO EXILLON ENERGY PLC
Introduction
We have been engaged by the Exillon Energy PLC (the “Company”) to review the condensed consolidated set of financial statements in the half-yearly financial report for the six months ended 30 June 2013 which comprises the interim consolidated statement of comprehensive income, interim consolidated statement of financial position, interim consolidated statement of changes in equity, interim consolidated statement of cash flows and the related notes 1 to 24. We have read the other information contained in the half yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed consolidated set of financial statements.
This report is made solely to the company in accordance with guidance contained in International Standard on Review Engagements 2410 (UK and Ireland) “Review of Interim Financial Information Performed by the Independent Auditor of the Entity” issued by the Auditing Practices Board. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our work, for this report, or for the conclusions we have formed.
Directors’ Responsibilities
The half-yearly financial report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure and Transparency Rules of the United Kingdom’s Financial Conduct Authority.
As disclosed in note 2, the annual consolidated financial statements of the company are prepared in accordance with IFRS. The condensed consolidated set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34, “Interim Financial Reporting”.
Our Responsibility
Our responsibility is to express to the Company a conclusion on the interim condensed consolidated set of financial statements in the half-yearly financial report based on our review.
Scope of Review
We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410, “Review of Interim Financial Information Performed by the Independent Auditor of the Entity” issued by the Auditing Practices Board for use in the United Kingdom. A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK and Ireland) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.
Conclusion
Based on our review, nothing has come to our attention that causes us to believe that the interim condensed consolidated set of financial statements in the half-yearly financial report for the six months ended 30 June 2013 is not prepared, in all material respects, in accordance with International Accounting Standard 34 and the Disclosure and Transparency Rules of the United Kingdom’s Financial Conduct Authority.
