Genel Energy plc Unaudited results for the period ended 30 June 2018

Transcription

1 P a g e 1 7 August 2018 Genel Energy plc Unaudited results for the period ended 30 June 2018 Genel Energy plc ( Genel or the Company ) announces its unaudited results for the six months ended 30 June Murat Özgül, Chief Executive of Genel, said: Genel continues to deliver on its focus. We are generating significant free cash flow, averaging over $10 million a month in the first half of 2018 and moving us rapidly towards a net cash position. The impressive performance we have seen at Peshkabir will further increase cash generation, and the ongoing appraisal success provides the potential for both production to exceed guidance and for proven and probable reserves to increase. Growing cash generation provides a solid bedrock from which we are able to pursue multiple growth opportunities, with Bina Bawi oil offering exciting potential within the Genel portfolio. With 11 wells currently drilling or to be drilled on our producing assets in the Kurdistan Region of Iraq in H2 2018, of which eight are expected to be completed and adding to production by the end of the year, we are well positioned to both add value through the drill bit and further bolster our financial strength. Results summary ($ million unless stated) H H1 FY Production (bopd, working interest) 32,100 37,100 35,200 Revenue Net gain arising from the RSA EBITDAX Depreciation and amortisation (63.6) (45.7) (117.4) Exploration expense (0.5) (4.8) (1.9) Impairment of property, plant and equipment - - (58.2) Operating profit Cash flow from operating activities Capital expenditure Free cash flow Cash Total debt Net debt Basic EPS ( per share) EBITDAX is earnings before interest, tax, depreciation, amortisation, exploration expense and impairment which is operating profit adjusted for the add back of depreciation and amortisation ($63.6 million), exploration expense ($0.5 million) and impairment of property, plant and equipment (nil) 2. Free cash flow is net cash generated from operating activities less cash outflow due to purchase of intangible assets ($10.5 million) and purchase of property, plant and equipment ($29.5 million) and interest paid ($15.0 million) 3. Cash reported at 30 June 2018 excludes $17.5 million of restricted cash 4. Reported IFRS debt less cash

2 P a g e 2 Highlights Net working interest production averaged 32,100 bopd in H1 2018, in line with guidance Peshkabir continues to exceed expectations, with the successful Peshkabir-4 and 5 wells boosting gross current field production to 35,000 bopd o Peshkabir-5 has successfully proved the westward extension of the field, with an increase in proven and probable reserves expected to follow Net working interest production currently c.35,500 bopd $151 million of cash proceeds received in H (H1 : $139 million), boosted by the impact of the Receivable Settlement Agreement and a higher oil price, with strong free cash flow generation of $70 million Cash of $233 million at 30 June 2018 ($162 million at 31 December ) Net debt of $64 million at 30 June 2018 ($135 million at 31 December ) Outlook 11 wells set to be under drilling operations across assets in the Kurdistan Region of Iraq in H2 2018, with eight expected to be completed and contributing to production by the end of the year Cash generation expected to remain strong in H2 2018, with monthly free cash flow of over $10 million Genel expects to be in a net cash position around the end of 2018 Field development plan for Bina Bawi oil complete and set to be submitted to the Ministry of Natural Resources, with Bina Bawi and Miran gas plans to also be submitted in H guidance refined: o Production guidance of c.32,800 bopd reiterated, with the potential for this to be exceeded through an ongoing positive performance at Peshkabir and the resumption of drilling at Tawke and Taq Taq o Capital expenditure net to Genel is forecast to be $ million (previously $ million): - Tawke PSC and Taq Taq net to Genel of $70-80 million (previously $60-85 million), as work ramps up across both licences - Miran and Bina Bawi capex of $15-30 million (previously $25-40 million), as the work programme focuses on progression of the high-value oil opportunity at Bina Bawi - African exploration cost unchanged at$10-15 million, with the majority relating to seismic shooting offshore Morocco, which will be covered by restricted cash - Opex of c.$30 million and G&A of c.$15 million cash cost unchanged For further information, please contact: Genel Energy Andrew Benbow, Head of Communications Vigo Communications Patrick d Ancona There will be a presentation for analysts and investors today at 0930 BST, with an associated webcast available on the Company's website, This announcement includes inside information. Disclaimer This announcement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil & gas exploration and production business. Whilst the Company believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to factors beyond the Company s control or within the Company s control where, for example, the Company decides on a change of plan or strategy. Accordingly no reliance may be placed on the figures contained in such forward looking statements. The information contained herein has not been audited and may be subject to further review.

3 P a g e 3 OPERATING REVIEW PRODUCTION Net working interest production in H averaged 32,100 bopd, in line with guidance. (by PSC in bopd) Export via Refinery Total Total Genel net pipeline sales 1 sales production 2 production Tawke (inc. Peshkabir) 104, , ,771 26,443 Taq Taq 11,603 1,182 12,785 12,769 5,618 Total 116,507 1, , ,540 32,061 1 Refinery sales at Taq Taq denote sales to the Bazian refinery 2 Difference between production and sales relates to inventory movements All sales during the period were invoiced at the wellhead export netback price. KRI OIL ASSETS Five wells were spud across our assets in the KRI in the period, four of which were on the Peshkabir field. Drilling work is heavily loaded towards the second half of the year, with 11 wells set to be under operation in H2 on our producing fields, with eight expected to be adding to production by the end of the year. TAWKE PSC (25% working interest) The Tawke PSC produced an average of 105,800 bopd in H1 2018, slightly down on H1 (109,700 bopd), with additional production from the successful drilling campaign at the Peshkabir field coming post-period end. Current Tawke PSC production is c.121,000 bopd, with success from the remaining Peshkabir wells, and the resumption of drilling at the Tawke field, having the potential to further increase this figure. Production from the Tawke PSC benefits from the Receivable Settlement Agreement ( RSA ), and these increases bolster our already significant free cash flow generation. Tawke field Activity in H1 included ongoing workovers of existing wells, which has mitigated decline at the Tawke field in the last three months. Drilling will resume at the field in the second half of the year, with up to four production wells set to be spud. Two are scheduled as Jeribe producers, and up to two as Cretaceous producers. Drilling will arrest production decline at Tawke, as expected with mature field infill drilling, with the overall objective to maximise production and cash-generation. Peshkabir field Peshkabir continues to exceed expectations, with the benefit of ongoing appraisal success increasing production in H Peshkabir-4 is now adding to production at a stable rate of 12,000 bopd, with Peshkabir-5 adding a further 8,000 bopd, materially surpassing the operator s previously announced summer 2018 Peshkabir production target of 30,000 bopd. The field is currently producing c.35,000 bopd, with another four wells set to be completed in Peshkabir-5 was drilled seven kilometres west of Peshkabir-3, and has successfully proved the westward extension of the field. As it was drilled in an area designated P3 (possible) reserves, should production continue to match current expectations then it would lead to an increase in proven and probable reserves at the field. With 217 MMboe of reserves booked in the in the P3 (possible) category as at the end of 2018, this increase is potentially significant. Activity continues apace at Peshkabir. Two wells, Peshkabir-6 and Peshkabir-7, are now at target depth, with the former aiming to establish the Cretaceous oil/water contact and exploring the field's

4 P a g e 4 untested deeper Triassic formation, and the latter targeting infill production. Peshkabir-8 will also target further production, with Peshkabir-9 being drilled to test the eastern extension of the field, as we work with the operator to ascertain the full extent of Peshkabir s potential. Given the potential for a material increase from current production levels, work is being undertaken on facilities at the field. The central processing facility, which has been brought across from Taq Taq and is expected onstream later this year, is set to ensure that surface capacity is sufficient to service production. Discussions are ongoing with the operator regarding the Enhanced Oil Recovery project, under which excess gas from Peshkabir would be used to boost oil production from the Tawke licence. TAQ TAQ (44% working interest, joint operator) Production at Taq Taq remained stable in H1 as the well intervention and production optimisation programme, focused on the provision of artificial lift and water shut off in existing wells, continued to give encouraging results. The stabilisation of production provides a solid base from which to ramp up activity at the field. Work to analyse the result of the TT-29w well, which encountered a deeper free water level and more extensive oil bearing cretaceous reservoirs on the northern flank of the field than previously forecast, has now been completed. The results have helped in the formulation of an updated field development plan ( FDP ), which has now been completed and agreed with our field partners and the Ministry of Natural Resources. Phase one of the FDP is a five well programme, starting towards the end of Q3, and ending in Q The drilling programme will target the flanks in order to prove up the remaining potential of the field, starting with the TT-32 well, which will test the extent of oil to the north of the TT-29w well. The next well will then be drilled as a sidetrack on the western flank of the field, before the rig moves to the southern flank. Drill locations will follow depending on results. Given the stabilisation of production at Taq Taq, we expect these wells to increase field production, with the benefits starting to be seen towards the end of the year. The field continues to generate meaningful free cash flow, boosted by an ongoing cost reduction programme. BINA BAWI AND MIRAN (100% working interests and operator) Work continues to unlock the transformational potential of the Bina Bawi and Miran licences. The focus in H1 has been on the progression of the high-value early oil development at Bina Bawi. The field development plan for Bina Bawi oil has now been completed, and is set to be submitted to the Ministry of Natural Resources. The FDP confirms Genel s expectation that first oil would be achievable around six months after the final investment decision. Light oil (44-47 API) has already been tested at Bina Bawi, with the Bina Bawi-3 well having flowed at c.3,500 bopd. Phase one of the development would see the recompletion of this well, and a sidetrack of the Bina Bawi-1 well, both of which target the proven Mus reservoir, and would aim for a combined 5,000 bopd of initial production. The cost to first oil is estimated at c.$20 million. Phase two, to be executed simultaneously to phase one, would be the drilling of up to four new wells, targeting a production plateau of 10-15,000 bopd, achievable a year from the beginning of work. Phase three would then constitute additional infill wells as required. Oil production from Bina Bawi would benefit from cost-recovery of the significant capital outlay already made by Genel at Bina Bawi, and has the potential to add material cash flow. Discussions are ongoing with the Ministry of Natural Resources in order to expedite the development of Bina Bawi oil.

5 P a g e 5 Genel estimates that 34 MMbbls of light oil is recoverable under the FDP, and would be converted to 2P reserves upon final investment decision. In January 2018 Bina Bawi and Miran CPRs confirmed a c.45% uplift to gross 2C raw gas resources to 14.8 Tcf. The upstream part of the project has been materially de-risked, with 1C volumes more than sufficient for the gas volumes required under the gas lifting agreement. Following the CPR, further reservoir engineering has demonstrated the viability of high-rate gas wells, which in turn more than halves the number of wells required to produce the volumes under the gas lifting agreement, materially reducing the overall cost of the project. A field development plan regarding Bina Bawi gas is set to be submitted to the Ministry of Natural Resources around the end of Q3 2018, with one for the Miran field around the end of the year. Genel is ready to progress the upstream as required, with further investment to be made appropriate to progress on the midstream. EXPLORATION Onshore Somaliland, the processing of c.3,500 km of raw 2D seismic data on the SL-10B/13 (Genel 75% working interest, operator) and Odewayne (Genel 50% working interest, operator) is almost complete. Analysis and interpretation is underway. Evidence of a thick Mesozoic rift basin continues to provide encouragement, and the first analysis of this highly-prospective region in over 25 years is expected to complete in Q4. A prospect inventory will then be developed, guiding the optimal strategy to maximise future value, with the potential to spud a well around the end of The 3D seismic campaign on the Sidi Moussa licence (Genel 75% working interest, operator), offshore Morocco, has now begun. Seismic acquisition is expected to be completed in the middle of Q Fast-track processing will begin ahead of the completion of this acquisition, as Genel de-risks the licence and assesses future activity.

6 P a g e 6 FINANCIAL REVIEW For 2018 the financial priorities of the Company are the following: Maintenance of a strong balance sheet and management of liquidity runway throughout the development of the Miran and Bina Bawi fields Continued focus on capital allocation, with prioritisation of highest value investment in assets with ongoing or near-term cash generation Continued focus on cost optimisation and performance management Selective investment in value accretive growth opportunities that provide visible cash generation and debt capacity In the first half of the year, successful delivery of these priorities, together with an improving oil price, has produced positive results, with free cash flow of $70 million representing an increase of 28% on the previous year. Our net debt has reduced significantly to $64 million compared to $135 million at the end of and we expect to be in a net cash position around the end of We will continue to be disciplined in our capital allocation and invest in areas where we can deliver value. Currently this means investment in Peshkabir, where success will provide incremental cash generation in the second half, and our other producing assets, which also offer opportunities to increase near-term cash flow. We will make further investment in Bina Bawi oil and our gas potential when we can see a clear roadmap to unlocking value. As there remains limited visibility on the gas developments at Bina Bawi and Miran, spend has been minimised, with the focus on completing the FDP for Bina Bawi oil. Rigorous cost management is maintained across all operations, while ensuring spend is sufficient to take advantage of the growth opportunities in the portfolio. A summary of the financial results for the year is provided below. As regular payments for oil sales have now been received from the KRG for almost three years, the Company will cease to make monthly announcements, and will instead update on cash receipts as part of its standard corporate reporting schedule. Financial results for the half-year Income statement Revenue has increased by 85% year-on-year, from $87.1 million to $161.1 million. This is principally a result of the improved revenue generation from the Tawke PSC arising from the RSA, which was signed in August and generated incremental revenue of $48.2 million in the first half of Additional benefit has arisen from improved Brent oil price of $71/bbl (H1 : $52/bbl). Working interest production of 32,100 bopd was lower than the first half last year (H1 : 37,100 bopd), which benefited from Taq Taq working interest daily production being around 5,000 bopd higher since around May. Production costs of $12.1 million (H1 : $13.2 million) are broadly in line with last year, with $/bbl staying around $2/bbl. Depreciation and amortisation of oil assets has increased overall by $18.6 million as a result of the inclusion of amortisation of $28.8 million relating to intangible assets arising from the RSA. This was offset by a $10.2 million decrease in depreciation as a result of lower production.

7 P a g e 7 General and administration costs were $11.8 million (H1 : $10.1 million), of which cash costs were $8.6 million (H1 : $6.4 million). Gross cost was reduced by 8% from the prior year, with the net increase caused primarily by movement in the exchange rates between sterling and US dollar. Taxation Under the KRI PSC s, tax due is paid on behalf of the Company by the KRG from the KRG s own share of revenues, resulting in no tax payment required or expected to be made by the Company. Capital expenditure Capital expenditure for the period was $34.1 million (H1 : $41.0 million). Cost recovered spend on producing assets in the KRI was $27.8 million (H1 : $28.1 million) with spend on exploration and appraisal assets amounting to $6.3 million (H1 : $12.9 million), principally incurred on the Miran PSC and the Bina Bawi PSC. Cash flow and cash Net cash flow from operations was increased as a result of higher revenue to $125.1 million (H1 : $114.2 million), with last year benefiting from $50.9 million of one-off positive working capital movements relating to the overdue KRG receivable. Free cash flow after interest was $70.1 million (H1 : $54.6 million). $17.5 million (H1 : $18.5 million) of cash is restricted and therefore excluded from reported cash of $233.2 million (H1 : $245.7 million). Overall, there was a net increase in cash of $71.1 million compared to a decrease of $161.1 million last period after $216.7 million of cash was used to buy back of Company bonds in H1. Debt Reported IFRS debt was $297.0 million (31 December : $296.8 million) and net debt was $63.8 million (31 December : $134.8 million). The bond has three financial covenant maintenance tests: Financial covenant Test H Net debt / EBITDAX (rolling 12 months) < Equity ratio (Total equity/total assets) > 40% 77% Minimum liquidity > $30m $233m Net assets Net assets at 30 June 2018 were $1,672.9 million (31 December : $1,609.8 million) and consist primarily of oil and gas assets of $1,823.6 million (31 December : $1,847.9 million), trade receivables of $84.4 million (31 December : $73.3 million) and net debt of $63.8 million (31 December : $134.8 million). Liquidity / cash counterparty risk management The Company monitors its cash position, cash forecasts and liquidity on a regular basis. The Company holds surplus cash in treasury bills or on time deposits with a number of major financial institutions. Suitability of banks is assessed using a combination of sovereign risk, credit default swap pricing and credit rating. Dividend No interim dividend will be paid (H1 : nil) or is expected to be paid in the near future.

8 P a g e 8 Going concern The Directors have assessed that the Company s forecast liquidity provides adequate headroom over forecast expenditure for the 12 months following the signing of the half-year condensed consolidated financial statements for the period ended 30 June 2018 and consequently that the Company is considered a going concern. Principal risks and uncertainties The Company is exposed to a number of risks and uncertainties that may seriously affect its performance, future prospects or reputation and may threaten its business model, future performance, solvency or liquidity. The following risks are the principal risks and uncertainties of the Company, which are not all of the risks and uncertainties faced by the Company: Development and recovery of reserves and resources; Commercialisation of KRI gas business; M&A activity; KRI natural resources industry; Payment for KRI sales; Regional risk; Corporate governance failure; Capital structure and financing; Local communities; and Health and safety risks. Further detail on each risk was provided in the Annual Report. There has been no change in principal risks and uncertainties since year-end. Statement of directors responsibilities The directors confirm that these condensed interim financial statements have been prepared in accordance with International Accounting Standard 34, Interim Financial Reporting, as adopted by the European Union and that the interim management report includes a true and fair review of the information required by DTR and DTR 4.2.8, namely: an indication of important events that have occurred during the first six months 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 financial year; and material related-party transactions in the first six months and any material changes in the related-party transactions described in the last annual report. The directors of Genel Energy plc are listed in the Genel Energy plc Annual Report for 31 December. A list of current directors is maintained on the Genel Energy plc website: By order of the Board Murat Ozgul CEO 6 August 2018 Esa Ikaheimonen CFO 6 August 2018 Disclaimer This announcement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil & gas exploration and production business. Whilst the Company believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to factors beyond the Company s control or within the Company s control where, for example, the Company decides on a change of plan or strategy. Accordingly, no reliance may be placed on the figures contained in such forward looking statements.

9 P a g e 9 Condensed consolidated statement of comprehensive income For the period ended 30 June months to 30 June months to 30 June Year to 31 Dec Notes $m $m $m Revenue Production costs 4 (12.1) (13.2) (27.5) Depreciation and amortisation of oil assets 4 (63.4) (44.8) (116.1) Gross profit Exploration expense 4 (0.5) (4.8) (1.9) Impairment of property, plant and equipment (58.2) General and administrative costs 4 (11.8) (10.1) (21.0) Net gain arising from the RSA Operating profit Operating profit is comprised of: EBITDAX Depreciation and amortisation (63.6) (45.7) (117.4) Exploration expense 4 (0.5) (4.8) (1.9) Impairment of property, plant and equipment (58.2) Gain arising from bond buy back Finance income Bond interest expense 5 (15.0) (20.9) (35.5) Other finance expense 5 (1.1) (5.8) (28.0) Profit before income tax Income tax expense (1.0) Profit and total comprehensive income Attributable to: Shareholders equity Profit per ordinary share Basic Diluted

10 P a g e 10 Condensed consolidated balance sheet At 30 June June June 31 Dec Notes $m $m $m Assets Non-current assets Intangible assets 8 1, ,282.9 Property, plant and equipment Trade and other receivables , , ,847.9 Current assets Trade and other receivables Restricted cash Cash and cash equivalents Total Assets 2, , ,106.9 Liabilities Non-current liabilities Trade and other payables (74.5) (93.0) (70.7) Deferred income (33.8) (39.0) (36.1) Provisions (31.0) (24.5) (29.3) Borrowings 11 (297.0) (404.0) (296.8) (436.3) (560.5) (432.9) Current liabilities Trade and other payables (48.1) (85.6) (59.4) Deferred income (5.3) (3.7) (4.8) (53.4) (89.3) (64.2) Total liabilities (489.7) (649.8) (497.1) Net assets 1, , ,609.8 Owners of the parent Share capital Share premium account 4, , ,074.2 Accumulated losses (2,445.1) (2,757.3) (2,508.2) Total equity 1, , ,609.8

11 Condensed consolidated statement of changes in equity For the period ended 30 June 2018 P a g e 11 Share Share Accumulated Total capital premium losses equity $m $m $m $m At 1 January ,074.2 (2,784.6) 1,333.4 Profit and total comprehensive income Share-based payments At 30 June ,074.2 (2,757.3) 1,360.7 At 1 January ,074.2 (2,784.6) 1,333.4 Profit and total comprehensive income Share-based payments At 31 December and 1 January ,074.2 (2,508.2) 1,609.8 Profit and total comprehensive income Share based payments At 30 June ,074.2 (2,445.1) 1,672.9

12 P a g e 12 Condensed consolidated cash flow statement For the period ended 30 June June 30 June 31 Dec 2018 Notes $m $m $m Cash flows from operating activities Profit and total comprehensive income Adjustments for: Gain on bond buy back - (32.6) (32.6) Finance income (2.1) (3.4) (4.9) Bond interest expense Other finance expense Taxation Depreciation and amortisation Exploration expense Impairment of property, plant and equipment Net gain arising from the RSA - - (293.8) Other non-cash items Changes in working capital: Proceeds against overdue receivable Trade and other receivables (10.2) 4.1 (33.5) Trade and other payables and provisions (7.1) (9.0) 0.6 Cash generated from operations Interest received Taxation paid (0.1) (0.1) (0.3) Net cash generated from operating activities Cash flows from investing activities Purchase of intangible assets (10.5) (12.7) (26.8) Purchase of property, plant and equipment (29.5) (23.4) (52.4) Restricted cash Net cash used in investing activities (39.0) (35.1) (78.2) Cash flows from financing activities Repurchase of Company bonds - (216.7) (216.7) Bond refinancing - - (128.5) Interest paid (15.0) (23.5) (42.7) Net cash used in financing activities (15.0) (240.2) (387.9) Net increase / (decrease) in cash and cash equivalents 71.1 (161.1) (245.1) Foreign exchange income / (loss) on cash and cash equivalents 0.1 (0.2) 0.1 Cash and cash equivalents at 1 January Cash and cash equivalents at period end

13 P a g e 13 Notes to the condensed consolidated financial statements 1. Basis of preparation The Company is a public limited company incorporated and domiciled in Jersey with a listing on the London Stock Exchange. The address of its registered office is 12 Castle Street, St Helier, Jersey, JE2 3RT. The half-year condensed consolidated financial statements for the six months ended 30 June 2018 and six months ended 30 June are unaudited and have been prepared in accordance with the Disclosure and Transparency Rules of the Financial Conduct Authority and with IAS 34 Interim Financial Reporting as adopted by the European Union and were approved for issue on 6 August They do not comprise statutory accounts within the meaning of Article 105 of the Companies (Jersey) Law The half-year condensed consolidated financial statements should be read in conjunction with the annual financial statements for the year ended 31 December, which have been prepared in accordance with IFRS as adopted by the European Union. The annual financial statements for the period ended 31 December were approved by the board of directors on 21 March The report of the auditors was unqualified, did not contain an emphasis of matter paragraph and did not contain any statement under the Companies (Jersey) Law The financial information for the year to 31 December has been extracted from the audited accounts. The Company provides non-gaap measures to provide greater understanding of its financial performance and financial position. EBITDAX is presented in order for the users of the financial statements to understand the profitability of the Company, which excludes the impact of costs attributable to exploration activity, which tend to be one-off in nature, and the non-cash costs relating to depreciation, amortisation and impairments. Free cash flow is presented in order to show the free cash flow generated that is available for the Board to use to invest in the business. Net debt is reported in order for users of the financial statements to understand how much debt remains unpaid if the Company paid its debt obligations from its available cash. There have been no changes in related parties since year-end and there are not significant seasonal or cyclical variations in the Company s total revenues. Going concern At the time of approving the half-year condensed consolidated financial statements, the directors have a reasonable expectation that the Company has adequate resources to continue in operational existence for the 12 months from the balance sheet date and therefore its consolidated financial statements have been prepared on a going concern basis. 2. Accounting policies The accounting policies adopted in preparation of these half-year condensed consolidated financial statements are consistent with those used in preparation of the annual financial statements for the year ended 31 December. The preparation of these half-year condensed consolidated financial statements in accordance with IFRS requires the Company to make judgements and assumptions that affect the reported results, assets and liabilities. Where judgements and estimates are made, there is a risk that the actual outcome could differ from the judgement or estimate made. The Company has assessed the following as being areas where changes in judgements, estimates or assumptions could have a significant impact on the financial statements. Significant accounting judgements, estimates and assumptions In preparing these half-year condensed consolidated financial statements, the following significant estimates and judgements have been made: Estimation of future oil price The estimation of future oil price has a significant impact throughout the financial statements, primarily in relation to the estimation of the recoverable value of property, plant and equipment, intangible assets and net gain arising from the RSA for the year ended 31 December. It is also relevant to the assessment of going concern and the viability statement. The Company s forecast of average Brent oil price for future years is based on a range of publicly available market estimates and is summarised in the table below, with the 2022 price then inflated at 2% per annum.

14 P a g e 14 $/bbl HY 2018 forecast YE forecast Estimation of hydrocarbon reserves and resources and associated production profiles Estimates of hydrocarbon reserves and resources are inherently imprecise, require the application of judgement and are subject to future revision. The Company s estimation of the quantum of oil and gas reserves and resources and the timing of its production and monetisation impact the Company s financial statements in a number of ways, including: testing recoverable values for impairment; the calculation of depreciation and amortisation and assessing the cost and likely timing of decommissioning activity and associated costs. This estimation also impacts the assessment of going concern and the viability statement. Proven and probable reserves are estimates of the amount of hydrocarbons that can be economically extracted from the Company s assets. The Company estimates its reserves using standard recognised evaluation techniques. Generally, the Company considers proven and probable reserves ( 2P generally accepted to have circa 50% probability) to be the best estimate for future production and quantity of oil within an asset when assessing its recoverable amount, and therefore this usually forms the basis of calculating depreciation, amortisation of oil and gas assets and testing for impairment. Assets assessed as 2P are generally classified as property, plant and equipment as development or producing assets and depreciated using the units of production methodology. Hydrocarbons that are not assessed as 2P are considered to be resources and are classified as exploration and evaluation assets. These assets are expenditures incurred before technical feasibility and commercial viability is demonstrable. Estimates of resources 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 and are likely to contain estimates and judgements with a wide range of possibilities. These assets are considered for impairment under IFRS 6. Once a field commences 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. Assessment of reserves and resources are determined using estimates of oil and gas in place, recovery factors and future commodity prices, the latter having an impact on the total amount of recoverable reserves. Estimation of oil and gas asset values Estimation of the asset value of oil and gas assets is calculated from a number of inputs that require varying degrees of estimation. Principally oil and gas assets are valued by estimating the future cash flows based on a combination of reserves and resources, costs of appraisal, development and production, production profile and future sales price and discounting those cash flows at an appropriate discount rate. Future costs of appraisal, development and production are estimated taking into account the level of development required to produce those reserves and are based on past costs, experience and data from similar assets in the region, future petroleum prices and the planned development of the asset. However, actual costs may be different from those estimated. Discount rate is assessed by the Company using various inputs from market data, external advisers and internal calculations. A discount rate of 12.5% was used for impairment testing of the oil assets of the Company. In addition, the estimation of the recoverable amount of the Miran/Bina Bawi cash generating unit ( CGU ), which is classified under IFRS as an exploration and evaluation intangible asset and consequently carries the inherent uncertainty explained above, includes the key assessment that the project will progress, which is outside of the control of management and is dependent on the progress of government to government discussions regarding supply of gas an sanctioning of development of both of the midstream for gas and the upstream for oil. Lack of progress could result in significant delays in value realisation and consequently a lower asset value.

15 P a g e 15 Change in accounting estimate discount rate for assessing recoverable amount of producing assets Following the significant change in the macro geo-political, economic and industry environment, the Company has updated the discount rate used for assessing the recoverable amount of its producing assets from 15% to 12.5%. This has had no impact on the financial statements, although it has a positive impact on the recoverable amount of both the Tawke CGU and the Taq Taq CGU. At the end of last year, the Company disclosed that a 2.5% change in discount rate would have a $70 million impact on the recoverable amount of the Tawke CGU and a $5 million impact on the Taq Taq CGU. The disclosures for the half-year are provided in note 9. Estimation of netback price and entitlement used to calculate reported revenue, trade receivables and forecast future cash flows Netback price is used to value the Company s revenue, trade receivables and its forecast cash flows used for impairment testing and viability. It is the aggregation of realised price less transportation and handling costs. The Company does not have direct visibility on the components of the netback price realised for its oil because sales are managed by the KRG, but invoices are currently raised for payments on account using a netback price agreed with the KRG. Change in accounting estimate - netback price The Company has increased the estimated netback price adjustment by $1/bbl using the methodology agreed with the KRG for raising invoices for all sales of oil, effective from 1 August. Netback adjustments to Brent are now estimated as $13/bbl discount for the Tawke PSC (: $12/bbl) and a $6/bbl discount for the Taq Taq PSC (: $5/bbl). This has resulted in a decrease of $3.6 million to H revenue, of which $2.2 million relates to. At the end of last year, the Company disclosed that a $5/bbl change in Long-term Brent would impact the Tawke CGU by $23 million and the Taq Taq CGU by $2 million, so a $1/bbl change in netback adjustment has an impact of around $5 million in total across the two CGUs. The netback adjustment price agreed with the KRG may change in the future. A $1/bbl difference in netback price would impact current year revenue and trade receivables by circa $4 million with disclosures on the sensitivities of the recoverable amount of producing assets provided in note 9. Tawke RSA intangible asset On 23 August the Company signed documentation confirming an agreement had been reached with the KRG to put in place a definitive mechanisms for the payment to the Company of trade receivables built up from overdue amounts with nominal value of $469 million owed for sales since mid-2014 ( overdue KRG receivable ) together with nominal value of circa $300 million amounts owed for export sales marketed by SOMO made before 2014 for which the Company has never recognised revenue ( overdue pre-2014 receivable ). Until the RSA, the Company reported the overdue KRG receivable in the balance sheet at its amortised cost. Key inputs to the assessment of amortised cost were: oil price, production forecast and mechanism for payment. Estimates of oil price and production forecast were based on the inputs used for testing of property, plant and equipment for impairment. When estimating the payment mechanism, although the Company expected either an increase in payments, or an alternative structure to be agreed to accelerate payments, it was assessed that there was not sufficient evidence to support the use of anything other than the existing payment mechanism, which was 5% of the asset level revenue for the Tawke and Taq Taq licences. At the year-ended 31 December 2016, this resulted in the amortised cost being lower than carrying value and consequently the overdue KRG receivable was impaired to its reported book value of $207 million compared to its nominal value of $469 million. In, the RSA resulted in the overdue KRG receivable balance being waived and in return the Company received: (1) a 4.5% royalty interest on gross Tawke PSC revenue lasting for 5 years ( the ORRI); (2) the waiver of capacity building payments due on all profit oil received under the Tawke PSC; and (3) the waiver of $4.6 million of amounts due to the KRG. As the RSA occurred at arm s length, the fair value of the consideration received from the KRG described above, which was recognised as an intangible asset Tawke RSA, was considered to be equal to the fair value of the receivables. The Tawke RSA exceeded the carrying amount of receivables at the time of settlement resulting in a gain of $293.8 million being recognised in the profit or loss. Assessing the fair value of both items required the estimation of future oil price, production profile and reserves and the appropriate discount rate. Because management assessed that the cash flows had the same risk profile as revenue generated from the Tawke PSC, oil price, production profile, reserves and discount rate were estimated using the same methodology as used for the impairment testing of the Tawke PSC property, plant and equipment cash generating unit as explained above, albeit at July rather than at year-end.

16 P a g e 16 Estimation of cost and timing of decommissioning cost Key inputs to the reported decommissioning provision is the cost, timing and discount rate to apply to the cash flows. The cost has been estimated based on a report prepared by a third party in April, with timing of costs estimated to be incurred between 2028 and 2038, from the latest life of field plans. The estimated cash flows have been discounted using a discount rate of 4%, which is estimated using a risk free rate adjusted for timing uncertainty. Business combinations The recognition of business combinations requires the excess of the purchase price of acquisitions over the net book value of assets acquired to be allocated to the assets and liabilities of the acquired entity. The Company makes judgements and estimates in relation to the fair value allocation of the purchase price. The fair value exercise is performed at the date of acquisition. Owing to the nature of fair value assessments in the oil and gas industry, the purchase price allocation exercise and acquisition-date fair value determinations require subjective judgements based on a wide range of complex variables at a point in time. The Company uses all available information to make the fair value determinations. In determining fair value for acquisitions, the Company utilises valuation methodologies including discounted cash flow analysis. The assumptions made in performing these valuations include assumptions as to discount rates, foreign exchange rates, commodity prices, the timing of development, capital costs, and future operating costs. Any significant change in key assumptions may cause the acquisition accounting to be revised. New Standards The new accounting standards and amendments to existing standards have been adopted by the Group effective 1 January 2018: IFRS 15 Revenue from Contracts with Customers, IFRS 9 Financial Instruments, Amendments to IFRS 2, and Amendments to IAS 40. The adoption of these standards and amendments has had no material impact on the Company s results or financial statement disclosures. Revenue recognition now requires definition of the customer, performance obligations and the price and allocation of price into performance obligations. The Company s performance obligation in its contract with the single customer is the delivery of crude oil at a pre-determined netback adjustment to dated Brent and the control is transferred to the buyer at the metering point when the revenue is recognised. As a result, adoption of IFRS 15 had no material change to the presentation and measurement of the Company revenue in the interim financial statements. The Company s accounting treatment of the buyback of bonds in were in line with IFRS 9 hence no transitional adjustments were required. The impact of changes to the impairment model from incurred credit losses to expected credit loss model under IFRS 9 is immaterial since the trade receivables balance are at a consistent level compared to the established operating cycle, with no issues with payment in the c.3 years. IFRS 16, which becomes effective by 1 January 2019, requires the lessee to recognize the right to use the asset and the liability, depreciate the associated asset, re-measure and reduce the liability through lease payments; unless the underlying leased asset is of low value and/or short term in nature. The Company is not considering early application of the Standard. The Company s leases are mostly low value or short term in nature. The work is currently underway to assess the financial statements impact of adopting IFRS 16, which is estimated to affect both assets and liabilities by less than c.$1 million. The following new accounting standards, amendments to existing standards and interpretations have been issued but are not yet effective and have not yet been endorsed by the EU: Amendments to IFRS 9 Financial Instruments (effective 1 January 2019), Amendments to IAS 28 Investments in Associates and Joint Ventures (effective 1 January 2019), Annual Improvements to IFRS Standards 2015 (effective 1 January 2019), IFRIC 23 Uncertainty over Income Tax Treatments (effective 1 January 2019) and Amendments to IAS 19 Employee Benefits (effective 1 January 2019). None of these standards have been early adopted. Financial risk factors The Company s activities expose it to a variety of financial risks: credit risk, currency risk, interest risk and liquidity risk. Since the half-year condensed consolidated financial statements do not include all financial risk management information and disclosures required in the annual financial statements; they should be read in conjunction with the Company s annual financial statements as at 31 December. There have been no significant changes in any risk management policies since year end.

17 P a g e Segmental information The Company has three reportable business segments: Oil, Miran/Bina Bawi ( MBB ) and Exploration ( Expl. ). Capital allocation decisions for the Oil segment are considered in the context of the cash flows expected from the production and sale of crude oil. The Oil segment is comprised of the producing fields on the Tawke PSC and the Taq Taq PSC, which are located in the KRI and make sales predominantly to the KRG. The Miran/Bina Bawi segment is comprised of the oil and gas upstream and midstream activity on the Miran PSC and the Bina Bawi PSC, which are both in the KRI this was previously labelled as the Gas segment. The exploration segment is comprised of exploration activity, principally located in Somaliland and Morocco. 6 months ended 30 June 2018 Oil MBB Expl. Other Total $m $m $m $m $m Revenue Cost of sales (75.5) (75.5) Gross profit Exploration (expense) / credit - (0.2) (0.3) - (0.5) General and administrative costs (11.8) (11.8) Operating profit / (loss) 85.6 (0.2) (0.3) (11.8) 73.3 Operating profit / (loss) is comprised of EBITDAX (11.6) Depreciation and amortisation (63.4) - - (0.2) (63.6) Exploration (expense) / credit - (0.2) (0.3) - (0.5) Finance income Bond interest expense (15.0) (15.0) Other finance expense (0.8) (0.1) - (0.2) (1.1) Profit before tax 84.8 (0.3) (0.3) (24.9) 59.3 Capital expenditure Total assets 1, ,162.6 Total liabilities (82.1) (79.8) (27.3) (300.5) (489.7) Revenue includes $48.2 million (30 June : nil, 31 December : $33.9 million) arising from the ORRI. Total assets and liabilities in the Other segment are predominantly cash and debt balances. Other includes corporate assets, liabilities and costs, elimination of intercompany receivables and intercompany payables, which are non-segment items.

18 P a g e 18 6 months ended 30 June Oil MBB Expl. Other Total $m $m $m $m $m Revenue Cost of sales (58.0) (58.0) Gross profit Exploration (expense) / credit - (1.9) (2.9) - (4.8) Impairment of property, plant and equipment General and administrative costs (10.1) (10.1) Operating profit / (loss) 29.1 (1.9) (2.9) (10.1) 14.2 Operating profit / (loss) is comprised of EBITDAX (9.2) 64.7 Depreciation and amortisation (44.8) - - (0.9) (45.7) Exploration expense - (1.9) (2.9) - (4.8) Impairment of property, plant and equipment Gain arising from bond buy back Finance income Bond interest expense (20.9) (20.9) Other finance expense (0.6) (0.1) - (5.1) (5.8) Profit / (Loss) before tax 31.2 (2.0) (2.9) (2.8) 23.5 Capital expenditure Total assets ,010.5 Total liabilities (94.4) (98.4) (45.7) (411.3) (649.8) Total assets and liabilities in the Other segment are predominantly cash and debt balances. Other includes corporate assets, liabilities and costs, elimination of intercompany receivables and intercompany payables, which are non-segment items.

19 P a g e 19 For the period ended 31 December Oil MBB Expl. Other Total $m $m $m $m $m Revenue Cost of sales (143.6) (143.6) Gross profit Exploration (expense) / credit - (4.6) (1.9) Impairment of property, plant and equipment (58.2) (58.2) Net gain arising from the RSA General and administrative costs (21.0) (21.0) Operating profit / (loss) (4.6) 2.7 (21.0) Operating profit / (loss) is comprised of EBITDAX (19.7) Depreciation and amortisation (116.1) - - (1.3) (117.4) Exploration (expense) / credit - (4.6) (1.9) Impairment of property, plant and equipment (58.2) (58.2) Gain arising from bond buy back Finance income Bond interest expense (35.5) (35.5) Other finance expense (1.1) (0.1) - (26.8) (28.0) Profit / (Loss) before tax (4.7) 2.7 (48.5) Capital expenditure Total assets 1, ,106.9 Total liabilities (84.3) (75.3) (32.4) (305.1) (497.1) Total assets and liabilities in the Other segment are predominantly cash and debt balances. Other includes corporate assets, liabilities and costs, elimination of intercompany receivables and intercompany payables, which are non-segment items.