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GENL Genel Energy Plc

83.30
-0.50 (-0.60%)
28 Mar 2024 - Closed
Delayed by 15 minutes
Share Name Share Symbol Market Type Share ISIN Share Description
Genel Energy Plc LSE:GENL London Ordinary Share JE00B55Q3P39 ORD 10P
  Price Change % Change Share Price Bid Price Offer Price High Price Low Price Open Price Shares Traded Last Trade
  -0.50 -0.60% 83.30 83.80 84.40 85.20 82.50 85.20 353,603 16:35:09
Industry Sector Turnover Profit EPS - Basic PE Ratio Market Cap
Oil And Gas Field Expl Svcs 432.7M -7.3M -0.0261 -32.07 233.86M

Genel Energy PLC: Half-Year Results (711361)

07/08/2018 7:04am

UK Regulatory


Dow Jones received a payment from EQS/DGAP to publish this press release.

 
 
 Genel Energy PLC (GENL) 
Genel Energy PLC: Half-Year Results 
 
07-Aug-2018 / 07:00 GMT/BST 
Dissemination of a Regulatory Announcement that contains inside information 
according to REGULATION (EU) No 596/2014 (MAR), transmitted by EQS Group. 
The issuer is solely responsible for the content of this announcement. 
 
           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 2018. 
 
            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) 
 
                                               H1     H1      FY 
 
                                             2018   2017    2017 
 
Production (bopd, working interest)        32,100 37,100  35,200 
Revenue                                     161.1   87.1   228.9 
Net gain arising from the RSA                   -      -   293.8 
EBITDAX1                                    137.4   64.7   475.5 
Depreciation and amortisation              (63.6) (45.7) (117.4) 
Exploration expense                         (0.5)  (4.8)   (1.9) 
Impairment of property, plant and               -      -  (58.2) 
equipment 
Operating profit                             73.3   14.2   298.0 
Cash flow from operating activities         125.1  114.2   221.0 
Capital expenditure                          34.1   41.0    94.1 
Free cash flow2                              70.1   54.6    99.1 
Cash3                                       233.2  245.7   162.0 
Total debt                                  300.0  422.8   300.0 
Net debt4                                    63.8  158.3   134.8 
Basic EPS (¢ per share)                      21.3    8.4    97.1 
 
1) 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 
 
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 
 
· 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 H1 2018 (H1 2017: $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 2017) 
 
· Net debt of $64 million at 30 June 2018 ($135 million at 31 December 
2017) 
 
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 H2 2018 
 
· 2018 guidance refined: 
 
· 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 
 
· Capital expenditure net to Genel is forecast to be $95-125 million 
(previously $95-140 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                          +44 20 7659 5100 
 
Andrew Benbow, Head of Communications 
 
Vigo Communications                   +44 20 7390 0230 
 
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, 
           www.genelenergy.com [1]. 
 
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. 
 
OPERATING REVIEW 
 
PRODUCTION 
 
    Net working interest production in H1 2018 averaged 32,100 bopd, in line 
           with guidance. 
 
(by PSC   Export via   Refinery     Total      Total   Genel net 
in bopd)   pipeline     sales1      sales    productio productio 
                                                n2         n 
Tawke       104,904      0.35      104,904    105,771   26,443 
(inc. 
Peshkabir 
) 
  Taq Taq   11,603       1,182      12,785    12,769     5,618 
    Total   116,507      1,182     117,689    118,540   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 2017 (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 H2 2018. 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 2018. 
 
       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 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 Q2 2019. 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. 
 
   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 2019. 
 
       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 Q4 2018. Fast-track processing 
   will begin ahead of the completion of this acquisition, as Genel de-risks 
           the licence and assesses future activity. 
 
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 2017 and we expect to be in a net cash position around 
           the end of 2018. 
 
  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 2017 and 
   generated incremental revenue of $48.2 million in the first half of 2018. 
  Additional benefit has arisen from improved Brent oil price of $71/bbl (H1 
           2017: $52/bbl). 
 
    Working interest production of 32,100 bopd was lower than the first half 
      last year (H1 2017: 37,100 bopd), which benefited from Taq Taq working 
   interest daily production being around 5,000 bopd higher since around May 
           2017. 
 
   Production costs of $12.1 million (H1 2017: $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. 
 
         General and administration costs were $11.8 million (H1 2017: $10.1 
    million), of which cash costs were $8.6 million (H1 2017: $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 2017: $41.0 
     million). Cost recovered spend on producing assets in the KRI was $27.8 
    million (H1 2017: $28.1 million) with spend on exploration and appraisal 
      assets amounting to $6.3 million (H1 2017: $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 2017: $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 2017: $54.6 million). 
 
  $17.5 million (H1 2017: $18.5 million) of cash is restricted and therefore 
    excluded from reported cash of $233.2 million (H1 2017: $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 2017. 
 
           Debt 
 
Reported IFRS debt was $297.0 million (31 December 2017: $296.8 million) and 
           net debt was $63.8 million (31 December 2017: $134.8 million). 
 
           The bond has three financial covenant maintenance tests: 
 
Financial covenant                        Test  H1 2018 
Net debt / EBITDAX (rolling 12 months)   < 3.0    0.1 
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 2017: $1,609.8 
million) and consist primarily of oil and gas assets of $1,823.6 million (31 
    December 2017: $1,847.9 million), trade receivables of $84.4 million (31 
    December 2017: $73.3 million) and net debt of $63.8 million (31 December 
           2017: $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 2017: nil) or is expected to be paid in 
           the near future. 
 
           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 2017 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 4.2.7 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 2017. A list of current directors is maintained on 
the Genel Energy plc website: www.genelenergy.com [2] 
 
           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. 
 
           Condensed consolidated statement of comprehensive income 
 
For the period ended 30 June 2018 
 
                                                6      6    Year 
                                           months months 
 
                                                           to 31 
                                            to 30  to 30     Dec 
                                             June   June 
                                             2018   2017 
 
                                                            2017 
                               Notes           $m     $m      $m 
 
Revenue                          3          161.1   87.1   228.9 
 
Production costs                 4         (12.1) (13.2)  (27.5) 
Depreciation and                 4         (63.4) (44.8) (116.1) 
amortisation of oil 
assets 
Gross profit                                 85.6   29.1    85.3 
 
Exploration expense              4          (0.5)  (4.8)   (1.9) 
Impairment of property,          4              -      -  (58.2) 
plant and equipment 
General and                      4         (11.8) (10.1)  (21.0) 
administrative costs 
Net gain arising from            2              -      -   293.8 
the RSA 
Operating profit                             73.3   14.2   298.0 
 
Operating profit is 
comprised of: 
 
EBITDAX                                     137.4   64.7   475.5 
Depreciation and                           (63.6) (45.7) (117.4) 
amortisation 
Exploration expense              4          (0.5)  (4.8)   (1.9) 
Impairment of property,          4              -      -  (58.2) 
plant and equipment 
 
Gain arising from bond           11             -   32.6    32.6 
buy back 
Finance income                   5            2.1    3.4     4.9 
Bond interest expense            5         (15.0) (20.9)  (35.5) 
Other finance expense            5          (1.1)  (5.8)  (28.0) 
Profit before income tax                     59.3   23.5   272.0 
Income tax expense               6              -      -   (1.0) 
Profit and total                             59.3   23.5   271.0 
comprehensive income 
 
Attributable to: 
Shareholders' equity                         59.3   23.5   271.0 
                                             59.3   23.5   271.0 
 
Profit per ordinary share 
 
Basic                                7       21.3    8.4    97.1 
Diluted                              7       21.2    8.4    96.7 
 
           Condensed consolidated balance sheet 
 
At 30 June 2018 
 
                                                         31 Dec 
 
                                     30 June   30 June     2017 
 
                                        2018      2017 
                             Notes        $m        $m       $m 
 
Assets 
Non-current assets 
Intangible assets                8   1,264.1     930.2  1,282.9 
Property, plant and              9     559.5     604.5    565.0 
equipment 
Trade and other receivables     10         -     127.1        - 
                                     1,823.6   1,661.8  1,847.9 
Current assets 
Trade and other receivables     10      88.3      84.5     78.5 
Restricted cash                         17.5      18.5     18.5 
Cash and cash equivalents       11     233.2     245.7    162.0 
                                       339.0     348.7    259.0 
 
Total Assets                         2,162.6   2,010.5  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                           1,672.9   1,360.7  1,609.8 
 
Owners of the parent 
Share capital                           43.8      43.8     43.8 
Share premium account                4,074.2   4,074.2  4,074.2 
Accumulated losses                 (2,445.1) (2,757.3) (2,508.2 
                                                              ) 
Total equity                         1,672.9   1,360.7  1,609.8 
 
           Condensed consolidated statement of changes in equity 
 
For the period ended 30 June 2018 
 
                       Share   Share Accumulated losses    Total 
 
                     capital premium                      equity 
                          $m      $m                 $m       $m 
 
At 1 January 2017       43.8 4,074.2          (2,784.6)  1,333.4 
 
Profit and total           -       -               23.5     23.5 
comprehensive income 
Share-based payments       -       -                3.8      3.8 
 
At 30 June 2017         43.8 4,074.2          (2,757.3)  1,360.7 
 
At 1 January 2017       43.8 4,074.2          (2,784.6)  1,333.4 
 
Profit and total           -       -              271.0    271.0 
comprehensive income 
Share-based payments       -       -                5.4  5.4 5.4 
 
At 31 December 2017     43.8 4,074.2          (2,508.2)  1,609.8 
and 1 January 2018 
 
Profit and total           -       -               59.3     59.3 
comprehensive income 
Share based payments       -       -                3.8      3.8 
 
At 30 June 2018         43.8 4,074.2          (2,445.1)  1,672.9 
 
           Condensed consolidated cash flow statement 
 
For the period ended 30 June 2018 
 
                                                          31 Dec 
 
                                       30     30            2017 
                                     June   June 
                                     2018   2017 
                             Notes     $m     $m              $m 
 
Cash flows from operating 
activities 
Profit and total                     59.3   23.5           271.0 
comprehensive income 
Adjustments for: 
Gain on bond buy                        - (32.6)          (32.6) 
back 
Finance income                      (2.1)  (3.4)           (4.9) 
Bond interest                        15.0   20.9            35.5 
expense 
Other finance                         1.1    5.8            28.0 
expense 
Taxation                                -      -             1.0 
Depreciation and                     63.6   45.7           117.4 
amortisation 
Exploration expense                   0.5    4.8             1.9 
Impairment of                           -      -            58.2 
property, plant and 
equipment 
Net gain arising                        -      -         (293.8) 
from the RSA 
Other non-cash items                  3.0    2.8             2.8 
Changes in working 
capital: 
Proceeds against                        -   50.9            67.5 
overdue receivable 
Trade and other                    (10.2)    4.1          (33.5) 
receivables 
Trade and other                     (7.1)  (9.0)             0.6 
payables and 
provisions 
Cash generated from                 123.1  113.5           219.1 
operations 
Interest received                     2.1           0.8      2.2 
Taxation paid                       (0.1)         (0.1)    (0.3) 
Net cash generated                  125.1         114.2    221.0 
from operating 
activities 
 
Cash flows from 
investing activities 
Purchase of                        (10.5)        (12.7)   (26.8) 
intangible assets 
Purchase of                        (29.5)        (23.4)   (52.4) 
property, plant and 
equipment 
Restricted cash                       1.0           1.0      1.0 
Net cash used in                   (39.0)        (35.1)   (78.2) 
investing activities 
 
Cash flows from 
financing activities 
Repurchase of                           -       (216.7)  (216.7) 
Company bonds 
Bond refinancing                        -             -  (128.5) 
Interest paid                      (15.0)        (23.5)   (42.7) 
Net cash used in                   (15.0)       (240.2)  (387.9) 
financing activities 
 
Net increase /                       71.1       (161.1)  (245.1) 
(decrease) in cash 
and cash equivalents 
Foreign exchange                      0.1         (0.2)      0.1 
income / (loss) on 
cash and cash 
equivalents 
Cash and cash                       162.0         407.0    407.0 
equivalents at 1 
January 
Cash and cash              11       233.2  245.7           162.0 
equivalents at 
period end 
 
           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 2017 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 2018. They do not comprise statutory accounts within the meaning of 
     Article 105 of the Companies (Jersey) Law 1991. The half-year condensed 
    consolidated financial statements should be read in conjunction with the 
 annual financial statements for the year ended 31 December 2017, which have 
 been prepared in accordance with IFRS as adopted by the European Union. The 
      annual financial statements for the period ended 31 December 2017 were 
      approved by the board of directors on 21 March 2018. 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 1991. The 
   financial information for the year to 31 December 2017 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 2017. 
 
         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 2017. 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. 
 
$/bbl            2019 2020 2021 2022 
HY 2018 forecast  63   66   72   74 
YE 2017 forecast  63   66   72   74 
 
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. 
 
     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 2017. Netback adjustments to Brent are now 
estimated as $13/bbl discount for the Tawke PSC (2017: $12/bbl) and a $6/bbl 
discount for the Taq Taq PSC (2017: $5/bbl). This has resulted in a decrease 
  of $3.6 million to H1 2018 revenue, of which $2.2 million relates to 2017. 
      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 2017 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 2017, 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 2017 rather than at 
           year-end. 
 
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 2017, 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 2017 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 2015-2017 (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 2017. There have been no significant 
           changes in any risk management policies since year end. 
 
           3. 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 
 
                                           Expl.           Total 
 
                               Oil    MBB          Other 
                                $m     $m     $m      $m      $m 
 
Revenue                      161.1      -      -       -   161.1 
Cost of sales               (75.5)      -      -       -  (75.5) 
Gross profit                  85.6      -      -       -    85.6 
 
Exploration (expense) /          -  (0.2)  (0.3)       -   (0.5) 
credit 
General and administrative       -      -      -  (11.8)  (11.8) 
costs 
Operating profit / (loss)     85.6  (0.2)  (0.3)  (11.8)    73.3 
 
Operating profit / (loss) 
is comprised of 
 
EBITDAX                      149.0      -      -  (11.6)   137.4 
Depreciation and            (63.4)      -      -   (0.2)  (63.6) 
amortisation 
Exploration (expense) /          -  (0.2)  (0.3)       -   (0.5) 
credit 
 
Finance income                   -      -      -     2.1     2.1 
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           27.8    5.7    0.6       -    34.1 
Total assets               1,049.6  869.5   33.8   209.7 2,162.6 
Total liabilities           (82.1) (79.8) (27.3) (300.5) (489.7) 
 
  Revenue includes $48.2 million (30 June 2017: nil, 31 December 2017: $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. 
 
6 months ended 30 June 2017 
 
                                           Expl.           Total 
 
                               Oil    MBB          Other 
                                $m     $m     $m      $m      $m 
 
Revenue                       87.1      -      -       -    87.1 
Cost of sales               (58.0)      -      -       -  (58.0) 
Gross profit                  29.1      -      -       -    29.1 
 
Exploration (expense) /          -  (1.9)  (2.9)       -   (4.8) 
credit 
Impairment of property,          -      -      -       -       - 
plant and equipment 
General and administrative       -      -      -  (10.1)  (10.1) 
costs 
Operating profit / (loss)     29.1  (1.9)  (2.9)  (10.1)    14.2 
 
Operating profit / (loss) 
is comprised of 
 
EBITDAX                       73.9      -      -   (9.2)    64.7 
Depreciation and            (44.8)      -      -   (0.9)  (45.7) 
amortisation 
Exploration expense              -  (1.9)  (2.9)       -   (4.8) 
Impairment of property,          -      -      -       -       - 
plant and equipment 
 
Gain arising from bond buy       -      -      -    32.6    32.6 
back 
Finance income                 2.7      -      -     0.7     3.4 
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           28.1    7.5    5.4       -    41.0 
Total assets                 845.3  883.5   59.9   221.8 2,010.5 
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. 
 
For the period ended 31 December 2017 
 
                                           Expl.           Total 
 
                               Oil    MBB          Other 
                                $m     $m     $m      $m      $m 
 
Revenue                      228.9      -      -       -   228.9 
Cost of sales              (143.6)      -      -       - (143.6) 
Gross profit                  85.3      -      -       -    85.3 
 
Exploration (expense) /          -  (4.6)    2.7       -   (1.9) 
credit 
Impairment of property,     (58.2)      -      -       -  (58.2) 
plant and equipment 
Net gain arising from the    293.8      -      -       -   293.8 
RSA 
General and administrative       -      -      -  (21.0)  (21.0) 
costs 
Operating profit / (loss)    320.9  (4.6)    2.7  (21.0)   298.0 
 
Operating profit / (loss) 
is comprised of 
 
EBITDAX                      495.2      -      -  (19.7)   475.5 
Depreciation and           (116.1)      -      -   (1.3) (117.4) 
amortisation 
Exploration (expense) /          -  (4.6)    2.7       -   (1.9) 
credit 
Impairment of property,     (58.2)      -      -       -  (58.2) 
plant and equipment 
 
Gain arising from bond buy       -      -      -    32.6    32.6 
back 
Finance income                 2.7      -      -     2.2     4.9 
Bond interest expense            -      -      -  (35.5)  (35.5) 
Other finance expense        (1.1)  (0.1)      -  (26.8)  (28.0) 
Profit / (Loss) before tax   322.5  (4.7)    2.7  (48.5)   272.0 
 
Capital expenditure           59.5   15.5   19.1       -    94.1 
Total assets               1,057.9  860.8   34.0   154.2 2,106.9 
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. 
 
4. Operating costs 
****************** 
 
                        6 months to   6 months to     Year to 31 
                       30 June 2018  30 June 2017  December 2017 
                                 $m            $m             $m 
 
Production costs               12.1          13.2           27.5 
Depreciation of oil            34.6          44.8           83.3 
and gas property, 
plant and equipment 
Amortisation of oil            28.8             -           32.8 
and gas intangible 
assets 
Cost of sales                  75.5          58.0          143.6 
 
Exploration expense             0.5           4.8            1.9 
 
Impairment of                     -             -           58.2 
property, plant and 
equipment (note 9) 
 
Corporate cash costs            8.6           6.4           16.9 
Corporate share based           3.0           2.8            2.8 
payment expense 
Depreciation and                0.2           0.9            1.3 
amortisation of 
corporate assets 
General and                    11.8          10.1           21.0 
administrative 
expenses 
 
Exploration expense relates to accruals for costs or obligations relating to 
   licences where there is ongoing activity or that have been, or are in the 
           process of being, relinquished. 
 
5) Finance expense and income 
 
              6 months to 30    6 months to 30        Year to 31 
                   June 2018         June 2017     December 2017 
                          $m                $m                $m 
 
Bond                  (15.0)            (20.9)            (35.5) 
interest 
payable 
Unwind of              (1.1)             (5.8)            (28.0) 
discount 
on 
liabilitie 
s / 
premium 
paid on 
bond 
buyback 
Finance               (16.1)            (26.7)            (63.5) 
expense 
 
Bank                     2.1               0.7               2.2 
interest 
income 
Unwind of                  -               2.7               2.7 
discount 
on trade 
receivable 
s 
Finance                  2.1               3.4               4.9 
income 
 
6. Income tax expense 
********************* 
 
 A taxation charge is incurred on the profits of the Turkish and UK services 
  companies. All corporation tax due on petroleum sales is paid on behalf of 
   the Company by the government from the government's share of revenues and 
     there is no tax payment required or expected to be made by the Company. 
 
Under the terms of the KRI PSCs, the Company is not required to pay any cash 
taxes with tax paid on its behalf by the government. It is not known at what 
    rate tax is paid, but it is estimated that the current tax rate would be 
     between 15% and 40%. If this was known it would result in a gross up of 
    revenue with a corresponding debit entry to taxation expense with no net 
         impact on the income statement or on cash. In addition, it would be 
necessary to assess whether any deferred tax asset or liability was required 
           to be recognised. 
 
7. Earnings per share 
********************* 
 
           Basic 
 
  Basic earnings per share is calculated by dividing the profit attributable 
to equity holders of the Company by the weighted average number of shares in 
           issue during the period. 
 
                           6 months to 30 June 2018     6   Year 
                                                    month  to 31 
                                                     s to Decemb 
                                                       30     er 
                                                     June   2017 
                                                     2017 
                                                 $m    $m     $m 
 
Profit attributable to equity                  59.3  23.5  271.0 
holders of the Company ($m) 
 
                                        279,025,723 278,3 279,01 
                                                    95,19  3,724 
                                                        0 
 
Weighted average number of 
ordinary shares - number 1 
Basic earnings per share - cents               21.3   8.4   97.1 
per share 
1Excluding shares held as 
treasury shares 
 
           Diluted 
 
           The Company purchases shares in the market to satisfy share plan 
  requirements so diluted earnings per share is only adjusted for restricted 
         shares not included in the calculation of basic earnings per share: 
 
                           6 months to 30 June 2018     6   Year 
                                                    month  to 31 
                                                     s to Decemb 
                                                       30     er 
                                                     June   2017 
                                                     2017 
                                                 $m    $m     $m 
 
Profit attributable to equity holders of       59.3  23.5  271.0 
the Company ($m) 
 
                                           279,025, 278,3 279,01 
                                                723 95,19  3,724 
                                                        0 
 
Weighted average number of ordinary 
shares - number 1 
Adjustment for performance shares,         1,222,47     - 1,234, 
restricted shares and share options               5          474 
Total number of shares                     280,248, 278,3 280,24 
                                                198 95,19  8,198 
                                                        0 
Diluted earnings per share - cents per         21.2   8.4   96.7 
share 
1Excluding shares 
held as treasury 
shares 
 
8. Intangible assets 
******************** 
 
                          Exploration and  Tawke  Other   Total 
                        evaluation assets 
 
                                             RSA assets 
                                       $m     $m     $m      $m 
Cost 
At 1 January 2017                 1,497.4      -    6.3 1,503.7 
Additions                            12.9      -    0.3    13.2 
Discount unwind of                    5.3      -      -     5.3 
contingent 
consideration 
Exploration expense                 (4.6)      -      -   (4.6) 
Balance at 30 June                1,511.0      -    6.6 1,517.6 
2017 
 
At 1 January 2017                 1,497.4      -    6.3 1,503.7 
Additions                            34.6      -    0.2    34.8 
ARO provision                         2.5      -      -     2.5 
Additions (note 10)                     -  425.1      -   425.1 
Discount unwind of                 (22.3)      -      -  (22.3) 
contingent 
consideration 
Transfer to property,              (22.8)      -      -  (22.8) 
plant and equipment 
Exploration expense                (17.7)      -      -  (17.7) 
Balance at 31                     1,471.7  425.1    6.5 1,903.3 
December 2017 and 1 
January 2018 
 
Additions                             6.3      -      -     6.3 
Discount unwind of                    3.9      -      -     3.9 
contingent 
consideration 
Non-cash additions                    0.4      -      -     0.4 
for ARO/IFRS2 
Exploration expense                 (0.5)      -      -   (0.5) 
Balance at 30 June                1,481.8  425.1    6.5 1,913.4 
2018 
 
Accumulated 
amortisation and 
impairment 
At 1 January 2017                 (581.3)      -  (5.7) (587.0) 
Amortisation charge                     -      -  (0.4)   (0.4) 
for the period 
At 30 June 2017                   (581.3)      -  (6.1) (587.4) 
 
At 1 January 2017                 (581.3)      -  (5.7) (587.0) 
Amortisation charge                     - (32.8)  (0.6)  (33.4) 
for the period 
At 31 December 2017               (581.3) (32.8)  (6.3) (620.4) 
and 1 January 2018 
 
Amortisation charge                     - (28.8)  (0.1)  (28.9) 
for the period 
At 30 June 2018                   (581.3) (61.6)  (6.4) (649.3) 
 
Net book value 
At 30 June 2017                     929.7      -    0.5   930.2 
At 31 December 2017                 890.4  392.3    0.2 1,282.9 
At 30 June 2018                     900.5  363.5    0.1 1,264.1 
 
         Exploration and evaluation assets are principally the Company's PSC 
    interests in exploration and appraisal assets in the Kurdistan Region of 
      Iraq, comprised of the Miran (book value: $537.3 million, 2017: $535.3 
   million) and Bina Bawi (book value: $330.9 million, 2017: $323.1 million) 
    gas assets. Further explanation on oil and gas assets is provided in the 
     significant accounting judgements, estimates and assumptions in note 1. 
 
   Tawke RSA cash flows arise from the RSA, details of which are provided in 
           note 1. 
 
The sensitivities below provide an indicative impact on net asset value of a 
        change in long term Brent, discount rate or production and reserves, 
           assuming no change to any other inputs. 
 
Sensitivities 
 
                                  Bina Bawi / Miran  Tawke 
 
                                                       RSA 
                                                 $m     $m 
 
Long term Brent +/- $5/bbl                   +/- 90  +/- 9 
Discount rate +/-2.5%                       +/- 260 +/- 30 
Production and reserves +/- 10%              +/- 78 +/- 52 
 
9. Property, plant and equipment 
******************************** 
 
                            Oil and gas assets  Other 
 
                                               assets      Total 
                                            $m     $m         $m 
Cost 
At 1 January 2017                      2,599.2    8.9    2,608.1 
Additions                                 28.1    0.2       28.3 
At 30 June 2017                        2,627.3    9.1    2,636.4 
 
At 1 January 2017                      2,599.2    8.9    2,608.1 
Additions                                 59.5    0.5       60.0 
ARO provision                              3.6      -        3.6 
Transfer from intangible                  22.8      -       22.8 
assets1 
Other                                    (1.2)      -      (1.2) 
At 31 December 2017 and 1              2,683.9    9.4    2,693.3 
January 2018 
 
Additions                                 27.8      -       27.8 
     Non-cash additions for                1.4      -        1.4 
                  ARO/IFRS2 
At 30 June 2018                        2,713.1    9.4    2,722.5 
 
Accumulated depreciation 
and impairment 
At 1 January 2017                    (1,978.2)  (7.9)  (1,986.1) 
Depreciation charge for the             (44.8)  (0.5)     (45.3) 
period 
Other                                    (0.5)      -      (0.5) 
At 30 June 2017                      (2,023.5)  (8.4)  (2,031.9) 
 
At 1 January 2017                    (1,978.2)  (7.9)  (1,986.1) 
Depreciation charge for the             (83.3)  (0.7)     (84.0) 
period 
Impairment                              (58.2)      -     (58.2) 
At 31 December 2017 and 1            (2,119.7)  (8.6)  (2,128.3) 
January 2018 
 
Depreciation charge for the             (34.6)  (0.1)     (34.7) 
period 
At 30 June 2018                      (2,154.3)  (8.7)  (2,163.0) 
 
Net book value 
At 30 June 2017                          603.8    0.7      604.5 
At 31 December 2017                      564.2    0.8      565.0 
At 30 June 2018                          558.8    0.7      559.5 
 
  Oil and gas assets are the Company's investments in the Tawke (book value: 
   $475.4 million, 2017: $477.8 million) and Taq Taq PSCs (book value: $83.4 
million, 2016: $86.4 million) in the KRI, further explanation on oil and gas 
  assets is provided in the significant accounting judgements, estimates and 
           assumptions in note 1. 
 
The sensitivities below provide an indicative impact on net asset value of a 
        change in long term Brent, discount rate or production and reserves, 
           assuming no change to any other inputs. 
 
Sensitivities 
 
                                Taq Taq  Tawke 
                                     $m     $m 
 
Long term Brent +/- $5/bbl        +/- 3 +/- 19 
Discount rate +/-2.5%             +/- 6 +/- 45 
Production and reserves +/-10%    +/- 9 +/- 43 
 
10. Trade and other receivables 
 
                                  30 June 30 June 2017 31 Dec 
                                                    $m 
 
                                     2018                2017 
                                       $m                  $m 
 
  Trade receivables - non-current       -        127.1      - 
      Trade receivables - current    84.4         74.6   73.3 
Other receivables and prepayments     3.9          9.9    5.2 
                                     88.3        211.6   78.5 
 
   Trade receivables are amounts owed for oil sales to the KRG, which is the 
           only customer. 
 
Ageing of trade receivables 
 
     Under the terms of the Tawke and Taq Taq PSCs, payment is due within 30 
      days. Since February 2016, a track record of payments being received 3 
months after invoicing, which has been assessed as the established operating 
    cycle under IAS1. The fair value of trade receivables is broadly in line 
           with the carrying value. 
 
Period                        Year in which amounts overdue 
ended 
30 June 
2018 
                                     were recognised 
                         Not due  2018    2017    2016    Total 
 
                           $m      $m      $m      $m      $m 
Trade receivables at      84.4      -       -       -     84.4 
30 June 2018 
 
Period                        Year in which amounts overdue 
ended 
31 
Decembe 
r 2017                               were recognised 
                         Not due  2017    2016    2015    Total 
 
                           $m      $m      $m      $m      $m 
Trade receivables at      73.3      -       -       -     73.3 
31 December 2017 
 
           Movement on trade receivables in the period 
 
                                  30     30        31 Dec 
                                June   June 
                                2018 
 
                                                     2017 
                                       2017 
                                  $m 
 
                                                       $m 
                                         $m 
Carrying value at 1             73.3         253.5        253.5 
January 
Revenue excl. royalty          158.9          84.7        224.4 
income 
Net proceeds                 (147.8)       (139.3)      (262.7) 
Discount unwind                    -           2.7          2.7 
Impairment                         -             -            - 
Net gain arising from              -             -        293.8 
the RSA 
Write-off of overdue               -             -      (425.1) 
KRG receivable in 
exchange for 
intangible assets 
Other                              -           0.1       (13.3) 
Carrying value at               84.4         201.7         73.3 
period end 
 
11. Borrowings and net debt 
 
30 June 2018 
 
         1 Jan 2018 Discoun Buyback Other Net other     30 June 
                          t                 changes        2018 
                     unwind                 in cash 
                 $m      $m      $m    $m        $m          $m 
2022          296.8     0.1       -   0.1         -       297.0 
Bond 
10.0% 
Cash        (162.0)       -       -     -    (71.2)     (233.2) 
Net Debt      134.8     0.1       -   0.1    (71.2)        63.8 
 
The fair value of the bonds is materially in line with the carrying value. 
 
31 December 2017 
 
                1 Jan Discount Buyback Refinance     Net  31 Dec 
                 2017   unwind                     other    2017 
                                                 changes 
                                                 in cash 
                   $m       $m      $m        $m      $m      $m 
2019 Bond       648.2     22.9 (249.3)   (421.8)       -       - 
7.5% 
2022 Bond           -        -       -     296.8       -   296.8 
10.0% 
Cash          (407.0)        -   216.7     128.5 (100.2) (162.0) 
Net Debt        241.2     22.9  (32.6)       3.5 (100.2)   134.8 
 
  In March 2017, the Company repurchased $252.8 million nominal value of its 
   own bonds for net cash of $216.7 million - the purchased bonds had a book 
     value of $249.3 million resulting in Company net debt reducing by $32.6 
           million. 
 
    In June 2017, the Company cancelled these bonds, together with the $55.4 
    million nominal value of bonds repurchased in March 2016, resulting in a 
    reduction in total outstanding debt from $730 million to $421.8 million. 
   Ongoing annual interest expense is consequently reduced to $31.6 million. 
  The fair value of the $421.8 million nominal value of the bonds at 30 June 
           2017 was $373 million (31 December 2016: $549 million). 
 
     In December 2017, the Company completed its refinancing of the bonds by 
   reducing the outstanding bond debt from $421.8 million to $300 million by 
way of an early redemption of $121.8 million for cash of $125.5 million. The 
  maturity of the $300 million nominal value of remaining bonds was extended 
to December 2022, with some other changes in terms. The refinancing has been 
accounted for under IAS39 as an extinguishment and consequently has resulted 
 in a net finance expense of $19.7 million, representing the acceleration of 
   the recognition of the associated discount unwind expense and the premium 
           paid for the early redemption of the bonds. 
 
           12. Capital commitments and operating lease commitments 
 
The Company had no material outstanding commitments for future minimum lease 
           payments under non-cancellable operating leases. 
 
   Under the terms of its PSCs and JOAs, the Company has certain commitments 
     that are generally defined by activity rather than spend. The Company's 
      capital programme for the next few years is explained in the operating 
  review and is in excess of the activity required by its PSCs and JOAs. The 
   Company leases temporary production and office facilities under operating 
    leases. During the period ended 30 June 2018 $0.7 million (30 June 2017: 
      $0.6 million) was expensed to the statement of comprehensive income in 
respect of these operating leases. Drill rigs are leased on a day-rate basis 
 for the purpose of drilling exploration or development wells. The aggregate 
      payments under drilling contracts are determined by the number of days 
           required to drill each well and are capitalised as exploration or 
           development assets as appropriate. 
 
Independent review report to Genel Energy plc 
 
Report on the half-year financial statements 
 
Our conclusion 
 
     We have reviewed Genel Energy plc's half-year financial statements (the 
"interim financial statements") in the half-year results of Genel Energy plc 
 for the 6 month period ended 30 June 2018. Based on our review, nothing has 
  come to our attention that causes us to believe that the interim financial 
   statements are not prepared, in all material respects, in accordance with 
     International Accounting Standard 34, 'Interim Financial Reporting', as 
  adopted by the European Union and the Disclosure Guidance and Transparency 
       Rules sourcebook of the United Kingdom's Financial Conduct Authority. 
 
What we have reviewed 
 
           The interim financial statements comprise: 
 
? the condensed consolidated balance sheet as at 30 June 2018; 
 
? the condensed consolidated statement of comprehensive income for the 
period then ended; 
 
? the condensed consolidated cash flow statement for the period then ended; 
 
? the condensed consolidated statement of changes in equity for the period 
then ended; and 
 
? the explanatory notes to the interim financial statements. 
 
The interim financial statements included in the half-year results have been 
  prepared in accordance with International Accounting Standard 34, 'Interim 
   Financial Reporting', as adopted by the European Union and the Disclosure 
Guidance and Transparency Rules sourcebook of the United Kingdom's Financial 
           Conduct Authority. 
 
   As disclosed in note 1 to the interim financial statements, the financial 
    reporting framework that has been applied in the preparation of the full 
annual financial statements of the Group is applicable law and International 
     Financial Reporting Standards (IFRSs) as adopted by the European Union. 
 
Responsibilities for the interim financial statements and the review 
******************************************************************** 
 
Our responsibilities and those of the directors 
 
   The half-year results, including the interim financial statements, is the 
   responsibility of, and has been approved by, the directors. The directors 
  are responsible for preparing the half-year results in accordance with the 
         Disclosure Guidance and Transparency Rules sourcebook of the United 
           Kingdom's Financial Conduct Authority. 
 
      Our responsibility is to express a conclusion on the interim financial 
       statements in the half-year results based on our review. This report, 
including the conclusion, has been prepared for and only for the company for 
the purpose of complying with the Disclosure Guidance and Transparency Rules 
   sourcebook of the United Kingdom's Financial Conduct Authority and for no 
       other purpose. We do not, in giving this conclusion, accept or assume 
    responsibility for any other purpose or to any other person to whom this 
 report is shown or into whose hands it may come save where expressly agreed 
           by our prior consent in writing. 
 
What a review of interim financial statements involves 
 
 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, 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. 
 
   We have read the other information contained in the half-year results and 
       considered whether it contains any apparent misstatements or material 
   inconsistencies with the information in the interim financial statements. 
 
PricewaterhouseCoopers LLP 
 
Chartered Accountants 
 
London 
 
           6 August 2018 
 
ISIN:          JE00B55Q3P39 
Category Code: IR 
TIDM:          GENL 
LEI Code:      549300IVCJDWC3LR8F94 
Sequence No.:  5841 
EQS News ID:   711361 
 
End of Announcement EQS News Service 
 
 
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