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Genel Energy PLC: Half-Year Results -8-

DJ Genel Energy PLC: Half-Year Results

Genel Energy PLC (GENL) 
Genel Energy PLC: Half-Year Results 
 
06-Aug-2019 / 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. 
 
         6 August 2019 
 
         Genel Energy plc 
 
         Unaudited results for the period ended 30 June 2019 
 
 Genel Energy plc ('Genel' or 'the Company') announces its unaudited results 
         for the six months ended 30 June 2019. 
 
         Bill Higgs, Chief Executive of Genel, said: 
 
   "These results demonstrate the continued success of our strategy - highly 
         cash generative production underpins capital investment in growth 
      opportunities that deliver rapid returns and enables a compelling cash 
         return to shareholders through our dividend. 
 
Our production grew 17% in H1 2019, and pro forma free cash flow rose to $76 
   million. This cash generation, and our strong balance sheet, allows us to 
  both increase investment in growing the business as well as returning cash 
      to shareholders via dividends. Accordingly, we have today announced an 
         interim dividend of $14 million. 
 
     Disciplined capital allocation remains at the core of our business. The 
        speed with which our investments pay back means that cash is quickly 
recycled to create most value for shareholders. The cash that our production 
  generates funds work now underway at Sarta and Qara Dagh, with plenty left 
      over to both pay a dividend and seek new opportunities, as we progress 
         Genel's growth strategy." 
 
Results summary ($ million unless stated) 
 
                                         H1     H1      FY 
 
                                       2019   2018    2018 
 
Production (bopd, working interest)  37,400 32,100  33,700 
Revenue                               194.3  161.1   355.1 
EBITDAX 1                             167.3  137.4   304.1 
Depreciation and amortisation        (74.8) (63.6) (136.2) 
Exploration (expense) / credit        (0.6)  (0.5)     1.5 
Impairment of intangible assets           -      - (424.0) 
Operating profit / (loss)              91.9   73.3 (254.6) 
Cash flow from operating activities   142.3  125.1   299.2 
Capital expenditure                    72.2   34.1    95.5 
Free cash flow2                        56.7   70.1   164.2 
Pro forma free cash flow2              75.6   70.1   164.2 
Dividend payments                      27.4      -       - 
Cash3                                 353.3  233.2   334.3 
Total debt                            300.0  300.0   300.0 
Net cash (debt)4                       55.8 (63.8)    37.0 
Basic EPS (¢ per share)                27.2   21.3 (101.6) 
Underlying EPS (¢ per share)1          59.9   49.2   109.0 
 
1) EBITDAX is operating profit / (loss) adjusted for the add back of 
depreciation and amortisation ($74.8 million) and exploration expense 
($0.6 million). Underlying EPS is EBITDAX divided by the weighted average 
number of ordinary shares 
 
2) Free cash flow is set out on page 7 and does not include $18.9 million, 
invoiced for Tawke production and due in June 2019 and received late on 9 
July 2019, with the delay due to a change in the Operator's banking 
arrangements. Pro forma free cash flow of $75.6 million includes this 
payment. 
 
3) Cash reported at 30 June 2019 excludes $10 million of restricted cash 
and the $18.9 million noted above 
 
4) Reported IFRS debt less cash 
 
Highlights 
 
· Working interest production averaged 37,400 bopd in H1 2019 (H1 2018: 
32,100 bopd), an increase of 17% compared to H1 2018 
 
· 8 wells completed in H1 2019, resulting in year-on-year production 
increases at both the Tawke and Taq Taq PSCs 
 
· Free cash generation of $57 million in H1 2019 (H1 2018: $70 million), 
which increases to $76 million when including the post period receipt of 
$19 million, with annual free cash flow yield of c.20% of current market 
capitalisation 
 
· Net cash of $56 million at 30 June 2019 (net debt of $64 million at 30 
June 2018) 
 
· Following the receipt of all payments relating to April 2019, Genel 
had $390 million of cash as of 5 August 2019, a net cash position of $92 
million 
 
· Addition of Sarta and Qara Dagh to the portfolio in January 2019 
provides near-term production and material future growth potential 
 
· Maiden dividend distribution of 10¢ per share paid on 24 June 2019 
 
· Interim dividend of 5¢ per share confirmed 
 
· Genel retains an open mandate for a share buy-back programme of up to 
$10 million, and will continue to review purchasing opportunities 
 
Outlook 
 
· Net production guidance in 2019 maintained at close to Q4 2018 levels of 
36,900 bopd, an increase of c.10% year-on-year 
 
· Drilling programme ongoing, with over 10 wells set to be completed by 
early 2020 
 
· Active discussions with the Kurdistan Regional Government ('KRG') 
regarding Bina Bawi are ongoing, focused on agreeing the detailed 
commercial terms for the integrated Phase 1 oil and gas development and 
approval of the associated field development plans 
 
· Work continuing at Sarta to prepare for production by the middle of 2020 
 
· QD-2 well location agreed at Qara Dagh, well pad civil engineering work 
set to begin 
 
· Farm-out process relating to Somaliland acreage to begin in late Q3 2019 
 
· Genel expects to generate material free cash flow in H2 2019, even while 
investment in growth increases 
 
· 2019 capital expenditure is expected to be towards the top end of the 
$150-170 million guidance range 
 
· Searches for a new Chairman and Chief Operating Officer are progressing 
 
· The Company continues to actively pursue growth and is assessing 
opportunities to make value-accretive additions to the portfolio 
 
         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. 
 
CEO STATEMENT 
 
      Genel aims to be a world-class creator of shareholder value by growing 
    high-margin production through rapid development and an efficient use of 
    capital, recycling cash flows into an expanding asset portfolio with the 
   potential to deliver significant growth, while generating sufficient cash 
throughout the investment cycle to fund a material and progressive dividend. 
 
GENERATING CASH WHILE INVESTING IN GROWTH 
 
   The oil we produce is good quality, low-cost, and highly cash generative, 
         with a development model focused on optimising cost and minimising 
development risk. This makes our business highly cash generative. Setting us 
 apart from the majority of our peers both within the region and outside, we 
   have been able to materially increase production without significant cash 
    out - in fact our asset portfolio generates material free cash flow even 
         while increasing production. 
 
This is best illustrated by the Tawke PSC, where production at Peshkabir has 
    increased from 12,000 bopd at the end of 2017 to over 55,000 bopd. While 
doing so Peshkabir continues to generate material free cash flow, adding $32 
million in the first half of 2019. Overall, capital expenditure in the first 
  half of $72 million has nearly doubled from last year, but still free cash 
         flow increased year-on-year. 
 
  Our low-cost production also makes us resilient to oil price fluctuations, 
    and we generate cash at a low oil price. As an illustration, even if the 
 Brent oil price averaged $36/bbl in 2019 we would still generate sufficient 
         cash to pay our dividend of $40 million from free cash flow. 
 
     The level and speed of our cash generation allows us the optionality to 
         recycle capital into those areas that promise to create the maximum 
  shareholder value. The priority remains investing in our current producing 
   assets to underpin this cash generation, and subsequently spending is now 
         set to ramp up at Sarta and Qara Dagh. 
 
       Commercial discussions continue on Bina Bawi, and we are increasingly 
     confident of making sufficient progress to enable work on the ground to 
    begin next year, with the potential for Bina Bawi oil to also add to our 
    production in 2020. And we will continue to generate free cash flow even 
         after making these investments in growth. 
 
         A MATERIAL AND PROGRESSIVE DIVIDEND 
 
  With our strong cash generation, even while investing in growth and adding 
assets to the portfolio, paying a dividend was the ultimate intended outcome 
         of our strategy. With our portfolio having the potential to double 
         production in coming years, and an M&A strategy focused on boosting 
   near-term cash generation, we see the baseline annual distribution of $40 

(MORE TO FOLLOW) Dow Jones Newswires

August 06, 2019 02:00 ET (06:00 GMT)

DJ Genel Energy PLC: Half-Year Results -2-

million as having the potential to grow on an annual basis. 
 
FOCUS ON ESG 
 
 ESG continues to be a key focus of Genel, and we are committed to acting as 
         a socially responsible contributor to the global energy mix. On the 
  environmental side, we aim to minimise GHG emissions per barrel across the 
   portfolio. Working with DNO at Peshkabir, the reinjection of gas into the 
Tawke field will eliminate routine flaring while having the added bonus of a 
positive return on investment - another financial benefit that sets us apart 
         from some of our peers. 
 
   As work progresses on Sarta, we will keep emissions to a minimum ahead of 
     initiating a flares out programme in due course, and further our social 
   investment work. Previously this work has centred on the area surrounding 
    Taq Taq through work focusing on the environment, health, education, and 
 economic empowerment, and initiatives are set to get under way around Sarta 
       and Qara Dagh. Genel will continue to strive to ensure that the local 
         community benefits from the work we do in their community. 
 
OPERATING REVIEW 
 
PRODUCING ASSETS 
 
  Working interest production in H1 2019 averaged 37,400 bopd, a rise of 17% 
         year-on-year. 
 
(by PSC   Export via   Refinery     Total      Total   Genel net 
in bopd)   pipeline      sales      sales    productio productio 
                                                n1         n 
    Tawke   127,070        -       127,070    126,650   31,660 
    (inc. 
Peshkabir 
        ) 
  Taq Taq   13,135         -        13,135    13,150     5,785 
    Total   140,205        -       140,205    139,800   37,445 
 
1 Difference between production and sales relates to inventory movements 
 
    All sales during the period were invoiced at the wellhead export netback 
         price. 
 
         Tawke PSC (25% working interest) 
 
     Production from the Tawke PSC averaged 126,650 bopd, an increase of 20% 
 year-on-year and 12% on the FY 2018 figure. This performance was the result 
         of the success of Peshkabir, where production averaged 54,950 bopd. 
       Production from the Tawke PSC continues to be highly cash-generative, 
         contributing $87 million in free cash flow at an asset level. 
 
      The underlying well stock at the Tawke field has produced in line with 
     expectations. Drilling is required to offset natural field decline, and 
      three wells came onto production in the period. T-52 came on stream in 
    mid-February, and T-54 in April, and the two wells have averaged c.3,500 
       bopd in combined additional production. The T-55 well began adding to 
         production in June and will be followed by a further four confirmed 
  cretaceous producers, while the T-57 well will test the Jurassic potential 
at Tawke. The field partners will also drill a programme of shallower Jeribe 
         wells. 
 
  Peshkabir continues to perform well, with success at both the P-9 and P-10 
      wells helping increase production. Surface facility work has also been 
 completed, and production from the P-2 and P-3 wells is now flowing through 
 the 50,000 bopd central processing facility. Trucking activity is set to be 
       eliminated following the commissioning of the 60,000 bopd pipeline to 
         Fishkabour, helping to reduce costs from an already low base. 
 
  The P-11 well is nearing completion, and three more wells are scheduled to 
spud in 2019. Work on the enhanced oil recovery project wherein gas is piped 
    from Peshkabir to be injected into the Tawke reservoir, both eliminating 
flaring and increasing recovery rates, is now underway and is expected to be 
         commissioned in H1 2020. 
 
         Taq Taq (44% working interest, joint operator) 
 
 Drilling on the flanks at Taq Taq continued to bear fruit in H1, and helped 
   production at the field average 13,150 bopd in H1 2019, an increase of 3% 
      year-on-year and 6% on the FY 2018 figure. The TT-32 well completed in 
     January on the northern flank of the field with an initial flow rate of 
   c.3,000 bopd. This was followed by the TT-20z well, on the western flank, 
  which entered production at a rate of 2,000 bopd. Both wells have recently 
 seen a decline in production and are now in line with Genel's expectations, 
         having been choked back to control water production. 
 
   The TT-33 well, on the southern flank, has tested water from three zones, 
 and has not flowed oil at any significant rate, demonstrating that the free 
        water level on the southern flank is higher than to the north. Going 
forward, the field partners will continue to target the flanks of the field, 
     with a focus on horizontal wells to delay water production and maximise 
recovery. Wells continue to provide a positive return on investment, and Taq 
     Taq generated $8.4 million of free cash flow in H1 2019. Two horizontal 
 wells are scheduled to be drilled on the northern flank of the field in the 
second half of the year, and the TT-19x well is currently underway. Drilling 
      in the second half of the year aims to deliver year-on-year production 
         growth. 
 
         PRE-PRODUCTION ASSETS 
 
         Sarta (30% working interest) 
 
    To date, four exploration wells at Sarta have discovered hydrocarbons at 
multiple intervals, from the Tertiary down to the Triassic. This contributes 
to the Company's unrisked P50 gross resource estimate of c.500 MMbbls. Phase 
         1A represents a low-cost development of the Jurasssic Mus-Adaiyah 
reservoirs. This phase is designed to recover 2P gross reserves of 34 MMbbls 
    through two existing wells (Sarta-2 and Sarta-3) both of which flowed at 
  c.7,500 bopd on test, and one additional development well to be drilled in 
  2021. Insights from production behaviour during this first phase, combined 
      with an appraisal and development well campaign planned for 2021, will 
 provide the technical foundation for prudent expansion investment decisions 
  aimed at maturing Sarta into a low cost, long-life, cash generative asset. 
 
   Construction work for the Phase 1A development is already underway. Civil 
      engineering work commenced in May ahead of mobilising the facility and 
  flowline contractors to the field. Production remains on track to begin in 
         the middle of 2020. 
 
         Qara Dagh (40% working interest, operator) 
 
    The Qara Dagh prospect was first tested by the vertical exploration well 
  QD-1 in 2011. The reservoir was encountered much deeper than prognosed and 
        operational issues meant the well was significantly overbalance when 
 drilling the reservoir, in so doing damaging the reservoirs ability to flow 
     hydrocarbons. Despite these setbacks QD-1 still tested a light oil from 
         Cretaceous fractured carbonates. 
 
    Re-evaluation of the structural model post QD-1, based on new 2D seismic 
         combined with fieldwork, indicates that the well was drilled on the 
south-eastern flank of the prospect. The location for the second exploration 
  well, QD-2, has been chosen to test the structural crest c.10 km to the NW 
   of where QD-1 flowed oil to surface. QD-2 will be drilled with a deviated 
   trajectory through the same reservoir tested by QD-1 in order to maximise 
     fracture intersection. Managed pressure drilling is being considered to 
   minimise reservoir damage. Genel has undertaken a baseline Environmental, 
    Social and Health Impact Assessment study and will commence construction 
 work on the well pad and associated camp shortly. The QD-2 well is on track 
         to spud in H1 2020. 
 
Bina Bawi and Miran (100% working interest, operator) 
 
     Negotiations between Genel and the KRG are ongoing regarding commercial 
         terms for a staged and integrated oil and gas development. 
 
     In line with Genel's strategy, the development of Bina Bawi (and in the 
  future, Miran) is set to be done in phases. Through disciplined allocation 
       of capital, Genel is focused on aligning stakeholders and setting the 
         framework for an attractive and investable project. 
 
     Genel and the KRG are now aligned on a phase one upstream project scope 
   delivering a reduced c.250 MMscfd raw gas. The KRG and Genel will jointly 
  fund the midstream gas development required to process the raw gas, partly 
   making use of revenues from the accelerated development of Bina Bawi oil. 
 
 Discussions are ongoing, with regular meetings taking place between the KRG 
        and Genel. Genel has recently made a formal proposal consistent with 
 previously negotiated terms, balancing initial returns from the development 
         of oil with the medium-term requirement for funding the midstream 
         development. 
 
         Genel is seeking approval for this proposal and the Bina Bawi field 
         development plan in order to commence with the oil development and 
       commission a FEED study for the award of an Engineering, Procurement, 
   Construction, Installation & Commissioning ('EPCIC') contract relating to 
   the midstream development. The latter would take around 12 months, and be 
         funded via the Bina Bawi oil development. 
 
         African exploration 
 
Onshore Somaliland, interpretation of the 2018 2D seismic data together with 
 continued basin analysis has led to the maturation of a prospects and leads 
   inventory for the SL10B13 block (Genel 75% working interest and operator) 
         which confirms the longstanding view that the block has significant 
      hydrocarbon potential. A number of potentially high impact exploration 
    targets have been identified within play types directly analogous to the 
         prolific Yemeni rift basins. 
 
  Once these prospects and leads have been quantified in terms of volumetric 
        potential and associated geological risk the Company will initiate a 
farm-out campaign, commencing late Q3 2019. This remains consistent with the 
    Company's capital allocation approach, as long-term reserves replacement 

(MORE TO FOLLOW) Dow Jones Newswires

August 06, 2019 02:00 ET (06:00 GMT)

DJ Genel Energy PLC: Half-Year Results -3-

from legacy African exploration assets is targeted through the lowest 
possible capital outlay. On the Odewayne block further seismic processing is 
         continuing in order to complete the Company's understanding of the 
  prospectivity of the block. In both cases the minimum work commitments and 
        associated expenditure for the current licence periods has been met. 
 
      On the Sidi Moussa block offshore Morocco (Genel 75% working interest, 
      operator), processing of the multi-azimuth broadband 3D seismic survey 
 acquired in 2018 over the prospective portions of the block continues. This 
  completes the work obligations associated with the current licence period. 
     Once completed, the Company plans to initiate a farm-out campaign in Q1 
     2020, aimed at bringing a partner onto the licence prior to considering 
   further commitments. The Company is currently engaged in discussions with 
       the Moroccan Government with respect to the requisite licence time to 
         complete this forward plan. 
 
FINANCIAL REVIEW 
 
         For 2019 the financial priorities of the Company are the following: 
 
· Continued focus on capital allocation, with prioritisation of highest 
value investment in assets with ongoing or near-term cash and value 
generation 
 
· Investment in lower risk development of opportunities with high 
potential. This currently includes the delivery of first oil at Sarta and 
drilling a well on a discovered resource at Qara Dagh. Investment at Bina 
Bawi will be added should appropriate commercial terms and conditions be 
reached 
 
· Continued focus on acquiring assets with the potential to add 
significant value to the Company through near to mid-term cash generation. 
The objective is to establish a portfolio of assets that strengthens the 
portfolio of Sarta, Qara Dagh and Bina Bawi oil in replacing and 
increasing the Company's cash generation when the override royalty 
agreement ends in Q3 2022, and also to augment gas development to grow 
cash generation thereafter. Overall putting together a funnel that 
supports continuing material free cash flow well into the next decade and 
providing the basis for a progressive dividend 
 
· Continued focus on the capital structure of the Company 
 
· Genel is committed to distributing a minimum of $40 million in 
dividends each year. Given the forecast free cash flow of the Company, 
this figure is expected to grow 
 
  In the first half of the year, successful delivery of these priorities has 
 produced positive results. Pro forma free cash flow of $75.6 million, which 
 includes post period receipt of $18.9 million, represents an increase of 8% 
 on the prior year, despite the $5/bbl fall in Brent oil price and increased 
         investment of $30 million in production and pre-production assets: 
 
(all figures $ million)              H1 2019 H1 2018 FY 2018 
Operating cash flow and other         142.3   125.1   299.2 
Producing asset cost recovered capex (48.7)  (29.5)  (65.3) 
Development capex                     (9.4)     -       - 
Exploration and appraisal capex      (12.2)  (10.5)  (39.7) 
Interest and other                   (15.3)  (15.0)  (30.0) 
Free cash flow                        56.7    70.1    164.2 
Cash received post period end         18.9      -       - 
Pro forma free cash flow              75.6    70.1    164.2 
 
       This increase in capital expenditure principally relates to increased 
         investment at Peshkabir and Sarta. 
 
  Peshkabir is our priority for capital allocation. Due to well productivity 
 and positive commercial terms, capital investment is recovered within three 
   months. Investment in this asset has resulted in the material increase in 
  production, currently c.55,000 bopd, increased central processing capacity 
to 55,000 bopd and optimisation of costs by building pipeline transportation 
  to replace trucking, which reduces transportation costs by 50¢ per barrel. 
 
 Sarta represents significant growth potential, with current work focused on 
         building towards first oil in the middle of 2020. 
 
Other spend in the year has been focused on preparation for drilling at Qara 
      Dagh, and drilling production wells and water disposal wells at Tawke, 
    Peshkabir and Taq Taq. We now plan to drill two additional wells at both 
  Peshkabir and Taq Taq, with capital expenditure expected to be towards the 
         top end of the previously provided range of $150-170 million. 
 
     In January we indicated our expectation of free cash generation of $100 
million at $45/bbl. Since then we have added the Sarta and Qara Dagh assets. 
        With the additional capex on these assets estimated to be around $50 
     million, we now expect material free cash generation for the full year, 
         which excludes dividend payments, to be in excess of $100 million. 
 
  We will continue to be disciplined in our capital allocation and invest in 
areas where we can deliver value. This applies both to allocation of capital 
       to the existing portfolio and also to assets or opportunities that we 
         acquire. 
 
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. 
 
         Financial results for the half-year 
 
         Income statement 
 
   Working interest production of 37,400 bopd was higher than the first half 
last year (H1 2018: 32,100 bopd), which principally benefited from more than 
         doubled Peshkabir production. 
 
    Revenue has increased by 21% compared to H1 2018, from $161.1 million to 
 $194.3 million, with the decrease in the average Brent oil price of $66/bbl 
(H1 2018: $71/bbl) being offset by the improvement in production. Production 
costs of $18.1 million (H1 2018: $12.1 million) were higher due to increased 
production, with opex per barrel at c.$2.7/bbl compared to c.$2.1/bbl in the 
     first half this year. The increase has been caused by trucking costs at 
 Peshkabir - we expect trucking to be replaced by the pipeline in the second 
         half of the year. 
 
General and administration costs were $9.5 million (H1 2018: $11.8 million), 
of which cash costs were $7.2 million (H1 2018: $8.6 million). The reduction 
       from the prior period is a result of higher capitalisation as capital 
         activity has increased, principally at Sarta and Qara Dagh. 
 
      The increase in revenue resulted in a net increase in EBITDAX of $29.9 
         million compared to last period. 
 
(all figures $ million)         H1 2019 H1 2018 FY 2018 
Revenue                          194.3   161.1   355.1 
Operating costs                 (18.1)  (12.1)  (28.7) 
G&A (excl. depreciation)         (8.9)  (11.6)  (22.3) 
EBITDAX                          167.3   137.4   304.1 
Depreciation and amortisation   (74.8)  (63.6)  (136.2) 
Exploration (expense) / credit   (0.6)   (0.5)    1.5 
Impairment of intangible assets    -       -    (424.0) 
Operating profit / (loss)        91.9    73.3   (254.6) 
 
  EBITDAX is presented in order for the users of the financial statements to 
 understand the cash 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. EBITDAX is used as the basis for underlying earnings per share, 
         for the reasons provided above. 
 
 Bond interest expense of $15.0 million was in line with prior year. Finance 
   income of $2.4 million (H1 2018: $2.1 million) was bank interest, finance 
expense of $2.9 million (H1 2018: $1.1 million) included a non-cash discount 
   unwind expense on liabilities, and fees related to the bondholder waiver. 
         There is no taxation on operational profits: under the terms of the 
 Kurdistan Region of Iraq ('KRI') PSC's, corporate income tax due is paid on 
      behalf of the Company by the KRG from the KRG's own share of revenues, 
resulting in no corporate income tax payment required or expected to be made 
   by the Company. Tax presented in the income statement of $0.4 million (H1 
   2018: nil) was related to taxation of the service companies. Depreciation 
  and amortisation of oil assets has increased overall by $10.8 million as a 
         result of higher production. 
 
         Capital expenditure 
 
  Capital expenditure is the aggregation of additions to property, plant and 
       equipment ($64.6 million) and intangible assets ($7.6 million) and is 
      reported to provide investors with an understanding of the quantum and 
nature of investment that is being made in the business. Capital expenditure 
for the period was $72.2 million, predominantly focused on production assets 
         and the Sarta PSC ($11.3m): 
 
(all figures $ million)               H1 2019 H1 2018 FY 2018 
Cost recovered production capex        53.3    27.8    70.4 
Pre-production capex - oil             11.3      -       - 
Pre-production capex - gas              5.6     5.7    12.0 
Other exploration and appraisal capex   2.0     0.6    13.1 
Capital expenditure                    72.2    34.1    95.5 
 
         Cash flow, cash, net cash and debt 
 
Free cash flow is presented in order to show the free cash generated that is 
 available for the Board to invest in the business. The measure provides the 
   reader a better understanding of the underlying business cash flows. Free 
     cash flow was $56.7m, with an overall increase in cash of $19.0m in the 
         period compared to an increase of $71.2 million last period: 
 
(all figures $ million)              H1 2019 H1 2018 FY 2018 
Free cash flow                        56.7    70.1    164.2 
Dividend paid                        (29.0)     -       - 
Purchase of shares                    (8.7)     -       - 
Release of restricted cash and other    -      1.1     8.1 

(MORE TO FOLLOW) Dow Jones Newswires

August 06, 2019 02:00 ET (06:00 GMT)

DJ Genel Energy PLC: Half-Year Results -4-

Net change in cash                    19.0    71.2    172.3 
Opening cash                          334.3   162.0   162.0 
Closing cash                          353.3   233.2   334.3 
Debt reported under IFRS             (297.5) (297.0) (297.3) 
Net cash / (debt)                     55.8   (63.8)  (37.0) 
 
Closing cash of $353.3 million excludes restricted cash of $10.0 million (H1 
  2018: $17.5 million), which is also excluded from net cash at 30 June 2019 
  of $55.8 million. Net cash is reported in order for users of the financial 
 statements to understand how much cash remains if the Company paid its debt 
         obligations from its available cash on the period end date. 
 
   Reported IFRS debt was $297.5 million (31 December 2018: $297.3 million), 
comprised of $300 million of bond debt less amortised costs. The bond pays a 
     10.0% coupon and matures in December 2022. The bond has three financial 
         covenant maintenance tests: 
 
Financial covenant                        Test  H1 2019 
Net debt / EBITDAX (rolling 12 months)< 3.0   (0.2) 
Equity ratio (Total equity/Total assets) > 40%    71% 
Minimum liquidity                        > $30m  $353m 
 
A reconciliation of debt and cash is provided in note 11 to the financial 
statements. 
 
Net assets 
 
Net assets at 30 June 2019 were $1,373.6 million (31 December 2018: $1,331.4 
million) and consist primarily of oil and gas assets of $1,437.3 million (31 
   December 2018: $1,384.2 million), trade receivables of $116.6 million (31 
    December 2018: $94.8 million) and net cash of $55.8 million (31 December 
         2018: $37.0 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 
 
         Maiden dividend distribution of $27.4 million (2018: nil) paid to 
     shareholders in June 2019. An interim dividend of 5¢ per share has been 
         confirmed: 
 
· Ex-dividend date: 12 December2019 
 
· Record Date: 13 December 2019 
 
· Payment Date: 8 January 2020 
 
         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 2019 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: the 
         development and recovery of oil reserves; reserve replacement; 
    commercialisation of the KRI gas business; M&A activity; the KRI natural 
 resources industry and regional risk; corporate governance failure; capital 
  structure and financing; local community support; the environmental impact 
   of oil and gas extraction; and health and safety risks. Further detail on 
 many of these risks was provided in the 2018 Annual Report. Since year-end, 
    the environmental impact of oil and gas extraction has been added to the 
         risk register, reflecting the increased focus on ESG issues. 
 
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 2018. A list of current directors is maintained on 
         the Genel Energy plc website: www.genelenergy.com [2] 
 
         By order of the Board 
 
         Bill Higgs 
 
         CEO 
 
         5 August 2019 
 
         Esa Ikaheimonen 
 
CFO 
 
5 August 2019 
 
         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 2019 
 
                                                6      6    Year 
                                           months months 
 
                                                           to 31 
                                            to 30  to 30     Dec 
                                             June   June 
                                             2019   2018 
 
                                                            2018 
                                Notes          $m     $m      $m 
 
Revenue                           3         194.3  161.1   355.1 
 
Production costs                  4        (18.1) (12.1)  (28.7) 
Depreciation and                  4        (74.2) (63.4) (134.5) 
amortisation of oil assets 
Gross profit                                102.0   85.6   191.9 
 
Exploration (expense) /           4         (0.6)  (0.5)     1.5 
credit 
Impairment of intangible          4             -      - (424.0) 
assets 
General and administrative        4         (9.5) (11.8)  (24.0) 
costs 
Operating profit / (loss)                    91.9   73.3 (254.6) 
 
Operating profit / (loss) 
is comprised of: 
EBITDAX                                     167.3  137.4   304.1 
Depreciation and                           (74.8) (63.6) (136.2) 
amortisation 
Exploration (expense) /           4         (0.6)  (0.5)     1.5 
credit 
Impairment of intangible          4             -      - (424.0) 
assets 
 
Finance income                    5           2.4    2.1     4.4 
Bond interest expense             5        (15.0) (15.0)  (30.0) 
Other finance expense             5         (2.9)  (1.1)   (3.2) 
Profit / (loss) before                       76.4   59.3 (283.4) 
income tax 
Income tax expense                6         (0.4)      -   (0.2) 
Profit / (loss) and total                    76.0   59.3 (283.6) 
comprehensive income / 
(expense) 
 
Attributable to: 
Shareholders' equity                         76.0   59.3 (283.6) 
                                             76.0   59.3 (283.6) 
 
Profit / (loss) per ordinary                    ¢      ¢       ¢ 
share 
Basic                                 7      27.2   21.3 (101.6) 
Diluted                               7      27.1   21.2 (101.6) 
 
         Condensed consolidated balance sheet 
 
At 30 June 2019 
 
                                                         31 Dec 
 
                                     30 June   30 June     2018 
 
                                        2019      2018 
                             Notes        $m        $m       $m 
 
Assets 
Non-current assets 
Intangible assets                8     796.1   1,264.1    818.4 
Property, plant and              9     641.2     559.5    565.8 
equipment 
                                     1,437.3   1,823.6  1,384.2 
Current assets 
Trade and other receivables     10     125.6      88.3     99.4 
Restricted cash                 11      10.0      17.5     10.0 
Cash and cash equivalents       11     353.3     233.2    334.3 
                                       488.9     339.0    443.7 
 
Total Assets                         1,926.2   2,162.6  1,827.9 
 
Liabilities 
Non-current liabilities 
Trade and other payables             (120.8)    (74.5)   (76.8) 
Deferred income                       (28.1)    (33.8)   (31.9) 
Provisions                            (34.7)    (31.0)   (32.9) 
Borrowings                      11   (297.5)   (297.0)  (297.3) 
                                     (481.1)   (436.3)  (438.9) 
Current liabilities 
Trade and other payables              (65.3)    (48.1)   (52.6) 
Deferred income                        (6.2)     (5.3)    (5.0) 
                                      (71.5)    (53.4)   (57.6) 
 
Total liabilities                    (552.6)   (489.7)  (496.5) 
 
Net assets                           1,373.6   1,672.9  1,331.4 
 
Owners of the parent 
Share capital                           43.8      43.8     43.8 
Share premium account                4,046.6   4,074.2  4,074.2 
Accumulated losses                 (2,716.8) (2,445.1) (2,786.6 
                                                              ) 
Total equity                         1,373.6   1,672.9  1,331.4 
 
         Condensed consolidated statement of changes in equity 
 
For the period ended 30 June 2019 
 

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DJ Genel Energy PLC: Half-Year Results -5-

Share   Share Accumulated losses    Total 
 
                     capital premium                      equity 
                          $m      $m                 $m       $m 
 
At 1 January 2018       43.8 4,074.2          (2,508.2)  1,609.8 
 
Profit and total           -       -               59.3     59.3 
comprehensive 
income 
Share-based                -       -                3.8      3.8 
payments 
 
At 30 June 2018         43.8 4,074.2          (2,445.1)  1,672.9 
 
At 1 January 2018       43.8 4,074.2          (2,508.2)  1,609.8 
 
(Loss) and total           -       -            (283.6)  (283.6) 
comprehensive 
(expense) 
Share-based                -       -                5.2  5.4 5.2 
payments 
 
At 31 December          43.8 4,074.2          (2,786.6)  1,331.4 
2018 and 1 January 
2019 
 
Profit and total           -       -               76.0     76.0 
comprehensive 
income 
Share-based                -       -                2.5      2.5 
payments 
Purchase of shares         -       -              (8.2)    (8.2) 
to satisfy share 
awards 
Purchase of                -       -              (0.5)    (0.5) 
treasury shares 
Dividend payment           - (27.6)1                  -   (27.6) 
 
At 30 June 2019         43.8 4,046.6          (2,716.8)  1,373.6 
 
1 The Companies (Jersey) Law 1991 does not define the expression "dividend" 
but refers instead to "distributions". Distributions may be debited to any 
account or reserve of the Company (including share premium account). 
 
         Condensed consolidated cash flow statement 
 
For the period ended 30 June 2019 
 
                                                          31 Dec 
 
                                        30     30           2018 
                                      June   June 
                                      2019   2018 
                              Notes     $m     $m             $m 
 
Cash flows from operating 
activities 
Profit / (Loss) and total             76.0   59.3        (283.6) 
comprehensive income / 
(expense) 
Adjustments for: 
Finance income              5        (2.4)  (2.1)          (4.4) 
Bond interest               5         15.0   15.0           30.0 
expense 
Other finance               5          2.9    1.1            3.2 
expense 
Taxation                               0.4      -            0.2 
Depreciation and            4         74.8   63.6          136.2 
amortisation 
Exploration expense         4          0.6    0.5          (1.5) 
/ (credit) 
Impairment of               4            -      -          424.0 
intangible assets 
Other non-cash items                 (1.4)    3.0            4.9 
Changes in working 
capital: 
(Increase) /                        (21.8) (11.1) (21.5) 
decrease in trade 
receivables 
(Increase) /                        -      0.9    (1.1) 
decrease in other 
receivables 
Increase /                          (3.7)  (7.1)  9.2 
(decrease) in trade 
and other payables 
Cash generated from                  140.4  123.1          295.6 
operations 
Interest received           5          2.4           2.1     4.4 
Taxation paid                        (0.5)         (0.1)   (0.8) 
Net cash generated                   142.3         125.1   299.2 
from operating 
activities 
 
Cash flows from 
investing activities 
Purchase of                         (12.2)        (10.5)  (39.7) 
intangible assets 
Purchase of                         (58.1)        (29.5)  (65.3) 
property, plant and 
equipment 
Restricted cash             11           -           1.0     8.5 
Net cash used in                    (70.3)        (39.0)  (96.5) 
investing activities 
 
Cash flows from 
financing activities 
Dividends paid to           11      (27.4)             -       - 
company's 
shareholders 
Dividend related                     (1.6)             -       - 
expenses 
Purchase of shares                   (8.2)             -       - 
for employee share 
trust 
Purchase of treasury        11       (0.5)             -       - 
shares 
Lease payments              13       (0.3)             -       - 
Interest paid                       (15.0)        (15.0)  (30.0) 
Net cash used in                    (53.0)        (15.0)  (30.0) 
financing activities 
 
Net increase /                        19.0          71.1   172.7 
(decrease) in cash 
and cash equivalents 
Foreign exchange                         -           0.1   (0.4) 
income / (loss) on 
cash and cash 
equivalents 
Cash and cash                        334.3         162.0   162.0 
equivalents at 1 
January 
Cash and cash               11       353.3  233.2          334.3 
equivalents at 
period end 
 
         Notes to the condensed consolidated financial statements 
 
1) Basis of preparation 
 
    Genel Energy Plc - registration number: 107897 (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 2019 and six months ended 30 June 2018 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 2019. 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 2018, which have 
 been prepared in accordance with IFRS as adopted by the European Union. The 
      annual financial statements for the period ended 31 December 2018 were 
      approved by the board of directors on 19 March 2019. 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 2018 has been extracted 
         from the audited accounts. 
 
 There have been no changes in related parties since year-end and no related 
      party transactions that had a material effect on financial position or 
   performance in the period. There are not significant seasonal or cyclical 
         variations in the Company's total revenues. 
 
Going concern 
 
 The Company regularly evaluates its financial position, cash flow forecasts 
         and its covenants by sensitizing with a range of scenarios which 
    incorporates change in oil prices, discount rates, production volumes as 
      well as capital and operational spend. As a result, the Directors have 
   assessed that the Company's forecast liquidity provides adequate headroom 
     over its forecast expenditure for the 12 months following the half-year 
    condensed consolidated financial statements for the period ended 30 June 
       2019 and consequently that the Company is considered a going concern. 
 
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 2018. 
 
         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 or 
      estimates could have a significant impact on the financial statements. 
 
         Significant estimates 
 
The following are the critical estimates that the directors have made in the 
 process of applying the Company's accounting policies and that has the most 
   significant effect on the amounts recognised in the financial statements. 
 
  Estimation of hydrocarbon reserves and resources and associated production 
         profiles and costs 
 
Estimates of hydrocarbon reserves and resources are inherently imprecise 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, cost 
   and monetisation impact the Company's financial statements in a number of 
 ways, including: testing recoverable values for impairment; the calculation 
   of depreciation, amortisation and assessing the cost and likely timing of 
         decommissioning activity and associated costs. 
 
    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. 
  Assets assessed as proven and probable reserves ("2P" - generally accepted 
  to have circa 50% probability) are generally classified as property, plant 
  and equipment as development or producing assets and depreciated using the 
units of production methodology. The Company considers its best estimate for 
future production and quantity of oil within an asset based on a combination 
         of internal and external evaluations and uses this as the basis of 
 calculating depreciation and amortisation of oil and gas assets and testing 
         for impairment. 
 
 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 

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DJ Genel Energy PLC: Half-Year Results -6-

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. 
 
  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 nominal discount rate 
 of 12.5% is used when assessing the impairment testing of the Company's oil 
         assets. 
 
   In addition, estimation of the recoverable amounts of both Miran and Bina 
    Bawi CGUs, which are classified under IFRS as exploration and evaluation 
 intangible assets and consequently carry the inherent uncertainty explained 
 above, include the key assessment that the projects 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 and 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. 
 
         Estimation of future oil price and netback 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. It is 
         also relevant to the assessment of going concern. 
 
 Netback price is used to value the Company's revenue, trade receivables and 
  its forecast cash flows used for impairment testing. 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. 
 
The trade receivable is recognised when the control on oil is transferred to 
   the customer at the metering point, as this is the time the consideration 
         becomes unconditional. The trade receivable reflects the Company's 
         entitlement based on the netback price and oil transferred. 
 
         Acquisitions of Sarta and Qara Dagh PSCs 
 
 On 28 February 2019 the Company completed the acquisition of a 30% interest 
    in the Sarta PSC, with an economic date of 1 January 2019. Shortly after 
   acquisition date, final investment decision ("FID") was taken on phase 1A 
 development, resulting in the recognition of gross 2P reserves at the asset 
  level of 34mmbbls, of which the Company's share was 10mmbbls. The interest 
has been accounted for as an asset acquisition under IAS 16, with the result 
    being the recognition of a development asset, reflecting the acquired 2P 
  reserves. Consideration for the asset is a combination of cost recoverable 
 carry and a milestone success payment and has been assessed based on the 2P 
         reserves that have been recognised. 
 
       On the same date, the Company also completed the acquisition of a 40% 
         interest in the Qara Dagh PSC. Consideration on the asset is cost 
         recoverable carry arrangement on one well. 
 
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. 
 
         Joint arrangements 
 
      Arrangements under which the Company has contractually agreed to share 
control with another party, or parties, are joint ventures where the parties 
 have rights to the net assets of the arrangement, or joint operations where 
   the parties have rights to the assets and obligations for the liabilities 
 relating to the arrangement. Investments in entities over which the Company 
 has the right to exercise significant influence but has neither control nor 
      joint control are classified as associates and accounted for under the 
         equity method. 
 
 The Company recognises its assets and liabilities relating to its interests 
         in joint operations, including its share of assets held jointly and 
         liabilities incurred jointly with other partners. 
 
         Farm-in/farm-out 
 
Farm-out transactions relate to the relinquishment of an interest in oil and 
gas assets in return for services rendered by a third party or where a third 
     party agrees to pay a portion of the Company's share of the development 
   costs (cost carry). Farm-in transactions relate to the acquisition by the 
Company of an interest in oil and gas assets in return for services rendered 
         or cost-carry provided by the Company. 
 
   Farm-in/farm-out transactions undertaken in the development or production 
        phase of an oil and gas asset are accounted for as an acquisition or 
  disposal of oil and gas assets. The consideration given is measured as the 
  fair value of the services rendered or cost-carry provided and any gain or 
      loss arising on the farm-in/farm-out is recognised in the statement of 
 comprehensive income. A profit is recognised for any consideration received 
in the form of cash to the extent that the cash receipt exceeds the carrying 
         value of the associated asset. 
 
 Farm-in/farm-out transactions undertaken in the exploration phase of an oil 
  and gas asset are accounted for on a no gain/no loss basis due to inherent 
       uncertainties in the exploration phase and associated difficulties in 
 determining fair values reliably prior to the determination of commercially 
 recoverable proved reserves. The resulting exploration and evaluation asset 
         is then assessed for impairment indicators under IFRS 6. 
 
         New Standards 
 
The following new accounting standards, amendments to existing standards and 
     interpretations are effective on 1 January 2019. Amendments to IFRS 9 - 
      Prepayment Features with Negative Compensation, Amendments to IAS 28 - 
Long-term Interests in Associates and Joint Ventures, Amendments to IAS 19 - 
      Plan Amendment, Curtailment or Settlement, IFRIC 23 - Uncertainty over 
      Income Tax Treatments, Annual Improvements to IFRS Standards 2015-2017 
  Cycle. The adoption of these standards and amendments has had no impact on 
         the Company's results or financial statement disclosures. 
 
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 References to the Conceptual 
     Framework in IFRS Standards (effective 1 Jan 2020), Amendment to IFRS 3 
Business Combinations (effective 1 Jan 2020) and Amendments to IAS 1 and IAS 
         8: Definition of Material (effective 1 Jan 2020). 
 
Changes in accounting policies 
 
    IFRS 16 - Leases, which became effective by 1 January 2019, requires the 
lessee to recognise 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 has adopted IFRS 16 retrospectively from 1 
      January 2019, but has not restated comparatives for the 2018 reporting 
      period, as permitted under the specific transitional provisions in the 
    standard. The reclassifications and the adjustments arising from the new 
    leasing rules are therefore recognised in the opening balance sheet on 1 

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DJ Genel Energy PLC: Half-Year Results -7-

January 2019 and further explained in Note 13. 
 
         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 2018. 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, development field on 
 Sarta PSC and appraisal field on Qara Dagh 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. 'Other' 
         includes corporate assets, liabilities and costs, elimination of 
   intercompany receivables and intercompany payables, which are non-segment 
         items. 
 
6 months ended 30 June 2019 
 
                                           Expl.           Total 
 
                               Oil    MBB          Other 
                                $m     $m     $m      $m      $m 
 
Revenue from contracts       188.7      -      -       -   188.7 
with customers 
Revenue from other sources     5.6      -      -       -     5.6 
Cost of sales               (92.3)      -      -       -  (92.3) 
Gross profit                 102.0      -      -       -   102.0 
 
Exploration (expense) /          -  (0.2)  (0.4)       -   (0.6) 
credit 
General and administrative       -      -      -   (9.5)   (9.5) 
costs 
Operating profit / (loss)    102.0  (0.2)  (0.4)   (9.5)    91.9 
 
Operating profit / (loss) 
is comprised of 
EBITDAX                      176.2      -      -   (8.9)   167.3 
Depreciation and            (74.2)      -      -   (0.6)  (74.8) 
amortisation 
Exploration (expense) /          -  (0.2)  (0.4)       -   (0.6) 
credit 
 
Finance income                   -      -      -     2.4     2.4 
Bond interest expense            -      -      -  (15.0)  (15.0) 
Other finance expense        (1.0)  (0.1)      -   (1.8)   (2.9) 
Profit / (loss) before tax   101.0  (0.3)  (0.4)  (23.9)    76.4 
 
Capital expenditure           64.6    5.6    2.0       -    72.2 
Total assets               1,082.9  467.4   35.1   340.8 1,926.2 
Total liabilities          (146.0) (88.5) (12.6) (305.5) (552.6) 
 
 Revenue from contracts with customers includes $54.7 million (30 June 2018: 
      $48.2 million, 31 December 2018: $105.4 million) arising from the 4.5% 
  royalty interest on gross Tawke PSC revenue ending at the end of July 2022 
         ("the ORRI"). Total assets and liabilities in the other segment are 
         predominantly cash and debt balances. 
 
6 months ended 30 June 2018 
 
                                           Expl.           Total 
 
                               Oil    MBB          Other 
                                $m     $m     $m      $m      $m 
 
Revenue from contracts       158.9      -      -       -   158.9 
with customers 
Revenue from other sources     2.2      -      -       -     2.2 
Cost of sales               (75.5)      -      -       -  (75.5) 
Gross profit                  85.6      -      -       -    85.6 
 
Exploration expense              -  (0.2)  (0.3)       -   (0.5) 
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) 
 
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 / (loss) 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) 
 
Total assets and liabilities in the other segment are predominantly cash and 
         debt balances. 
 
For the period ended 31 December 2018 
 
                                           Expl.           Total 
 
                              Oil     MBB          Other 
                               $m      $m     $m      $m      $m 
Revenue from contracts      350.3       -      -       -   350.3 
with customers 
Revenue from other            4.8       -      -       -     4.8 
sources 
Cost of sales             (163.2)       -      -       - (163.2) 
Gross profit                191.9       -      -       -   191.9 
 
Exploration (expense) /         -   (0.4)    1.9       -     1.5 
credit 
Impairment of intangible        - (424.0)      -       - (424.0) 
assets 
General and                     -       -      -  (24.0)  (24.0) 
administrative costs 
Operating profit / (loss)   191.9 (424.4)    1.9  (24.0) (254.6) 
 
Operating profit / (loss) 
is comprised of 
EBITDAX                     326.4       -      -  (22.3)   304.1 
Depreciation and          (134.5)       -      -   (1.7) (136.2) 
amortisation 
Exploration (expense) /         -   (0.4)    1.9       -     1.5 
credit 
Impairment of intangible        - (424.0)      -       - (424.0) 
assets 
 
Finance income                  -       -      -     4.4     4.4 
Bond interest expense           -       -      -  (30.0)  (30.0) 
Other finance expense       (1.7)   (0.2)      -   (1.3)   (3.2) 
Profit / (Loss) before      190.2 (424.6)    1.9  (50.9) (283.4) 
income tax 
 
Capital expenditure          70.4    12.0   13.1       -    95.5 
Total assets              1,015.4   457.7   35.5   319.3 1,827.9 
Total liabilities          (89.1)  (84.4) (16.1) (306.9) (496.5) 
 
Total assets and liabilities in the other segment are predominantly cash and 
         debt balances. 
 
4. Operating costs 
****************** 
 
                        6 months to   6 months to     Year to 31 
                       30 June 2019  30 June 2018  December 2018 
                                 $m            $m             $m 
 
Production costs               18.1          12.1           28.7 
Depreciation of oil            39.7          34.6           72.4 
and gas property, 
plant and equipment 
Amortisation of oil            34.5          28.8           62.1 
and gas intangible 
assets 
Cost of sales                  92.3          75.5          163.2 
 
Exploration expense /           0.6           0.5          (1.5) 
(credit) 
 
Impairment of                     -             -          424.0 
intangible assets 
(note 8) 
 
Corporate cash costs            7.2           8.6           17.4 
Corporate share-based           1.7           3.0            4.9 
payment expense 
Depreciation and                0.6           0.2            1.7 
amortisation of 
corporate assets 
General and                     9.5          11.8           24.0 
administrative 
expenses 
 
5) Finance expense and income 
 
              6 months to 30    6 months to 30        Year to 31 
                   June 2019         June 2018     December 2018 
                          $m                $m                $m 
 
Bond                  (15.0)            (15.0)            (30.0) 
interest 
payable 
Other                  (2.9)             (1.1)             (3.2) 
finance 
expense 
Finance               (17.9)            (16.1)            (33.2) 
expense 
 
Bank                     2.4               2.1               4.4 
interest 
income 
Finance                  2.4               2.1               4.4 
income 
 
 Bond interest payable is the cash interest cost of Company bond debt. Other 
finance expense primarily relates to the discount unwind on the bond and the 
         asset retirement obligation provision. 
 
6. Income tax expense 
********************* 
 
        Current tax expense is incurred on the profits of the Turkish and UK 
  services companies. Under the terms of KRI PSC's, corporate income tax due 
     is paid on behalf of the Company by the KRG from the KRG's own share of 
 revenues, resulting in no corporate income tax payment required or expected 
 to be made by the Company. 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 may 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 2019      6   Year to 
                                                months        31 
                                                 to 30  December 
                                                  June      2018 
                                                  2018 

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$m     $m        $m 
 
Profit /                                   76.0   59.3   (283.6) 
(Loss) 
attributable 
to equity 
holders of 
the Company 
($m) 
 
Weighted                            279,435,346 279,02 279,065,7 
average                                          5,723        17 
number of 
ordinary 
shares - 
number 1 
Basic                                      27.2   21.3   (101.6) 
earnings / 
(loss) per 
share - 
cents 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   6 months to       Year to 31 
                     30 June 2019  30 June 2018    December 2018 
                               $m            $m               $m 
 
Profit / (Loss)              76.0          59.3          (283.6) 
attributable to 
equity holders of 
the Company ($m) 
 
Weighted average      279,435,346   279,025,723      279,065,717 
number of ordinary 
shares - number 1 
Adjustment for            812,852     1,222,475        1,182,481 
performance shares, 
restricted shares 
and share options 
Total number of       280,248,198   280,248,198      280,248,198 
shares 
Diluted earnings /           27.1          21.2          (101.6) 
(loss) per share - 
cents per 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 2018               1,471.7   425.1    6.5  1,903.3 
Additions                           6.3       -      -      6.3 
Discount unwind of                  3.9       -      -      3.9 
contingent 
consideration 
Other                             (0.1)       -      -    (0.1) 
At 30 June 2018                 1,481.8   425.1    6.5  1,913.4 
 
At 1 January 2018               1,471.7   425.1    6.5  1,903.3 
Additions                          25.1       -    0.3     25.4 
Discount unwind of                  8.1       -      -      8.1 
contingent 
consideration 
Other                            (11.7)       -      -   (11.7) 
At 31 December 2018             1,493.2   425.1    6.8  1,925.1 
and 1 January 2019 
 
Additions                           7.6       -    0.4      8.0 
Discount unwind of                  4.3       -      -      4.3 
contingent 
consideration 
Other                                 -       -      -        - 
At 30 June 2019                 1,505.1   425.1    7.2  1,937.4 
 
Accumulated 
amortisation and 
impairment 
At 1 January 2018               (581.3)  (32.8)  (6.3)  (620.4) 
Amortisation charge                   -  (28.8)  (0.1)   (28.9) 
for the period 
At 30 June 2018                 (581.3)  (61.6)  (6.4)  (649.3) 
 
At 1 January 2018               (581.3)  (32.8)  (6.3)  (620.4) 
Amortisation charge                   -  (62.1)  (0.2)   (62.3) 
for the period 
Impairment                      (424.0)       -      -  (424.0) 
At 31 December 2018           (1,005.3)  (94.9)  (6.5) (1,106.7 
and 1 January 2019                                            ) 
 
Amortisation charge                   -  (34.5)  (0.1)   (34.6) 
for the period 
At 30 June 2019               (1,005.3) (129.4)  (6.6) (1,141.3 
                                                              ) 
 
Net book value 
At 30 June 2018                   900.5   363.5    0.1  1,264.1 
At 31 December 2018               487.9   330.2    0.3    818.4 
At 30 June 2019                   499.8   295.7    0.6    796.1 
 
                                                   30 Jun    31 
                                                            Dec 
                                                     2019  2018 
CGU carrying value                                     $m    $m 
Bina Bawi PSC             Discovered gas and oil,   347.4 338.7 
                          appraisal 
Miran PSC                 Discovered gas and oil,   117.9 116.2 
                          appraisal 
Somaliland PSC            Exploration                33.4  33.0 
Qara Dagh PSC             Exploration / Appraisal     1.1     - 
Exploration and                                     499.8 487.9 
evaluation assets 
 
Tawke overriding royalty                            188.5 217.5 
Tawke capacity building payment waiver              107.2 112.7 
Tawke RSA assets                                    295.7 330.2 
 
The table below shows the indicative sensitivity of the Bina Bawi CGU net 
present value to changes to long term Brent, discount rate or production and 
reserves, assuming no change to other inputs. 
 
                                         $m 
 
Long term Brent +/- $5/bbl           +/- 13 
Discount rate +/-2.5%               +/- 101 
Production and reserves +/- 10%      +/- 32 
 
9. Property, plant and equipment 
******************************** 
 
                                 Development 
                                      assets 
 
                     Producing                     Other 
                        assets 
 
                                                  assets   Total 
                            $m            $m          $m      $m 
Cost 
At 1 January 2018      2,683.9             -         9.4 2,693.3 
Additions                 27.8             -           -    27.8 
Non-cash additions         1.4             -           -     1.4 
for ARO/share-based 
payments 
At 30 June 2018        2,713.1             -         9.4 2,722.5 
 
At 1 January 2018      2,683.9             -         9.4 2,693.3 
Additions                 70.4             -         0.2    70.6 
Non-cash additions         2.9             -           -     2.9 
for ARO/share-based 
payments 
At 31 December 2018    2,757.2             -         9.6 2,766.8 
and 1 January 2019 
 
Asset acquisitions           -          49.4           -    49.4 
Additions                 53.3          11.3           -    64.6 
Right-of-use assets          -             -         1.9     1.9 
(note 13) 
Net change in                -         (1.9)           -   (1.9) 
payable 
Non-cash additions         1.6             -           -     1.6 
for ARO/share-based 
payments 
At 30 June 2019        2,812.1          58.8        11.5 2,882.4 
 
Accumulated 
depreciation and 
impairment 
At 1 January 2018    (2,119.7)             -       (8.6) (2,128. 
                                                              3) 
Depreciation charge     (34.6)             -       (0.1)  (34.7) 
for the period 
At 30 June 2018      (2,154.3)             -       (8.7) (2,163. 
                                                              0) 
 
At 1 January 2018    (2,119.7)             -       (8.6) (2,128. 
                                                              3) 
Depreciation charge     (72.4)             -       (0.3)  (72.7) 
for the period 
At 31 December 2018  (2,192.1)             -       (8.9) (2,201. 
and 1 January 2019                                            0) 
 
Depreciation charge     (39.7)             -       (0.5)  (40.2) 
for the period 
At 30 June 2019      (2,231.8)             -       (9.4) (2,241. 
                                                              2) 
 
Net book value 
At 30 June 2018          558.8             -         0.7   559.5 
At 31 December 2018      565.1             -         0.7   565.8 
At 30 June 2019          580.3          58.8         2.1   641.2 
 
                                            30 Jun        31 Dec 
                                              2019          2018 
CGU                                             $m            $m 
carrying 
value 
Tawke PSC  Oil production                    488.5         478.2 
Taq Taq    Oil production                     91.8          86.9 
PSC 
Producing                                    580.3         565.1 
assets 
 
Sarta PSC  Oil development                    58.8             - 
 
       Asset acquisitions of $49.4 million relates to the Sarta PSC. Further 
 explanation on oil and gas assets is provided in the significant accounting 
      judgements and estimates in note 2. The sensitivities below provide an 
      indicative impact on net present value of a change in long term Brent, 
   discount rate or production and reserves, assuming no change to any other 
         inputs. 
 
                                Taq Taq CGU Tawke CGU 
                                         $m        $m 
 
Long term Brent +/- $5/bbl            +/- 3    +/- 28 
Discount rate +/-2.5%                 +/- 5    +/- 52 
Production and reserves +/-10%        +/- 9    +/- 71 
 
10. Trade and other receivables 
 
                                  30 June 30 June 2018 31 Dec 
                                                    $m 
 
                                     2019                2018 
                                       $m                  $m 
 
                Trade receivables   116.6         84.4   94.8 
Other receivables and prepayments     9.0          3.9    4.6 
                                    125.6         88.3   99.4 
 
      Trade receivables are amounts owed for the revenue from contracts with 
        customers. The Company reports trade receivables net of any capacity 
        building payables (30 June 2019: $4.2 million 31 December 2018: $1.9 
         million). 
 
  Under the Tawke and Taq Taq PSCs, payment for entitlement is due within 30 
  days. Since February 2016, a track record of payments being received three 
  months after invoicing has been established, and consequently three months 
has been assessed as the established operating cycle under IAS 1. At 30 June 
 2019, $18.9M relating to the entitlement arising from the Tawke PSC had not 
 been received. This was caused by operator banking issues, with the balance 

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