Full-Year Results
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Genel Energy PLC (GENL) 20 March 2019 Genel Energy plc Audited results for the year ended 31 December 2018  Genel Energy plc ('Genel' or 'the Company') announces its audited results for the year ended 31 December 2018.  Murat Özgül, Chief Executive of Genel, said: "Genel's strategy at the start of 2018 was clear - generate material free cash flow from producing assets, build and invest in a rich funnel of transformational development opportunities, and return capital to shareholders at the appropriate time. We are delivering on this strategy.  2018 was another year of material free cash flow generation, we continued to transform our balance sheet and the addition of assets with the potential of Sarta and Qara Dagh led to a very successful delivery on the first two parts of our strategy. We will continue to develop opportunities and invest in growth. As we do so, a robust cash flow outlook and our confidence in Genel's future prospects underpins our initiation of a material and sustainable dividend policy."  Results summary ($ million unless stated)
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 There will be a presentation for analysts and investors today at 0900 GMT, with an associated webcast available on the Company's website, www.genelenergy.com.  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.   CHAIRMAN'S STATEMENT I am pleased to welcome you to Genel Energy's eighth annual results statement. Political stability in the Kurdistan Region of Iraq and a recovery in the oil price provided a positive backdrop for our operations in 2018. With a firm focus on our renewed strategy, Genel delivered across all key areas of its business, with the economic tailwinds helping to deliver material free cash flow and to create significant shareholder value. Highly cash generative and growing production, supplemented by recent additions to the portfolio, and our financial strength, position us well to continue this performance in coming years.  Delivering on our strategy Our strategic bedrock remains our highly cash-generative producing assets. The success of Peshkabir, where production grew almost five-fold over the year to over 50,000 bopd, ahead of schedule and under budget, provided rapid growth on the Tawke PSC. The increase at Peshkabir was supported by the redeployment of Taq Taq's early processing facility, and field management work at the Taq Taq field itself helped to stabilise production and provide a base from which we expect to now add growth in 2019. The combination of the two led to Genel slightly outperforming on production guidance for the year.  Maximising the value of these assets, and generating material free cash flow, was our core priority and positions us to now focus on progressing the material opportunities in our portfolio. As we demonstrated our capability to grow and expand operations, we moved firmly into a net cash position, and our free cash flow will continue to more than fund our investment programme for the foreseeable future. Our financial strength will increase further even as we ramp up our disciplined expenditure, allowing us to initiate a material and sustainable dividend policy. Our compelling mix of operational expertise and balance sheet strength has helped us to join up with major partners as we look to provide a long-term increase in shareholder value.  Growth on all key metrics As we progress through 2019 we continue to grow on all key metrics. Our cash position is rising on a monthly basis, our production is forecast to increase 10% year-on-year, and the addition of Sarta and growth at Peshkabir has delivered an increase in our 2P reserves.  Last year we stated that Genel aimed to add assets that build on the strengths of the current portfolio, prioritising areas of low to moderate political risk while retaining a focus on cash generation. Given the successful elections and ongoing improvement in the economic situation, we now see the KRI as such an area, as reflected in the reduction of our internal discount rate and reinforced by well over three years of consecutive payments for oil exports.  We were delighted with the addition of stakes in Sarta and Qara Dagh to the Genel portfolio, which are a key step as we continue to develop opportunities to expand our portfolio of high-value assets. Being chosen as a partner by Chevron was a strong endorsement of Genel's technical and commercial strengths, and the projects are an ideal fit for our strategy. Qara Dagh has a proven hydrocarbon system and significant resource potential estimated by Genel at c.200 MMbbls, while Sarta offers near-term production. With unrisked gross P50 resources estimated at c.500 MMbbls Sarta has the potential to scale up and be a low-cost, long-life, cash-generative asset. Should appraisal work prove successful, field production should materially increase just as payments from the Receivable Settlement Agreement tail away, ensuring significant free cash flow generation for years to come.  Generating cash, creating opportunity The generation of free cash flow is a key focus for Genel, and a core tenet of our strategy for value creation. It is our aim to generate cash while delivering transformational growth. In 2018 we generated $164 million in free cash flow at the same time as increasing Peshkabir production and progressing the development of our asset portfolio. 2019 will see this strategy ramp up. We will be involved in the drilling of around 20 wells in the Kurdistan Region of Iraq, progressing plans for Sarta and Qara Dagh, finalising the commercial discussion relating to Bina Bawi, and still expect to generate free cash flow of well over $100 million.  We are a Company that is focused on providing material growth and are investing accordingly. Ingrained capital discipline and a focus on cash flow generation provides us with increased confidence over our long-term cash flows, reaffirming our commitment to share success directly with our shareholders and leading us to initiate a material and sustainable dividend. As we look to provide investors with a compelling proposition combining both growth and a material annual return, we are set to approach bondholders to request a waiver of the dividend restriction so we might facilitate the acceleration of a first dividend distribution into 2019.  Long-term value creation Genel has a balanced portfolio combining near-term cash generation and potentially transformational growth opportunities. We do not see the additions of the stakes in Sarta and Qara Dagh as being the end of our ambitions by any means, and we continue to selectively seek further additions to the portfolio that match our strategic focus.  2018 was a hugely successful year that also sets up the Company for material growth in years to come. I would like to take this opportunity to thank our supportive shareholders, whose patience is now being rewarded, and reaffirm our commitment to becoming a world-class independent E&P creator of shareholder value.   CEO STATEMENT 2018 was another successful year for Genel. Our continued focus on our key objectives helped us to deliver our strategic goals, growing reserves, production, and cash while adding material growth opportunities.  While looking to grow the business, we never forget that our first priority is the safety and security of our workforce and the communities in which we operate. We are pleased to report another year of operations without a lost time incident and there has now been no such incident at Genel or TTOPCO operations since 2015, over eight million working hours. In 2018 we also met our objective of zero losses of primary containment. Genel takes great pride in our operations, and we work hard to continuously improve our systems and make sure that all possible precautions are in place. This focus, and the quality of our workforce, is a factor that is attractive to potential partners, and therefore important to our overall strategic goals.  Material cash generation Our primary strategic goal in 2018 was the maximisation of free cash flow from our producing operations. This was our key capital allocation priority, and the majority of our $95 million of capital expenditure was invested in the Tawke and Taq Taq PSCs. As previously stated, we look to invest our capital in those areas that promise to deliver the most value to shareholders. In 2018 the priority was therefore Peshkabir, where exceptional well performance delivers returns of over $8 for every $1 invested, with cost recovery on the initial investment less than a month after production begins. Few assets anywhere offer such a rapid return.  The investment in the well programme boosted Peshkabir production from 12,000 bopd at the start of 2018 to 55,000 bopd by the year-end. Due to the high investment returns at Peshkabir, drilling on the Tawke field was limited in the year, and the field therefore naturally declined. As Peshkabir moves from appraisal to development, the focus of drilling in 2019 will move back to Tawke. Up to 14 wells are set to be drilled on the main Tawke field, with the operator expecting production to stabilise at c.75,000 bopd as a result.  Drilling activity at Taq Taq was also limited in 2018. Work in H1 2018 focused on workovers and well management, and so the performance of the field ahead of the resumption of drilling was very encouraging, with minimal production declines. We are now two wells into a five well drilling programme, focused on the flanks of the field. Production from the last two wells, TT-29w and TT-32, has been robust - and illustrates that there are still wells to be drilled at Taq Taq that are attractive economically. The positive performance has significantly increased well profitability, making wells at Taq Taq again an attractive capital allocation option.  This focus on capital allocation, and the positive drilling results, helped boost our free cash flow to $164 million. We expect to continue generating material free cash flow in 2019 - $44 million was generated in the first two months of the year - even after investing in the tremendous profitable growth opportunities within our portfolio.  Adding growth opportunities The addition of stakes in Sarta and Qara Dagh was a huge positive for Genel. The two fields provide precisely what we are looking for as we take steps to build a portfolio of high-value assets - low-cost, low-risk entry into opportunities that promise near-term production, with material growth potential and significant longer term upside.  Sarta will be brought on to production in 2020, and it has the potential for production to ramp up to transformational levels. In the success case, Sarta perfectly fits into Genel's production profile, with the potential to add company-changing cash flows after the override payments under the receivable settlement agreement end in H2 2022.  Being chosen as a partner by Chevron is a real boost for Genel, and the combination of the two companies brings together Genel's experience in the KRI and low-cost operating capability on the ground with Chevron's oil major capabilities.  We look forward to getting started both at Sarta and Qara Dagh, with the latter most likely being the premier remaining appraisal opportunity in the KRI. There is a proven hydrocarbon system on the block, with a previous well drilled off structure flowing light oil. The chance to therefore drill a more optimally located well is enormously exciting.  Bina Bawi is the third asset in our portfolio that has transformational growth potential. With light oil able to be produced within six months of the agreement of commercial terms with the government it is a significant opportunity, although progress on reaching such an agreement with the Kurdistan Regional Government ('KRG') has been challenging. A field development plan ('FDP') for Bina Bawi relating to both oil and gas was submitted in H2 2018 detailing the early production of light oil and taking a phased development approach towards the gas, which would reduce initial capital expenditure and achieve the earliest date for first gas.  Talks have recently focused on how best to develop the oil and progress the gas project. The deadline to meet the conditions precedent related to the Bina Bawi gas lifting agreement has been extended until 30 April 2019, after which there is a further 12 months to renegotiate the gas lifting agreement. Constructive talks are continuing, and can do so after April, and any significant further investment in the Bina Bawi licence will be subject to an appropriate commercial solution agreed with the KRG.  A field development plan was also submitted for Miran. As noted in our trading and operations update in January, with the focus on Bina Bawi, we have reviewed of the value of the Miran PSC carried in the Company accounts. The decision has been made to write down the Miran asset by $424 million, pending any movement on field development discussions. We continue to believe that the licence holds significant potential, and development can follow a similar plan to Bina Bawi, but pending clarity on a development timeline, this is a prudent action based on accounting principles.  Returning capital to shareholders Genel has a balanced portfolio, with material production and cash generation and transformational growth opportunities in the pipeline. These opportunities are more than funded out of our current cash flow, and our outlook illustrates that our cash position will continue to grow over the long-term while still allowing for ongoing portfolio investment and more. As such, now is the right time for us to initiate a material and sustainable dividend policy.  Outlook In 2019 we expect production to grow, material cash generation, and the progression of the opportunities in our portfolio.  Our strategic ambitions remain clear - we will focus on generating cash, investing in opportunities, and returning capital to shareholders. Our ability to do the latter is the next step in delivering on our strategy. We remain committed to materially growing the company, and will actively appraise opportunities to make disciplined additions to the portfolio that will further bolster our cash generation story.   OPERATING REVIEW Reserves and resources development Genel's proven (1P) and proven plus probable (2P) net working interest reserves totalled 99 MMbbls and 155 MMbbls respectively, a reserve replacement ratio of 117% and 141%.  This increase follows successful drilling at Peshkabir helping bolster reserves replacement on the Tawke PSC, stability at Taq Taq, and the addition of reserves at Sarta post-period end.  Â
 Production Production in 2018 was 33,700 bopd, with the success at Peshkabir and stability at Taq Taq helping to offset the natural field declines at Tawke. Drilling in 2018 was concentrated on the successful appraisal campaign at Peshkabir, with only limited activity at the Tawke field and Taq Taq. 2019 will see more development work at Peshkabir, while 10 wells are set to be drilled at Tawke and four at Taq Taq. Through stabilising production at Tawke, Genel expects production in 2019 to be roughly in line with that of Q4 2018, 36,900 bopd, an increase of approximately 10% year-on-year.  Work over the last two years has significantly diversified our producing well stock. At the start of 2017 production came from 46 wells at two fields. The number of producing wells had increased by 50% by January 2019, and our production now comes from 69 wells at three fields, making the portfolio more diverse and reliable for production and cash flow.  Average production in 2019 to date is 37,200 bopd, in line with guidance. KRI assets Tawke PSC (25% working interest) Production on the Tawke PSC, operated by DNO, averaged 113,020 bopd in 2018, with production from Peshkabir contributing 27,660 bopd to this figure. With drilling activity on the Tawke PSC concentrating on Peshkabir, production at the Tawke field declined to 75,000 bopd by the end of 2018. Work in 2019 will be focused on stabilising production, and 10 wells have been included in Genel's firm activity plan for the year, with the operator planning to drill up to 14.  Activity in H1 2018 included ongoing workovers of existing wells, and limited drilling resumed in H2. One deep Cretaceous well and two shallow Jeribe wells were brought onstream, and these zones will continue to be targeted for production in 2019.  Peshkabir Ongoing drilling success at Peshkabir resulted in production increasing from 12,000 bopd in January to over 55,000 bopd at the end of 2018, ahead of schedule and under budget. Wells were drilled across the structure, and each successfully added to production.  Ahead of the commissioning of a 50,000 bopd central processing facility ('CPF') each well produced via test spreads, a cost-effective way of maximising cash generation while appraising the field. This is a model that we will look to replicate at Sarta and Qara Dagh.  In 2018 the focus at the field was on drilling and appraising, and six wells were drilled in the year. Another two are scheduled in our firm budget for 2019, when field development work will come to the fore. As well as the ongoing commissioning of a 50,000 bopd CPF, a 60,000 bopd capacity pipeline is under construction and work will begin later in the year on building the gas gathering and processing facilities to enable reinjection of the associated gas produced at the field into the Tawke field, both reducing flaring and increasing recoverability at the latter. The gas gathering and injection system is forecast to be operational in early 2020.  The first well in the 2019 programme, Peshkabir-9, has now been completed as a producing well. The well was drilled on the eastern flank of the structure, two kilometres from the Peshkabir-3 well, and therefore confirms production across the entirety of the Peshkabir structure. Production at Peshkabir is currently c.55,000 bopd.  Taq Taq (44% working interest, joint operator) Taq Taq performed well in 2018, with production stabilising in the second half of the year through successful field management operations and workovers. Drilling on the field has restarted in earnest, with successful progress being made on our five well programme targeting the flanks of the field. Two wells in the programme have now been completed.  The TT-32 well on the northern flank followed the success of TT-29w, and it is currently contributing c.3,000 bopd to overall field production. The rig has now moved to drill the TT-20 well, with a further three wells scheduled to be drilled at Taq Taq in 2019. We will continue with the current well programme, with the aim of adding to overall field production.  Sarta (30% working interest) Having completed the transaction in February, the field partners are now progressing with the development of the asset, which will be done in phases.  Phase 1A begins with the recompletion of the Sarta-2 well and the placing of the Sarta-3 well on production, both of which flowed c.7,500 bopd on test, and the construction of a central processing facility with a 20,000 bopd capacity. The processing facility will be installed on a lease operate maintain basis.  First oil is expected in the middle of 2020, with a total cost to Genel of $60 million to the end of 2020. Initial production will be trucked.  Following the completion of the initial wells in 2020, it is expected that the rig will move to drill back to back development wells as we rapidly appraise the field. Further production capacity will then be added as required as the field is developed and production ramps up, with test spreads being used in a similar way as they were in the development of Peshkabir. The use of an appraise while producing strategy akin to Peshkabir will allow for the optimal evaluation of the gross resources with further production capacity being added as the field is appraised.  Qara Dagh (40% working interest, operator) Genel acquired 40% equity in the Qara Dagh appraisal licence and became the operator through a carry arrangement, covering activity for the QD-2 well. This well is estimated to cost c.$40 million and is set to be drilled in H1 2020.  Qara Dagh offers an exciting appraisal opportunity. The QD-1 well, completed in 2011, tested light oil in two zones from the Shiranish formation. This is despite it being drilled on a location based on an incorrect structural model, which has since been re-evaluated through the subsequent reprocessing of 2D seismic, further 2D seismic acquisition, and the integration of learnings from the QD-1 well.  The QD-2 well is designed to test a more crestal position on the structure with a high angle well to maximise contact with reservoir fractures. Work is underway on assessing the optimal location for the well.  Bina Bawi and Miran (100% working interest, operator) Bina Bawi and Miran are assets that have the potential to generate significant shareholder value, and efforts in 2018 continued to explore a commercial solution to allow the unlocking of the material resources.  Work is focused on Bina Bawi, where the potential for the development of light oil provides the opportunity for near-term revenues that in turn can be used to expedite the development of the 8.2 Tcf of gas resources. The field is also preferentially situated, being only 30 km from Taq Taq's central processing facility and export route.  The FDP for oil at Bina Bawi detailed the production of 15 MMbbls of light oil during the first phase, with first oil production being possible around six months following final investment decision, which is predicated on approval by the KRG.  The FDP for gas at Bina Bawi detailed a gas project with an initial raw gas capacity of 250-300 MMscfd, adopting a modular development strategy that would utilise incremental increases as facilities are replicated. This reduces the capital expenditure requirement to first gas while retaining material future upside. Operational progress at Bina Bawi is dependent on an agreement on commercial terms, and Genel will step up efforts to bring in a partner once the project is more clearly defined. Any progress at Miran would be subsequent to Bina Bawi.  Exploration and appraisal Africa Onshore Somaliland, seismic processing completed on the SL-10-B/13 block (Genel 75% working interest, operator) in Q4 2018, and analysis and interpretation is underway. Initial indications confirm the Company view that the block has hydrocarbon potential. Genel continues to develop a prospect inventory and assess next steps ahead of a farm-out process and potentially spudding a well with a partner in 2020. On the Odewayne block further seismic processing is to be undertaken in order to complete the Company's understanding of the prospectivity of the block.  On the Sidi Moussa block offshore Morocco (Genel 75% working interest, operator), the acquisition of a c.3,500 km2 multi-azimuth broadband 3D seismic survey completed in November. PSTM and PSDM processing will continue through 2019. Genel has no additional work commitments relating to the licence. The Company will undertake a farm-out campaign once processing and interpretation has progressed sufficiently, ahead of a decision on whether to drill a well in the future.   FINANCIAL REVIEW Overview The Company has maintained its disciplined and value focused capital allocation philosophy, investing primarily in its producing assets in 2018. The result is significant free cash flow generation of $164 million, an increase of 66% on the previous year, and a transformed balance sheet, with net cash of $37 million reported at year-end, a figure that increased to $81 million by the end of February.  Proceeds of $335 million were significantly higher than the previous year (2017: $263 million), as a result of a full year of benefit from the RSA, which was effective from August 2017 and an improved average oil price average of $71/bbl (2017: $54/bbl). EBITDAX of $304 million was an increase of 67% on last year, if the one-off gain arising from the RSA is excluded.  The Company's capital allocation priority remains unchanged: investing in the growth of the business, both on existing assets and also adding new assets. With an enhanced long term portfolio, continuous focus on value and increased cash generation, we are confident in delivering on our objective to become the industry leading generator of shareholder value.  The financial strength of the business, its strong future cash generation and its resilience to downside scenarios has led us to initiate a material and sustainable dividend policy. We intend to pay a minimum dividend of $40 million per annum, with the intention of growing this as our liquidity increases. Due to our resilience, this minimum is payable at a lower oil price, but we will of course ensure that payments made are appropriate.  We will pay a dividend in 2020 relating to the 2019 financial year, with the intention that this will be split between an interim and final dividend, to be paid one-third/two-third. Although we have been strengthening our credit continuously, and will continue to do the same, the non-cash impairment of the Miran gas asset means that we need to seek a waiver from our bondholders for a dividend in 2019. Subject to acceptable waiver discussions with our bondholders, we intend to accelerate the distribution and pay a dividend in 2019.  Our dividend policy provides a meaningful and competitive return to shareholders, appropriately commensurate with the underlying value of the business, without in any way compromising our ability to invest in growth through progression of value realisation from our existing portfolio and the acquisition of appropriate new assets.  Successful focus on financial objectives For 2018, the financial priorities of the Company were the following:
 Cost recoverable investment in producing assets led to positive results. At Peshkabir a high performance ramp up was achieved, increasing production from c.15,000 bopd to c.55,000 bopd. At Taq Taq, wells drilled successfully increased production at the end of the year, and TT-32 suggests there is potential for additional upside production that can be unlocked from further drilling work. Towards the end of the year, work on Tawke included workovers and the drilling of additional wells. We expect to realise the benefits of these wells next year when, together with further wells planned in 2019, the incremental production is planned to stabilise production at this mature field.  Operating expenditure at our producing assets was already one of the lowest in the world at c.$2.5/bbl - in 2018 the average operating expense per barrel remained at around the same level.  At Bina Bawi, commercial discussions have been ongoing with capital investment delayed until an appropriate commercial structure with an appropriate derisked cash flow profile can be agreed. We continue to look at the best way to develop the asset and minimise spend while maximising the potential for value creation. We will continue this approach in 2019. At Miran, any progress would be subsequent to Bina Bawi, with Miran effectively held on a care and maintenance basis in the meantime. The clear separation of the two assets and the prioritisation of Bina Bawi has resulted in a significant impairment to the carrying value of the Miran PSC. Detail is provided in note 1 to the financial statements.  Through the year, the Company has assessed potential asset acquisition opportunities with a priority on low-cost entry and near-term cash generation. This has resulted in the completion of the acquisition of interests in the Sarta and Qara Dagh licences in early 2019, which represent significant growth potential for the Company. We will pursue further acquisition activity in the future.  For 2019 the financial priorities of the Company are the following:
 A summary of the financial results for the year is provided below.  Financial results for the year Income statement Working interest production of 33,700 bopd was slightly reduced compared to last year (2017: 35,200 bopd), principally as a result of decline in Tawke which was mostly offset by Peshkabir.  Revenue increased from $228.9 million to $355.1 million. The year-on-year increase was caused principally by improved oil price of average $71/bbl (2017 average: $54/bbl) and a full year impact of the RSA, which was effective from August 2017.  Production costs of $28.7 million slightly increased from last year (2017: $27.5 million) primarily as a result of production contribution from Peshkabir.  The increase in revenue resulted in EBITDAX of $304.1 million, this is lower than last year (2017: $475.5 million), which included the one off gain on RSA of $293.8 million. Excluding the one-off gain last year, EBITDAX improved by 67%.  Depreciation of $72.4 million (2017: $83.3 million) reduced year-on-year as a result of lower production. Amortisation of Tawke intangibles increased to $62.1 million due to a full year impact of the RSA (2017: $32.8 million).  Exploration expense resulted with a credit balance of $1.5 million with the net effect of $1.3 million release of previous years' accruals for already relinquished Cote d'Ivoire licence and net $0.2 million for Morocco licence (2017: $1.9 million expense).  An impairment expense of $424.0 million (2017: $58.2 million) was recorded in relation to the Miran PSC, which is explained further in note 1.  Cash general and administrative costs of $17.4 million were largely unchanged (2017: $16.9 million).  Finance income of $4.4 million (2017: $4.9 million) was bank interest income (2017: $2.2 million). Other finance expense of $3.2 million (2017: $28.0 million) was comprised of non-cash discount unwind expense on liabilities (2017: $8.3 million) whereas last year there was $3.7 million premium paid and $16.0 million accelerated discount unwind on redemption of the bonds.  There is no taxation on operational profits: 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. Tax presented in the income statement of $0.2 million (2017: $1.0 million) was related to taxation of the Turkish and UK service companies.  Capital expenditure Capital expenditure in the year was $95.5 million (2017: $94.1 million). Cost recovered spend on producing assets in the KRI was $70.4 million (2017: $59.5 million) with spend on exploration and appraisal assets amounting to $25.1 million (2017: $34.6 million), principally incurred on the Miran, Bina Bawi and Somaliland PSCs.  Cash flow and cash Net cash flow from operations was $299.2 million (2017: $221.0 million). This was positively impacted by $92.5 million (2017: $86.5) of proceeds being received for the historic KRG receivable, and $242.6 million (2017: $176.8 million) received for current sales.  Free cash flow before interest was $194.2 million (2017: $141.8 million) and free cash flow after interest was $164.2 million (2017: $99.1 million).  $10.0 million (2017: $18.5 million) of cash was restricted and therefore excluded from reported cash of $334.3 million (2017: $162.0 million). Overall, there was a net increase in cash of $172.7 million compared to a decrease of $245.1 million last year.  Debt Total debt was at $297.3 million (2017: $296.8 million) and resulted in net cash of $37.0 million (2017: $134.8 million net debt).   The bond has three financial covenant maintenance tests: Â
Net assets Net assets at 31 December 2018 were $1,331.4 million (2017: $1,609.8 million) and consist primarily of oil and gas assets of $1,384.2 million (2017: $1,847.9 million), trade receivables of $94.8 million (2017: $73.3 million) and net cash of $37.0 million (2017: $134.8 million net debt).  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 dividend (2017: nil) has been declared for the year ended 31 December 2018. Note that 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), save for nominal capital account or capital redemption reserve. In all cases, the Company is only permitted to make a distribution if the Directors authorising it have made a prior solvency statement. The Directors will decide which account to debit in relation to each specific distribution.  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 annual report for the period ended 31 December 2018 and consequently that the Company is considered a going concern.  Consolidated statement of comprehensive income For the year ended 31 December 2018 Â
 Consolidated balance sheet At 31 December 2018 Â
   Consolidated statement of changes in equity For the year ended 31 December 2018  Â
      Consolidated cash flow statement For the year ended 31 December 2018 Â
  Notes to the consolidated financial statements  1. Summary of significant accounting policies  1.1   Basis of preparation The consolidated financial statements of Genel Energy Plc - registration number: 107897 (the Company) have been prepared in accordance with International Financial Reporting Standards as adopted by the European Union and interpretations issued by the IFRS Interpretations Committee (together 'IFRS'); are prepared under the historical cost convention except as where stated; and comply with Company (Jersey) Law 1991. The significant accounting policies are set out below and have been applied consistently throughout the period.  The Company prepares its financial statements on a historical cost basis, unless accounting standards require an alternate measurement basis. Where there are assets and liabilities calculated on a different basis, this fact is disclosed either in the relevant accounting policy or in the notes to the financial statements.  Items included in the financial information of each of the Company's entities are measured using the currency of the primary economic environment in which the entity operates (the functional currency). The consolidated financial statements are presented in US dollars to the nearest million ($m) rounded to one decimal place, except where otherwise indicated.  For explanation of the key judgements and estimates made by the Company in applying the Company's accounting policies, refer to significant accounting judgements and estimates on pages 18 and 21.  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 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. Free cash flow is presented in order to show the free cash flow generated that is available for the Board 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 last year.  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 signing of the annual report for the period ended 31 December 2018 and consequently that the Company is considered a going concern.  Foreign currency Foreign currency transactions are translated into the functional currency of the relevant entity using the exchange rates prevailing at the dates of the transactions or at the balance sheet date where items are re-measured. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at period-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the statement of comprehensive income within finance income or finance costs.  Consolidation The consolidated financial statements consolidate the Company and its subsidiaries. These accounting policies have been adopted by all companies.  Subsidiaries Subsidiaries are all entities over which the Company has control. The Company controls an entity when it is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Company. They are deconsolidated from the date that control ceases. Transactions, balances and unrealised gains on transactions between companies are eliminated.    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.  Acquisitions The Company uses the acquisition method of accounting to account for business combinations. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured at their fair values at the acquisition date. The Company recognises any non-controlling interest in the acquiree at fair value at time of recognition or at the non-controlling interest's proportionate share of net assets. Acquisition-related costs are expensed as incurred.  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 IFRS6.  1.2   Significant accounting judgements and estimates The preparation of the financial statements in accordance with IFRS requires the Company to make judgements and estimates 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 judgements The following is the critical judgement, apart from those involving estimations (which are dealt with separately below), 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.  Tawke CGU Tawke RSA intangible asset (which is explained below) 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, as a result, both assets are combined as a single cash generating unit for impairment testing.  Significant estimates 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 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. 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, 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 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 IFRS6.  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.  Change in accounting estimate The Company has updated its estimated reserves and resources with the accounting impact summarised below under estimation of oil and gas asset values.  Estimation of oil and gas asset valuesEstimation 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 both the Miran and Bina Bawi CGUs, which are classified under IFRS as an exploration and evaluation intangible asset and consequently carries 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.  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 year-end are provided in note 9.  Change in accounting estimate and judgement - Miran PSC (intangible assets) As a result of the development of negotiations through 2018, management assess the Bina Bawi and Miran PSCs as separate cash generating units, whereas last year they were assessed as one cash generating unit. Whereas previously a large scale combined processing facility serving both assets was considered, with delivery of required gas volumes contributed from either licence, discussions are now focused on commencing with a smaller scale development of the Bina Bawi asset that would then be scaled up in phases, with development of the Miran PSC deprioritised. Management assesses the deprioritisation of the Miran PSC, with discussions on Bina Bawi active and detailed, as an impairment indicator and consequently have tested its carrying value for impairment. Principal changes to past estimates relating to the fair value less costs of disposal valuation of Miran relate to timing, cost estimates and risking. Because of the uncertainties existing around these items, as well as approach and commercial terms for the development of the asset, the assessment of valuation carries inherent uncertainty and for this reason, in addition to the estimates made, the Board has included contingencies for costs and timing and additionally an overall reduction in valuation to reflect risking of the project. The risking has been applied at 50% of the calculated value, which was assessed using a discount rate of 15%. This has resulted in an estimate of the recoverable value of Miran as $113 million, which results in an impairment charge of $424 million.  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.  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 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 2023 price then inflated at 2% per annum.   Â
 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.  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.  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 by circa $5 million and trade receivables by circa $1 million with disclosures on the sensitivities of the recoverable amount of producing assets provided in note 9.  1.3 Accounting policies The accounting policies adopted in preparation of these financial statements are consistent with those used in preparation of the annual financial statements for the year ended 31 December 2017, adjusted for transitional requirements where necessary, further explained under revenue and changes in accounting policies headings.  Revenue Revenue for oil sales is recognised when the control of the product is deemed to have passed to the customer, in exchange for the consideration amount determined by the terms of the contract. For exports the control passes to the customer when the oil enters the export pipe, for domestic sales this is when oil is collected by truck by the customer.  Revenue is oil sales. Revenue is earned based on the entitlement mechanism under the terms of the relevant PSC; ORRI, which is earned on 4.5% of gross field revenue from the Tawke licence until July 2022; and royalty income. Entitlement has two components: cost oil, which is the mechanism by which the Company recovers its costs incurred on an asset, and profit oil, which is the mechanism through which profits are shared between the Company, its partners and the KRG. The Company pays capacity building payments on profit oil from Taq Taq licence, which becomes due for payment once the Company has received the relevant proceeds. Profit oil revenue is always reported net of any capacity building payments that will become due. Capacity building payments due on Tawke profit oil receipts were waived from August 2017 onwards as part of the RSA. ORRI is calculated as 4.5% of Tawke PSC field revenue. Royalty income was received in advance and is recognised in line with production.  The Company's oil sales are made to the KRG which is the counterparty of the PSCs and are valued at a netback price, which is calculated from the estimated realised sales price for each barrel of oil sold, less selling, transportation and handling costs and estimates to cover additional costs. A netback adjustment is used to estimate the price per barrel that is used in the calculation of entitlement and is explained further in significant accounting estimates and judgements.  The payment terms for the Company's sales are typically due within 30 days but under the normal operating cycle, payments are received on 75 days average. The Company does not expect to have any contracts where the period between the transfer of oil to the customer and the payment exceeds one year. Therefore, the transaction price is not adjusted for the time value of money.  The Company is not able to measure the tax that has been paid on its behalf and consequently revenue is not reported gross of income tax paid.  The Company adopted IFRS 15 Revenue from Contracts with Customers for the year commencing 1 January 2018. IFRS 15 addresses the way that revenue derived from contracts with customers is recognised in the financial statements and replaces IAS 18 Revenue. The transition from IAS 18 to IFRS 15 does not have an impact on revenue recognised in the financial statements.  For the year ended 31 December 2018, in accordance with IFRS 15, the Company has identified its contracts with its single customer (the KRG) as each oil sale contract (PSC) for each field licence. The Company's single performance obligation within these contracts is the delivery of oil and the transaction price within these contracts is dated Brent adjusted for the netback amount. The performance obligation is satisfied and the Company recognises revenue when control of the oil is transferred to the customer at the metering point.  For the prior year ended 31 December 2017, under IAS 18, the Company also recognised revenue when the oil was transferred to the customer at the metering point as this was when the significant risks and rewards of ownership were deemed to have passed to the customer, it could be measured reliably and it was assessed as probable that economic benefit would flow to the Company. Therefore, there has been no significant change in the Company's revenue recognition on transition to the new standard IFRS 15.   In applying IFRS 15 as set out above, there are no significant judgements made in determining the timing of the satisfaction of the performance obligation, the transaction price or the amounts allocated to performance obligations. The Company has adopted IFRS 15 using the modified retrospective approach, under this approach the prior year's financial statements are not restated and the impact of adoption is recognised in the opening reserves at 1 January 2018. As the impact of adoption on the Company is not material, no adjustment has been recognised in opening reserves.  Intangible assets Exploration and evaluation assets Oil and gas assets classified as exploration and evaluation assets are explained under Oil and Gas assets below.  Tawke RSA Intangible assets include the Receivable Settlement Agreement ('RSA')effective from 1 August 2017, which was entered into in exchange for trade receivables due from KRG for Taq Taq and Tawke past sales. The RSA was recognised at cost and is amortised on a units of production basis in line with the economic lives of the rights acquired, as further explained in Note 8.  Other intangible assets Other intangible assets that are acquired by the Company are stated at cost less accumulated amortisation and less accumulated impairment losses. Amortisation is expensed on a straight-line basis over the estimated useful lives of the assets of between 3 and 5 years from the date that they are available for use.  Property, plant and equipment Development assets Oil and gas assets classified as development assets are explained under Oil and Gas assets below.  Other property, plant and equipment Other property, plant and equipment are principally the Company's leasehold improvements and other assets and are carried at cost, less any accumulated depreciation and accumulated impairment losses. Costs include purchase price and construction cost. Depreciation of these assets is expensed on a straight-line basis over their estimated useful lives of between 3 and 5 years from the date they are available for use.  Oil and gas assets Costs incurred prior to obtaining legal rights to explore are expensed to the statement of comprehensive income.  Exploration, appraisal and development expenditure is accounted for under the successful efforts method. Under the successful efforts method only costs that relate directly to the discovery and development of specific oil and gas reserves are capitalised as exploration and evaluation assets within intangible assets so long as the activity is assessed to be de-risking the asset and the Company expects continued activity on the asset into the foreseeable future. Costs of activity that do not identify oil and gas reserves are expensed. All licence acquisition costs, geological and geophysical costs and other direct costs of exploration, evaluation and development are capitalised as intangible assets or property, plant and equipment according to their nature. Intangible assets comprise costs relating to the exploration and evaluation of properties which the directors consider to be unevaluated until assessed as being 2P reserves and commercially viable.  Once assessed as being 2P reserves they are tested for impairment and transferred to property, plant and equipment as development assets. Where properties are appraised to have no commercial value, the associated costs are expensed as an impairment loss in the period in which the determination is made.  Development expenditure is accounted for in accordance with IAS 16 - Property, plant and equipment. Assets are depreciated once they are available for use and are depleted on a field-by-field basis using the unit of production method. The sum of carrying value and the estimated future development costs are divided by total forecast 2P production to provide a $/barrel unit depreciation cost. Changes to depreciation rates as a result of changes in reserve quantities and estimates of future development expenditure are reflected prospectively.  The estimated useful lives of property, plant and equipment and their residual values are reviewed on an annual basis and changes in useful lives are accounted for prospectively. The gain or loss arising on the disposal or retirement of an asset is determined as the difference between the sales proceeds and the carrying amount of the asset and is recognised in the statement of comprehensive income for the relevant period.  Where exploration licences are relinquished or exited for no consideration or costs incurred are neither de-risking nor adding value to the asset, the associated costs are expensed to the income statement.  Impairment testing of oil and gas assets is considered in the context of each cash generating unit. A cash generating unit is generally a licence, with the discounted value of the future cash flows of the CGU compared to the book value of the relevant assets and liabilities. As an example, the Tawke CGU is comprised of the Tawke RSA intangible asset, property, plant and equipment (relating to both the Tawke field and the Peshkabir field) and the associated decommissioning provision.  Subsequent costs The cost of replacing part of an item of property and equipment is recognised in the carrying amount of the item if it is probable that the future economic benefits embodied within the part will flow to the Company, and its cost can be measured reliably. The net book value of the replaced part is expensed. The costs of the day-to-day servicing and maintenance of property, plant and equipment are recognised in the statement of comprehensive income.  Business combinationsThe 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.  Leases Leases in which a significant portion of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Payments made under operating leases (net of any incentives received from the lessor) are expensed to the statement of comprehensive income on a straight-line basis over the period of the lease.     Financial assets and liabilities The Company adopted IFRS 9 Financial Instruments, for the year commencing 1 January 2018. IFRS 9 addresses the classification, measurement and recognition of financial assets and financial liabilities. IFRS 9 replaces IAS 39 Financial instruments: Recognition and measurement.  The transition from IAS 39 to IFRS 9 does not have a significant impact on the financial statements and no adjustment has been recognised in the opening reserves at 1 January 2018.  Changes in the Company's accounting policies resulting from the adoption of IFRS 9 are set out under the subheadings below.  Classification The Company assesses the classification of its financial assets on initial recognition at amortised cost, fair value through other comprehensive income or fair value through profit and loss. The Company assesses the classification of its financial liabilities on initial recognition at either fair value through profit and loss or amortised cost.  Recognition and measurement Regular purchases and sales of financial assets are recognised at fair value on the trade-date - the date on which the Company commits to purchase or sell the asset. Trade and other receivables, trade and other payables, borrowings and deferred contingent consideration are subsequently carried at amortised cost using the effective interest method.  The impact of adoption of IFRS 9 on financial instrument classification and measurement is shown in the table below. Â
 Trade and other receivables Trade receivables are amounts due from crude oil sales, sales of gas or services performed in the ordinary course of business. If payment is expected within one year or less, trade receivables are classified as current assets otherwise they are presented as non-current assets. Trade receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method, less provision for impairment. The Company's assessment of impairment model based on expected credit loss is explained below.  Cash and cash equivalents In the consolidated balance sheet and consolidated statement of cash flows, cash and cash equivalents includes cash in hand, deposits held on call with banks, other short-term highly liquid investments and includes the Company's share of cash held in joint operations.  Interest-bearing borrowings Borrowings are recognised initially at fair value, net of any discount in issuance and transaction costs incurred. Borrowings are subsequently carried at amortised cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the statement of comprehensive income over the period of the borrowings using the effective interest method.  Fees paid on the establishment of loan facilities are recognised as transaction costs of the loan to the extent that it is probable that some or all of the facility will be drawn down. In this case, the fee is deferred until the draw-down occurs. To the extent there is no evidence that it is probable that some or all of the facility will be drawn down, the fee is capitalised as a pre-payment for liquidity services and amortised over the period of the facility to which it relates.  Borrowings are presented as long or short-term based on the maturity of the respective borrowings in accordance with the loan or other agreement. Borrowings with maturities of less than twelve months are classified as short-term. Amounts are classified as long-term where maturity is greater than twelve months. Where no objective evidence of maturity exists, related amounts are classified as short-term.  Trade and other payables Trade and other payables are recognised initially at fair value. Subsequent to initial recognition they are measured at amortised cost using the effective interest method.  Offsetting Financial assets and liabilities are offset and the net amount reported in the balance sheet when there is a legally enforceable right to offset the recognised amounts and there is an intention to settle on a net basis or realise the asset and settle the liability simultaneously.  Provisions Provisions are recognised when the Company has a present obligation as a result of a past event, and it is probable that the Company will be required to settle that obligation. Provisions are measured at the Company's best estimate of the expenditure required to settle the obligation at the balance sheet date, and are discounted to present value where the effect is material. The unwinding of any discount is recognised as finance costs in the statement of comprehensive income.  Decommissioning Provision is made for the cost of decommissioning assets at the time when the obligation to decommission arises. Such provision represents the estimated discounted liability for costs which are expected to be incurred in removing production facilities and site restoration at the end of the producing life of each field. A corresponding cost is capitalised to property, plant and equipment and subsequently depreciated as part of the capital costs of the production facilities. Any change in the present value of the estimated expenditure attributable to changes in the estimates of the cash flow or the current estimate of the discount rate used are reflected as an adjustment to the provision.  Impairment Oil and gas assets The carrying amounts of the Company's oil and gas assets are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists then the asset's recoverable amount is estimated. The recoverable amount of an asset or cash generating unit is the greater of its value in use and its fair value less costs of disposal. For value in use, the estimated future cash flows arising from the Company's future plans for the asset are discounted to their present value using a nominal post tax discount rate that reflects market assessments of the time value of money and the risks specific to the asset. For fair value less costs of disposal, an estimation is made of the fair value of consideration that would be received to sell an asset less associated selling costs (which are assumed to be immaterial). Assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (cash generating unit).  The estimated recoverable amount is then compared to the carrying value of the asset. Where the estimated recoverable amount is materially lower than the carrying value of the asset an impairment loss is recognised. Non-financial assets that suffered impairment are reviewed for possible reversal of the impairment at each reporting date.  Property, plant and equipment and intangible assets Impairment testing of oil and gas assets is explained above. When impairment indicators exist for other non-financial assets, impairment testing is performed based on the higher of value in use and fair value less costs of disposal. The Company assets' recoverable amount is determined by fair value less costs of disposal.    Financial assets IFRS 9 introduces a forward-looking impairment model based on expected credit losses (ECLs) of financial assets. The standard requires the Company to book an allowance for ECLs for its financial assets.  The Company has assessed impact of the new requirement on its trade receivables as at 31 December 2018, which are expected to be collected in 2019 under the normal operating cycle. For the contracts under IFRS 15 with no significant financing component, allowance is provided for lifetime ECLs of the financial asset. The model calculates net present value of outstanding receivables discounted by the discount rate, for a range of possible scenarios including short and mid-term delays and no payment with a probability assigned to each, and determines the ECL as the weighted average of these scenarios. The Company uses both past track record of receivables, information available until the reporting date and future expected performance. The result of the Company's assessment is that the effect of the ECL on the financial statements is not determined to be material and no amount is recorded in the accounts.  For the year ended 31 December 2017, no bad debt provision was recorded against trade receivables and therefore the changes from the incurred credit loss model under IAS 39 to the expected credit loss model under IFRS 9 has no significant impact to the Company's financial statements.  A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimate of future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortised cost is calculated as the difference between its carrying amount, and the present value of the estimated future cash flows discounted at the original effective interest rate. All impairment losses are recognised as an expense in the statement of comprehensive income. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognised.  Share capital Ordinary shares are classified as equity.  Employee benefits Short-term benefits Short-term employee benefit obligations are expensed to the statement of comprehensive income as the related service is provided. A liability is recognised for the amount expected to be paid under short-term cash bonus or profit-sharing plans if the Company has a present legal or constructive obligation to pay this amount as a result of past service provided by the employee and the obligation can be estimated reliably.  Share-based payments The Company operates a number of equity-settled, share-based compensation plans. The economic cost of awarding shares and share options to employees is recognised as an expense in the statement of comprehensive income equivalent to the fair value of the benefit awarded. The fair value is determined by reference to option pricing models, principally Monte Carlo and adjusted Black-Scholes models. The charge is recognised in the statement of comprehensive income over the vesting period of the award.  At each balance sheet date, the Company revises its estimate of the number of options that are expected to become exercisable. Any revision to the original estimates is reflected in the statement of comprehensive income with a corresponding adjustment to equity immediately to the extent it relates to past service and the remainder over the rest of the vesting period.  Finance income and finance costs Finance income comprises interest income on cash invested, foreign currency gains and the unwind of discount on any assets held at amortised cost. Interest income is recognised as it accrues, using the effective interest method.  Finance expense comprises interest expense on borrowings, foreign currency losses and discount unwind on any liabilities held at amortised cost. Borrowing costs directly attributable to the acquisition of a qualifying asset as part of the cost of that asset are capitalised over the respective assets.  Taxation 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 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. Current tax expense is incurred on the profits of the Turkish and UK services companies.  Segmental reporting IFRS 8 requires the Company to disclose information about its business segments and the geographic areas in which it operates. It requires identification of business segments on the basis of internal reports that are regularly reviewed by the CEO, the chief operating decision maker, in order to allocate resources to the segment and assess its performance.  Related parties Parties are related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the party in making financial or operational decisions. Parties are also related if they are subject to common control. Transactions between related parties are transfers of resources, services or obligations, regardless of whether a price is charged and are disclosed separately within the notes to the consolidated financial information.  New standards The new accounting standards and amendments to existing standards have been adopted by the Company effective 1 January 2018: IFRS 15 - Revenue from Contracts with Customers, IFRS 9 - Financial Instruments, Amendments to IFRS 2, Amendments to IAS 40 and IFRIC 22 Foreign Currency Transactions and Advance Consideration. The adoption of IFRS 15 and IFRS 9 are further explained under the changes in accounting policies heading. Amendments to IFRS 2, Amendments to IAS 40 and IFRIC 22 Foreign Currency Transactions and Advance Consideration have no impact to the financial statements as at 31 December 2018.  IFRS 16 - Leases, which becomes 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 is not considering early application of the Standard. The Company's leases are mostly low value or short term in nature. Had the Company early adopted the standard, it is estimated that the assets and liabilities would increase by $2m and income statement would be debited net by $0.1m as at 31 December 2018.  The following new accounting standards, amendments to existing standards and interpretations have been issued and endorsed by the EU but are not yet effective: Amendments to IFRS 9 Financial Instruments (effective 1 January 2019), Amendments to IAS 28 - Investments in Associates and Joint Ventures (effective 1 January 2019) and IFRIC 23 - Uncertainty over Income Tax Treatments (effective 1 January 2019). None of these standards have been early adopted.  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: Annual Improvements to IFRS Standards 2015-2017 (effective 1 January 2019), Amendments to IAS 19 - Plan Amendment, Curtailment or Settlement (effective 1 January 2019)and Amendment to IFRS 3 Business Combinations (effective 1 January 2020). None of these standards have been early adopted.  Changes in accounting policies Revenue recognition under IFRS 15 - Revenue from Contracts with Customers - requires a 5 step approach which is defined as the identification of the contract with the customer, performance obligations, transaction price, allocation of price into performance obligations and revenue recognition when the conditions are met. The Company's performance obligation in its contract with the single customer is the delivery of crude oil at a netback adjustment to dated Brent and the control is transferred to the buyer at the metering point when the revenue is recognised. Transition to IFRS 15 resulted in no adjustment to the measurement of the Company's previous year revenue in its financial statements.  Transition to IFRS 9 - Financial Instruments - introduced two significant changes that may have effect on the Company financial statements which are derecognition of financial liabilities and the change from incurred credit loss model to the expected credit loss model for financial assets. The Company's accounting treatment of the bond buyback for the year ended 31 December 2017 was in line with the requirements of IFRS 9 hence no transitional adjustments were made. In applying IFRS 9 on trade receivables as set out above, the expected credit loss under the new standard is not determined to be material. 2. 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. '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 2018
Revenue from contracts with customers includes $105.4 million (2017: $33.9 million) arising from the ORRI. The ORRI will expire at the end of July 2022 and is explained further under significant accounting estimates and judgements under the Tawke RSA intangible asset. Total assets and liabilities in the other segment are predominantly cash and debt balances. Â Â Â For the period ended 31 December 2017
  Total assets and liabilities in the other segment are predominantly cash and debt balances. Â
   5. Finance expense and incomeÂ
 Bond interest payable is the cash interest cost of Company bond debt. In 2018, unwind of discount on liabilities primarily relates to the discount unwind on the bond (note 15) and on the asset retirement obligation provision (note 14). In 2017, the Company extended the maturity of $300.0 million of its bonds and redeemed bonds with a nominal value of $121.8 million. This resulted in the derecognition of the existing debt balance and recognition of an expense of $19.7 million, comprised of $3.7 million relating to the premium paid and $16.0 million accelerated discount unwind.   6. Income tax expense Current tax expense is incurred on the profits of the Turkish and UK services companies. Under the terms of the KRI PSCs, the Company is not required to pay any cash corporate income taxes as explained in note 1.   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. Â
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: Â
1 Excluding shares held as treasury shares          8. Intangible assets
 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: $116.2 million, 2017: $535.3 million) and Bina Bawi (book value: $338.7 million, 2017: $323.1 million) gas assets. The remaining balance is comprised of Somaliland asset (book value: $33.0 million 2017: $32.0 million). The Miran PSC has been impaired by $424.0 million - further explanation is provided in note 1.  Tawke RSA assets are comprised of the ORRI (book value: $217.5 million 2017: $269.8 million) and CBP waiver (book value: $112.7 million 2017: $122.5 million), 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
        9. Property, plant and equipment
 Development assets are the Company's investments in the Tawke PSC (book value: $478.2 million, 2017: $477.8 million) and the Taq Taq PSC (book value: $86.9 million, 2017: $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
  10. Trade and other receivables
 Trade receivables are amounts owed for the revenue from contracts with customers. The Company reports trade receivables net of any capacity building payables (2018: $1.9 million 2017: $1.5 million).  Ageing of trade receivables 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 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. Â
Â
  Movement on trade receivables in the period
  11. Cash and cash equivalents and restricted cash
 Cash is primarily held on time deposit with major financial institutions or in US Treasury. Restricted cash of $10.0 million relates principally to exploration activities in Morocco.          12. Trade and other payables
Payables are predominantly short-term in nature or are repayable on demand and, as such, for these payables there is minimal difference between contractual cash flows related to the financial liabilities and their carrying amount.  Contingent consideration includes a balance of $68.5 million (2017: $60.5 million) recognised at its discounted fair value using the effective interest rate, which has been added to the book value of Bina Bawi intangible asset. The nominal value of this balance is $145.0 million and its payment is contingent on gas production at the Bina Bawi and Miran assets meeting a certain volume threshold. The unwind of the discount is capitalised against the relevant intangible assets.  Refer to note 10 for the details of the offset of the capacity building payables with trade receivables.   13. Deferred income
 14. Provisions
Provisions cover expected decommissioning and abandonment costs arising from the Company's assets. The decommissioning and abandonment provision is based on the Company's best estimate of the expenditure required to settle the present obligation at the end of the period discounted at 4%. The cash flows relating to the decommissioning and abandonment provisions are expected to occur between 2031 and 2038. Â Â 15. Borrowings and net debt / (net cash)
 The fair value of the bonds is $308.3 million (2017: $293.6 million). Â
 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.  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 IFRS 9 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.   16. Financial Risk Management Credit risk Credit risk arises from cash and cash equivalents, trade and other receivables and other assets. The carrying amount of financial assets represents the maximum credit exposure. The maximum credit exposure to credit risk at 31 December was:
 Credit risk for trade receivables is explained in note 1 and relates to there being a single customer. There are no receivables overdue at the period end and no allowance is made under the expected credit loss model as explained at note 1. Cash is deposited in US treasury bills or term deposits with banks that are assessed as appropriate based on, among other things, sovereign risk, CDS pricing and credit rating. Credit risk is managed on Company basis.  Liquidity risk The Company is committed to ensuring it has sufficient liquidity to meet its payables as they fall due. At 31 December 2018 the Company had cash and cash equivalents of $334.3 million (2017: $162.0 million).  Oil price risk The Company's revenues are calculated from Dated Brent oil price, and a $5/bbl change in average Dated Brent would result in a profit before tax change of circa $24 million. Sensitivity of the carrying value of its assets to oil price risk is provided in notes 8 and 9.  Currency risk As substantially all of the Company's transactions are measured and denominated in US dollars, the exposure to currency risk is not material and therefore no sensitivity analysis has been presented.  Interest rate risk The Company reported borrowings of $297.3 million (2017: $296.8 million) in the form of a bond maturing in December 2022, with fixed coupon interest payable of 10% on the nominal value of $300 million. Although interest is fixed on existing debt, whenever the Company wishes to borrow new debt or refinance existing debt, it will be exposed to interest rate risk. A 1% increase in interest rate payable on a balance similar to the existing debt of the Company would result in an additional cost of $3 million per annum.  Capital management The Company manages its capital to ensure that it remains sufficiently funded to support its business strategy and maximise shareholder value. The Company's short term funding needs are met principally from the cash flows generated from its operations and available cash of $334.3 million (2017: $162.0 million).  17. Share capital
1Ordinary shares includes 1,005,839 (2017: 1,234,474) treasury shares  There have been no changes to the authorised share capital since it was determined to be 10,000,000,000 ordinary shares of £0.10 per share.  18. Share based payments  The Company has three share-based payment plans: a performance share plan, restricted share plan and a share option plan. The main features of these share plans are set out below. Â
 In 2018, awards were made under the performance share plan and restricted share plan, no awards were made under the share option plan, the numbers of outstanding shares under the PSP, RSP and SOP as at 31 December 2018 are set out below: Â
The range of exercise prices for share options outstanding at the end of the period is 621.15p to 1,046.00p. The weighted average remaining contractual life of the outstanding share options is 2 years. Â Fair value of options granted has been measured either by use of the Black-Scholes pricing model or by use of a formula based on past calculations. The model takes into account assumptions regarding expected volatility, expected dividends and expected time to exercise. In the absence of sufficient historical volatility for the Company, expected volatility was estimated by analysing the historical volatility of FTSE-listed oil and gas producers over the three years prior to the date of grant. The expected dividend assumption was set at 0%. The risk-free interest rate incorporated into the model is based on the term structure of UK Government zero coupon bonds. The inputs into the fair value calculation for RSP and PSP awards granted in 2018 and fair values per share using the model were as follows:
 The weighted average fair value for PSP awards granted in the period is 137p and for RSP awards granted in the period is 180p.  Total share based payment charge for the year was $6.3 million (2017: $5.4 million).  19. 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 office facilities under operating leases. During the period ended 31 December 2018 $1.4 million (2017: $1.2 million) was expensed to the statement of comprehensive income in respect of these operating leases.  Drill rig contracts are service contracts where contractors provide the rig together with the services and the contracted personnel on a day-rate basis for the purpose of drilling exploration or development wells. The Company has no right of use of the rigs itself. 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.     20. Related parties  The directors have identified related parties of the Company under IAS24 as being: the shareholders; members of the Board; and members of the executive committee, together with the families and companies, associates, investments and associates controlled by or affiliated with each of them. The compensation of key management personnel including the directors of the Company is as follows: Â
 There are no other significant related party transactions.  21. Events occurring after the reporting period  The Company has reached agreement to acquire 30% equity of the Sarta PSC and 40% equity of the Qara Dagh PSC, both of which are located in the KRI and are exploration and appraisal assets.  22. Subsidiaries and joint arrangements  The Company has two joint arrangements in relation to its producing assets Taq Taq and Tawke. The Company holds 44% working interest in Taq Taq PSC and owns 55% of Taq Taq Operating Company Limited. The Company holds 25% working interest in Tawke PSC which is operated by DNO ASA.  For the period ended 31 December 2018 the principal subsidiaries of the Company were the following: Â
 1 Registered office is 12 Castle Street, St Helier, Jersey JE2 3RT 2 Registered office is Fifth floor, 36 Broadway, London SW1H 0DB 3 Registered office is Prins Bernhardplein 200, 1097 JB, Amsterdam, Netherlands 4 Registered office is PO Box 1338. Maico Building, The Valley, Anguilla 5 3rd Floor, Geneva Place, Waterfront Drive, PO Box 3175, Road Twon, Tortola, BVI and is a joint operation service company through which the Company jointly operates the Taq Taq PSC with its partner 6 Registered office is PO box 309 Ugland House, Grand Cayman, KY1-1104, Cayman Islands 7 Registered office is Next Level İş Merkezi, Eskişehir Yolu, Dumlupınar Bulvarı, No:3A-101, Söğütözü, Ankara, 06500, Turkey 8Registered office is 6 Hope Street, Castletown, IM9 1AS, Isle of Man 9 Registered office is 7 Boulevard Latrille Cocody, 25 B.P. 945 Abidjan 25, Cote d'Ivoire 10Registered office is PO Box 146, Road Town, Tortola, BVI 11Registered office is Fifth floor, 36 Broadway, London SW1H 0BH  23. Annual report  Copies of the 2018 annual report will be despatched to shareholders in April 2019 and will also be available from the Company's registered office at 12 Castle Street, St Helier, Jersey JE2 3RT and at the Company's website - www.genelenergy.com.  24. Statutory financial statements  The financial information for the year ended 31 December 2018 contained in this preliminary announcement has been audited and was approved by the board on 21 March 2019. The financial information in this statement does not constitute the Company's statutory financial statements for the years ended 31 December 2018 or 2017. The financial information for 2018 and 2017 is derived from the statutory financial statements for 2017, which have been delivered to the Registrar of Companies, and 2018, which will be delivered to the Registrar of Companies and issued to shareholders in April 2019. The auditors have reported on the 2018 and 2017 financial statements; their report was unqualified and did not include a reference to any matters to which the auditors drew attention by way of emphasis without qualifying their report. The statutory financial statements for 2018 are prepared in accordance with International Financial Reporting Standards (IFRS) as adopted for use in the European Union. The accounting policies (that comply with IFRS) used by Genel Energy plc are consistent with those set out in the 2017 annual report.  |
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| ISIN: | JE00B55Q3P39 |
| Category Code: | FR |
| TIDM: | GENL |
| LEI Code: | 549300IVCJDWC3LR8F94 |
| Sequence No.: | 7869 |
| EQS News ID: | 789463 |
| Â | |
| End of Announcement | EQS News Service |
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