DJ Genel Energy PLC: Half-Year Results
Genel Energy PLC (GENL) Genel Energy PLC: Half-Year Results 06-Aug-2020 / 07:00 GMT/BST Dissemination of a Regulatory Announcement that contains inside information according to REGULATION (EU) No 596/2014 (MAR), transmitted by EQS Group. The issuer is solely responsible for the content of this announcement. 6 August 2020 Genel Energy plc Unaudited results for the period ended 30 June 2020 Genel Energy plc ('Genel' or 'the Company') announces its unaudited results for the six months ended 30 June 2020. Bill Higgs, Chief Executive of Genel, said: "Genel's robust business model, which is designed to provide resilience in a challenging environment, has demonstrated its value as the Company negotiates the headwinds facing the sector in 2020. Our low-cost production and the capital flexibility within our development programme have enabled us to preserve the strength of our balance sheet even while investing in growth. Given the lower oil price and overdue payments, the fact that we still expect to end 2020 in a net cash position - even after dividend distributions and making the investment to bring Sarta to production this year - is a testament to our resilience, and we have today confirmed an interim dividend of 5¢ per share." Results summary ($ million unless stated) H1 2020 H1 2019 FY 2019 Production (bopd, working interest) 32,100 37,400 36,250 Revenue 88.4 194.3 377.2 EBITDAX1 65.1 167.3 321.8 Depreciation and amortisation (82.6) (74.8) (158.5) Exploration expense (1.3) (0.6) (1.2) Impairment of oil and gas assets (286.3) - (29.8) Impairment of trade receivables (34.9) - - Operating (loss) / profit (340.0) 91.9 132.3 Underlying (loss) / profit2 (32.2) 76.6 134.9 Cash flow from operating activities 85.5 142.3 272.9 Capital expenditure 58.5 72.2 158.1 Free cash flow3 6.5 56.7 99.0 Dividends paid 41.3 27.4 27.4 Cash4 355.3 353.3 390.7 Total debt 300.0 300.0 300.0 Net cash5 57.2 55.8 92.8 Basic EPS (¢ per share) (128.9) 27.2 37.8 Underlying EPS (¢ per share)2 (11.7) 27.4 49.0 Average Brent oil price ($/bbl) 40 65 64 1) EBITDAX is operating (loss) /profit adjusted for the add back of depreciation and amortisation ($82.6 million), exploration expense ($1.3 million), impairment of property, plant and equipment ($242.0 million), impairment of intangible assets ($44.3 million) and impairment of trade receivables ($34.9 million). 2) Underlying EPS is underlying profit (page 9) divided by weighted average number of shares 3) Free cash flow is reconciled on page 10 4) Cash reported at 30 June 2020 excludes $3.1 million of restricted cash, and takes into account the dividend paid in June 5) Reported cash less IFRS debt (page 10) Highlights · Cash of $355 million at 30 June 2020 ($353 million at 30 June 2019) · Net cash of $57 million at 30 June 2020 (net cash of $56 million at 30 June 2019) · $110 million received from the Kurdistan Regional Government ('KRG') in H1 2020 · Updated payment mechanism introduced in April, under which the KRG committed to settling monthly sales invoices by the middle of the following month · $121 million remains outstanding in relation to oil sales from November 2019 to February 2020 - discussions continue with the KRG over settlement arrangements · Despite the monies outstanding, the fall in oil price and non-payment of the override, $6.5 million of free cash flow was generated in H1 2020 due to Genel's low-costs and resilient business model allowing flexible expenditure · Production cost of $2.9/bbl in H1 2020 · Capital expenditure of $58.5 million in H1 as spending cut due to the external environment · G&A costs of $6.6 million, a reduction of c.30% year-on-year, as activity is rephased · Production of 32,100 bopd in H1 2020, due in part to the impact of COVID-19, coupled with payment uncertainty, resulting in reduced drilling activity at the Tawke PSC · Production averaged 33,000 bopd in July 2020, following fast tracking of activity at the Tawke PSC against an improved backdrop · Continued focus on safety: zero lost time incidents and zero losses of primary containment in the period · Impairments of $286 million largely due to reduction in Brent oil price forecast · Interim dividend of 5¢ per share confirmed (2019: 5¢ per share) Outlook · Genel's low-cost production, flexible capital investment programme, and robust balance sheet makes it resilient to lower oil prices, and the Company expects to retain a net cash position at the end of 2020 at the prevailing oil price, while still investing in key growth assets · Capex of c.$45 million expected in H2, with c.50% to be spent on moving Sarta to production in Q4, where work has continued despite the challenges resulting from COVID-19 · Genel continues discussions with the KRG regarding the recovery of the $121 million receivable Enquiries: Genel Energy +44 20 7659 5100 Andrew Benbow, Head of Communications Vigo Communications +44 20 7390 0230 Patrick d'Ancona There will be a presentation for analysts and investors today at 0900 BST, with an associated webcast available on the Company's website, www.genelenergy.com [1]. This announcement includes inside information. Disclaimer This announcement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil & gas exploration and production business. Whilst the Company believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to factors beyond the Company's control or within the Company's control where, for example, the Company decides on a change of plan or strategy. Accordingly, no reliance may be placed on the figures contained in such forward looking statements. The information contained herein has not been audited and may be subject to further review. CEO STATEMENT No natural resources company has been immune from the impacts of COVID-19 and the resulting collapse in demand and fall in the oil price. In the face of this material change in circumstances, we focused on controlling what is within our power to control in the near-term, while continuing to build the business fit for a future of fewer and better natural resources projects in the long-term. In this regard our business model positions us well both now, as we have a strong balance sheet and limited fixed capital expenditure, and for the future. We have a business model designed for tough times, and we moved quickly to rebase our spending appropriately for the external environment, reducing our full-year capital expenditure forecast by c.$75 million to just over $100 million, and continuing to focus on managing costs elsewhere in the business. Given the external environment, we continued to allocate capital to those areas that can provide the greatest returns and deliver shareholder value. Due to the oil price and lack of certainty over the deferred receivable and override payments, investing at Taq Taq is not currently a priority, and work at Tawke has the ability to rapidly scale up as the external environment improves. Despite the reduction in investment, production from Tawke has been in line with internal expectations, and the significant increase in production in July is an encouraging illustration of what can be achieved once investment resumes. The key focus of capital allocation in 2020 has been Sarta, where work is continuing along a critical path to production in Q4. Genel is already the only multi-licence producer in the KRI, and further diversifying production by bringing Sarta into production with its tremendous growth potential is a milestone that we are all looking forward to reaching. It is a testament to our balance sheet and careful financial management that, even with $121 million outstanding from the KRG for production in November 2019 to February 2020 and override payments unpaid, we are able to continue allocating capital to direct returns to shareholders, and our interim dividend of 5¢ per share has been retained. While the mechanism through which the receivable from the KRG will be recovered has yet to be finalised, we are confident that a solution that works for both parties will be found, as has been done in the past, and our discussions with the KRG continue. ESG As the external environment has deteriorated due to COVID-19, it has not lessened our focus on ESG. The safety of our workforce and contractors remains a key priority, and we are pleased to continue our record of not having a lost-time injury since 2015. We are also working hard on improving our ESG activities, and better communicating the things that we already do well. We recognise that we have a long way to go, but are proud of our track record in the KRI, where we have aimed to have a positive impact ever since our operations started almost 15 years ago. In this time, we have funded and
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DJ Genel Energy PLC: Half-Year Results -2-
successfully delivered 245 social investment and community projects, spending almost $60 million. In the first half of the year we have become a member of both Transparency International UK and TRACE, and become a signatory of the United Nations Global Compact, supporting our aim of being a socially responsible contributor to the global energy mix. Our sustainability report, due in September, will provide further detail and enhanced disclosure on all ESG aspects. OPERATING REVIEW The impact of COVID-19 led to a significant reduction in activity in 2020. By this point of the year, we were expecting to have continued an active drilling programme at Tawke and Peshkabir, to be drilling at Qara Dagh, and for Sarta to be advancing towards production. The fall in the oil price and the delay in receipt of payments from the KRG, resulted in an appropriate reduction in expenditure at the Tawke PSC, while the direct impact of COVID-19 on supply chains and the movement of people into the KRI forced us to notify the KRG of the occurrence of a force majeure event preventing the Company from being able to perform its contractual obligations as scheduled at Qara Dagh. Work has continued at Sarta, our key capital allocation priority in 2020, and despite the challenges faced initial production is still expected later this year. Production In line with internal expectations given the updated work plan. (bopd) Gross Net Gross Net production production production production H1 2020 H1 2020 H1 2019 H1 2019 Tawke 59,790 14,950 71,700 17,920 Peshkabir 48,790 12,200 54,950 13,740 Taq Taq 11,260 4,950 13,150 5,780 Total 119,840 32,100 139,800 37,440 PRODUCING ASSETS Tawke PSC (25% working interest) Gross production from the Tawke licence averaged 108,580 bopd during the first half of 2020, and 102,000 bopd during the second quarter of the year, as the operator halted development activity to preserve cash at a time of historically low and uncertain oil prices. In June 2020, following the stabilisation of oil prices and export payments, activity was fast tracked at the Tawke licence and production quickly increased by 15,000 bopd month-on-month to raise average July 2020 production to 115,000 bopd. The Peshkabir-to-Tawke gas reinjection project (the first enhanced oil recovery project in the KRI) was commissioned in June, and aims to unlock additional oil reserves at Tawke while significantly reducing gas flaring and CO2 emissions at Peshkabir. Taq Taq (44% working interest, joint operator) Production at Taq Taq averaged 11,260 bopd in H1, in line with expectations given the activity plan. As has been the case for some time, activity at Taq Taq is focused on maximising cash generation and, given the oil price, the TT-35 well, which completed in April, was the only well in the 2020 drilling programme. This well initially added c.600 bopd to production, but is no longer producing, following a mechanical issue. Activity at the field will remain appropriate for the external environment and aligned with our capital allocation priorities, and it is not expected that there will be any further drilling activity in 2020. PRE-PRODUCTION ASSETS Sarta (30% working interest) Despite the significant operational challenges caused by COVID-19, including the closure of borders impacting supply chains and the movement of people into the KRI, work has continued at Sarta, and first oil remains on target for Q4 this year. Civil construction work at the field is materially complete, with remaining work now focussing on the completion and commissioning of the 20,000 bopd capacity early-production facility. Production will begin following the recompletion of the Sarta-2 well, re-entry of the Sarta-3 well, and commissioning of the facility through which oil will be produced and processed ahead of tanker loading and transport to the export pipeline at Khurmala. With first oil now in sight, plans are well underway for the next stage of the phase 1A pilot development, an appraisal programme which aims to fully utilise the facility capacity and convert more of the 253 MMbbls of gross resources assigned by ERCE to the Mus-Adaiyah-Butmah reservoirs into reserves. A three well campaign is scheduled for 2021, with environmental baselining underway ahead of construction of the well pads, in line with the previously announced schedule. The first of these wells, S-6, is expected to spud in Q1 and will be followed immediately by the S-1D well. While focussing on the primary Mus-Adaiyah-Butmah reservoirs these wells are also set to target additional reservoir intervals, a cost-efficient way to maximise the gathering of information which will help inform the Company's view of the wider potential of Sarta. In order to minimise the time between appraisal success and monetisation the field partners are investigating a range of options for oil production from these 2021 wells. Qara Dagh (40% working interest, operator) Due to ongoing uncertainty caused by COVID-19, Genel notified the KRG of the occurrence of a force majeure event preventing the Company from being able to perform its contractual obligations as scheduled. Work continues to take place to ensure that Genel is in the best possible position to start to drill the QD-2 well once external conditions improve and the force majeure event ceases. This has included the securing of an amendment to the rig contract with Parker, in expectation of the future lifting of the force majeure event, while from a community engagement perspective emergency food aid has been provided to vulnerable groups within the Qara Dagh community, and the construction of firebreaks in nearby agricultural land have been funded. Bina Bawi and Miran (100% working interest, operator) As previously stated, Genel received documentation from the KRG in mid-April, and then further documents were received in June. This documentation did not adequately reflect the commercial concepts and risk sharing that were expected for the development of Bina Bawi's gas and oil resources. Discussions are now taking place with the KRG at the highest level as Genel seeks to progress the development of Bina Bawi. African exploration A farm-out process relating to the highly prospective SL10B13 block (100% working interest and operator) in Somaliland began in Q4 2019 and while conditions for farm-out have been challenging in the first half of 2020, a number of companies continue to engage with the Company with respect to the opportunity. Regarding Morocco, and the Lagzira block (75% working interest and operator), despite the logistical challenges posed by COVID-19 having caused some delay to the completion of the 3D seismic processing project being carried out by Western Geco, Genel continues to work towards a future farm-out campaign aimed at bringing a partner onto the licence prior to considering further commitments. FINANCIAL REVIEW Overview The impact of COVID-19 has been significant. The resulting drop in oil demand exacerbated the fall in oil price this year, which deteriorated from around $60/bbl at the start of 2020 to a low of under $20/bbl in April. Although the oil price has since improved, there remains significant uncertainty as to how COVID-19 and its aftermath will impact economies, oil demand and therefore oil price over the near and mid-term. This has caused significant economic pressure on the KRG's finances, pressure that has manifested itself in two ways: firstly, the deferral of payments owed by the KRG for sales made in the four months from November 2019 to February 2020 inclusive, amounting to $121 million; secondly, the non-payment of the Tawke override royalty from 1 March 2020. It is clear that macro-economic uncertainty will extend into 2021 and likely beyond, creating a challenging backdrop against which to progress our business and seek to deliver on our commitment to run a business that is resilient to downside scenarios, is cash generative, and delivers growth when other oil and gas companies cannot. All of the above means that the Company's business model, developed over the past few years to be profitable at low prices and resilient at very low prices, has been tested on its ability to: · Progress value creative growth projects in a challenging environment; · Demonstrate material flexibility in capital allocation, supporting the generation of free cash flow even at low oil prices; · Pay a dividend. Our assessment is that our business model has stood up well to the challenge. Much of the hard work done in previous years has positioned us well: costs have had previous scrutiny so required optimisation rather than a radical overhaul; and asset development plans had been set up within a high capital flexibility model that mitigates financial risk, optimises cash generation and expedites capital return and payback, so we were able to adapt plans to the external environment. The table below summarises our financial performance in the first half of 2020 (all figures $ million unless stated): H1 2020 H1 2019 FY 2019
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DJ Genel Energy PLC: Half-Year Results -3-
Brent average oil price $40/bbl $65/bbl $64/bbl Revenue 88.4 194.3 377.2 Opex (16.8) (18.1) (37.7) G&A (excl. depreciation and (6.5) (8.9) (17.7) amortisation) EBITDAX 65.1 167.3 321.8 Producing asset capex (35.7) (53.3) (115.1) Net cash interest1 (13.4) (12.6) (23.4) Surplus before growth capex and dividend 16.0 101.4 183.3 Development capex (11.5) (11.3) (22.1) Exploration and appraisal capex (11.3) (7.6) (20.9) (Deficit) / Surplus (6.8) 82.5 140.3 Working capital and other 13.3 (25.8) (41.3) Free cash flow 6.5 56.7 99.0 1 Net cash interest is bond interest payable less bank interest income (note 5) · Our producing assets have delivered predictable production, and liquidity has been preserved by taking quick steps to materially reduce capex to a level appropriate to the oil price · General and administration costs have been optimised · The capital needs for Sarta first oil had already been optimised in line with our business plan (low capital need, early cash generation), meaning that even in this financial environment, we have been able to continue to allocate capital to the project · Force majeure declared at Qara Dagh, but we have continued to invest where possible to position the project for a rapid and efficient restart once force majeure is lifted and operating conditions permit The overall result is that revenue generated in the period more than cover our costs, resulting in a surplus of $16.0 million before investment in growth. Our investment in growth projects, principally Sarta and Qara Dagh, reduced that surplus to a deficit for the period of $6.8 million, with working capital movements turning that deficit into a positive free cash flow of $6.5 million. This has enabled the Company to preserve its balance sheet strength, reporting net cash of $355 million. Despite not receiving $120.8 million due in the period, this is a reduction of only $22 million from the post-interim dividend cash number reported at 31 December 2019 of $377 million. Accounting impairments Despite the business model proving to be resilient in the first half, there has been a significant reduction in both near-term and long-term oil price forecasts, with the change from the assumptions used for the previous reporting period summarised in the table below: $/bbl 2020 2021 2022 2023 2024 Forecast 40 43 50 55 60 Year-end forecast 65 67 68 72 73 The decrease in oil price, and to a significantly lesser extent the increase in discount rate and deferral of some barrels into future periods as a result of reduced activity, has resulted in a significant decrease in the net present value of the Company's oil and gas assets. This has resulted in a total impairment of $286.3 million. In addition, there has been an impairment of $34.9 million to the $120.8 million nominal value of receivables owed by the KRG for sales made in the four months from November 2019 to February 2020. The net present value has been estimated for accounting purposes based on the initial communication from the KRG, which indicates repayment would commence once oil price is above $50/bbl. However, the mechanism for, and pace of, repayment has not yet been agreed, and Genel expects to receive the nominal balance owed of $120.8 million in full. Resilient financial strength - well positioned to take advantage of an unpredictable environment With cash of $355 million, producing asset cash flows that cover corporate and bond interest costs and fund pre-production investment, and Sarta expected to be on production by the end of the year, the Company is well positioned for 2021. Genel will be ready to capitalise if the macro-environment starts to improve, with a business that is already cash generative when investing in pre-production growth projects and with a material receivable balance expected to be recovered in line with the improvement in oil price. In a downside scenario our business model and financial strength provides us with an opportunity to take advantage both organically and inorganically: with potential to drill Qara Dagh at a lower cost than might have been expected, and the potential to acquire new assets that may become available due to the financial stress on less resilient businesses. Capital allocation and growth As set out above, our business model supports the preservation of our financial strength and has led us to generate cash even in a period with a low oil price and irregular receipts of payments. Looking forward, due to COVID-19 and the related oil price uncertainty, there remains a lack of clarity on the mechanism for the recovery of the $121 million of monies owed and the timing of the resumption of Tawke override payments. There is therefore uncertainty over the timing and value of very material cash inflows that were previously included in our base case near to mid-term liquidity planning scenarios. This emphasises the considerable extent to which our business model has been tested and how durable it has proved to be. However, the quantum of the uncertainty over timing of receipt of monies that we are contractually due is significant and means that there is a very wide range of liquidity outcomes ahead of us. The level of capital that is appropriate for the Company to commit to its capital allocation priorities depends on its confidence in the quantum and timing of future cash flows, and Genel constantly reviews its capital allocation plans, aiming to deliver the greatest returns and to preserve balance sheet strength. The Company has a portfolio that contains assets with material value creation possibilities, with discovered resource with the potential to add incremental value to the share price greater than the current market capitalisation of the Company. The higher our confidence in receipts, and dependent on operating conditions, the more pace can be brought to the development of these projects in the event that commercial, technical and operational conditions support investment. Dividend In 2019, our confidence in our business plan to replace and grow producing asset cash generation at value accretive cost was demonstrated by the commencement of a sustainable and material dividend, and $41 million was distributed to shareholders. The dividend remains a core part of our business model, which is focused on growth and the protection of financial strength. The financial strength of our business and the flexibility in our cost base enabled us to reaffirm the final dividend at our full-year 2019 results, and we have retained our interim dividend of 5¢ per share. Financial priorities and outlook The table below summarises our progress against the 2020 financial priorities of the Company as set out at our 2019 results. FY2020 financial priorities Progress · Maintaining our financial · Net cash expected to be strength through existing maintained at year-end at market conditions current oil price · Continued focus on capital · Despite COVID-19 bringing allocation, with material challenges: prioritisation of highest progression towards Sarta value investment in assets first oil in 2020 and with ongoing or near-term investment in Qara Dagh cash and value generation appraisal, once force majeure removed, remain our key capital allocation priorities · Delivery of a 2020 work · A recut 2020 work programme programme on time and on and budget preserving budget, that is appropriate liquidity and reducing costs to the external environment · We are reducing spend on controllable inputs · Continued focus on · Management continues to seek identifying and developing growth opportunities that fit additional assets that offer the Company's capital potential for significant structure and business model value to the Company with near to mid-term cash generation, primarily to further build the Company's cash generation options when the override royalty agreement ends in Q3 2022 and provide the basis for increasing the dividend in the future Our capital allocation philosophy remains the same, despite the recent fall in oil price - invest in those projects with the potential to create most shareholder value, targeting those assets that fit the criteria set out previously. In light of the likely macro volatility and uncertainty that lies ahead, in order to maximise our ability to move quickly and deploy capital to take advantage of prevailing conditions, the Board has decided to reverse its previous decision to comply with premium listing rules. The principal impact of this is that the Company will no longer apply chapter 10 of the Listing Rules with respect to classifying transactions (such as acquisitions and disposals) and so will have the benefit of being able to execute transactions more efficiently, a significant advantage in the current environment. See note 13 for more information.
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DJ Genel Energy PLC: Half-Year Results -4-
We will continue to be disciplined in our capital allocation and invest in areas that can deliver most shareholder value. Rigorous cost management will be maintained across all operations, ensuring spend is sufficient to take advantage of the growth opportunities in the portfolio, and to maximise (net present) value of the portfolio. A summary of the financial results for the year is provided below. Financial results for the period Income statement (all figures $ million) H1 2020 H1 2019 FY 2019 Production (bopd, working interest) 32,100 37,400 36,250 Profit oil 24.0 64.6 117.2 Cost oil 47.6 69.4 147.2 Override royalty 16.8 60.3 112.8 Revenue 88.4 194.3 377.2 Operating costs (16.8) (18.1) (37.7) G&A (excl. depreciation and (6.5) (8.9) (17.7) amortisation) EBITDAX 65.1 167.3 321.8 Depreciation and amortisation (82.6) (74.8) (158.5) Net interest (14.7) (15.5) (27.7) Income tax expense - (0.4) (0.7) Underlying (loss) / profit (32.2) 76.6 134.9 Impairment (321.2) - (29.8) Exploration expense (1.3) (0.6) (1.2) (Loss) / Profit (354.7) 76.0 103.9 Working interest production of 32,100 bopd decreased year-on-year (H1 2019: 37,400 bopd), principally as a result of lower average production from Peshkabir, with the decrease in revenue from $194.3 million to $88.4 million, principally caused by: · Lower Brent $62 million · Lower capex resulting in lower cost oil $21 million · Lower production $10 million · Override unpaid from March onwards $10 million Production costs of $16.8 million decreased from last period (H1 2019: $18.1 million) as a result of scaled back activity in producing assets. Production cost per barrel increased from $2.7/bbl to $2.9/bbl due to decreased production. General and administration costs were $6.6 million (H1 2019: $9.5 million), of which corporate cash costs were $4.9 million (H1 2019: $6.6 million). The reduction from the prior period is a result of optimisation of costs and increased operational activity, principally at Sarta and Qara Dagh. The decrease in revenue resulted in EBITDAX of $65.1 million (H1 2019: $167.3 million): 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. Underlying profit is presented in order to understand the profitability of the recurring business, excluding the impact of items that tend to be one off in nature, such as impairment and exploration expenditure. Depreciation of $51.6 million (H1 2019: $39.7 million) and Tawke intangibles amortisation of $30.9 million (H1 2019: $34.5 million) increased as a result of a combination of decrease in production profile and higher estimated future costs on the Tawke PSC (depreciation/bbl: $8.6/bbl (H1 2019: $5.8/bbl), noting that these costs are fully recoverable. An impairment expense of $254.7 million for Tawke CGU, $31.6 million for Taq Taq and $34.9 million for trade receivables was booked which is explained further in note 2 (H1 2019: nil). Bond interest expense of $15.0 million was in line with the prior period. Finance income of $1.6 million (H1 2019: $2.4 million) was bank interest income. Other finance expense of $1.3 million (H1 2019: $2.9 million) included a non-cash discount unwind expense on liabilities. In relation to taxation, under the terms of the KRI production sharing contracts, 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 was related to taxation of the service companies (H1 2020: nil, H1 2019: $0.4 million). Capital expenditure Capital expenditure is the aggregation of spend on production assets ($35.7 million) and pre-production assets ($22.8 million) and is reported to provide investors with an understanding of the quantum and nature of investment that is being made in the business. Capital expenditure for the period was $58.5 million, predominantly focused on production assets and the Sarta PSC ($11.5 million) and Qara Dagh ($4.4 million): (all figures $ million) H1 2020 H1 2019 FY 2019 Cost recovered production capex 35.7 53.3 115.1 Pre-production capex - oil 11.5 11.3 22.1 Pre-production capex - gas 5.9 5.6 11.9 Other exploration and appraisal capex 5.4 2.0 9.0 Capital expenditure 58.5 72.2 158.1 Cash flow, cash, net cash and debt Gross proceeds received was $110.0 million (H1 2019: $167.5 million), of which $22.9 million (H1 2019: $54.2 million) was received for the override royalty. (all figures $ million) H1 2020 H1 2019 FY 2019 Brent average oil price $40/bbl $65/bbl $64/bbl Operating cash flow 85.5 142.3 272.9 Producing asset cost recovered capex (38.1) (48.7) (105.1) Development capex (11.6) (9.4) (18.7) Exploration and appraisal capex (13.7) (12.2) (26.5) Restricted cash (0.1) - 7.0 Interest and other (15.5) (15.3) (30.6) Free cash flow 6.5 56.7 99.0 Free cash flow is presented in order to show the free cash generated that is available for the Board to invest in the business. The measure provides the reader a better understanding of the underlying business cash flows. Free cash flow before dividend was $6.5 million, with an overall decrease in cash of $35.4 million in the period (H1 2019: $19.0 million increase). (all figures $ million) H1 2020 H1 2019 FY 2019 Free cash flow 6.5 56.7 99.0 Dividend paid (incl. expenses) (41.3) (29.0) (29.0) Purchase of shares (0.7) (8.7) (13.5) Other 0.1 - (0.1) Net change in cash (35.4) 19.0 56.4 Opening cash 390.7 334.3 334.3 Closing cash 355.3 353.3 390.7 Debt reported under IFRS (298.1) (297.5) (297.9) Net cash / (debt) 57.2 55.8 92.8 Closing cash of $355.3 million and net cash of $57.2 million (H1 2019: $55.8 million) exclude restricted cash of $3.1 million (H1 2019: $10.0 million). Net cash is reported in order for users of the financial statements to understand how much cash remains if the Company paid its debt obligations from its available cash on the period end date. Reported IFRS debt was $298.1 million (31 December 2019: $297.9 million), comprised of $300 million of bond debt less amortised costs. The bond pays a 10.0% coupon and matures in December 2022. A reconciliation of debt and cash is provided in note 11 to the financial statements. The bond has three financial covenant maintenance tests: Financial covenant Test H1 2020 Net debt / EBITDAX< 3.0 (0.3) Equity ratio (Total equity/Total assets) > 40% 64% Minimum liquidity > $30m $355m Net assets Net assets at 30 June 2020 were $1,005.7 million (31 December 2019: $1,386.1 million) and consist primarily of oil and gas assets of $1,107.5 million (31 December 2019: $1,412.5 million), trade receivables of $90.2 million (31 December 2019: $150.2 million) and net cash of $57.2 million (31 December 2019: $92.8 million). Liquidity / cash counterparty risk management The Company monitors its cash position, cash forecasts and liquidity on a regular basis. The Company holds surplus cash in treasury bills or on time deposits with a number of major financial institutions. Suitability of banks is assessed using a combination of sovereign risk, credit default swap pricing and credit rating. Dividend Interim dividend distribution of $13.6 million was paid in January 2020, and a final dividend distribution of $27.7 million in June 2020 (June 2019: $27.4 million). The Board is recommending no change in the interim dividend of 5¢ per share (2019: 5¢ per share), a total distribution of c.$13.6 million. Total dividends declared in 2020 amount to $41.3 million (2019: $40.8 million), representing 15¢ per share (2019: 15¢ per share). The payment timetable for the interim dividend is below: · Ex-dividend date: 12 November 2020 · Record Date: 13 November 2020 · Payment Date: 11 December2020 Going concern The Directors have assessed that the Company's forecast liquidity provides adequate headroom over forecast expenditure for the 12 months following the signing of the half-year condensed consolidated financial statements for the period ended 30 June 2020 and consequently that the Company is considered a going concern. In assessing going concern, the Directors have assessed that prolonged prevalence of COVID-19 may have a further negative impact on the
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DJ Genel Energy PLC: Half-Year Results -5-
oil price and in turn revenues, operational activity and receipt of amounts owed. The Company's low run rate costs, flexible capital programme, and strong cash position provide appropriate mitigation of the reduction of cash inflows that COVID-19 may cause for the going concern basis to remain appropriate. Principal risks and uncertainties The Company is exposed to a number of risks and uncertainties that may seriously affect its performance, future prospects or reputation and may threaten its business model, future performance, solvency or liquidity. The following risks are the principal risks and uncertainties of the Company, which are not all of the risks and uncertainties faced by the Company: the development and recovery of oil reserves; reserve replacement; commercialisation of the KRI gas business; M&A activity; the KRI natural resources industry and regional risk; a deterioration in the external environment caused by COVID-19; corporate governance failure; capital structure and financing; local community support; the environmental impact of oil and gas extraction; and health and safety risks. Further detail on many of these risks was provided in the 2019 Annual Report. Since year-end, the environmental impact of oil and gas extraction has been added to the risk register, reflecting the increased focus on ESG issues, along with the impact of COVID-19. Statement of directors' responsibilities The directors confirm that these condensed interim financial statements have been prepared in accordance with International Accounting Standard 34, 'Interim Financial Reporting', as adopted by the European Union and that the interim management report includes a true and fair review of the information required by DTR 4.2.7 and DTR 4.2.8, namely: · an indication of important events that have occurred during the first six months and their impact on the condensed set of financial statements, and a description of the principal risks and uncertainties for the remaining six months of the financial year; and · material related-party transactions in the first six months and any material changes in the related-party transactions described in the last annual report. The directors of Genel Energy plc are listed in the Genel Energy plc Annual Report for 31 December 2019. A list of current directors is maintained on the Genel Energy plc website: www.genelenergy.com [2] By order of the Board Bill Higgs CEO 5 August 2020 Esa Ikaheimonen CFO 5 August 2020 Disclaimer This announcement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil & gas exploration and production business. Whilst the Company believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to factors beyond the Company's control or within the Company's control where, for example, the Company decides on a change of plan or strategy. Accordingly, no reliance may be placed on the figures contained in such forward looking statements. Condensed consolidated statement of comprehensive income For the period ended 30 June 2020 6 months 6 months Year to 30 June to 30 June to 31 Dec 2020 2019 2019 Note $m $m $m Revenue 3 88.4 194.3 377.2 Production costs 4 (16.8) (18.1) (37.7) Depreciation and 4 (82.5) (74.2) (157.1) amortisation of oil assets Gross (loss) / (10.9) 102.0 182.4 profit Exploration expense 4 (1.3) (0.6) (1.2) Impairment of 4,8 (44.3) - - intangible assets Impairment of 4,9 (242.0) - (29.8) property, plant and equipment Impairment of trade 4,10 (34.9) - - receivables General and 4 (6.6) (9.5) (19.1) administrative costs Operating (loss) / (340.0) 91.9 132.3 profit Operating (loss) / profit is comprised of: EBITDAX 65.1 167.3 321.8 Depreciation and 4 (82.6) (74.8) (158.5) amortisation Exploration expense 4 (1.3) (0.6) (1.2) Impairment of 4,8 (44.3) - - intangible assets Impairment of 4,9 (242.0) - (29.8) property, plant and equipment Impairment of trade 4,10 (34.9) - - receivables Finance income 5 1.6 2.4 6.6 Bond interest 5 (15.0) (15.0) (30.0) expense Other finance 5 (1.3) (2.9) (4.3) expense (Loss) / Profit (354.7) 76.4 104.6 before income tax Income tax expense 6 - (0.4) (0.7) (Loss) / Profit and (354.7) 76.0 103.9 total comprehensive (expense) / income Attributable to: Shareholders' equity (354.7) 76.0 103.9 (354.7) 76.0 103.9 (Loss) / Profit per ¢ ¢ ¢ ordinary share Basic 7 (128.9) 27.2 37.8 Diluted 7 (128.9) 27.1 37.4 Underlying1 (11.7) 27.4 49.0 1. Underlying profit is reconciled on page 9 Condensed consolidated balance sheet At 30 June 2020 30 June 2020 30 June 2019 31 Dec 2019 Note $m $m $m Assets Non-current assets Intangible assets 8 716.0 796.1 775.6 Property, plant and 9 391.5 641.2 636.9 equipment 1,107.5 1,437.3 1,412.5 Current assets Trade and other 10 98.3 125.6 157.4 receivables Restricted cash 3.1 10.0 3.0 Cash and cash 355.3 353.3 390.7 equivalents 456.7 488.9 551.1 Total assets 1,564.2 1,926.2 1,963.6 Liabilities Non-current liabilities Trade and other (124.7) (120.8) (118.8) payables Deferred income (26.8) (28.1) (26.7) Provisions (39.0) (34.7) (37.4) Borrowings 11 (298.1) (297.5) (297.9) (488.6) (481.1) (480.8) Current liabilities Trade and other (66.9) (65.3) (91.7) payables Deferred income (3.0) (6.2) (5.0) (69.9) (71.5) (96.7) Total liabilities (558.5) (552.6) (577.5) Net assets 1,005.7 1,373.6 1,386.1 Owners of the parent Share capital 43.8 43.8 43.8 Share premium account 4,005.4 4,046.6 4,033.4 Accumulated losses (3,043.5) (2,716.8) (2,691.1) Total equity 1,005.7 1,373.6 1,386.1 Condensed consolidated statement of changes in equity For the period ended 30 June 2020 Share Share Accumulated Total equity capital premium losses $m $m $m $m At 1 January 43.8 4,074.2 (2,786.6) 1,331.4 2019 Profit and - - 76.0 76.0 total comprehensive income Share-based - - 2.5 2.5 payments Purchase of - - (8.2) (8.2) shares to satisfy share awards Purchase of - - (0.5) (0.5) treasury shares Dividend - (27.6)1 - (27.6) payment At 30 June 43.8 4,046.6 (2,716.8) 1,373.6 2019 At 1 January 43.8 4,074.2 (2,786.6) 1,331.4 2019 Profit and - - 103.9 103.9 total comprehensive income Share-based - - 5.1 5.1 payments Purchase of - - (8.2) (8.2) shares to satisfy share awards Purchase of - - (5.3) (5.3) treasury shares Dividends - (40.8) - (40.8) provided for or paid1 At 31 December 43.8 4,033.4 (2,691.1) 1,386.1 2019 and 1 January 2020 Loss and total - - (354.7) (354.7) comprehensive expense Share-based - - 3.0 3.0 payments Purchase of - - (0.7) (0.7) shares for employee share awards Dividends - (28.0) - (28.0) provided for or paid1 At 30 June 43.8 4,005.4 (3,043.5) 1,005.7 2020 1 The Companies (Jersey) Law 1991 does not define the expression "dividend"
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but refers instead to "distributions". Distributions may be debited to any account or reserve of the Company (including share premium account). Condensed consolidated cash flow statement For the period ended 30 June 2020 30 June 2020 30 June 2019 31 Dec 2019 Note $m $m $m Cash flows from operating activities (Loss) / Profit and (354.7) 76.0 103.9 total comprehensive (expense) / income Adjustments for: Net finance expense 5 14.7 15.5 27.7 Taxation 6 - 0.4 0.7 Depreciation and 4 82.6 74.8 158.5 amortisation Exploration expense 4 1.3 0.6 1.2 Impairment of 4 44.3 - - intangible assets Impairment of 4 242.0 - 29.8 property, plant and equipment Impairment of 4 34.9 - - receivables Other non-cash items (0.3) (1.4) (2.4) Changes in working capital: Decrease / (Increase) 22.0 (21.8) (55.4) in trade receivables Decrease / (Increase) 0.1 - (0.2) in other receivables (Decrease) / Increase (2.7) (3.7) 3.3 in trade and other payables Cash generated from 84.2 140.4 267.1 operations Interest received 5 1.6 2.4 6.6 Taxation paid (0.3) (0.5) (0.8) Net cash generated 85.5 142.3 272.9 from operating activities Cash flows from investing activities Purchase of (13.7) (12.2) (26.5) intangible assets Purchase of property, (49.7) (58.1) (123.8) plant and equipment Movement in (0.1) - 7.0 restricted cash Net cash used in (63.5) (70.3) (143.3) investing activities Cash flows from financing activities Dividends paid to (41.3) (29.0) (29.0) company's shareholders, including expenses Purchase of shares (0.7) (8.2) (8.2) for employee share trust Purchase of treasury - (0.5) (5.3) shares Lease payments (0.5) (0.3) (0.6) Interest paid (15.0) (15.0) (30.0) Net cash used in (57.5) (53.0) (73.1) financing activities Net (decrease) / (35.5) 19.0 56.5 increase in cash and cash equivalents Foreign exchange gain 0.1 - (0.1) / (loss) on cash and cash equivalents Cash and cash 390.7 334.3 334.3 equivalents at 1 January Cash and cash 355.3 353.3 390.7 equivalents at 31 December Notes to the condensed consolidated financial statements 1. Basis of preparation Genel Energy Plc - registration number: 107897 (the Company) is a public limited company incorporated and domiciled in Jersey with a listing on the London Stock Exchange. The address of its registered office is 12 Castle Street, St Helier, Jersey, JE2 3RT. The half-year condensed consolidated financial statements for the six months ended 30 June 2020 and six months ended 30 June 2019 are unaudited and have been prepared in accordance with the Disclosure and Transparency Rules of the Financial Conduct Authority and with IAS 34 'Interim Financial Reporting' as adopted by the European Union and were approved for issue on 6 August 2020. They do not comprise statutory accounts within the meaning of Article 105 of the Companies (Jersey) Law 1991. The half-year condensed consolidated financial statements should be read in conjunction with the annual financial statements for the year ended 31 December 2019, which have been prepared in accordance with IFRS as adopted by the European Union. The annual financial statements for the period ended 31 December 2019 were approved by the board of directors on 18 March 2020. The report of the auditors was unqualified, did not contain an emphasis of matter paragraph and did not contain any statement under the Companies (Jersey) Law 1991. The financial information for the year to 31 December 2019 has been extracted from the audited accounts. There have been no changes in related parties since year-end and no related party transactions that had a material effect on financial position or performance in the period. There are not significant seasonal or cyclical variations in the Company's total revenues. Going concern The Company regularly evaluates its financial position, cash flow forecasts and its compliance with financial covenants by considering multiple combination of oil price, discount rates, production volumes, payments, capital and operational spend scenarios. As a result, the Directors have assessed that the Company's forecast liquidity provides adequate headroom over its forecast expenditure for the 12 months from the date of signing the half-year condensed consolidated financial statements for the period ended 30 June 2020 and consequently that the Company is considered a going concern. 2. Summary of significant accounting policies The accounting policies adopted in preparation of these half-year condensed consolidated financial statements are consistent with those used in preparation of the annual financial statements for the year ended 31 December 2019. The preparation of these half-year condensed consolidated financial statements in accordance with IFRS requires the Company to make judgements and assumptions that affect the reported results, assets and liabilities. Where judgements and estimates are made, there is a risk that the actual outcome could differ from the judgement or estimate made. The Company has assessed the following as being areas where changes in judgements or estimates could have a significant impact on the financial statements. Significant judgements Apart from those involving estimations (which are dealt with separately below), there are no significant judgements 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. Significant estimates The following are the significant estimates that the directors have made in the process of applying the Company's accounting policies and that has the most significant effect on the amounts recognised in the financial statements. Estimation of hydrocarbon reserves and resources and associated production profiles and costs Estimates of hydrocarbon reserves and resources are inherently imprecise and are subject to future revision. The Company's estimation of the quantum of oil and gas reserves and resources and the timing of its production, cost and monetisation impact the Company's financial statements in a number of ways, including: testing recoverable values for impairment; the calculation of depreciation, amortisation and assessing the cost and likely timing of decommissioning activity and associated costs. 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 are generally classified as property, plant and equipment as development or producing assets and depreciated using the units of production methodology. The Company considers its best estimate for future production and quantity of oil within an asset based on a combination of internal and external evaluations and uses this as the basis of calculating depreciation and amortisation of oil and gas assets and testing for impairment. Hydrocarbons that are not assessed as reserves are considered to be resources and are classified as exploration and evaluation assets. These assets are expenditures incurred before technical feasibility and commercial viability is demonstrable. Estimates of resources for undeveloped or partially developed fields are subject to greater uncertainty over their future life than estimates of reserves for fields that are substantially developed and being depleted and are likely to contain estimates and judgements with a wide range of possibilities. These assets are considered for impairment under IFRS 6. Once a field commences production, the amount of proved reserves will be subject to future revision once additional information becomes available through, for example, the drilling of additional wells or the observation of long-term reservoir performance under producing conditions. As those fields are further developed, new information may lead to revisions. Assessment of reserves and resources are determined using estimates of oil and gas in place, recovery factors and future commodity prices, the latter having an impact on the total amount of recoverable reserves. Change in accounting estimate The Company has updated its estimated production profiles with the accounting impact summarised below under estimation of oil and gas asset values. Estimation of oil and gas asset values
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