GENEL ENERGY (LON:GENL) Genel Energy PLC: Full-Year Results
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Genel Energy PLC (GENL)
15 March 2022 Genel Energy plc
Audited results for the year ended 31 December 2021
Genel Energy plc ('Genel' or 'the Company') announces its audited results for the year ended 31 December 2021.
Bill Higgs, Chief Executive of Genel, said: "Our strategy and business model remain focused on cash generation. Prior to the invasion of Ukraine and the associated increase in the oil price, we were well positioned for our free cash flow to materially increase from $86 million in 2021 to around a quarter of a billion dollars this year. At the prevailing oil price, and given that there seems no quick resolution to the appalling events unfolding, this figure is expected to increase significantly.
The forecast extent of our cash generation, from an existing position of financial strength, provides the potential to deliver significant growth and further returns to shareholders. Our priority is investment in production to maximise the value of our existing assets, and continuing to develop Sarta. Given the strong outlook and ongoing cash generation, we have increased our final dividend by 20%, continuing to fulfil our aim of paying a material and progressive dividend."
Results summary ($ million unless stated)
Highlights
Outlook
Enquiries:
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.
Genel will also host a live presentation on the Investor Meet Company platform on Thursday 17 March at 1000 GMT. The presentation is open to all existing and potential shareholders. Questions can be submitted pre-event via your Investor Meet Company dashboard up until 9am the day before the meeting or at any time during the live presentation. Investors can sign up to Investor Meet Company for free and add to meet Genel Energy PLC via: https://www.investormeetcompany.com/genel-energy-plc/register-investor.
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 tenth annual results. Writing last year, the world was still very much in the middle of the COVID-19 pandemic, with an uncertain economic environment and fluctuating oil price illustrating how Genel's resilience stood us in good stead to thrive as the environment improved.
The pandemic is still not over and it continues to provide operational challenges, but the economic recovery was well underway. The world is now reacting to a different crisis in Ukraine and, with no swift resolution to this crisis in sight, the ongoing impact to oil and gas supply and demand dynamics is uncertain and the resulting oil price spike (and volatility) has the potential to be prolonged.
A strategy that delivers Such oil price strength does not impact our strategy, with underlying principles that are as relevant in times of a high oil price as they are in times of significant challenges. We aim to increase our low-cost and low-carbon production, invest in growth, and retain surplus cash to pay a material and sustainable dividend, as we aim to provide investors with a compelling mix of growth and returns.
The low-cost of our production in the Kurdistan Region of Iraq means that it is cash generative at a low oil price, allowing us to continue investing in growth and retain our material dividend. At the prevailing oil price, it is high-margin and extremely cash generative.
The cash that we generate provides us with a degree of freedom to make prudent investment decisions, targeting expenditure on those areas that promise to deliver greatest value to our stakeholders. In 2021 Sarta was a key focus of our investment. While initial production has not reached the levels that we hoped it is a pilot project, and a profitable one, and we have made substantial progress on the appraisal programme required to understand the asset.
We remain rigorous in our management of capital expenditure. Qara Dagh drilling did not lead to the result that we wanted, but it is a measure of our discipline that the correct decision was made to halt drilling at the appropriate time. We retain high-impact exploration in the portfolio, and it is testament to the team that a successful farm-out was completed on our Somaliland acreage. This is a highly-prospective and underexplored region, and we look forward to progressing this asset towards the drilling of an exciting well with our new partner.
Material investment was made in growth assets in 2021, and we still generated significant free cash flow, demonstrating the efficacy of our business model and quality of our production. This allowed us to fulfil our strategic aim of paying a progressive dividend, with the interim dividend increased, and the final dividend also lifted by 20%, given the cash generation that we expect in 2022.
Board changes We continue to ensure that Genel has an appropriately structured Board to support the delivery of our agreed strategy. In 2021 George Rose, Martin Gudgeon, and Esa Ikaheimonen left the Board, all having made valuable contributions. Esa was a leader in solidifying our robust business model and he leaves the Company well placed, with a strong balance sheet and the financial flexibility to take advantage of the opportunities ahead of us. The process for an appointment of Esa's successor is at an advanced stage. In the meantime, Luke Clements, our Head of Finance and Planning, has been appointed as Interim CFO.
The appointment of Yetik Mert at the end of the year deepened the regional experience of the Board, and we continue to work with our shareholders in ensuring strategic alignment as we seek to create value for all.
A key decision the Board took last year to protect shareholder value related to the Bina Bawi and Miran assets, and it was a decision that we had no practical alternative but to make. Genel management had made every effort over a number of years to engage with the Kurdistan Regional Government on the development of these fields, but it became clear that the KRG did not intend to permit their development in accordance with the terms of the PSCs. As a consequence of the KRG's repudiatory breach of the PSCs, we elected to treat the PSCs as terminated and claim compensation. Our claims for substantial damages are being brought in a private London seated international arbitration.
From our perspective it is business as usual in relation to our other assets. We have been, and remain, a committed partner of the KRG and our operations have been a tremendous boost for the Kurdistan Region, and we intend this to continue for a long time to come.
Making a positive difference 2022 marks 20 years of this relationship, with Genel having signed the Taq Taq PSC back in 2002. In this time we have invested c.$3.5 billion in our assets, generating over $21 billion in revenue for the KRG while also providing employment and opportunities for local communities. We have also spent $60 million on social initiatives and completed over 250 community projects.
To mark twenty years in the KRI we will be increasing the ambition of our social investments under the Genel20 banner in alignment with UN Sustainable Development Goals. We continue to believe that it is crucial for our actions to not only deliver shareholder value, but also have a positive impact on the communities in which we operate, with an environmental footprint that is supportive of the goals of the energy transition. The world still needs to utilise natural resources, and we have the right assets, in the right locations, being delivered in the right way, as we aim to be a socially responsible contributor to the global energy mix.
CEO STATEMENT A resilient business model Genel entered 2022 at an advantage, with low-cost operations delivering a high-margin and material cash generation that opens up exciting possibilities. We look forward with confidence, and we never lose focus on the key strength of our business model, which is defined by resilience and the mitigation of downside risk.
As the COVID-19 pandemic decimated global economies and reduced the demand for oil, our low-cost operations and the flexibility of our capital allocation positioned us well for the resulting low-oil price environment. It allowed us to progress assets and retain our dividend, illustrating the financial resilience that is our watchword.
In 2021 we demonstrated a different type of resilience, as we faced an array of technical and operational challenges. The pandemic continued to make life at our fields tough, and I am proud of the way that our staff dealt with the ongoing restrictions placed on them to keep so many work-fronts open and progressing. Each month provided different challenges and situations for us to overcome, and at Qara Dagh in particular this led to the difficult but correct choice to suspend drilling operations for technical reasons.
These challenges once again shone a light on our business model and our character, and our success in managing uncertainty while maximising cash generation is a testament to its strengths.
Sarta provided a real-world case study of the strength of our model. Through minimising upfront investment and initiating pilot production, we generate cash as we appraise to ensure that development costs are appropriate. Our downside risk mitigation therefore has practical upside. Despite its challenges, our Sarta production generated an operating profit in 2021, contributing towards our appraisal costs. As we continue our work to understand the field, we are flexible with our approach, generating cash and developing the asset appropriately - the conversion of the old Sarta-4 well to a water injector to help maximise production, being a good example.
Taking this approach across our portfolio resulted in overall free cash flow of $86 million and an increased dividend. We expect to materially better this cash flow performance in 2022, while also progressing our strategic plans.
Boosted operational capability As we seek to deliver on our strategy, we have ramped up our operational capability accordingly. In 2021 Genel drilled its first sole operated wells since 2014, and given the multi-well programme we had to hit the ground running. Three rigs were mobilised and three wells were spud across Sarta and Qara Dagh, and for an extended period of the year in simultaneous operations. As well as drilling operations, 230,000 hours of civil engineering work took place, as eight kilometres of flow lines were laid to help enable early production from Sarta appraisal wells.
There are routinely 300 people at our sites in the KRI, many of them local as we continue to focus on providing opportunities for the community, and we had no COVID-19 related downtime. This is a testament to the efforts put in by our team.
Entering 2022, we have increased skills and expertise across the Company, appropriate for the next stage of our journey as we look to grow our operated production.
Cash generation providing opportunity Driven by our cash generation, this next stage brings with it numerous opportunities. At the time of writing the Brent oil price is substantially over $100/bbl, which if sustained would lead to our cash generation in 2022 well exceeding a quarter of a billion dollars. In line with our business model though, this will not affect our focus on financial discipline. There are too many examples of companies investing as if the high oil price will last forever; at Genel we want to build a future-proofed portfolio that minimises downside risk while providing investors with material growth potential.
The focus of our investment therefore remains our producing assets, and work in 2022 will tell us a lot more about the investment that will be required to allow Sarta to fulfil its potential. Somaliland offers great potential in the event of drilling success, with one prospect alone able to target half a billion barrels of recoverable oil, but exploration will take time.
Delivering growth and returns Our organic portfolio is therefore exciting, and can contribute significantly in providing us with the scale and potential that we need as we aim to establish Genel as an investment prospect that is difficult to ignore. We are committed to our material dividend, and to illustrating to investors that it is sustainable in the long-term. As such, we are keen to replace the cash generation that will be lost once Tawke override payments end and add diverse long-life cash generative production. We continue to consider potential acquisitions that fit our business model and aims, and will remain highly selective and opportunistic in this area.
Focus on ESG Doing the right things, in the right way, with the right people, and acting in alignment with our values remains key to our strategic success, and we continue our focus on ESG. Management is spending a significant amount of time on sustainability, with our newly formed Strategy and Growth Execution Committee meeting regularly to discuss ongoing efforts in this area.
Our standalone Sustainability Report provides greater detail on our work, but our aims are simple.
We look to provide stakeholder returns through the production of natural resources, while minimising our environmental footprint, in communities where it can make a tangible difference to people's lives. As the energy transition gathers pace, we want to fulfil our aim of being a socially responsible contributor to the global energy mix, delivering the low-cost and low-carbon barrels that are necessary as we transition to clean energy.
Somaliland has the potential to embody this aim, as the KRI has done. Should exploration be successful, onshore production in Somaliland can be low-cost, low-carbon, and deliver a material and tangible benefit to local people and the host government in a region that has real need for economic development.
Outlook We look forward to progressing our activity in Somaliland this year, but our key focus in 2022 is on cash generation and accessing the opportunities that this provides for us. Robust Tawke production forms the bedrock of our plans, and as this year progresses we will better understand Sarta's ability to supplement this over the long-term.
We expect Sarta production to continue offsetting declines from our other mature fields, and the high-margin of this production means that we expect free cash flow of significantly over $250 million in 2022, even after continuing growth expenditure at Sarta. I look forward to updating our shareholders on our strategic progress.
OPERATING REVIEW Reserves and resources development Genel's proven (1P) and proven plus probable (2P) net working interest reserves totalled 63 MMbbls (31 December 2020: 69 MMbbls) and 104 MMbbls (31 December 2020: 117 MMbbls) respectively at the end of 2021.
The appraisal results of Sarta-5 and Sarta-6 will be incorporated into our assessment of the reserves of Sarta at the appropriate time.
Production Production averaged 31,710 bopd in 2021, in line with the previous year, as the addition of production from Sarta offset ongoing declines at the mature Taq Taq field, where no drilling took place. Tawke continues to form the bedrock of our production and cash generation, and production was robust in 2021.
PRODUCING ASSETS Tawke PSC (25% working interest) Gross production at the Tawke licence averaged 108,700 bopd in 2021, of which the Peshkabir field contributed 61,800 bopd, and the Tawke field 46,900 bopd.
Drilling at the Tawke field resumed in Q3 2021 after an 18 month pause caused by the low oil price environment, during which time production decline was partially offset by gas injection and workovers.
DNO expects the ramp up in drilling activities to maintain Tawke licence gross production at around 105,000 bopd during 2022.
Gas management is ongoing, and a total of 7.6 billion cubic feet (461,500 tonnes of CO2) of otherwise flared Peshkabir gas was captured and injected into the Tawke field in 2021.
Sarta (30% working interest, operator) Gross production averaged 6,400 bopd in 2021, with just over 2.5 million barrels having been produced from start up in late November 2020 to year end 2021, as the results of this early pilot production from the asset continues to help shape the view of full field development.
Oil has been delivered through more than 10,000 tanker journeys, without any lost time incidents or downtime due to COVID-19.
Drilling and completion operations at Sarta-1D concluded in November 2021, with successful testing carried out in Q1 2022. During testing, production was achieved from multiple zones and fluid samples were acquired successfully. The upper zones produced dry oil while the lower zones produced a mixture of oil and water, in line with expectations.
The well entered production on 8 March 2022, initially at a rate of c.2,500 bopd from the upper zones only, to allow dry oil production while monitoring interference effects with the nearby Sarta-2 and Sarta-3 wells.
Using the experience of other fields in the KRI, we are focused on producing and developing Sarta in the most appropriate and cost-effective way possible using our produce, appraise, and develop philosophy. Oil production from Sarta-1D was fast tracked, with a short c.2 km flowline installed in Q4 2021 removing any lag time between well testing results and monetisation of the resource through the adjacent early production facility.
Following the initial results of production from the Sarta-2 and Sarta-3 wells, the Viking I-21 Rig moved from the Sarta-1D site to Sarta-4 to workover the legacy exploration well for use as a produced water disposal well, which will help optimise production. Once complete, Sarta-4 will allow production from the lower zones of Sarta-1D, with the added the water disposal also allowing the managing and maximisation of production from Sarta-2 and Sarta-3.
The Sarta-5 and Sarta-6 step out wells, designed to appraise the field away from the pilot production facility, are key in resolving the current uncertainty over the size and shape of the Sarta field. Drilling and completion operations concluded at Sarta-5 at the end of 2021, with well testing set to begin shortly, and the Sarta-6 well has now spud.
In 2021, in line with our focus on reducing emissions, Genel initiated engineering studies on Gas and Emissions Management at Sarta including the potential use of renewable sources to help power our operations. The work will be matured in 2022 allowing for concept selection, informed by the results of Sarta 5 and Sarta 6.
As we took over operatorship on 1 January 2022, we will be increasing our social footprint in the region as a key part of our Genel20 activities.
Taq Taq (44% working interest, joint operator) Gross production at Taq Taq averaged 5,940 bopd in 2021, following the ongoing suspension of drilling activity as we continue to focus on optimising cash flow. We are working with the MNR and our partner with a view to the resumption of drilling in H2 2022.
PRE-PRODUCTION ASSETS Qara Dagh (40% working interest, operator) Drilling operations on the QD-2 well at Qara Dagh (40% working interest and operator) were suspended in December. This followed a challenging operation, with the well having initially been side-tracked in response to encountering more complex geology above the target reservoir than expected.
Following this, two further side-tracks were initiated, but the licence partners concluded that it was impractical to continue the drilling operations from this wellbore in an attempt to reach the primary objective because of insurmountable technical problems.
A thorough evaluation of the QD-2 well and its results is now being undertaken to inform next steps on the licence. The geological case for Qara Dagh remains intact and attractive, although a drilling decision will be made dependent on the ability of a new well to fit in with our business model, which will balance the significant upside with our focus on prudent capital allocation and the minimisation of downside risk.
African exploration In December, Genel signed a farm-out agreement relating to the SL10B13 block (Genel 51%, operator), Somaliland, with OPIC Somaliland Corporation ('OSC'), with all its share of future capital investment coming from CPC Corporation, Taiwan, the state-owned enterprise of Taiwan. Under the agreement, OSC received a 49% working interest in the block for a cash consideration of 49% of all Genel's historic back costs, plus a cash premium.
Somaliland has significant underexplored potential, with geology analogous to Yemen. The SL10B13 block is highly prospective, with multiple stacked prospects with over five billion barrels of prospective resources identified from the interpretation of the 2D seismic data acquisition completed in January 2018. One prospect alone could target over half a billion barrels across multiple stacked reservoirs. The prospective SL10B13 area is c.150 kilometres from the port at Berbera, offering a route to international markets.
The field partners are now working together to plan exploration drilling in this block, with an aim of drilling a well in 2023. It is currently estimated that a well can be drilled for a gross cost of c.$40 million.
Management recently undertook a visit to Somaliland as planning work intensifies, and as we move closer to the start of drilling operations our social activities will ramp up accordingly.
A farm-out campaign continues to be planned relating to the Lagzira block offshore Morocco (75% working interest and operator), with the aim of bringing in a partner prior to considering further commitments.
FINANCIAL REVIEW Overview of financial performance in 2021 The rapid recovery of the oil price in the year brought about a tripling of net income generated by our production business to $239 million. We have been rewarded for our activity in the second half of 2020, when drilling resumed on the Tawke PSC and Sarta first oil was delivered, despite the challenging operating conditions and uncertain oil price outlook at the time.
This material cash generation more than funded our capital allocation priorities - investment in derisking Sarta and Qara Dagh and the payment of a sustainable and progressive dividend.
The successful farm-out of our Somaliland SL10B-13 licence supports the funding of the progression of this exciting play, minimising our downside through reducing our capital at risk. This is evidence of our financial discipline, as we allocate appropriate levels of capital relevant to the risk and return of an investment opportunity.
Overall our net cash increased by $38 million in the year.
1 Nominal value of deferred receivables is $76.8 million (FY 2020: $120.8 million) and $37.8 million of invoiced override revenue where payment was suspended from March 2020 to December 2020 (see note 1) 2 Net cash interest is bond interest payable less bank interest income (see note 5) 3 In March 2020, KRG changed payments terms from three months in arrears to one month in arrears. At year-end the KRG owed three months of sales, adversely impacting free cash flow for the year by $65.0 million
Financial priorities of 2021 The table below summarises our progress against the 2021 financial priorities of the Company as set out at our 2020 results.
Dividend The material improvement in oil price, resumption of the override, and commencement of payment of amounts owed for deferred receivables provides the Company with a strong cash flow generation outlook.
The Company is committed to a sustainable and progressive dividend that is supported by resilient, diversified and predictable production and a robust cash generation outlook.
At the half year results, the Board approved an increase in the interim dividend from 5¢ to 6¢, a rise of c.$3 million per annum, and reaffirmed its commitment to the dividend being sustainable and progressive. Total dividends declared and paid in 2021 amounted to $44 million (2020: $42 million), representing 16¢ per share (2020: 15¢ per share).
The Board has now approved an increase in the final dividend from 10¢ to 12¢, resulting in an overall 20% increase in dividends year-on-year and total payments relating to 2021 of $50 million.
The payment timetable for the final dividend is below:
Outlook and financial priorities for 2022 We carry significant liquidity and are net cash positive with significant cash generation expected in 2022. We are well positioned to continue the derisking and progression of our existing portfolio, as well as add to it, in order to work towards an outlook 2P production profile that continues to support our sustainable and progressive dividend well into the future.
We continue to see a long-term oil price that is supportive to our business, and coupled with our focus on the right barrels in the right locations, means we are committed to our business model and remaining resilient to volatility and the challenges faced by the sector.
The focus of our business model remains unchanged:
For 2022, our financial priorities are the following:
Financial results for the year Income statement
Despite broadly unchanged production, revenue rose from $160 million to $335 million, principally caused by the higher Brent oil price and the resumption of the override from January onwards.
Production costs of $46 million increased from the prior year (2020: $33 million), with cost per barrel of $4/bbl (2020: $2.8/bbl). Both increases have been caused by the addition of Sarta, which commenced production in December 2020. We expect that the overall operating cost per barrel at the Sarta field will reduce to c.$5/bbl once production has increased to around the facility capacity - the Sarta plant is currently operating at less than 50% capacity. This compares favourably to revenue per barrel of $42/bbl.
General and administration costs were $14 million (2020: $13 million), of which corporate cash costs were $12 million (2020: $10 million).
The increase in revenue resulted in a similar increase to EBITDAX, which was $275 million (2020: $115 million). EBITDAX is presented in order to illustrate the cash profitability of the Company, and 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, impairments and write-offs.
Depreciation of $115 million (2020: $99 million) and Tawke intangibles amortisation of $58 million (2020: $55 million) increased in total as a result of change in depreciation per barrel inputs in the second half of 2020 and increase in Sarta production.
The Company has reported an expense of $403 million relating to the accounting derecognition of the assets and liabilities associated with the Bina Bawi and Miran licences. An impairment reversal of $24 million has been recognised relating to deferred trade receivables, which have been reassessed based on the current payment mechanism and outlook oil price. These are both explained in note 1.
Bond interest expense of $26 million (2020: $32 million) decreased due to lower debt, a lower coupon rate, and a reduction in the principal amount owed.
In relation to taxation, under the terms of 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 (2021: $0.2 million, 2020: $0.2 million).
Capital expenditure Capital expenditure is the aggregation of spend on production assets ($105 million) and pre-production assets ($58 million) and is reported to provide investors with an understanding of the quantum and nature of capital investment. Capital expenditure for the period was $164 million, predominantly focused on production assets and Sarta ($55 million) and Qara Dagh ($51 million):
Cash flow, cash, net cash and debt Gross proceeds received totalled $281 million (2020: $173 million), of which $72 million (2020: $23 million) was received for the override royalty and $35 million for receivable recovery.
Free cash flow is presented in order to illustrate the free cash generated for equity. Free cash flow was $86 million (2020: $4 million outflow) with an overall increase mainly as a result of higher Brent and resumption of the override.
The bonds maturing in 2025 have two financial covenant maintenance tests:
Net assets Net assets at 31 December 2021 were $581 million (31 December 2020: $930 million) which reduced as a result of write-off of intangible assets and derecognition of other payables, accruals and provisions following Genel's termination of Miran and Bina Bawi PSCs, and consist primarily of oil and gas assets of $539 million (31 December 2020: $1,095 million), trade receivables of $158 million (31 December 2020: $94 million) and net cash of $44 million (31 December 2020: $6 million net cash).
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.
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 2021 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 oil price and in turn revenues, operational activity and receipt of amounts owed.
The majority Iraq Federal Supreme Court judgment handed down on 15 February 2022 has had no impact on our operations and does not impact our assessment of Genel's going concern status.
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. Further explanation is provided in note 1 to the financial statements.
Consolidated statement of comprehensive income For the year ended 31 December 2021
1Underlying EPS / (LPS) is loss and total comprehensive (expense) / income adjusted for the add back of impairment / write-off of intangible assets, impairment of property, plant and equipment and reversal of impairment / (impairment) of receivables divided by weighted average number of ordinary shares.
Consolidated balance sheet At 31 December 2021
Consolidated statement of changes in equity For the year ended 31 December 2021
1 The Companies (Jersey) Law 1991 does not define the expression "dividend" but refers instead to "distributions". Distributions may be debited to any account or reserve of the Company (including share premium account).
Consolidated cash flow statement For the year ended 31 December 2021
Notes to the consolidated financial statements
1. Summary of significant accounting policies
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 consolidated financial statements of 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 ($ million) 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 19 and 22.
Going concern The Company regularly evaluates its financial position, cash flow forecasts and its compliance with financial covenants by considering multiple combinations of oil price, discount rates, production volumes, payments, capital and operational spend scenarios.
The Company has reported cash of $313.7 million, with no debt maturing until the second half of 2025 and significant headroom on both the equity ratio and minimum liquidity financial covenants. The strength of the balance sheet is expected to be enhanced through 2022.
The Company's low-cost assets and flexibility on commitment of capital mean that it is resilient to low oil prices, with the only customer, the KRG, demonstrating its ability to pay consistently in times of financial stress. In addition, specifically for the purposes of the going concern, management have modelled a downside scenario, recognising the impact of the COVID-19 pandemic, which includes a significant reduction in oil price from current levels combined with a reduction in production. Even with these downsides there is considered to be sufficient cash in the business and still more room for flexibility if needed given the nature of the discretionary capex planned.
Longer term, our low-cost, low-carbon assets, located in a region where oil revenues provide a material proportion of funding to the government and its people means that we are well positioned to address the appropriate challenges and demands that climate change initiatives are bringing to the sector. Given the footprint and the benefit to society generated, we see our portfolio as being well-positioned for a future of fewer and better natural resources projects, while the global energy mix continues to require hydrocarbons.
The majority Iraq Federal Supreme Court judgment handed down on 15 February 2022 has had no impact on our operations and does not impact our assessment of Genel's going concern status.
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 2021 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.
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 and associates 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-in/farm-out transactions undertaken in the exploration phase of an oil and gas asset are accounted for on a no gain/no loss basis due to inherent uncertainties in the exploration phase and associated difficulties in determining fair values reliably prior to the determination of commercially recoverable proved reserves. The resulting exploration and evaluation asset is then assessed for impairment indicators under IFRS 6. Any cash payment or proceeds are presented as an increase or reduction to additions respectively. Net additions to exploration and appraisal assets include farm out proceeds relating to SL10B13.
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.
Significant judgements The following are the significant judgements that the directors have made in the process of applying the Company's accounting policies and that have the most significant effect on the amounts recognised in the financial statements. The significant judgements also include recognition of revenue generated by the override royalty which is explained in the context of the significant estimates below.
Bina Bawi / Miran The Company has recognised an accounting expense of $403 million relating to the required derecognition of the intangible assets of $489 million and liabilities of $86 million relating to the Bina Bawi and Miran PSCs following Genel's termination of the PSCs on 10 December 2021. The Bina Bawi and Miran assets and liabilities were part of the pre-production segment as disclosed in note 2. The impairment expense of $403 million represents the write off of 100% of the asset balances relating to the PSCs. The liabilities which remain largely reflect the demobilisation.
Significant estimates The following are the critical estimates that the directors have made in the process of applying the Company's accounting policies and that have 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.
Proved 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 having 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 under IAS 36.
Hydrocarbons that are not assessed as reserves are considered to be resources and the related assets 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 Where the Company has updated its estimated reserves and resources any required disclosure of the impact on the financial statements is provided in the following sections.
Estimation of oil and gas asset values (note 8 and 9)Estimation of the asset value of oil and gas assets is calculated from a number of inputs that require varying degrees of estimation. Principally oil and gas assets are valued by estimating the future cash flows based on a combination of reserves and resources, costs of appraisal, development and production, production profile and future sales price and discounting those cash flows at an appropriate discount rate.
Future costs of appraisal, development and production are estimated taking into account the level of development required to produce those reserves and are based on past costs, experience and data from similar assets in the region, future petroleum prices and the planned development of the asset. However, actual costs may be different from those estimated.
Discount rate is assessed by the Company using various inputs from market data, external advisers and internal calculations. A post tax nominal discount rate of 13% derived from the Company's weighted average cost of capital (WACC) is used when assessing the impairment testing of the Company's oil assets at year-end. Risking factors are also used alongside the discount rate when the Company is assessing exploration and appraisal assets.
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 and intangible assets. It is also relevant to the assessment of ECL, 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 2026 price then inflated at 2% per annum.
The 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 Brent oil price average less transportation costs, handling costs and quality adjustments. 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.
Estimation of the recoverable value of deferred receivables (note 10) At the end of March 2020, in line with other International Oil Companies (IOCs) in Kurdistan, the KRG informed the Company that payments owed for sales made in the four months from November 2019 to February 2020 would be deferred. For Genel this amounted to $120.8 million.
For the period ended 30 June 2020, the Company estimated recovery of these deferred amounts, which resulted in an impairment of $34.9 million.
In December 2020, the KRG announced a reconciliation model for payment of the receivable relating to the unpaid invoices, whereby for each dollar above a monthly dated Brent average of $50/bbl, 50 cents per paying interest barrel would be paid towards monies owed. In May 2021, the KRG amended this reconciliation model so that it paid 20 cents per paying interest barrel would be paid towards monies owed.
Given the KRG has established a reconciliation model for payments, in order to assess the recoverable amount of deferred receivables at 31 December 2021, the Company has compared the carrying value of deferred receivables with the present value of the estimated future cash flows based on the KRG's communications, and using estimations of future oil prices and production scenarios. Under IFRS9, the Company has used a forward-looking impairment model based on a lifetime expected credit loss (ECL) assessment. The model calculates the net present value of deferred receivables using the effective interest rate for the period in which the revenue was recognised, which was 13%. The expected credit loss is the weighted average of these scenarios and is recognised in the income statement. The result of the Company's assessment was a reversal of previously recognised impairment in the amount of $24.1 million, principally as an output of clarity on the mechanism and increase in oil price. The Company has provided the detailed disclosures required by IFRS 9 ECL assessment in note 10.
Recognition of revenue generated by the override royalty, arising from the RSA Since 2017 when the RSA was signed, the Company has received override revenue from Tawke sales. At the end of March 2020, the KRG informed the Company that this override income was suspended for a minimum period up to December 2020. Because management did not have visibility on how or when this contractual right would be received, it assessed that the criteria for revenue recognition under IFRS15, specifically on payment terms and collectability, have not been met. The total amount of override revenue for the period between 1 March 2020 to 31 December 2020 that has not been recognised is $37.8 million.
The KRG has now communicated that override income owed will be paid by the reconciliation model explained above. Final position on an acceptable resolution on this has not yet been reached and with receipt of cash still dependent on oil price and production no revenue will be recognised until the Company has appropriate confidence in timing of receipt of payment.
Change in estimated cost of the financial commitment made on acquisition of Sarta PSC (note 12) The estimated cost of the financial commitment made on acquisition of the Sarta PSC has been updated to reflect the estimated cost of fulfilling that commitment and the success demonstrated in FY2021 of producing and receiving cash flows for the reserves of the licence. This resulted a $19.7 million decrease in other payables.
Decommissioning provision (note 14) Decommissioning provision is calculated from a number of inputs such as costs to be incurred in removing production facilities and site restoration at the end of the producing life of each field and that require varying degrees of estimation. These inputs are based on the Company's best estimate of the expenditure required to settle the present obligation at the end of the period inflated at 2% (2020: 2%) and discounted at 4% (2020: 4%). The cash flows relating to the decommissioning and abandonment provisions are expected to occur between 2028 and 2043.
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.
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 2020, adjusted for transitional requirements where necessary, further explained under revenue and changes in accounting policies headings.
Revenue Revenue from contracts with customers is earned based on the entitlement mechanism under the terms of the relevant PSC and overriding royalty income ('ORRI'), which is earned on 4.5% of gross field revenue from the Tawke licence until July 2022.
Under IFRS 15, entitlement revenue and ORRI 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.
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 entitlement earned on the Sarta and Taq Taq licences, which become 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.
On the Tawke licence, the Company also receives override revenue ('ORRI'), which is calculated as 4.5% of Tawke PSC field revenue. The override began in August 2017 and is due to end in July 2022.
The Company's oil sales are made to the KRG and are valued at a netback price which is explained further in significant accounting estimates and judgements.
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 has not been able to assess where revenue should be reported gross of implied income tax paid.
The Company's revenue from other sources includes a non-cash royalty income which is recognised in the statement of comprehensive income in a manner consistent with entitlement mechanism.
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.
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 Producing and Development assets Oil and gas assets classified as producing and 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 assets are classified under producing assets following the commercial production commencement.
Development expenditure is accounted for in accordance with IAS 16 - Property, plant and equipment. Producing 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 barrels to provide a $/barrel unit depreciation cost. Changes to depreciation rates as a result of changes in forecast production 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.
Right of use assets / Lease liabilities The Company recognises a right to use asset and lease 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 uses the following judgements permitted by the standard: applying a single discount rate to a portfolio of leases with reasonably similar characteristics, accounting for operating leases with a remaining lease term of less than 12 months as at balance sheet date as short-term leases, and using hindsight in determining the lease term where the contract contains options to extend or terminate the lease.
Right-of-use assets are depreciated over the lifetime of the related lease contract.
Lease liabilities were measured at the present value of the remaining lease payments, discounted using the lessee's incremental borrowing rate and included within trade and other payables.
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. 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.
Financial assets and liabilities 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.
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 under financial assets.
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.
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 and capitalised as part of the cost of the assets.
Impairment Exploration and evaluation assets Spend on exploration and evaluation assets is capitalised in accordance with IFRS 6. The carrying amounts of the Company's exploration and evaluation assets are reviewed at each reporting date to determine whether there is any indication of impairment under IFRS 6. Impairment assessment of exploration and evaluation assets is considered in the context of each cash generating unit, which is generally represented by relevant the licence.
Producing and Development assets The carrying amounts of the Company's producing and development 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 Impairment of financial assets is assessed under IFRS 9 with a forward-looking impairment model based on expected credit losses (ECLs). The standard requires the Company to book an allowance for ECLs for its financial assets. The Company has assessed its trade receivables as at 31 December 2021 for ECLs. Further explanation is provided in significant accounting judgements and estimates.
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.
Equity Share capital Amounts subscribed for share capital at nominal value. Ordinary shares are classified as equity.
When share capital recognised as equity is repurchased, the amount of the consideration paid, which includes directly attributable costs, is net of any tax effects and is recognised as a deduction in equity. Repurchased shares are classified as treasury shares and are presented as a deduction from total equity. When treasury shares are subsequently sold or reissued, the amount received is recognised as an increase in equity and the resulting surplus or deficit of the transaction is transferred to/from retained earnings.
Share premium Amounts subscribed for share capital in excess of nominal value.
Accumulated loss Cumulative net losses recognised in the statement of comprehensive income net of amounts recognised directly in equity.
Dividend Liability to pay a dividend is recognised based on the declared timetable. A corresponding amount is recognised directly in 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 equity-settled share-based compensation plans. The expense required in accordance with IFRS2 is recognised in the statement of comprehensive income over the vesting period of the award. The expense is determined by reference to option pricing models, principally Monte Carlo and adjusted Black-Scholes models.
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 the KRI PSCs, the Company is not required to pay any cash corporate income taxes as explained in significant accounting judgements and estimates. Current tax expense is incurred on profits of service 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 following new accounting standards, amendments to existing standards and interpretations are effective on 1 January 2021. Amendments to IFRS 4 Insurance Contracts - deferral of IFRS19, Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16 Interest Rate Benchmark Reform - Phase 2, Amendments to IFRS 16 Leases: Covid-19-related rent concessions beyond 30 June 2021. These standards are not expected to have a material impact on the Company's results or financials statement disclosures in the current or future reporting periods.
The following new accounting standards, amendments to existing standards and interpretations have been issued but are not yet effective: IFRS 17 Insurance contracts (effective 1 Jan 2023), Amendments to IAS 1 Presentation of Financial Statements: Classification of Liabilities as Current or Non-current (1 Jan 2023), Amendments to IFRS 3 Business Combinations; IAS 16 Property, Plant and Equipment; IAS 37 Provisions, Contingent Liabilities and Contingent Assets; Annual Improvements 2018-2020 (1 Jan 2022), Amendments to IAS 1 Presentation of Financial Statements and IFRS Practice Statement 2: Disclosure of Accounting policies (1 Jan 2023), Amendments to IAS 8 Accounting policies, Changes in Accounting Estimates and Errors: Definition of Accounting Estimates (1 Jan 2023), Amendments to IAS 12 Income Taxes: Deferred Tax related to Assets and Liabilities arising from a Single Transaction (1 Jan 2023). Nothing has been early adopted, and these standards are not expected to have a material impact on the Company's results or financials statement disclosures in the periods they become effective.
2. Segmental information
The Company has two reportable business segments: Production and Pre-production. Capital allocation decisions for the production segment are considered in the context of the cash flows expected from the production and sale of crude oil. The production segment is comprised of the producing fields on the Tawke PSC (Tawke and Peshkabir), the Taq Taq PSC (Taq Taq) and the Sarta PSC (Sarta) which are located in the KRI and make sales predominantly to the KRG. The pre-production segment is comprised of discovered resource held under the Qara Dagh PSC, the Bina Bawi PSC (derecognised in the year) and the Miran PSC (derecognised in the year), all in the KRI and 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 year ended 31 December 2021
Revenue from contracts with customers includes $101.9 million (2020: $14.7 million) arising from the ORRI, which is explained further in note 1. The ORRI was suspended from March 2020 to December 2020 and consequently no revenue has been recognised relating to this period as further explained in note 1.
Total assets and liabilities in the other segment are predominantly cash and debt balances.
Total assets and liabilities in the other segment are predominantly cash and debt balances.
5. Finance expense and income
Bond interest payable is the cash interest cost of the Company bond debt. Other finance expense (non-cash) primarily relates to the discount unwind on the bond and the asset retirement obligation provision.
6. Income tax expense
Current tax expense is incurred on profits of service 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. Loss per share
Basic Basic loss per share is calculated by dividing the loss attributable to owners of the parent by the weighted average number of shares in issue during the period.
1 Excluding shares held as treasury shares
Diluted The Company purchases shares in the market to satisfy share plan requirements so diluted earnings per share is adjusted for performance shares, restricted shares and share options not included in the calculation of basic earnings per share. Because the Company reported a loss for the year ended 31 December 2021 and 31 December 2020, the performance shares, restricted shares and share options are anti-dilutive and therefore diluted LPS is the same as basic LPS:
1 Excluding shares held as treasury shares
8. Intangible assets
9. Property, plant and equipment
1 Other line includes non-cash asset retirement obligation provision, share-based payment costs and production bonuses.
Sarta asset was transferred from development assets to producing assets following the commencement of production from the field at December 2020.
An impairment trigger assessment review was conducted by Management and the Board which concluded that there were no impairment triggers noted.
10. Trade and other receivables
From February 2016, payments were received consistently three months in arrears, which was assessed as the operating cycle under IAS1. From March 2020, payments were received one month in arrears, which was consequently used to assess receivables that were not due at 31 December 2020. At 31 December 2021, the Company is currently owed three months of payments, but there is no established operating cycle.
Recovery of the carrying value of the deferred receivables At the end of March 2020, in line with other International Oil Companies (IOCs) in Kurdistan, the KRG informed the Company that payments owed for sales made in the four months from November 2019 to February 2020 would be deferred. For Genel this amounted to $120.8 million. In 2021, the balance owed has reduced by $44.0 million from the opening balance of $120.8 to $76.8 million. This reduction is the result of nine payments being received in the period (the first two under the initial mechanism announced in December 2020 and the rest made under the revised mechanism announced in May 2021) and offset of payables due to KRG. The Company expects to recover the full nominal value of $76.8 million receivables owed from the KRG. Explanation of the assumptions and estimates in assessing the net present value of the deferred receivables are provided in note 1. Neither the nominal value nor the net present value includes $38 million owed to the Company for override revenue earned but not received for the period March 2020 to December 2020, which was not recognised as revenue for the reasons explained in note 1.
Sensitivities The table below shows the sensitivity of the net present value of the deferred receivables to oil price, assuming flat production and payment is received in line with the mechanism proposed by the KRG in May 2021, which is explained in note 1.
11. Cash and cash equivalents
Cash is primarily held on time deposit with major international financial institutions or in US Treasury bills.
12. Trade and other payables
Current 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. For non-current payables, liabilities are recognised at discounted fair value using the effective interest rate. Following the Bina Bawi PSC termination, other payables of $73.7 million related to Bina Bawi PSC have been derecognised which is further explained in note 1. Lease liabilities are included in other payables, further explanation is provided in note 19.
13. Deferred income
14. Provisions
Provisions cover expected decommissioning and abandonment costs arising from the Company's assets which are further explained in note 1. Reversals are related to the termination of the Miran and Bina Bawi PSCs.
15. Interest bearing loans and net cash
At 31 December 2021, the fair value of the $280 million of bonds held by third parties is $287.8 million (2020: $274.4 million).
The bonds maturing in 2025 have two financial covenant maintenance tests:
In October 2020, the Company issued a new $300 million senior unsecured bond with maturity in October 2025. The new bond has a fixed coupon of 9.25% per annum. In connection with the issue, the Company repurchased $222.9 million of its existing $300.0 million senior unsecured bond issue with maturity date in December 2022 at a price of 107 per cent. On 22 December 2020, the Company wrote to the Trustees confirming that they were exercising the right to call the remaining $77.1 million of the 2022 bond at the call price of 105 per cent. This settlement completed on 8 January 2021.
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:
All trade receivables are owed by the KRG. Cash is deposited with the US treasury or term deposits with banks that are assessed as appropriate based on, among other things, sovereign risk, CDS pricing and credit rating.
Liquidity risk The Company is committed to ensuring it has sufficient liquidity to meet its payables as they fall due. At 31 December 2021 the Company had cash and cash equivalents of $313.7 million (2020: $273.5 million, adjusted for settlement of bond debt post-year end).
Oil price risk The Company's revenues are calculated from netback price as further explained in note 1, and a $5/bbl change in average Dated Brent would result in a (loss) / profit before tax change of circa $25 million. Currency risk Other than head office costs, substantially all of the Company's transactions are denominated and/or reported in US dollars. The exposure to currency risk is therefore immaterial and accordingly no sensitivity analysis has been presented.
Interest rate risk The Company reported borrowings of $269.8 million (2020: $348.3 million) in the form of a bond maturing in October 2025, with fixed coupon interest payable of 9.25% on the nominal value of $280.0 million. Although interest is fixed on existing debts, 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 debts of the Company would result in an additional cost of circa $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 $313.7 million (2020: $354.5 million).
Financial instruments All financial assets and liabilities are measured at amortised cost. Due to their short-term nature, the carrying value of these financial instruments approximates their fair value. Their carrying values are as follows:
17. Share capital
1 Ordinary shares include 1,946,084 (2020: 2,577,720) treasury shares. Share capital includes 559,216 (2020: 3,236,109) of trust 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. Dividends
19. Right-of-use assets / Lease liabilities
The Company's right-of-use assets are related to the Sarta early production facility, offices and car leases are included within property, plant and equipment.
The weighted average lessee's incremental borrowing rate applied to the lease liabilities except Sarta early production facility was 2.5%. 4% was applied for the facility. The lease terms vary from one to five years.
Included within lease liabilities of $8.3 million (2020: $9.8 million) are non-current lease liabilities of $4.9 million (2020: $6.8 million). The identified leases have no significant impact on the Company's financing, bond covenants or dividend policy. The Company does not have any residual value guarantees. The contractual maturities of the Company's lease liabilities are as follows:
20. 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.
In 2021, 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 2021 are set out below:
The range of exercise prices for share options outstanding at the end of the period is 742.00p to 1,046.00p.
Fair value of awards granted during the year has been measured by use of the Monte-Carlo pricing model. The model takes into account assumptions regarding expected volatility, expected dividends and expected time to exercise. Expected volatility was also analysed with 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 2021 and fair values per share using the model were as follows:
The weighted average fair value for RSP awards granted in 2021 is 169p and for PSP awards granted in 2021 is 109p.
The inputs into the fair value calculation for RSP and PSP awards granted in 2020 and fair values per share using the model were as follows:
The weighted average fair value for RSP awards granted in 2020 is 119p and for PSP awards granted in 2020 is 107p.
Total share-based payment charge for the year was $5.5 million (2020: $5.8 million).
21. Capital commitments
Under the terms of its production sharing contracts ('PSC's) and joint operating agreements ('JOA's), 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.
22. Related parties
The directors have identified related parties of the Company under IAS 24 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:
There have been no changes in related parties since last year and no related party transactions that had a material effect on financial position or performance in the year.
23. Events occurring after the reporting period
On 24 February 2022 Russia invaded Ukraine. The Company is monitoring the rapidly evolving sanctions situation particularly with regard to the supply chain and the movement and trading of KRG oil.
The Company notes the majority Federal Iraq Supreme Court decision handed down on 15 February 2022 which has had no impact on our operations.
24. Subsidiaries and joint arrangements
The Company has four joint arrangements in relation to its producing assets Taq Taq, Tawke, Sarta and pre-production asset Qara Dagh. 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. The Company holds 30% working interest in Sarta PSC which is operated by Chevron. The Company holds 40% working interest in Qara Dagh PSC which is operated by the Company.
For the period ended 31 December 2021 the principal subsidiaries of the Company were the following:
1 Registered office is 7 Boulevard Latrille Cocody, 25 B.P. 945 Abidjan 25, Cote d'Ivoire 2 Registered office is 6 Hope Street, Castletown, IM9 1AS, Isle of Man 3 Registered office is Fifth Floor, 36 Broadway, Victoria, London, SW1H 0BH, United Kingdom 4 Registered office is 12 Castle Street, St Helier, JE2 3RT, Jersey 5 Registered office is PO Box 1338, Maico Building, The Valley, Anguilla 6 Registered office is Gaziosmanpasa Mahallesi Bogaz Sokak No:10 D.21 Cankaya, Ankara, Turkey 7 Registered office is PO Box 146, Road Town, Tortola, British Virgin Islands 8 Registered office is 3rd Floor, Geneva Place, Waterfront Drive, PO Box 3175, Road Town, Tortola, Virgin Islands, British
Genel Energy Finance plc was liquidated during the year.
25. Annual report
Copies of the 2021 annual report will be despatched to shareholders in April 2022 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.
26. Statutory financial statements
The financial information for the year ended 31 December 2021 contained in this preliminary announcement has been audited and was approved by the board on 14 March 2022. The financial information in this statement does not constitute the Company's statutory financial statements for the years ended 31 December 2021 or 2020. The financial information for 2021 and 2020 is derived from the statutory financial statements for 2020, which have been delivered to the Registrar of Companies, and 2021, which will be delivered to the Registrar of Companies and issued to shareholders in April 2022. The auditors have reported on the 2021 and 2020 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 2021 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 2020 annual report. |
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| ISIN: | JE00B55Q3P39, NO0010894330 |
| Category Code: | FR |
| TIDM: | GENL |
| LEI Code: | 549300IVCJDWC3LR8F94 |
| Sequence No.: | 148977 |
| EQS News ID: | 1302267 |
| End of Announcement | EQS News Service |
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