Full-year Results 2022
26 May 2023
Hurricane Energy plc
("Hurricane", the "Company", or the "Group")
Full-year Results 2022
Hurricane Energy plc, the UK based oil and gas company, announces its full-year results for the period ended 31 December 2022.
Highlights
Financial results
· Revenues of $310.8 million from six liftings of Lancaster crude (2021: $240.5 million from seven liftings)
· Cash production costs of $37.4/bbl (2021: $28.2/bbl)
· Generated $175.9 million of free cash flow†, equivalent to $56.9/bbl (2021: $135.7 million, $36.2bbl)
· Profit after tax for the period of $108.7 million (2021: $18.2 million)
· Net free cash† of $121.4 million (31 December 2021: $51.5 million)
· Full bond repayment made in July 2022 of outstanding Convertible Bonds leaving the Company debt free
Operations
· Production within guidance with average daily rate of 8,500 bopd (2021: 10,300 bopd)
· Excellent operational uptime of 97%, covering planned and unplanned events
· Crude oil sales of 3.2 Mbbls sold across six cargoes in 2022
· Agreement reached in March 2022 with Bluewater for an extension to the Bareboat Charter for the Aoka Mizu FPSO
· Following technical reassessment, the Greater Warwick Area (GWA) was relinquished in July 2022 by the GWA Joint Venture
Corporate
· In February 2022, Philip Wolfe took over from John Wright as Chairman, followed by Juan Morera being appointed as a shareholder nominated Non-Executive Director in March 2022
· In May and July 2022, Linda Beal and Robin Allan respectively were appointed to the board as Independent Non-Executive Directors
· In November 2022, following receipt of an unsolicited bid for the Company valuing each share at 7.7p which the Board concluded should not be recommended to shareholders, the Company launched a Formal Sale Process , the results of which were announced post period
Post Period
· In March, following the FSP process, the Board recommended an acquisition of the entire issued, and to be issued, share capital of the Company by Prax Exploration & Production PLC, to be effected by means of a Scheme of Arrangement under Part 26 of the Companies Act 2006 (the Scheme), valuing each share at up to 12.5 pence in total
· Shareholder and applicable regulatory approvals for the recommended acquisition were received in May 2023
· The Court Sanction Hearing to consider the Scheme is scheduled for 7 June 2023. The Scheme remains subject to certain other conditions, including sanction by the Court at the Court Sanction Hearing and the delivery of a copy of the Court Order to the Registrar of Companies. Subject to the Scheme receiving the sanction of the Court, the delivery of a copy of the Court Order to the Registrar of Companies and the satisfaction (or, where applicable, the waiver) of the other Conditions set out in Part III of the Scheme Document, the Scheme is expected to become effective on 8 June 2023.
Antony Maris, CEO of Hurricane, commented:
"2022 has been both very challenging and a highly successful year for Hurricane, whilst also an extraordinarily volatile period for our sector. During the year, the importance of domestic energy security was exacerbated by the terrible events in Ukraine and by the subsequent concerns over energy supplies across Europe resulting in surging commodity prices.
The resulting high oil price early in the year, combined with outstanding operational performance at the Company's Lancaster field, significantly strengthened Hurricane's finances. Alongside this, working closely with our FPSO operator, we delivered superb uptime performance and produced towards the upper end of our annual production guidance. The field has now produced more than 15 million barrels.
The delivery of a technically skilled and commercially efficient, debt-free Company enhanced our industry reputation and attracted outside investor interest.
All this is a great credit to the team's ability and commitment which, given the challenges of the last few years in particular, have delivered full value and a great return for Shareholders."
†Designates a non-IFRS measure. See Appendix B to this announcement for definition and reconciliation to nearest equivalent statutory IFRS measures.
Contacts:
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Hurricane Energy plc Antony Maris, Chief Executive Officer communications@hurricaneenergy.com
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+44 (0)1483 862 820 |
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Stifel Nicolaus Europe Limited Nominated Adviser & Joint Corporate Broker Callum Stewart / Jason Grossman
|
+44 (0)20 7710 7600 |
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Investec Bank plc Joint Corporate Broker Chris Sim / Jarrett Silver / Charles Craven
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+44 (0)20 7597 5970 |
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Vigo Consulting Public Relations Patrick d'Ancona / Ben Simons
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+44 (0)20 7390 0230 |
About Hurricane
Hurricane has a 100% interest in and operates the Lancaster field, the UK's first field to produce from a fractured basement reservoir.
Visit Hurricane's website at www.hurricaneenergy.com
Inside Information
This announcement contains inside information as stipulated under the market abuse regulation (EU no. 596/2014). Upon the publication of this announcement via regulatory information service this inside information is now considered to be in the public domain.
Competent Person
The technical information in this release has been reviewed by Antony Maris, Chief Executive Officer, who is a qualified person for the purposes of the AIM Guidance Note for Mining, Oil and Gas Companies. Mr Maris is a petroleum engineer with more than 35 years' experience in the oil and gas industry. He has a B.Sc.(Eng.) Petroleum Engineering (Hons) from the Imperial College of Science and Technology (University of London), Royal School of Mines A.R.S.M., and an MBA from Kingston Business School.
Standard
Reserves and Contingent Resource estimates for the Lancaster field contained in this announcement have been prepared in accordance with the Petroleum Resource Management System guidelines endorsed by the Society of Petroleum Engineers, World Petroleum Congress, American Association of Petroleum Geologists and Society of Petroleum Evaluation Engineers.
Chairman's Statement
Dear shareholder,
I am pleased to present the 2022 annual report for Hurricane Energy, the first year of my chairmanship.
2022 was a busy and important year for Hurricane, and 2023 to date has been transformational for the Company, as we hope to complete the recommended acquisition of Hurricane by Prax Exploration & Production PLC (Prax) (a wholly-owned subsidiary of State Oil Limited) imminently.
The terrible events in Ukraine provided a volatile backdrop for the energy sector throughout 2022, with sharp movements in commodity prices and an enhanced focus on security of energy supply. The imposition by the UK government of the Energy Profits Levy only added to the sense of instability for the sector.
Operationally and commercially 2022 was a strong year for the Company. Production averaged 8,500 bopd from the Lancaster field with uptime of 97%. In July 2022 we were able to pay off our outstanding convertible bonds, as a result of the excellent operational performance at the field, combined with strong oil prices. In May we welcomed Linda Beal to the Board, followed shortly thereafter with Robin Allan joining us in July. Both joined as Independent Non-Executive Directors, and have contributed superbly to our discussions since their arrivals in what has been a busy time for the Board.
Having repaid our debt and established a firmer footing, the Company considered its options in terms of increasing production at Lancaster. However, despite many months of engagement we did not receive the requisite comfort from the regulator, the NSTA, required for the very material investment proposed.
In November 2022, following receipt of an unsolicited bid for the Company valuing each share at 7.7p which the Board concluded should not be recommended to shareholders, and with our largest investor, Crystal Amber, being clear that they wished to monetise their holding in Hurricane and would not support an investment-led growth strategy, the Board launched a Formal Sale Process.
This thorough and exhaustive process culminated in the Board recommending an offer from Prax. Should the Scheme be sanctioned by the Court, I believe Hurricane has an exciting future as part of the wider Prax organisation.
During what has been an exciting but also challenging period, I would like to thank our staff, the Board and our advisors for their continuing hard work during a particularly busy and uncertain time for the Company.
Philip Wolfe
Chairman
25 May 2023
Chief Executive Officer's Review
"A year of continued strong delivery"
Introduction
2022 has been both highly challenging and a highly successful year for Hurricane, whilst also an extraordinarily volatile period for our sector. During the year, the importance of domestic energy security was exacerbated by the terrible events in Ukraine and by the subsequent concerns over energy supplies across Europe resulting in surging commodity prices. In addition, the introduction of the Energy Profits Levy in the UK, followed by a slow decline in product prices back to levels seen at the start of the year, contributed to the challenges faced by an industry with long term investment cycles.
The resulting high oil price early in the year, combined with outstanding operational performance at the Company's Lancaster field, significantly strengthened Hurricane's finances, and led to the full repayment in July 2022 of the outstanding Convertible Bonds. This represented a major milestone for our Company.
Alongside this, working closely with our FPSO operator, we delivered superb uptime performance and produced towards the upper end of our annual production guidance. The field has now produced more than 15 million barrels.
With Hurricane finally underpinned by firm financial foundations, debt-free and with significant cash in hand, we devoted more time to addressing the future of the Company, prioritising the best investment opportunities that could add significant value for shareholders. This, however, attracted attention from outside investors at a time when our largest shareholder had also indicated its desire to monetise the value of its shareholding and that it would not support an investment-led growth strategy.
Following an unsolicited offer for the Company, the Board decided to launch a Formal Sale Process (FSP), which, at the end of a thorough and exhaustive process, delivered an offer from Prax Exploration & Production PLC (Prax). The Court hearing to sanction the Scheme resulting from that offer is scheduled for 7 June 2023.
Operational review
Greater Lancaster Area (GLA)
The year saw a very strong operational performance by the Aoka Mizu FPSO at the Company's Lancaster field. The field has performed well, delivering on average 8,500 barrels of oil per day during the year- towards the upper end of our 2022 production guidance. The anticipated natural decline coupled with increased water cut, offset by high uptime, informed production levels, and these factors are expected to play their part in future field performance.
During the period there were six cargo liftings totalling 3.2 million barrels delivering revenues of $310.8 million.
Over a two-day period in May the Company conducted several flow performance tests on the P7z well that involved temporarily reducing the flow rate from the P6 well. The data obtained will be useful in refining production forecasts for P6. In September the planned annual maintenance shutdown was carried out on the Aoka Mizu with production being successfully restarted ahead of the originally anticipated timeframe.
As a condition of the approval from the Regulator for below bubble point production, renewed production, flare, and vent consents are applied for on an ongoing three-monthly basis. During December 2021, the well gauge pressure reached and declined below bubble point. No production issues arising from reaching bubble point have been observed to date. The Company continues to monitor this closely and has continued to receive the required consents from the Regulator on a three-monthly basis.
Management's production guidance for the full calendar year 2023 is 5,900 - 7,100 bopd. This assumes FPSO production planned uptime of 96.5% and production from the P6 well alone on artificial lift via an electrical submersible pump (ESP). Guidance also includes the impact of an annual maintenance shutdown, anticipated to occur during Q3 2023.
Hurricane concluded positive negotiations with Bluewater (Aoka Mizu) B.V. (Bluewater), the owner of the Aoka Mizu FPSO, with regards to an extension and announced in March 2022 that it had signed a contract with Bluewater for an extension to the Bareboat Charter beyond the original expiry date of 4 June 2022.
The key terms of the extension are:
1. The charter was extended to cover the remaining economic life of the Lancaster field.
2. Either party can give six months' notice to terminate the charter.
3. The existing day rate and tariff for the vessel remained at $75,000 per day and 8% of revenue respectively.
4. Hurricane agreed to establish a secured deposit account of up to $18.7 million for the benefit of Bluewater to cover the costs associated with the day rate for the six- month notice period and decommissioning in respect of the vessel.
This was an important step forward. It was key that Hurricane and Bluewater found a mutually acceptable deal to enable the Company to continue production beyond repayment of the Convertible Bonds.
Alongside ongoing production operations, the Company evaluated the possibility of drilling an additional production well, the P8 well. Although first discussed with the Regulators in 2021, in early 2022, when the Company recognised that not only would it clear its debt but also potentially have sufficient funds to both fully cover the cost of a new well in Lancaster and also its other operational requirements, we engaged with the Regulators concerning the unique challenges Hurricane faces.
The originally approved development plan included flaring as the approved gas disposal mechanism and, under the NSTA approval of the amendment to this plan, allowed for production below the bubble point.
The Company has worked hard to reduce its emissions and had significant success in achieving reductions through the combined hard work and efforts of our team and Bluewater. Hurricane is fully cognisant of the increased scrutiny and oversight in this area and continues to look at ways of further reducing our overall environmental footprint, where it is economically and commercially viable to do so. However, being fully aware of the challenge concerning flare volumes and the impact that any additional production would have, the Company worked tirelessly with both OPRED and the NSTA to address the environmental impact of new investment.
We believe that the project is consistent with the requirements placed upon Hurricane to maximise economic recovery as part of the OGA Strategy's Central Obligation 2a. Whilst the project would lead to a short-term increase in emissions, we also believe we are fully aligned with the OGA Strategy's Central Obligation 2b, which is to assist the Secretary of State in meeting the country's Net Zero targets.
Interaction on this latter point has been detailed, and rightly both challenging and highly scrutinised. The situation Hurricane faces is that the retrofitting of a new gas export or disposal system to the existing development is technically challenging, with a high capex requirement. The expected recovery of gas from an additional well, including the benefit of the extended life of the field, was such that the economics of the investment were below the threshold considered appropriate for Hurricane to commit to such a project.
We are fully aware of the challenge the NSTA faces in terms of the interaction between the competing objectives of maximising economic recovery whilst reducing emissions. The Company therefore offered that all incremental emissions from the new well (including those associated with the extension of the life of the field) would be covered by verifiable carbon offsetting.
The informal feedback from the NSTA during the six months of interaction was that, even where there is no technical and economically viable solution to mitigate the emissions that is reasonable in the circumstances, then the NSTA still may or may not grant the consents when requested.
The project and the level of financial commitments are of major significance to the Company, particularly given the risk associated with continued performance of the existing single well. Therefore, whilst the Company believes the proposed P8 project would be within the regulatory guidance, the Board has concluded that, in the absence of any comfort from the Regulator, the additional financial commitments to offshore equipment suppliers and the associated financial risk of proceeding with P8 was too great.
Greater Warwick Area (GWA) & Halifax
In April, the GWA Joint Venture (JV) announced that it had reassessed its understanding of the Greater Warwick area, evaluated both the basement and the Mesozoic potential of the JV's licences, and considered all options for further appraisal and routes to possible development.
In June, Hurricane reported that it had determined that further appraisal and development costs to reach an economic development on the Warwick discovery within the remaining licence term was not feasible for the Company. Further to discussions with the Company's JV partner, Spirit Energy, the JV therefore decided to relinquish the Warwick P2294 licence area. This was in addition to the previously announced decision to relinquish the Lincoln P1368(S) licence sub area.
In addition, in September 2022 the Company determined that the costs required to further evaluate the Halifax licence (P2308) and the low likelihood of a successful economic development meant that the right next step was to relinquish the licence. As with the GWA licences, there was no reasonable expectation that the P2308 licence could generate any near-term cash realisation, and therefore voluntarily relinquishing the licence at that time allowed the Company to focus its time and financial resources on alternative and more attractive opportunities. All previously capitalised costs relating to Halifax have already been impaired and therefore no further impairments were required.
We have delivered all the required information and data to the Regulator and these assets have been relinquished. Activities to close down the JV are ongoing, and this is anticipated to be completed during 2023.
Decommissioning Activities
In early 2022, in accordance with the provisions of the Petroleum Act 1998 and related guidance, Hurricane and Bluewater submitted for the consideration of the Secretary of State for Business, Energy and Industrial Strategy, a draft Decommissioning Programme for the Lancaster Field FPSO. The draft was published to allow interested parties to be consulted on such decommissioning proposals well in advance of forecast cessation of production operations.
Health and Safety
In 2022 Hurricane delivered excellent HSE performance with no Lost Time Incidents or Recordable Incidents throughout the year, and no spills to sea and no loss of containment events. The Lost Time Incident Frequency Rate (LTIFR) for 2022 was nil compared to 1.71 for 2021 and 1.29 for 2020 (figures are per million man-hours).
Throughout the year, the impact of COVID-19 on our operations reduced significantly through the effectiveness of the Government's vaccination programme and relaxation of Government and Health Protection COVID-19 Guidelines. Two occupational illness cases were recorded where occupational transmission of COVID-19 occurred. We retained offshore COVID-19 testing capability, the ability to quarantine positive cases and repatriate confirmed positive COVID-19 cases to shore via our Central Medical Emergency Dispatch (CMED) aviation provider. Where there have been any suspected or confirmed cases offshore, medics have acted promptly to ensure anyone affected was isolated and treated in conjunction with advice from Bluewater's topside doctor. Dedicated Aviation Contractor CMED flights, with attendant paramedics were retained to repatriate suspected or confirmed COVID-19 cases back to shore for further assessment and treatment where necessary. We are pleased to report that COVID-19 did not adversely affect safe operations throughout the year.
Key activities undertaken throughout the year included continued safe production from the Lancaster Field with Bluewater's Aoka Mizu FPSO, completion of our annual planned maintenance shutdown for safety and production critical maintenance, completion of the Deep Cygnus subsea inspection, repair and maintenance (IRM) scope in August 2022 and successful recovery of a fishing net left at the location of the Whirlwind well head. This enabled completion of the seabed clearance at Whirlwind 205/21-5. All this work was completed without incident.
ESG
Despite the challenges the year has provided, Environmental, Social and Governance ("ESG") remains a key area of scrutiny in the Company. In June 2022, Hurricane published its third standalone ESG report, covering the approach to ESG and performance across its operations for the 2021 calendar year.
During 2022, our Scope 1 greenhouse gas emissions were 110,576 tonnes CO₂e, or 35.8 kg/bbl on an intensity basis. This compared with 139,584 tonnes CO₂e, or 37.2 kg/bbl in 2021, and 210,884 tonnes CO₂e and 41.5 kg/bbl in 2020.
These emissions meet the OEUK Scope 1 definition and include CO₂ as well as other greenhouse gases specified by the Kyoto Protocol. These figures are based on Intergovernmental Panel on Climate Change's (IPCC) Fifth Assessment report.
Currently, associated gas production from the Lancaster EPS is partially used as fuel gas for the Aoka Mizu FPSO, with the remainder flared under the consent within the approved Field Development Plan Addendum. We remain fully cognisant of the increased scrutiny and oversight in this area and are committed to continuing to look at ways of further reducing this figure and our overall environmental footprint in 2023 and beyond where it is economically and commercially viable to do so.
Reserves and resources
Since 2021, following the complete re-evaluation of the Lancaster field and its performance, the Company has been consistently in line with its production guidance, announced annually, and its cost base has been very stable year on year, rising mainly as a result of inflationary pressures.
This demonstrates an excellent understanding of what we have and how to extract it safely, efficiently and at the best value. In addition, based on our performance and interaction with them, the NSTA has agreed, without the need for a lengthy process to amend the formal Field Development Plan, to increase the pressure below the bubble point we can produce to - up to 600 psi from 300 psi.
This change in our depletion management regime and the incorporation of the oil volumes potentially present in the Victory and Rona sandstones, which onlap the Lancaster field, has allowed the transfer to Reserves of some of our Contingent Resources and to extend field life.
Hurricane elected to retain ERC Equipoise Limited (ERCE) to update its Competent Person's Report (CPR) on the Reserves and Contingent Resources of the Lancaster field, published on 16 March 2023 with an effective date of 31 December 2022, which included an asset valuation by ERCE. Their estimates of Lancaster field Reserves and the Contingent Resources are detailed in the tables below.
While the latest CPR shows an increase in the reserves, these reserves will largely be produced in the "tail" so are low contributors to value. We will continue to review trends in production decline, pressure, and water cut that may impact future production and the level of reserves.
In the ERCE CPR, ERCE has evaluated the Reserves for the field, assuming the effective date of 31 December 2022. The estimates of Reserves and the economic limit in each case are summarised in the table below.
|
Hurricane |
Gross Reserves |
Net Attributable Reserves |
||||
|
100% and operator |
1P |
2P |
3P |
1P |
2P |
3P |
|
Reserves (MMstb) |
4.1 |
6.6 |
10.3 |
4.1 |
6.6 |
10.3 |
|
Economic Limit |
Dec-2024 |
Feb-2026 |
Nov-2027 |
Dec-2024 |
Feb-2026 |
Nov-2027 |
A summary of the movements in net attributable 2P Reserves as compared to the previous CPR (effective date of 31 December 2021) is as follows:
|
|
Net attributable 2P Reserves (MMbbl) |
|
At 31 December 2021 |
5.8 |
|
Produced volumes in 2022 |
(3.1) |
|
|
|
|
Change in assumptions and economic life |
3.9 |
|
At 31 December 2022 |
6.6 |
ERCE has also updated its estimates of 2C Resources (Development Unclarified), which require further drilling to convert to Reserves. These are set out in the table below:
|
Hurricane |
Gross Contingent Resources |
Net Attributable Contingent Resource |
|||||
|
100% |
1C |
2C |
3C |
1C |
2C |
3C |
|
|
Lancaster |
(MMstb) |
(MMstb) |
(MMstb) |
(MMstb) |
(MMstb) |
(MMstb) |
|
|
|
8.3 |
31.6 |
82.7 |
8.3 |
31.6 |
82.7 |
|
New Business Opportunities
In addition to considering investing further in the Lancaster Field, the Company has been actively pursuing potential opportunities outside the Company's current asset base.
Focusing on the UKCS, the Company has continued to evaluate a number of farm in opportunities, acquisitions and mergers. Hurricane's management and staff have extensive experience in both oil and gas, through all stages of the asset life-cycle, and therefore the scope covered a range of new oil and gas investment opportunities. Should the Prax transaction complete, we will continue to look for both asset and corporate level opportunities that will help diversify our asset base, deliver value to shareholders, and strengthen the Company for the future.
Despite the volatility in commodity prices, and the uncertainties these create, Hurricane believes that its strong balance sheet, technical and operational expertise, and proven track record of capital project delivery offer a strong competitive advantage among its peer group.
Formal Sale Process
Following receipt of an unsolicited offer in mid-2022 and after a period of engagement with the offeror, Hurricane received a follow-up offer from that offeror which the Hurricane Board concluded should not be recommended to Hurricane Shareholders. Thereafter, on 2 November 2022, Hurricane announced the initiation of a FSP, to establish whether there was a bidder prepared to offer a value that the Hurricane Board considered to be attractive, relative to the standalone prospects of Hurricane as a publicly traded company and accordingly one that should be recommended to all Hurricane Shareholders. The Board appointed Stifel Nicolaus Europe Limited as its independent financial adviser with regards to the FSP.
The FSP was marketed to a wide audience of potential acquirors with an interest in acquiring assets on the UK Continental Shelf. This process culminated in the Board recommending an offer from Prax Exploration & Production PLC, (a wholly-owned subsidiary of State Oil Limited) which is a leading, British headquartered, international integrated and diversified midstream and downstream energy group. Full details of the recommended offer were published in the Scheme Document on 6 April 2023 and are available on Hurricane's website.
Reduction of Capital
Alongside the FSP, the Company also committed, that if the FSP did not result in a transaction, to commence a significant capital return programme with up to $70 million to be returned to shareholders in Q1 2023, upon completion of a Reduction of Capital.
The High Court approved the Reduction of Capital on 31 January 2023 with the sealed court order subsequently filed with the Registrar of Companies. This completed the Reduction of Capital process, allowing the Company to make capital returns to shareholders and supporting the FSP.
People and operations
This year has been another challenging one and I would also like to express my thanks to all our colleagues for their hard work, professionalism, and dedication. Hurricane's operational delivery since start-up of the Lancaster field has been first class. What would normally be many months of work on the technical review and development options screening was compressed into a much shorter timeframe without compromising on rigour or quality. The understanding of the field's performance has grown as has our rebuilding an excellent working relationship with the regulator, who recently commended Hurricane for excellent performance.
Since 2021, following the complete re-evaluation of the field and its performance, the Company has been consistently in line with its production guidance, announced annually, and its cost base has been very stable year on year through the hard work of the team to reduce and remove cost pressures, rising mainly as a result of macro-inflationary pressures.
Following the Government's relaxation of COVID-19 precautionary measures, we reopened the office in February 2022, returning to a hybrid working arrangement preserving some measure of home working. However, we have not forgotten the lessons learnt from the pandemic where we actively encouraged flexible working recognising that employees may have responsibility for childcare, home schooling, family members as well as other obligations. We continue to look at what works best as greater pressures for more interactive office-based work grows.
Outlook
When I joined Hurricane, my priority, working closely with the senior team, was to focus on creating value for shareholders despite the huge technical and financial challenges we faced. The offer from Prax shows how well we, as a team, have done.
Technically, we have demonstrated excellent operational understanding and found ways to improve recovery despite the financial limitations. Commercially, we have cleared our debt, provided a firm financial footing for assessing future opportunities and kept control of our costs despite inflationary pressures.
All this has built an excellent reputation across our industry and attracted outside investors wanting to take advantage of what could we bring to them.
Antony Maris
Chief Executive Officer
25 May 2023
Chief Financial Officer's Review
"A year of continued recovery and consolidation"
Highlights
|
|
2022 |
2021 |
|
Production |
3,089 Mbbl |
3,748 Mbbl |
|
Production rate* |
8,500 bopd |
10,300 bopd |
|
Sales volumes |
3,226 Mbbl |
3,576 Mbbl |
|
Revenue |
$310.8m |
$240.5m |
|
Average sales price realised |
$96.3/bbl |
$67.3/bbl |
|
Cash production cost per barrel† |
$37.4/bbl |
$28.2/bbl |
|
Free cashflow† |
$175.9m |
$135.7m |
|
Net free cash† |
$121.4m |
$51.5m |
|
Net debt† |
NIL |
$27.0m |
|
Underlying profit before tax† |
$113.6m |
$10.8m |
|
Statutory profit after tax |
$108.7m |
$18.2m |
* Rounded to nearest 100 bopd
† Non-IFRS measures. See Appendix B to the Financial Statements for definition and reconciliation to nearest equivalent statutory IFRS measures.
Overview
2022 was a year of continued recovery and consolidation for Hurricane. The first half of 2022 was an extraordinarily volatile period for our sector due to surging oil prices, exacerbated by the terrible events in Ukraine. Oil prices in the second half of 2022, whilst lower than the levels seen earlier in the year remained above $80 per barrel on a near continuous basis. The high oil price for the year, combined with excellent operational uptime of the Aoka Mizu FPSO at the Lancaster field, has continued to strengthen Hurricane's finances.
Over 3.2 million barrels of Lancaster crude were sold across six cargoes, generating $310.8 million revenue. This increase compared to 2021 is thanks to the strong oil prices seen in 2022 compared to 2021 which have helped to offset the impact of the lower level of production. This, combined with a continued focus on low operating costs and excellent production efficiency of 99%, produced free cashflow† of $175.9 million. Cash capex† in the year was $10.3 million.
Hurricane completed its repayment of Convertible Bonds during the year, with a final payment of $78.5 million being made in July 2022. At 31 December 2022, Hurricane was debt free with a net free cash† balance of $121.4m.
Although uncertainties remain, with oil prices still supportive and a debt free position, Hurricane is in a strong financial position.
Revenue
Revenue recognised for the year was $310.8 million (2021: $240.5 million), with an average realised price of $96.3/bbl (2021: $67.3/bbl) across 6 cargoes comprising 3.2 million barrels (2021: 7 cargoes comprising 3.6 million barrels). Whilst the average Dated Brent price for the year was $101.3/bbl, under the sales and marketing agreement Hurricane has in place with BP, the sale of Lancaster crude is priced by reference to the average of either the Dated Brent price of first or last five days in the month of lifting (at the buyer's option, declared by the 20th of the month). This arrangement means that the reference Dated Brent price for a cargo is typically lower than the spot price at the time of lifting. The lower number of cargoes reflects not only the declining rate of production, but also, where possible, maximising cargo sizes in 2022 to minimise transportation costs per barrel.
The average netback to the contractual Brent price was $2.7/bbl (2021: $2.7/bbl), representing the discount or premium offered by the refinery purchasing the crude, BP's marketing fee, and the freight and port costs incurred by the buyer in transporting Lancaster crude to its ultimate destination. The excellent FPSO uptime achieved means that Hurricane has continued to sell all cargoes on time, within specification and contractual terms, maintaining our reputation as a reliable producer. The sales arrangement with BP means that Hurricane receives cash for a sale typically within five days of the lifting occurring.
Cost of sales
Total cost of sales was $173.4 million, including $81.9 million of DD&A. Cash production costs† were $115.4 million (2021: $105.8 million), equivalent to $37.4 per barrel (2021: $28.2/bbl).
Excluding the revenue-linked incentive tariff, cash production costs per barrel increased from $22.8/bbl in 2021 to $29.3/bbl in 2022. This increase per barrel was driven by lower average production rates in 2022 as well as cost inflation. With a cost base that is largely fixed (i.e. not linked to production rates), natural decline in production and inflationary cost pressures, we expect cash production costs per barrel to increase during 2023; although we continue to look for cost savings internally and with our key contractors where possible.
Impairment of intangible assets and GWA licences
The overall strategic intent of the GWA Joint Venture has previously been the exploration and appraisal of the GWA licence areas, to assess hydrocarbon resource and commercially producible reserves, with the aim of producing reserves and ultimately identifying a fit for purpose field development in line with the GWA Joint Venture objectives and MER UK.
Hurricane together with its joint venture partner Spirit Energy has determined that further appraisal and development costs to reach an economic development on the discoveries in the GWA area within the remaining licence terms is not feasible, and the licences for P1368(S) (Lincoln asset) and P2294 (Warwick asset) were therefore relinquished in July 2022.
In anticipation of the licence Lincoln P1368(S) relinquishment, the carrying value of the Lincoln assets was fully impaired in 2021, resulting in an impairment charge of $54.3 million in that year. The GWA Joint Venture decision to surrender the Warwick P2294 licence subarea gives rise to an impairment charge of $4.1 million for the current year and the carrying value of the Warwick assets has therefore now also been fully impaired.
The aim going forward into 2023 is to bring the GWA JV to an orderly conclusion, with the main activity being the ongoing storage and disposal of joint property.
FPSO lease
In March 2022, Hurricane announced it had concluded an agreement with Bluewater to extend the charter of the Aoka Mizu FPSO beyond June 2022. The key terms of the agreement included:
· either party can give six months' notice to terminate the charter;
· the existing day rate and tariff for the vessel remains at $75,000 per day and 8% of revenue respectively; and
· Hurricane agrees to establish a secured deposit account of up to $18.7 million for the benefit of Bluewater to cover the costs associated with the day rate for the six-month notice period and decommissioning in respect of the vessel.
The revised agreement therefore gives Hurricane the security and flexibility to cover production from the Lancaster field for its remaining economic life, which is forecast to be until August 2025. For the purposes of accounting for the lease under IFRS 16, the lease term as been re-assessed to this date. This has resulted in an increase in the lease liability and corresponding lease asset.
Convertible Bond and debt management
During the second half of 2021, Hurricane completed a series of Convertible Bond buybacks leaving an amount of $78.5 million outstanding at 31 December 2021. This amount was repaid in July 2022, resulting in Hurricane now being in a debt free position.
Net debt and net free cash evolution:
The above chart shows net free cash of $52 million at 31 December 2021 which, after deducting Convertible Bond debt of $79 million shows a net debt position of $27 million at that date. Further to the payment of remaining element of the Convertible Bond debt in July 2022, the net debt position was cleared.
Other profit and loss
Net general and administrative costs (G&A) before non-cash items reduced from $23.6 million in 2021 to $8.7 million in 2022. This decrease was primarily due to significant expenditures having been incurred on the proposed financial restructuring during 2021, as well as the Group implementing cost saving measures such as the right-sizing of headcount (via recruitment freezes and targeted redundancies) by the end of that year.
Cashflow
Net free cash† bridge
1. Including transaction costs
† Non-IFRS measure. See Appendix B to the Financial Statements for definition and reconciliation to nearest equivalent statutory IFRS measure(s).
The Group ended the year with $121.4 million of net free cash†, an increase of $69.9 million from the position of $51.5 million at 31 December 2021.
Free cash flow† for the year was $175.9 million (2021: $135.7 million), equivalent to $56.9/bbl (2021: $36.2/bbl), driven by higher average realised Brent prices offset by the increase in day rate payable (from $25,000 to $75,000 per day) for the Aoka Mizu charter which became effective from June 2021. Cash capex† in the period was $10.3 million.
Restricted funds
As of 31 December 2022, the Group held $60.8 million of cash within restricted funds, relating to decommissioning security arrangements and amounts set aside to cover costs associated with the FPSO lease.
At the start of the year, the Group held £28.0 million ($37.8 million) in trust as security for its decommissioning liability on the Lancaster field, which includes the cost of abandoning the production wells, subsea infrastructure and related FPSO costs. During the year, an additional £5.7 million was placed into Trust following a request from the Regulator as a result of increases to the Group's decommissioning estimates. At 31 December 2022, a total of £33.7 million ($40.6 million) was held in trust as decommissioning security for the Lancaster EPS.
Included within restricted cash, cash equivalents and liquid investments is $20.2 million (2021: $7.9 million) set aside in relation to the Aoka Mizu FPSO bareboat charter. This amount was established and classified as restricted cash following the agreement in March 2022 to extend the FPSO lease. Under the terms of the contract, the Group is required to ring-fence amounts to ensure it could meet its liability to the lessor if the contract is terminated by the Group or the lessor. The $20.2 million amount consists of an original amount of $18.7m originally agreed with the lessor on extension of the lease in March 2022, with an additional $1.5 million subsequently being agreed to be set aside.
Tax
The Group recognised a total net tax charge for 2022 of $1.7 million.
Included in the net tax charge for the period is a tax charge of $6.2 million relating to the Energy (Oil and Gas) Profits Levy Act 2022 (EPL), which was introduced and took effect for profits generated from 26 May 2022 onwards at a rate of 25%.
Offsetting the EPL charge is a credit of $4.6 million representing amounts received in respect of R&D claims during 2022. Hurricane previously made claims for R&D tax credits in respect of financial years 2019 and 2020, including via the surrender of some brought forward tax losses, being R&D spend related to increasing reservoir understanding of fractured basement and optimising productivity and reserves recovery.
Tax losses
Due to the nature of the Group's business, it has accumulated significant tax losses since incorporation. The Group has $214.5 million of ring-fenced trading losses (including certain RDEC credits) and other allowances and supplementary charge losses and investment allowances of $629.8 million, which have no expiry date and would be available for offset against future trading profits, and $333.1 million of capital allowances available against future ring-fenced trading profits. The estimated value of these losses and allowances at prevailing tax rates, including the Group's pre-trading expenditure, future decommissioning costs and non-ring fence losses, is $428.3 million. See note 6.3 in the Financial Statements for further information.
Access to these losses and allowances is likely to be severely restricted at the point at which trading activities end (which would include a permanent cessation of production from the Lancaster EPS). Furthermore, in the event of any corporate transaction, access to the brought forward losses may be restricted if trade was deemed negligible at the point of a change in control or there was deemed to be a major change in the nature or conduct of the entity's trading activities. Furthermore, at prevailing oil prices, the Group will continue to utilise its existing ring fence losses as the Lancaster EPS generates taxable profits.
Going concern
The Directors have considered both the going concern and longer-term prospects of the Group, and have a reasonable expectation that the Group will continue in operational existence throughout the going concern period. For further details and analysis, see the Going Concern section of the Strategic Report.
Richard Chaffe
Chief Financial Officer
25 May 2023
Going concern and the Group's longer-term prospects
Going concern
The Group's business activities, together with the factors likely to affect its future development, performance and position are set out in this Strategic Report. The Group ended the year with $199.1 million of cash and cash equivalents, of which $138.4 million was unrestricted. After adjusting for working capital items, net free cash† at 31 December 2022 was $121.4 million. The Group's most significant long-term liabilities are committed lease liabilities in respect of the Aoka Mizu FPSO, following the final repayments in respect of the Convertible Bond having been made in July 2022.
Further details of the financial position of the Group, its cash flows and liquidity position are described in the Chief Financial Officer's Review; with the Group's off- and on-balance sheet commitments set out in notes 2.7 and 5.3 of the Group Financial Statements. In addition, note 5.8 to the Group Financial Statements includes the Group's objectives, policies and processes for managing its capital; and note 4.4 includes the Group's objectives concerning its financial risk management objectives; details of its financial instruments; and its exposures to credit, market and liquidity risk.
The Group monitors its capital position and its liquidity risk regularly throughout the year, with cashflow models and forecasts regularly produced and refreshed based on production profiles, latest estimates of oil prices, operating and G&A budgets, working capital assumptions, movements to and from restricted funds, and the Group's debt repayments. Sensitivities are run to reflect different scenarios including changes in reservoir performance, movements in oil price and changes to the timing and/or quantum of capital expenditure projects.
Assessment of going concern
Whilst each of the Principal Risks, which will be outlined in the 2022 Annual Report, has a potential impact on the business, the Directors' assessment of going concern focused on those that are the most critical to the Group's prospects, which are considered to be:
· Production delivery risks;
· FPSO and third-party infrastructure risks; and
· Oil price volatility
The Group's base case going concern assessment assumed the following:
· average Dated Brent oil price of $75/bbl in 2023 and $73/bbl in 2024;
· no sanctioned capital or development projects;
· continued use of the Aoka Mizu FPSO throughout the assessment period; and
· production from the P6 well alone in line with approved guidance and the production profiles consistent with the most recent CPR
· a return of cash by the Company to its shareholders in the form of either
o a dividend of £103 million being paid to shareholders following the agreement reached on the terms of a recommended acquisition of the Company's entire issued ordinary share capital by Prax Exploration & Production PLC (the terms and details of the recommended offer are set out in the Scheme Document, with completion of the acquisition being subject to court sanction)
o in event that the above acquisition is not completed, a return of $70 million to its shareholders
Under the base case scenario, the Group had sufficient headroom for a period of at least 12 months to fund ongoing working capital requirements.
Sensitivity analyses were also undertaken to reflect the following:
· a reduction to the forecast oil price curve of $20/bbl; and
· a 20% reduction to forecast production rates
Under the sensitivity cases above, both individually and in aggregate, the Group is projected to have sufficient cash to continue operating for a period of at least 12 months.
Reverse stress tests were also prepared to reflect additional adverse reductions in oil price and production to determine at what price or rate each would need to reduce to such that the Group would not have sufficient cash to continue operating for a period of at least 12 months. In the opinion of management, the likelihood of such a fall in price and/or production rate that would give rise to an inability to continue to operate over this period is remote.
Conclusion
As a result of the going concern assessment presented above, the Directors have a reasonable expectation that, taking into consideration the current macroeconomic situation, the Group has adequate resources to continue in operational existence throughout the going concern period.
Therefore, the Directors continue to adopt the going concern basis of accounting in preparing these consolidated financial statements and the financial statements do not include the adjustments that would result if the Group were unable to continue as a going concern.
Assessment of the Group's longer-term prospects
The longer-term prospects of the Group are driven by its strategy and business model, whilst factoring in the Group's principal risks and uncertainties.
Assessment of the business is performed over a number of different time periods for differing reasons, which include an annual budget cycle (with reforecasts made as appropriate during the year) and a long-term corporate model which incorporates the latest annual budget and provides forecast cash flow detail, where appropriate, on a field-by-field basis along with cash flows incurred and generated at a corporate level. These forecasts take into account the level of unrestricted cash and cash equivalents at the latest practicable date of preparation of this review, together with the forecast cash flow generation from the Lancaster EPS (based on expected production rates and oil prices as outlined above).
Extending the base case assessment (using average Dated Brent oil prices of $75/bbl in 2023 and $73/bbl in 2024), and on the key assumption that neither the Group nor Bluewater exercises their respective termination options over the bareboat charter of the Aoka Mizu FPSO earlier, the Group is projected to continue generating positive cashflows from operations until approximately the third quarter of 2025.
As the Group is able to exit the FPSO charter giving six-months notice and incurring no termination penalties, it has additional flexibility should oil price and/or production rate give rise to a significantly shorter than expected remaining economic life of the Lancaster EPS, or other factors mean the EPS was operating significantly below break-even level. Furthermore, the Group has placed significant funds in Trust as security to cover estimated decommissioning liabilities for the EPS and FPSO.
Hurricane Energy plc
Group Financial Statements 2022
Group Statement of Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
Year ended |
|
Year ended |
|
|
Notes |
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
|
|
$'000 |
|
$'000 |
|
|
|
|
|
|
|
|
Revenue |
2.1 |
|
310,776 |
|
240,540 |
|
Cost of sales |
2.2 |
|
(173,421) |
|
(173,125) |
|
Gross profit |
|
|
137,355 |
|
67,415 |
|
General and administrative expenses |
3.3 |
|
(9,355) |
|
(26,749) |
|
Gain on revision of lease term |
5.2 |
|
- |
|
49,125 |
|
Impairment of oil and gas assets |
2.3 |
|
- |
|
- |
|
Change in decommissioning estimates on fully impaired assets |
2.5 |
|
1,032 |
|
(1,972) |
|
Impairment of intangible exploration and evaluation assets and exploration expense written off |
2.4 & 4.3 |
|
(4,234) |
|
(54,280) |
|
Operating profit |
|
|
124,798 |
|
33,539 |
|
Finance income |
3.2 |
|
1,174 |
|
27 |
|
Finance costs |
3.2 |
|
(15,623) |
|
(30,656) |
|
Net gain on repurchase of Convertible Bonds |
5.1 |
|
- |
|
17,201 |
|
Fair value gain / (loss) on Convertible Bond embedded derivative |
5.1 |
|
27 |
|
(1,901) |
|
Profit before tax |
|
|
110,376 |
|
18,210 |
|
Tax |
6.1 |
|
(1,715) |
|
26 |
|
Total comprehensive profit for the year |
|
|
108,661
|
|
18,236 |
|
|
|
|
|
|
|
|
|
|
|
Cents |
|
Cents |
|
Earnings per share - basic and diluted |
3.1 |
|
5.46 |
|
0.92 |
All results arise from continuing operations.
Group Statement of Financial Position
|
|
|
|
|
|
|
|
|
Notes |
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
|
|
$'000 |
|
$'000 |
|
Non-current assets |
|
|
|
|
|
|
Intangible exploration and evaluation assets |
2.4 |
|
− |
|
3,830 |
|
Oil and gas assets |
2.3 |
|
99,593 |
|
98,296 |
|
Other non-current assets |
7.2 |
|
1,044 |
|
1,373 |
|
Deferred tax assets |
6.2 |
|
− |
|
104 |
|
Cash and cash equivalents |
4.1 |
|
60,754 |
|
− |
|
Liquid investments |
4.1 |
|
− |
|
37,783 |
|
|
|
|
161,391 |
|
141,386 |
|
Current assets |
|
|
|
|
|
|
Inventory |
2.2 |
|
26,430 |
|
27,488 |
|
Trade and other receivables |
4.2 |
|
3,675 |
|
2,591 |
|
Cash and cash equivalents |
4.1 |
|
138,383 |
|
76,792 |
|
|
|
|
168,488 |
|
106,871 |
|
Total assets |
|
|
329,879 |
|
248,257 |
|
Current liabilities |
|
|
|
|
|
|
Trade and other payables |
4.3 |
|
(15,887) |
|
(18,843) |
|
Lease liabilities |
5.2 |
|
(27,612) |
|
(13,880) |
|
Convertible Bond liability |
5.1 |
|
− |
|
(77,373) |
|
Convertible Bond embedded derivative |
5.1 |
|
− |
|
(27) |
|
Tax liabilities |
6.1 |
|
(3,617) |
|
− |
|
|
|
|
(47,116) |
|
(110,123) |
|
Non-current liabilities |
|
|
|
|
|
|
Lease liabilities |
5.2 |
|
(39,878) |
|
(1,910) |
|
Decommissioning provisions |
2.5 |
|
(47,057) |
|
(49,346) |
|
|
|
|
(86,935) |
|
(51,256) |
|
Total liabilities |
|
|
(134,051) |
|
(161,379) |
|
Net assets |
|
|
195,828 |
|
86,878 |
|
Equity |
|
|
|
|
|
|
Share capital |
5.4 |
|
2,885 |
|
2,885 |
|
Share premium |
|
|
822,458 |
|
822,458 |
|
Share option reserve |
5.5 |
|
23,321 |
|
23,321 |
|
Own shares reserve |
5.6 |
|
(556) |
|
(845) |
|
Foreign exchange reserve |
5.7 |
|
(90,828) |
|
(90,828) |
|
Accumulated deficit |
|
|
(561,452) |
|
(670,113) |
|
Total equity |
|
|
195,828 |
|
86,878 |
The Financial Statements of Hurricane Energy plc were approved by the Board and authorised for issue on 25 May 2023. They were signed on its behalf by:
Antony Maris, Chief Executive Officer
Group Statement of Changes in Equity
|
|
|
|
Share |
|
Foreign |
|
|
|
|
Share |
Share |
option |
Own shares |
exchange |
Accumulated |
|
|
|
capital |
premium |
reserve |
reserve |
reserve |
deficit |
Total |
|
|
$'000 |
$'000 |
$'000 |
$'000 |
$'000 |
$'000 |
$'000 |
|
At 1 January 2021 |
2,885 |
822,458 |
21,443 |
(923) |
(90,828) |
(688,349) |
66,686 |
|
Total comprehensive profit for the year |
− |
− |
− |
− |
− |
18,236 |
18,236 |
|
Share-based payments |
− |
− |
1,878 |
78 |
− |
− |
1,956 |
|
At 31 December 2021 |
2,885 |
822,458 |
23,321 |
(845) |
(90,828) |
(670,113) |
86,878 |
|
Total comprehensive profit for the year |
− |
− |
− |
− |
− |
108,661 |
108,661 |
|
Share-based payments |
− |
− |
− |
289 |
− |
− |
289 |
|
At 31 December 2022 |
2,885 |
822,458 |
23,321 |
(556) |
(90,828) |
(561,452) |
195,828 |
Group Cash Flow Statement
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended |
|
Year ended |
|
|
|
Notes |
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
|
|
|
$'000 |
|
$'000 |
|
|
|
|
|
|
|
|
|
Cash flows from operating activities |
|
|
|
|
|
|
|
Operating profit |
|
|
|
124,798 |
|
33,539 |
|
Adjustments for: |
|
|
|
|
|
|
|
Depreciation of property, plant and equipment |
|
2.3 |
|
82,184 |
|
98,099 |
|
Change in decommissioning estimates on fully impaired assets |
|
2.5 |
|
(1,032) |
|
1,972 |
|
Impairment of intangible exploration and evaluation assets and exploration expense written off |
|
2.4 & 4.3 |
|
4,234 |
|
54,280 |
|
Gain on revision of lease term |
|
5.2 |
|
− |
|
(49,125) |
|
Impairment of other right-of-use assets |
|
7.2 |
|
− |
|
719 |
|
Share-based payment charge |
|
3.3 |
|
289 |
|
1,956 |
|
Expenditure on proposed financial restructuring |
|
|
|
− |
|
15,903 |
|
Decommissioning spend |
|
2.5 |
|
(277) |
|
(4,824) |
|
Operating cash flow before working capital movements |
|
|
|
210,196 |
|
152,519 |
|
Movement in receivables |
|
|
|
(2,365) |
|
579 |
|
Movement in payables |
|
|
|
(3,909) |
|
5,356 |
|
Movement in crude oil, fuel and chemicals inventories |
|
2.2 |
|
2,087 |
|
(11,410) |
|
Cash used in operating activities |
|
|
|
206,009 |
|
147,044 |
|
Energy Profits Levy paid |
|
|
|
(2,582) |
|
− |
|
Net cash inflow from operating activities |
|
|
|
203,427 |
|
147,044 |
|
|
|
|
|
|
|
|
|
Cash flows from investing activities |
|
|
|
|
|
|
|
Interest received |
|
|
|
1,174 |
|
27 |
|
Movement in liquid investments |
|
|
|
34,739 |
|
(15,530) |
|
Expenditure on oil and gas assets |
|
|
|
(8,328) |
|
(6,618) |
|
Expenditure on other fixed assets |
|
|
|
− |
|
(2) |
|
Expenditure on intangible exploration and evaluation assets |
|
|
|
(699) |
|
(2,782) |
|
Movement in spares and supplies inventories |
|
2.2 |
|
(1,029) |
|
(4,793) |
|
R&D tax refund |
|
|
|
4,588 |
|
− |
|
Net cash used in investing activities |
|
|
|
30,445 |
|
(29,698) |
|
|
|
|
|
|
|
|
|
Cash flows from financing activities |
|
|
|
|
|
|
|
Repurchases of Convertible Bond principal for cancellation |
|
5.1 |
|
− |
|
(130,346) |
|
Convertible bond principal repayment |
|
5.1 |
|
(78,515) |
|
− |
|
Transaction costs |
|
5.1 |
|
(5) |
|
(1,311) |
|
Convertible Bond interest paid |
|
5.1 |
|
(4,416) |
|
(17,372) |
|
Lease repayments |
|
5.2 |
|
(27,837) |
|
(18,596) |
|
Interest and other finance charges paid |
|
|
|
(13) |
|
(34) |
|
Expenditure on proposed financial restructuring |
|
|
|
− |
|
(15,903) |
|
Net cash used in financing activities |
|
|
|
(110,786) |
|
(183,562) |
|
Net increase / (decrease) in cash and cash equivalents |
|
|
|
123,086 |
|
(66,216) |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year |
|
4.1 |
|
76,792 |
|
143,703 |
|
Net increase / (decrease) in cash and cash equivalents |
|
|
|
123,086 |
|
(66,216) |
|
Effects of foreign exchange rate changes |
|
|
|
(741) |
|
(695) |
|
Cash and cash equivalents at end of year |
|
4.1 |
|
199,137 |
|
76,792 |
|
|
|
|
|
|
|
|
Notes to the Group Financial Statements
for the year ended 31 December 2022
Section 1. General information and basis of preparation
Hurricane Energy plc is a public company, limited by shares, incorporated and domiciled in the United Kingdom and registered in England and Wales under the Companies Act 2006 (registered company number 05245689). The nature of the Group's operations and its principal activity is exploration, development and production of oil and gas reserves on the UK Continental Shelf.
1.1 Basis of preparation and consolidation
The Financial Statements have been prepared under the historical cost convention (except for derivative financial instruments which have been measured at fair value) in accordance with UK-adopted International Accounting Standards in conformity with the requirements of the Companies Act 2006 and in accordance with the requirements of the AIM Rules.
The Group Statement of Comprehensive Income and related notes represent results from continuing operations, there being no discontinued operations in the years presented.
The consolidated Financial Statements incorporate the Financial Statements of the Company and entities controlled by the Company (its subsidiaries) made up to 31 December each year. Control is achieved when the Company:
· has power over the investee;
· is exposed, or has rights, to variable returns from its involvement with the investee; and
· has the ability to use its power to affect its returns.
All intragroup transactions, balances, income and expenses are eliminated on consolidation.
The Group's joint arrangement with Spirit Energy Limited (Spirit) is accounted for as a joint operation (where the parties have rights to the assets and obligations for the liabilities of that arrangement). As such, in relation to its interests in the joint operation, the Group recognises its assets, liabilities, revenues and expenses of the joint operation, including its share of any jointly held or incurred assets, liabilities, revenues and expenses. These have been incorporated in the Financial Statements under the relevant headings. Details of this joint operation are set out in note 2.6.
In the opinion of the directors, the operations of the Group comprise one segment of business, being oil and gas exploration, development and production together with related activities in only one geographical area, the UK Continental Shelf.
1.2 Going concern
The Financial Statements have been prepared in accordance with the going concern basis of accounting. The forecasts and projections made in adopting the going concern basis take into account forecasts over oil prices, production rates, operating and G&A expenditure, and committed and sanctioned capital expenditure. In addition, sensitivity and reverse stress test analyses have been considered. Further details on the going concern assessment undertaken are outlined in the Going Concern section of the Strategic Report which confirms the directors have a reasonable expectation that, taking into consideration the current macroeconomic situation, the Group has adequate resources to continue in operational existence throughout the going concern period. Therefore, the directors continue to adopt the going concern basis of accounting in preparing these consolidated financial statements and the financial statements do not include the adjustments that would result if the Group were unable to continue as a going concern.
1.3 Significant events and changes in the period
The financial performance and position of the Group was significantly affected by the following events and changes during the year:
· Significant increase in revenue versus the prior year due to the continued strong recovery in crude oil prices;
· Fully repaying the remaining $78,515,000 Convertible Bond debt plus $1.5 million of accrued interest (note 5.1);
· An increase in the lease liabilities and right-of-use assets relating to the Aoka Mizu FPSO resulting from a renegotiation of the bareboat charter of the Aoka Mizu FPSO and increase in the lease term assumption against a background of higher oil prices, consistent performance on Lancaster and a change to the expected cessation of production (CoP) date from June 2024 to August 2025 (notes 2.3 and 5.2); and
· Impairments of intangible exploration and evaluation assets of $5.7 million following the decision to relinquish the Lincoln (P1368(S)) and Warwick (P2294) licences during the period. The exploration and evaluation assets within Halifax licence P2308 have been fully impaired in the year (note 2.4.1).
For further discussion about the Group's performance and financial position, see the Chief Executive Officer's Review and Chief Financial Officer's Review.
1.4 Foreign currencies and translation
These consolidated Financial Statements are presented in US Dollars, which is the Company's functional and presentation currency, and rounded to the nearest thousand unless otherwise stated. The functional currency is the currency of the primary economic environment in which the Group operates, as a significant proportion of expenditure and all of its current revenue is priced in US Dollars. All trading entities within the Group have a US Dollar functional currency.
Transactions in foreign currencies are recorded at the rates of exchange ruling at the transaction dates. Monetary assets and liabilities are translated into US Dollars at the exchange rate ruling at the balance sheet date, with a corresponding charge or credit to the Group Statement of Comprehensive Income.
The principal rates of exchange used were:
|
US Dollar / Pounds Sterling |
31 Dec 2022 |
31 Dec 2021 |
|
Year-end rate |
1.21 |
1.35 |
|
Average rate |
1.24 |
1.38 |
Upon disposal or liquidation of a subsidiary, any cumulative exchange differences recognised in equity as a result of previous changes in the functional currency of that subsidiary are recycled to the Group Statement of Comprehensive Income .
1.5 New and amended standards adopted by the Group
The Group has applied new accounting standards, amendments and interpretations for the first time:
· Property, Plant and Equipment: Proceeds before Intended Use - Amendments to IAS 16
· Onerous Contracts - Cost of Fulfilling a Contract - Amendments to IAS 37
· Annual Improvements to IFRS Standards 2018-2020, and
· Reference to the Conceptual Framework - Amendments to IFRS 3
The Group also applied the following amendments early:
· Disclosure of Accounting Policies - Amendments to IAS 1 and IFRS Practice Statement 2.
The adoption of the changes and amendments above has not had any material impact on the disclosure or on the amounts reported in the Financial Statements, nor are they expected to significantly affect future periods.
1.6 New and amended accounting standards not yet adopted
A number of other new and amended accounting standards and interpretations have been published that are not mandatory for the Group's financial year ended 31 December 2022, nor have they been early adopted. These standards and interpretations are not expected to have a material impact on the Group's consolidated Financial Statements.
1.7 Critical accounting judgements and key sources of estimation uncertainty
In the application of the Group's accounting policies, the directors are required to make judgements, estimates and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant. Actual results may differ from these estimates.
The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only the period, or in the period of the revision and future periods if the revision affects both current and future periods.
The following are critical judgements, apart from those involving estimations (which are dealt with separately below), that the directors have made in the process of applying the Group's accounting policies and that have the most significant effect on the amounts recognised in the Financial Statements:
· identification of impairment indicators for Lancaster field oil and gas assets (note 2.3);
· identification of impairment indicators for intangible exploration and evaluation assets (note 2.4);
· recognition of deferred tax assets (section 6);
· lease term of the Aoka Mizu FPSO (note 5.2); and
· quantum of decommissioning provision to be recognised (note 2.5)
The key assumptions concerning the future, and other key sources of estimation uncertainty at the balance sheet date that may have a significant risk of causing a material adjustment to the carrying amount of assets and liabilities within the next financial year, are:
· estimated future cash flows of oil and gas assets used for impairment testing (note 2.3)
· estimation of hydrocarbon Reserves and Contingent Resources (section 2);
· estimation of future taxable profits against which to recognise deferred tax assets (section 6).
The Convertible bond was repaid in full during the year and so there is no longer considered to be a key source of estimation uncertainty contained in the valuation of the Convertible bond embedded derivative (note 5.1) at 31 December 2022.
1.7.1 Impact of climate change and energy transition on critical judgements and estimates
Climate change and the transition to a low carbon economy were considered in preparing these consolidated Financial Statements. In particular, the energy transition is likely to impact future oil and gas prices which in turn may affect the recoverable amount of the Group's oil and gas assets. The estimate of future cash flows from oil and gas assets, which includes management's best estimate of future oil prices, is considered a key source of estimation uncertainty. In developing these price assumptions, consideration was given to a range of forecasts, including ones that were described as being consistent with achieving the 2015 COP 21 Paris Agreement goal to limit temperature rises to well below 2 degrees Celsius (the 'Paris compliant scenarios') and ones based on pledges announced by governments to date. Further details of the key assumptions in this area have been provided in note 2.3.1, including sensitivity analysis outlining the impact on the impairment charge of using higher or lower oil price assumptions to management's best estimate of oil prices. The oil price forecast used in the impairment assessment (disclosed in note 2.3.1) is estimated to be broadly aligned with forecasts consistent with pledges announced by governments to date; however, under current forecasts and with no further investment, the Group's oil and gas assets are likely to be fully depreciated within three years, during which timeframe it is expected that global demand for oil will remain robust. Accordingly, the impact of climate change on expected useful lives of the Group's current assets is not considered to be a significant judgement or estimate.
In addition to oil and gas assets, climate change could adversely impact the future development or viability of exploration and evaluation (E&E) prospects. The existence of impairment triggers for E&E assets is considered a critical accounting judgement, with further details of impairments recorded in the year and the amounts that remain capitalised at year end provided in note 2.4.
Section 2. Oil and gas operations
Accounting policies applicable to this section as a whole
Commercial reserves
Commercial Reserves are proved and probable oil and gas Reserves, which are defined as the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered to be economically viable. Proved and probable reserve estimates are based on a number of underlying assumptions including oil and gas prices, future costs, oil and gas in place and reservoir performance, which are inherently uncertain. There should be a 50% statistical probability that the actual quantity of Reserves will be more than the amount estimated as proven and probable Reserves and a 50% statistical probability that it will be less. However, the amount of Reserves that will be ultimately recovered from any field cannot be known with certainty until the end of the field's life.
Critical judgements and key sources of estimation uncertainty applicable to this section
Key source of estimation uncertainty - estimation of hydrocarbon Reserves and Contingent Resources
Hydrocarbon Reserves and Contingent Resources are those hydrocarbons that can be economically extracted from the Group's oil and gas assets. The Group's Reserves and Contingent Resources have been estimated based on information compiled by independent qualified persons, using standard recognised evaluation techniques. Inputs provided by management to the independent qualified persons include geological and reservoir information (as updated from data obtained through operation of a field), operating costs and decommissioning estimates. These inputs are challenged by the independent qualified persons and validated against analogue reservoirs, actual historical reservoir and production performance, and the costs of running and decommissioning similar fields and installations.
Changes to Reserves estimates may significantly impact the financial position and performance of the Group. This could include a significant change in the depreciation charge for oil and gas assets, provisions for decommissioning, the results of any impairment testing performed and the recognition and carrying value of any deferred tax assets.
The estimated quantity of remaining proved plus probable Reserves (2P Reserves) at 31 December 2022 in respect of the Lancaster EPS was independently assessed in March 2023 as being 6.6 MMbbl.
2.1 Revenue
Accounting policy
Revenue from contracts with customers is recognised when the Group satisfies its performance obligation of transferring control of oil to a customer. Transfer of control is usually concurrent with both transfer of title and the customer taking physical possession of the oil, which is determined by reference to the contract and relevant Incoterms. These performance obligations are satisfied at a point in time.
The amount of revenue recognised is measured at the transaction price, which is determined primarily by reference to quoted market prices at or around the time of lifting. Where final pricing terms are only available after delivery (e.g. using quoted prices or other information such as discharge quantity that can only be determined after the time of sale), revenue is initially recognised based on relevant prices at the time of sale on a provisional basis and subsequently adjusted. This variable consideration element is deemed highly probable not to result in a significant reversal of revenue as changes in pricing arising from post-sale adjustments are resolved within a short period of time following delivery and are not considered to be material.
All revenue is derived from contracts with customers and is comprised of only one category and geographical location, being the sale of crude oil from the Lancaster EPS. All sales were made to one external customer, being BP Oil International Limited.
|
|
Year ended |
Year ended |
|
|
31 Dec 2022 |
31 Dec 2021 |
|
|
$'000 |
$'000 |
|
|
|
|
|
Oil sales |
310,776 |
240,540 |
|
Revenue from contracts with customers |
310,776 |
240,540 |
|
|
|
|
|
Cargoes sold |
6 |
7 |
|
Sales volumes (thousand bbl) |
3,226 |
3,576 |
|
Average sales price realised ($/bbl) |
$96.3/bbl |
$67.3/bbl |
2.2 Cost of sales and inventory
Accounting policy
Crude oil inventories
Crude oil inventories are held at the lower of cost and net realisable value. The cost of crude oil is the cost of production, including direct labour and materials, depreciation and an appropriate portion of fixed overheads allocated based on normal operating capacity of the production facilities, determined on a weighted average cost basis. Net realisable value of crude oil is based on the market price of similar crude oil at the balance sheet date and costs to sell, adjusted if the sale of inventories after that date gives additional evidence about its net realisable value.
The cost of crude oil is expensed in the period in which the related revenue is recognised.
For other inventories, cost is determined on a weighted average basis (for fuel and chemicals) or a specific identification basis (for spares and supplies), including the cost of direct materials and (where applicable) direct labour and a proportion of overhead expenses. Items are classified as spares and supplies inventory where they are either standard parts, easily resalable or available for use on non-specific campaigns, and as oil and gas assets or intangible exploration and evaluation assets where they are specialised parts intended for specific projects. Net realisable value is determined by an estimate of the price that could be realised through resale or scrappage based on its condition at the balance sheet date.
Included within cost of sales are costs relating to emissions trading schemes. Provision is made at the end of each period for the cost of allowances required to cover carbon emissions made in the emission reporting period to date. The estimated cost of allowances required is based on the weighted average cost per unit of emissions expected to be incurred for the compliance period, calculated as the carrying amount of any allowances held plus the cost of meeting the expected shortfall (using the market price at the balance sheet date), divided by the expected total number of units of emissions for the compliance period. The provision is held on the Statement of Financial Position within trade and other payables until settled by the delivery of emissions certificates. Allowances granted free of charge are held at nil cost, with any gain on sale of free allowances granted recognised at the time of sale.
Cost of sales
|
|
|
Year ended |
Year ended |
|
|
|
31 Dec 2022 |
31 Dec 2021 |
|
|
Note |
$'000 |
$'000 |
|
|
|
|
|
|
Operating costs |
|
63,182 |
65,688 |
|
Depreciation of oil and gas assets - owned |
2.3 |
55,212 |
94,200 |
|
Depreciation of oil and gas assets - leased |
2.3 |
26,652 |
3,405 |
|
Movement in crude oil inventory |
|
3,553 |
(10,622) |
|
Variable lease payments |
5.2 |
24,822 |
20,454 |
|
|
|
173,421 |
173,125 |
Inventory
|
|
31 Dec 2022 |
31 Dec 2021 |
|
|
$'000 |
$'000 |
|
|
|
|
|
Crude oil |
9,760 |
13,313 |
|
Fuel and chemicals |
3,590 |
2,124 |
|
Spares and supplies |
13,080 |
12,051 |
|
|
26,430 |
27,488 |
The amount of crude oil inventory recognised as an expense in the year was $142.7 million (2021: $140.6 million).
2.3 Oil and gas assets
Accounting policies
Oil and gas assets are stated at cost less accumulated depreciation and any provision for impairment.
Oil and gas assets - cost
Oil and gas assets are accumulated generally on a field-by-field basis and represent the cost of developing the commercial Reserves discovered and bringing them into production, together with the intangible exploration and evaluation asset expenditures incurred in finding commercial Reserves transferred from intangible exploration and evaluation assets.
The cost of oil and gas properties also includes directly attributable staff and related overhead expenditure, which is allocated via the Group's time writing process, capitalised borrowing costs and the cost of provisions for future restoration and decommissioning.
Right-of-use assets (leased assets) are initially measured at cost, which comprises the initial measurement of the lease liability (see note 5.2), plus any lease payments made prior to lease commencement, initial direct costs incurred and the estimated cost of restoration or decommissioning, less any lease incentives received. Right-of-use assets are presented within property, plant and equipment on the Statement of Financial Position.
Oil and gas assets - depreciation
Oil and gas properties are depreciated from the commencement of production on a unit-of-production basis. This is the ratio of oil production in the period to the estimated Reserves base, which is the best estimate of proved plus probable Reserves (2P Reserves), at the end of the period, plus the production in the period. Costs used in the unit-of-production calculation comprise the net book values of producing assets, taking into account future development expenditures necessary to bring those Reserves into production. Where the carrying value of oil and gas assets has been impaired by using an expected cash flow approach, the equivalent expected future development costs and expected Reserves and Contingent Resources base are taken into account when determining the depreciation rate.
Impairment
An impairment test is performed whenever events and circumstances arising during the development or production phase indicate that the carrying value of an oil and gas property may exceed its recoverable amount.
The carrying value is compared against the expected recoverable amount of the asset, generally by reference to the present value of the future net cash flows expected to be derived from production of commercial Reserves. The cash-generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped as a single cash-generating unit where the cash inflows of each field are interdependent.
Any impairment identified is charged to the Group Statement of Comprehensive Income. Where conditions giving rise to an impairment subsequently reverse, the effect of the impairment charge is also reversed as a credit to the Group Statement of Comprehensive Income, net of any depreciation that would have been charged since the impairment.
|
|
|
Leased |
|
Owned |
|
Total |
|
|
Note |
$'000 |
|
$'000 |
|
$'000 |
|
Cost |
|
|
|
|
|
|
|
At 1 January 2021 |
|
101,821 |
|
784,558 |
|
886,379 |
|
Additions |
|
− |
|
4,572 |
|
4,572 |
|
Remeasurement of lease liability |
|
(18,212) |
|
− |
|
(18,212) |
|
Changes to decommissioning estimates |
2.5 |
1,961 |
|
1,514 |
|
3,475 |
|
At 31 December 2021 |
|
85,570 |
|
790,644 |
|
876,214 |
|
Additions |
|
− |
|
8,785 |
|
8,785 |
|
Remeasurement of lease liability |
5.2 |
75,897 |
|
− |
|
75,897 |
|
Changes to decommissioning estimates |
|
(851) |
|
(1,520) |
|
(2,371) |
|
At 31 December 2022 |
|
160,616 |
|
797,909 |
|
958,525 |
|
Depreciation and impairment |
|
|
|
|
|
|
|
At 1 January 2021 |
|
(80,204) |
|
(598,148) |
|
(678,352) |
|
Depreciation charge for the year |
|
(3,405) |
|
(94,200) |
|
(97,605) |
|
Provision for impairment |
|
(1,961) |
|
− |
|
(1,961) |
|
At 31 December 2021 |
|
(85,570) |
|
(692,348) |
|
(777,918) |
|
Depreciation charge for the year |
|
(26,653) |
|
(55,212) |
|
(81,865) |
|
Changes to decommissioning estimates expensed |
|
851 |
|
− |
|
851 |
|
At 31 December 2022 |
|
(111,372) |
|
(747,560) |
|
(858,932) |
|
Carrying amount at 31 December 2021 |
|
− |
|
98,296 |
|
98,296 |
|
Carrying amount at 31 December 2022 |
|
49,244 |
|
50,349 |
|
99,593 |
Oil and gas assets held under leases comprise solely the Aoka Mizu FPSO bareboat charter, which commenced in May 2019. During 2021, this lease term was reassessed, resulting in a decrease in the leased asset (including decommissioning asset) value to nil. As the reduction of lease asset value in 2021 included reducing the decommissioning asset value to nil, changes to the decommissioning estimates in the year of $(1.0) million have been expensed in full resulting in $nil impact to the leased asset. On 25 March 2022, the Group agreed an extension to the charter to cover the remaining economic life of the Lancaster field (see note 5.2).
Included within the cost of owned oil and gas assets is $42.8 million of capitalised borrowing costs (2021: $42.8 million)
The total amount of depreciation charged to oil and gas assets and other fixed assets was $82.2 million (2021: $98.1 million).
2.3.1 Impairment of oil and gas assets
Critical judgement - identification of impairment indicators for oil and gas assets
The asset balance relating to the Lancaster field held within property, plant and equipment is subject to an impairment assessment under IAS 36 'Impairment of Assets', whereby the Group is required to consider if there are any indicators of impairment. The judgement as to whether there are any indicators of impairment takes into consideration a number of internal and external factors, including: changes in estimated commercial Reserves; significant adverse changes to production versus previous estimates of management; changes in estimated future oil and gas prices; changes in estimated future capital and operating expenditure to develop and produce commercial Reserves; the market capitalisation of the Group falling and remaining significantly below the net book value of assets; and any indications that discount rates likely to be applied by market participants in assessing the asset's recoverable amount may have increased.
If an impairment indicator exists, an impairment test, which compares carrying value to the asset's recoverable amount (being the higher of value in use and fair value less cost to sell), is required to be carried out.
Critical judgements and key source of estimation uncertainty - estimated future cash flows of oil and gas assets used for impairment testing
The Group assesses its assets and cash-generating units (CGUs) in each reporting period to determine whether any indicators of impairment exist. Where indicators exist, a formal impairment test is undertaken to estimate the recoverable amount (which is the higher of fair value less costs of disposal (FVLCD) and value in use (VIU)). For the Lancaster field, the recoverable amount was based on VIU.
In making these estimates, a judgement has been made that the agreement on 25 March 2022 for the extension to the Aoka Mizu lease will allow Lancaster EPS operations to continue until such time as the estimated economic limit is reached (August 2025 based on the forecasts for production, oil price and operating costs).
These estimates and assumptions are subject to significant risk and uncertainty, and therefore changes to external factors and internal developments and plans can significantly impact these projections, which could lead to additional impairments or reversals in future periods. Sensitivity analysis to some of these estimates and assumptions are outlined below.
The trigger for the impairment test was the comparison of net assets of the Group at 31 December 2022 versus the market value of the Group based on the share price on that date. The recoverable amount was determined based on management's best estimate of value in use, using key assumptions, judgements and estimates as outlined below.
The key assumptions used within each cash flow projection are based on best estimates using past experience, latest internal technical analysis and external factors, and include:
· production forecasts in line with those included in the 2023 ERCE CPR as published on the Company's website at www.hurricaneenergy.com; and
· Dated Brent oil price assumptions (in real terms) of $82/bbl average for 2023, $77/bbl in 2024 and $74/bbl in 2025 (being forecasts of future oil prices extant as at 31 December 2022, as required by IAS 36);
· operating cost assumptions based on latest budgets, contracts and information from key suppliers;
· the extension to the Aoka Mizu FPSO charter agreed on 25 March 2022 will allow production to continue until August 2025 (being the estimated economic limit for the P6 well alone based on the forecasts for production, oil price and operating costs as outlined above), and an assumption that neither party exercises their respective termination option that would result in an end to the charter prior to that point; and
· a pre-tax real discount rate of 8.0%.
These estimates and assumptions are subject to risk and uncertainty, and therefore changes to external factors and internal developments and plans have the ability to significantly impact these projections, which could lead to additional impairments or future reversals in future periods.
The results of the impairment test were that no impairment charge was necessary.
The estimated impairment charge that would be recognised as a result of changes to some of these key estimates and assumptions made (in isolation) is as follows:
|
|
Impairment charge |
|
|
$m |
|
Oil price assumption: |
|
|
$5/bbl decrease to price curve |
- |
|
$10/bbl decrease to price curve
|
- |
|
|
|
|
Forecast production rates: |
|
|
5% decrease |
- |
|
10% decrease |
- |
|
|
|
|
Cessation of production and FPSO charter end date |
|
|
October 2023 |
32.0 |
|
December 2023 |
17.8 |
The sensitivities disclosed are considered in isolation and a result of changing only one variable.
A $10/bbl decrease to the forecast oil price is considered to be reasonably possible based on oil price volatility, and a 10% decrease to forecast production rates are considered to be reasonably possible based on experienced uptime and production levels.
2.4 Intangible exploration and evaluation assets
Accounting policy
The Group follows the successful efforts method of accounting for oil and gas exploration and evaluation activities (intangible exploration and evaluation assets) as permitted by IFRS 6 'Exploration for and Evaluation of Mineral Resources'.
Pre-licence costs, which relate to costs incurred prior to having obtained the legal right to explore an area, are charged directly to the Group Statement of Comprehensive Income within operating expenses as they are incurred.
Once a licence has been awarded, all licence fees and exploration and appraisal costs relating to that licence are initially capitalised in well, field or specific exploration cost centres as appropriate pending determination. These costs include directly attributable staff and related overhead expenditure, which is allocated to assets via the Group's timewriting process. Expenditure incurred during the various exploration and appraisal phases is then written off unless commercial Reserves have been established or the determination process has not been completed.
When commercial Reserves have been found and a field development plan has been approved, the net capitalised costs incurred to date in respect of those Reserves are transferred into a single field cost centre and reclassified as oil and gas properties within property, plant and equipment (subject to an impairment test before reclassification). Subsequent development costs in respect of the Reserves are capitalised within oil and gas properties.
If there are indicators of impairment (examples of which include the surrender, expiry or expected non-renewal of a licence; a lack of planned or budgeted substantive expenditure for a particular field; insufficient commercially viable Reserves resulting in a discontinuation of development; and data existing which indicates that the carrying amount of an asset is unlikely to be fully recovered either from successful development or sale), an impairment test is performed comparing the carrying value with its recoverable amount, being the higher of value in use (calculated as the estimated discounted future cash flows based on management's expectations of future oil and gas prices, production and costs) and its estimated fair value less costs to sell. Capitalised costs which are subsequently written off are classified as operating expenses.
The Group may enter into farm-out arrangements, whereby it assigns an interest in Reserves and future production to another party (the farmee). For farm-outs of assets that are in the exploration and evaluation stage, the Group does not recognise any consideration in respect of the farmee's committed or expected carry but continues to hold its remaining interest at the previous cost of the full interest, less any cash consideration received from the farmee upon entering the arrangement.
|
|
|
|
Year ended |
|
Year ended |
|
|
|
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
Note |
|
$'000 |
|
$'000 |
|
|
|
|
|
|
|
|
At 1 January |
|
|
3,830 |
|
55,390 |
|
Additions |
|
|
1,878 |
|
5,235 |
|
Provision for impairment and exploration expenditure written off |
2.4.1 |
|
(5,705) |
|
(54,280) |
|
Changes to decommissioning estimates |
2.5 |
|
(3) |
|
(2,515) |
|
At 31 December |
|
|
− |
|
3,830 |
Intangible exploration and evaluation assets represent the Group's share of the cost of licence interests and exploration and evaluation expenditure within its remaining Halifax licence (P2308) in the West of Shetland area, following the relinquishment of Lincoln (licence P1368(S)) and Warwick (licence P2294). The exploration and evaluation assets within Halifax licence P2308 have been fully impaired in the year.
Additions during the period primarily comprised licence fees, geological and other subsurface studies undertaken, and capitalised time writing costs.
2.4.1 Impairment and write-off of intangible exploration and evaluation assets
Critical judgement - identification of impairment indicators for intangible exploration and evaluation assets
Intangible exploration and evaluation assets are assessed for impairment when circumstances suggest that the carrying amount may exceed its recoverable value. This judgement is made with reference to the impairment indicators outlined in note 2.4 above.
The directors have fully considered and reviewed the potential value of licence interests, including carried forward exploration and evaluation expenditure. The directors have considered the Group's tenure to its licence interests, its plan for further exploration and evaluation activities in relation to these and the likely opportunities for realising the value of the Group's licences, either by farm-out or by development of the assets.
An impairment charge of $0.1 million has been recognised against the full carrying amount of exploration and evaluation expenditure attributable to the Halifax asset on licence P2308 as the 2022 CPR did not attribute any Reserves or Contingent Resources to Halifax, and the Group has no plans or budgets for substantive expenditure on further exploration or evaluation on this licence.
An impairment charge of $5.6 million has been recognised against the full carrying amount of exploration and evaluation expenditure attributable to the Greater Warwick Area (GWA) comprising the Lincoln asset (licence P1368(S)) and the Warwick asset (licence P2294) both of which have now been relinquished.
2.5 Decommissioning provisions
Accounting policy
Provisions for decommissioning are recognised in full when wells have been suspended or facilities have been installed. A corresponding amount equivalent to the provision is also recognised as part of the cost of either the related oil and gas exploration and evaluation asset or property, plant and equipment as appropriate. The amount recognised is the estimated cost of decommissioning, discounted to its net present value, and is reassessed each year in accordance with local conditions and requirements. Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision, and a corresponding adjustment to the related asset. Where the related asset is fully impaired, the corresponding adjustment is recognised in profit and loss. The unwinding of the discount on the decommissioning provision is classified within finance costs.
|
|
|
|
Year ended |
|
Year ended |
|
|
|
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
|
Note |
$'000 |
|
$'000 |
|
|
|
|
|
|
|
|
At 1 January |
|
|
49,346 |
|
61,141 |
|
Net new provisions and changes in estimates |
|
|
(2,557) |
|
(1,921) |
|
Utilised in year |
|
|
(277) |
|
(9,894) |
|
Unwinding of discount |
|
3.2 |
545 |
|
20 |
|
At 31 December |
|
|
47,057 |
|
49,346 |
|
|
|
|
|
|
|
|
Of which: |
|
|
|
|
|
|
Current |
|
|
− |
|
- |
|
Non-current |
|
|
47,057 |
|
49,346 |
|
|
|
|
47,057 |
|
49,346 |
|
|
|
|
|
|
|
|
Restricted funds held in respect of decommissioning: |
|
|
|
|
|
|
Restricted cash |
|
4.1 |
40,594 |
|
- |
|
Liquid investments |
|
4.1 |
− |
|
37,783 |
|
|
|
|
40,594 |
|
37,783 |
The provisions for decommissioning relate to the costs required to decommission the Lancaster EPS installations and the costs required to clean, remove and restore the Aoka Mizu FPSO at the end of the charter term. The decommissioning provision has been classified as non-current in line with the assumptions made for impairment testing of oil and gas assets, which assumes a cessation of production of the Lancaster field and expected incurrence of decommissioning costs in August 2025; being the estimated point at which the EPS becomes uneconomic absent any incremental development (2021: June 2024). Estimated costs are discounted at a rate of 3.58% and an annual inflation rate of 6.35% has been assumed.
Changes in estimates in the period have arisen from a change to the expected cessation of production date, changes in the assumed discount rate, changes in foreign exchange rates and increases to the assumed inflation rate.
Of the total net new provisions and changes in estimates, $1.52 million was recorded as non-cash reductions to oil and gas assets, and $1.04 million charged directly to the Group Statement of Comprehensive Income (as they related to changes in estimates on fully impaired assets and right-of-use assets).
The utilisation of provisions during the period related to the final costs associated with the plugging and abandonment of the Lincoln-14 well, and the Lancaster 4Z wells which were undertaken in 2021.
2.6 Joint operations
In September 2018 the Group entered into a joint operation with Spirit to share costs and risks associated with GWA in exchange for granting Spirit a 50% interest in the Group's P1368(S) and P2294 licences. The phased work programme was intended to comprise a planned tie-back of a GWA well to the Aoka Mizu FPSO, together with host modifications to the vessel and a gas export tie-in to the West of Shetland Pipeline System (WOSPS). Hurricane was fully carried up to a gross cost of $180.6 million for the first phase of this activity, with costs in excess of the carry amount having been shared on a 50:50 basis.
With effect from 6 March 2020, a new cost allocation framework was implemented whereby the joint operation builds-out only the equipment and materials required to for a single-well tie-back to the Aoka Mizu FPSO. These long-lead items are currently being held in storage. As part of this framework, the Group can elect to continue to build-out long-lead items related to the tie-in of the Aoka Mizu FPSO to the WOSPS on a sole risk basis as part of GLA activities.
In H1 2022 the joint operation agreed to surrender the Lincoln (P1368(S)) and the Warwick (P2294) licences. The P1368(S) licence was relinquished on 11 July 2022, and the P2294 licence was relinquished on 18 July 2022. Before the joint operation is formally concluded, there remain a number of operational and administrative matters to complete. The Group currently acts as operator of the joint operation and will continue to do so until these matters are concluded.
Amounts due from and to the joint operation partner are shown in notes 4.2 and 4.3 respectively.
Further details on the activities and progress of the joint operation are described in the Strategic Report.
2.7 Capital Commitments
As at the balance sheet date, the Group had the following outstanding contractual and other commitments:
|
|
|
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
|
|
$'000 |
|
$'000 |
|
|
|
|
|
|
|
|
Contractual commitments in respect of oil and gas assets |
490 |
|
1,201 |
||
|
Contractual commitments in respect of exploration and evaluation assets |
26 |
|
821 |
||
Commitments shown above are net of amounts expected to be funded by the Group's joint operation partner.
Section 3. Group Statement of Comprehensive Income
3.1 Earnings per share
|
|
Year ended |
|
Year ended |
|
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
$'000 |
|
$'000 |
|
|
|
|
|
|
Profit attributable to holders of Ordinary Shares in the Company used in calculating basic earnings per share (being profit after tax) |
108,661 |
|
18,236 |
|
Add back impact of: |
|
|
|
|
Convertible Bond - interest expense |
− |
|
- |
|
Convertible Bond - fair value gain |
− |
|
- |
|
Profit attributable to holders of Ordinary Shares in the Company used in calculating diluted earnings per share |
108,661 |
|
18,236 |
|
|
|
|
|
|
|
Number |
|
Number |
|
Weighted average number of Ordinary Shares used in calculating basic earnings per share |
1,990,423,900 |
|
1,989,927,148 |
|
Potential dilutive effect of: |
|
|
|
|
Convertible Bond |
− |
|
- |
|
Weighted average number of Ordinary Shares and potential Ordinary Shares used in calculating diluted earnings per share |
1,990,423,900 |
|
1,989,927,148 |
|
|
|
|
|
|
|
Cents |
|
Cents |
|
Basic earnings per share |
5.46 |
|
0.92 |
|
Diluted earnings per share |
5.46 |
|
0.92 |
In 2022 and 2021, the potential impact of the conversion feature included within the Convertible Bond was antidilutive as their conversion to Ordinary Shares would have increased earnings per share. At 31 December 2022 the Convertible Bonds had been fully repaid.
The inclusion of contingently issuable shares in the calculation of diluted earnings per share had no impact due to the immaterial quantum of awards outstanding at 31 December 2022.
3.2 Finance income and costs
|
|
Year ended |
|
Year ended |
|
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
$'000 |
|
$'000 |
|
|
|
|
|
|
Interest income on cash, cash equivalents and liquid investments |
1,174 |
|
27 |
|
Net foreign exchange gains |
− |
|
- |
|
Finance income |
1,174 |
|
27 |
|
|
|
|
|
|
Convertible Bond interest expense (note 5.1) |
(5,558) |
|
(24,810) |
|
Interest on lease liabilities (note 5.2) |
(3,873) |
|
(4,412) |
|
Other interest expense and bank charges |
(476) |
|
(217) |
|
Net foreign exchange losses |
(5,171) |
|
(1,197) |
|
Unwinding of discount on decommissioning provisions (note 2.5) |
(545) |
|
(20) |
|
Finance costs |
(15,623) |
|
(30,656) |
|
|
|
|
|
|
Net finance costs |
(14,449) |
|
(30,629) |
3.3 General and administrative expenditure
|
|
Year ended |
|
Year ended |
|
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
$'000 |
|
$'000 |
|
|
|
|
|
|
Wages and salaries |
7,699 |
|
9,939 |
|
Social security costs |
1,034 |
|
1,226 |
|
Defined contribution pension costs |
410 |
|
689 |
|
Staff costs |
9,143 |
|
11,854 |
|
Non-staff costs |
7,293 |
|
22,958 |
|
Gross general and administrative expenditure before recharges |
16,436 |
|
34,812 |
|
Capitalised into oil and gas assets |
(2,229) |
|
(3,025) |
|
Capitalised into intangible exploration and evaluation assets |
648 |
|
(3,456) |
|
Included within cost of sales |
(6,109) |
|
(4,752) |
|
Net general and administrative expenditure before non-cash items |
8,746 |
|
23,579 |
|
Non-cash general and administrative costs: |
|
|
|
|
Net share-based payment charge |
289 |
|
1,956 |
|
Depreciation of other fixed assets and other right-of-use assets |
320 |
|
495 |
|
Impairment of other right of use assets |
− |
|
719 |
|
General and administrative expenditure |
9,355 |
|
26,749 |
|
|
|
|
|
|
|
Number |
|
Number |
|
Average number of employees |
34 |
|
55 |
|
Details of directors' remuneration are provided in the Remuneration Report (note 7.3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
3.4 Share Based Payments
Accounting policy
The Share Incentive Plan (SIP) Trust is a separately administered discretionary trust whose assets mainly comprise shares in the Company. Own shares held by the SIP Trust are deducted from shareholders' funds and held at historical cost until they are sold to employees to satisfy share incentive plans. The assets, liabilities, income and costs of the SIP Trust are included in both the Company's and the consolidated Financial Statements.
During 2022 the Group operated a share-based payment plan being the Company's HMRC-approved SIP. The Group recognised a total charge of $0.3 million in respect of share-based payments in 2022.
During 2021, the Group operated a number of share-based payment plans, including several Performance Share Plans (PSPs), the Value Creation Plan (VCP) and the Company's HMRC-approved SIP. The Group recognised a total charge of $2.0 million in respect of share-based payments in 2021. All PSP awards lapsed unvested in November 2021 and all VCP awards lapsed unexercised upon expiry in November 2021, and therefore there were no performance-based share awards or options outstanding at 31 December 2021.
Section 4. Cash, working capital and financial instruments
Accounting policies applicable in general to this section
Financial assets and financial liabilities are recognised on the Group's Statement of Financial Position when the Group becomes party to the contractual provisions of the instrument.
Fair value
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. All assets and liabilities, for which fair value is measured or disclosed in the Financial Statements, are categorised within the fair value hierarchy, described as follows, based on the lowest-level input that is significant to the fair value measurement as a whole:
Level 1 - quoted (unadjusted) market prices in active markets for identical assets or liabilities;
Level 2 - valuation techniques for which the lowest-level input that is significant to the fair value measurement is directly or indirectly observable; and
Level 3 - valuation techniques for which the lowest-level input that is significant to the fair value measurement is unobservable.
Financial assets
Financial assets are initially recognised at fair value, and subsequently measured at amortised cost, less any allowances for losses using the expected credit loss model, being the difference between all contractual cash flows that are due to the Group in accordance with the contract and all the cash flows that the Group expects to receive.
Financial liabilities
Financial liabilities are classified as either financial liabilities at fair value through profit and loss (FVTPL) or as other financial liabilities. The Group derecognises financial liabilities when, and only when, the Group's obligations are discharged or cancelled, or they expire. Upon derecognition, the difference between the consideration paid to extinguish the liability and the carrying value of the liability at time of derecognition is recognised as a gain in the Group Statement of Comprehensive Income , net of any direct transaction costs.
Financial liabilities are classified at FVTPL when the financial liability is either held for trading or it is designated at FVTPL. A financial liability is classified as held for trading if it has been incurred principally for the purpose of repurchasing it in the near term or is a derivative that is not a designated or effective hedging instrument.
Financial liabilities at FVTPL are measured at fair value, with any gains or losses arising on changes in fair value recognised in profit or loss. The net gain or loss recognised in profit or loss incorporates any interest paid on the financial liability.
Other financial liabilities, including borrowings, are initially measured at fair value, net of transaction costs and are subsequently measured at amortised cost using the effective interest method, with interest expense recognised on an effective yield basis.
The effective interest method is a method of calculating the amortised cost of a financial liability and of allocating interest expense over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash payments through the expected life of the financial liability, or, where appropriate, a shorter period, to the net carrying amount on initial recognition.
Derivatives (other than embedded derivatives)
Derivatives are initially recognised at fair value at the date a derivative contract is entered into and are subsequently remeasured to their fair value at each balance sheet date. The resulting gain or loss is recognised in the Group Statement of Comprehensive Income immediately. The Group does not currently designate any derivatives as hedging instruments.
A derivative with a positive fair value is recognised as a financial asset whereas a derivative with a negative fair value is recognised as a financial liability. A derivative is presented as non-current if the remaining maturity of the instrument is more than 12 months and it is not expected to be realised or settled within 12 months.
Other derivatives are presented as current assets or current liabilities.
4.1 Cash and cash equivalents and liquid investments
Accounting policy
Cash includes cash on hand and cash with banks and financial institutions.
Cash equivalents are short-term, highly liquid investments that are readily convertible to known amounts of cash with three months or less remaining to maturity from the date of acquisition and that are subject to an insignificant risk of change in value.
Liquid investments are defined as short-term investments in fixed-term deposit accounts of between 3- and 12-months' maturity.
Cash and cash equivalents, and liquid investments, include amounts held in escrow or other reserved accounts that are contractually restricted to be used only for certain payments or transactions, and where the approval process for release of those funds is perfunctory, e.g. for dispersal to certain independent third parties for work undertaken as part of the Group's operations. Such amounts are classified as non-current if the payment or transaction is not expected to be realised or settled within 12 months.
|
|
31 Dec 2022 |
|
31 Dec 2021 |
||||
|
|
Restricted |
Unrestricted |
Total |
|
Restricted |
Unrestricted |
Total |
|
|
$'000 |
$'000 |
$'000 |
|
$'000 |
$'000 |
$'000 |
|
Current cash and cash equivalents |
− |
138,383 |
138,383 |
|
7,934 |
68,858 |
76,792 |
|
Non-current cash and equivalents |
60,754 |
− |
60,754 |
|
- |
- |
- |
|
Cash and cash equivalents (per Cash Flow Statement) |
60,754 |
138,383 |
199,137 |
|
7,934 |
68,858 |
76,792 |
|
Liquid investments |
− |
− |
− |
|
37,783 |
- |
37,783 |
|
Total cash and cash equivalents and liquid investments |
60,754 |
138,383 |
199,137 |
|
45,717 |
68,858 |
114,575 |
The carrying amounts of cash and cash equivalents and liquid investments are considered to be materially equivalent to their fair values.
The movement in restricted and unrestricted cash, cash equivalents and liquid investments is as follows:
|
|
Year ended 31 Dec 2022 |
|
Year ended 31 Dec 2021 |
||||
|
|
Restricted |
Unrestricted |
Total |
|
Restricted |
Unrestricted |
Total |
|
|
$'000 |
$'000 |
$'000 |
|
$'000 |
$'000 |
$'000 |
|
At 1 January |
45,717 |
68,858 |
114,575 |
|
51,603 |
114,911 |
166,514 |
|
Operating cash flows |
|
206,688 |
206,688 |
|
- |
147,970 |
147,970 |
|
Change in Lancaster EPS decommissioning security arrangements |
7,749 |
(7,749) |
− |
|
15,530 |
(15,530) |
- |
|
Capital expenditure and other investing cash flows |
− |
(4,614) |
(4,614) |
|
- |
(15,095) |
(15,095) |
|
Financing cash flows |
− |
(110,786) |
(110,786) |
|
- |
(183,562) |
(183,562) |
|
Movement in FPSO early termination reserve |
12,226 |
(12,226) |
− |
|
(18,670) |
18,670 |
- |
|
Net release of other restricted funds |
− |
− |
− |
|
(2,244) |
2,244 |
- |
|
Foreign exchange rate changes |
(4,938) |
(1,788) |
(6,726) |
|
(502) |
(750) |
(1,252) |
|
At 31 December |
60,754 |
138,383 |
199,137 |
|
45,717 |
68,858 |
114,575 |
Included within restricted cash, cash equivalents and liquid investments is $20.2 million (2021: $7.9 million) set aside in relation to the Aoka Mizu FPSO bareboat charter. This amount was established and classified as restricted cash following the agreement in March 2022 to extend the FPSO lease. Under the terms of the contract, the Group is required to ring-fence amounts to ensure it could meet its liability to the lessor if the contract is terminated by the Group or the lessor. The $20.2 million amount consists of an original amount of $18.7million originally agreed with the lessor on extension of the lease in March 2022, with an additional $1.5 million subsequently being agreed to be set aside.
Also in restricted cash, cash equivalents and liquid investments is $40.6 million decommissioning security for the Lancaster EPS (2021: $37.8 million).
4.2 Trade and other receivables
|
|
|
|
|
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
|
|
|
|
$'000 |
|
$'000 |
|
|
|
|
|
|
|
|
|
|
Amounts due from joint operation partner |
|
|
|
|
-- |
|
813 |
|
Trade receivables |
|
|
|
|
1,420
|
|
423 |
|
Prepayments |
|
|
|
|
1,130 |
|
1,058 |
|
Other receivables |
|
|
|
|
1,125 |
|
297 |
|
|
|
|
|
|
3,675 |
|
2,591 |
The carrying amounts of trade and other receivables are considered to be materially equivalent to their fair values and are unsecured. Joint operation receivables represent amounts which will be recovered from the Group's joint operation partner. Amounts billed to the joint operation partner accrue interest at LIBOR/SONIA and are generally due for settlement within ten days of being invoiced.
4.3 Trade and other payables
|
|
|
|
|
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
|
|
|
|
$'000 |
|
$'000 |
|
|
|
|
|
|
|
|
|
|
Amounts owed to joint operation partner |
|
|
|
|
1,407 |
|
- |
|
Trade payables |
|
|
|
|
352 |
|
2,915 |
|
Other payables |
|
|
|
|
260 |
|
351 |
|
Accruals |
|
|
|
|
13,868 |
|
15,577 |
|
|
|
|
|
|
15,887 |
|
18,843 |
The carrying amounts of trade and other payables are considered to be materially equivalent to their fair values and are unsecured. Trade and other payables are non-interest bearing and generally payable within 30 days.
Trade and other payables and accruals include the Group's share of joint operation payables, including amounts that the Group settles on behalf of joint operation partners.
Amounts owed to joint operating partner includes expenditure of $1.5 million relating to joint operations incurred by the Group as operator which have yet to be paid to joint operation partners and which has been classified as "Impairment of intangible exploration and evaluation assets and exploration expense written off" in the Statement of Comprehensive Income.
4.4 Financial risk management
The Group monitors and manages the financial risks relating to its operations on a continual basis. These include market risk, liquidity risk and credit risk.
The Group does not enter into or trade financial instruments, including derivatives, for speculative purposes. Other than the financial instruments referred to below, the Group's significant financial instruments are cash and cash equivalents (note 4.1), financial trade and other payables (note 4.3), financial trade and other receivables (note 4.2) and its Convertible Bond debt (note 5.1).
The Group considers the carrying value of all its financial assets and liabilities to be materially the same as their fair value.
4.4.1 Market risk
Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk comprises foreign exchange, interest rate and other commodity price risk.
Foreign currency risk
Foreign currency risk is the risk that fair value or future cash flows of a financial instrument will fluctuate because of changes in foreign exchange rates.
The Group undertakes transactions denominated in currencies other than its functional currency (which is the US Dollar). For transactions denominated in Pounds Sterling, the Group manages this risk by holding Sterling against actual or expected Sterling commitments to act as an economic hedge against exchange rate movements. From time to time, the Group enters into foreign exchange swaps to hedge specific future payments in other currencies; no such swaps were entered into or matured in the current or prior year. The Group has not designated any financial instruments as hedging instruments or hedged items.
The Group's cash and cash equivalents are mainly held in US Dollars and Pounds Sterling. At 31 December 2022, 54% of the Group's cash and cash equivalents and liquid investments were held in US Dollars (2021: 40%).
A 10% decrease in the strength of Sterling against the US Dollar would cause an estimated decrease of $8.2 million (2021: $5.3 million increase) on the profit after tax of the Group for the year ended 31 December 2022, with a 10% strengthening causing an equal and opposite increase. The impact on equity is the same as the impact on profit after tax. The exposure to other foreign currency exchange movements is not material. This sensitivity analysis includes the impact of retranslating foreign currency denominated monetary items at the balance sheet date, and assumes all other variables remain unchanged. Whilst the effect of any movement in exchange rates upon revaluing foreign currency denominated monetary items is charged or credited to the Group Statement of Comprehensive Income, the economic effect of holding Pounds Sterling against actual or expected commitments in Pounds Sterling is an economic hedge against exchange rate movements.
Interest rate risk
Interest rate risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market interest rates.
The Group is exposed to interest rate movements through its cash and cash equivalents and liquid investments which earn interest at variable interest rates.
For the year ended 31 December 2022, a 1% increase in interest rates would have increased the Group's profit after tax by approximately $2.0 million, and a 0.5% decrease would have reduced the Group's profit after tax by approximately $1.0 million, assuming that the amount of cash and cash equivalents at the balance sheet date had been in place for the whole year. The impact on equity would be the same as the impact on profit after tax.
Other price risk - commodity price risk
Commodity risk primarily arises from the sale of crude oil from the Lancaster EPS, as the price realised from the sale of crude oil is determined primarily by reference to quoted market prices in the month of lifting. Crude oil price risk is partially mitigated by a proportion of cost of sales (variable lease payments) being linked to the price of crude oil sold.
The Group enters into other commodity contracts (such as purchases of carbon emission allowances, fuel and chemicals) in the normal course of business, which are not derivatives, and are recognised at cost when the transactions occur.
4.4.2 Liquidity risk
Liquidity risk is the risk that the Group will encounter difficulty in meeting obligations associated with its financial liabilities that are settled by delivering cash or other financial assets.
Financial liabilities of the Group comprise trade payables (note 4.3), lease liabilities (note 5.2) and the Convertible Bond (note 5.1). The maturity analysis of financial liabilities is shown in note 5.3.
The Group manages its liquidity risk by maintaining adequate cash and cash equivalents where possible to cover its liabilities as and when they fall due. Methods of achieving this include utilising receivable bank letters of credit to accelerate receipt of cash due from crude oil sales (accelerating from standard payment terms to receipt within two to three working days after lifting), and cash calling amounts in advance from joint operation partners if required.
4.4.3 Credit risk
Credit risk is the risk that the Group will suffer a financial loss as a result of another party failing to discharge an obligation and arises from cash and other liquid investments deposited with banks and financial institutions, receivables from the sale of crude oil, and receivables outstanding from its joint operation partner.
Customers, banks and joint operation partners are subject to risk assessments using due diligence tools, credit reference agencies, and other publicly available information with regular monitoring to determine if the level of credit risk has changed. For deposits lodged at banks and financial institutions, only those parties with at least investment grade credit ratings assigned by an international credit rating agency are accepted. Similarly, where the Group enters into arrangements involving letters of credit to accelerate the receipt of cash from sales of crude oil, only banks with at least investment grade credit ratings are used.
The carrying value of cash and cash equivalents and trade and other receivables represents the Group's maximum exposure to credit risk at year end. The Group has no material financial assets that are past due.
Section 5. Capital and debt
5.1 Convertible Bond
Accounting policies
Debt and equity instruments are classified as either financial liabilities or as equity in accordance with the substance of the contractual arrangement.
An equity instrument is any contract that evidences a residual interest in the assets of an entity after deducting all of its liabilities. Equity instruments issued by the Group are recognised at the proceeds received, net of direct issue costs.
Where warrants are granted in conjunction with other equity instruments, which themselves meet the definition of equity, they are recorded at their fair value, which is measured using an appropriate valuation model. Warrants which do not meet the definition of equity are classified as derivative financial instruments.
The component parts of compound instruments, such as Convertible bonds, issued by the Group are classified separately as financial liabilities and equity in accordance with the substance of the contractual arrangement.
If the conversion feature of a Convertible bond issued does not meet the definition of an equity instrument, that portion is classified as an embedded derivative and measured accordingly. The debt component of the instrument is determined by deducting the fair value of the conversion option at inception from the fair value of the consideration received for the instrument as a whole. The debt component amount is recorded as a financial liability on an amortised cost basis using the effective interest rate method until extinguished upon conversion or at the instrument's maturity date.
Where debt instruments issued by the Group are repurchased for cancellation, the financial liability is derecognised at the point at which cash consideration is settled. Upon derecognition, the difference between the liability's carrying amount that has been cancelled and the consideration paid is recognised as a gain in the Group Statement of Comprehensive Income, net of any direct transaction costs.
Embedded derivatives
Derivatives embedded in financial instruments or other host contracts that are not financial assets are treated as separate derivatives when their risks and characteristics are not closely related to those of the host contracts and the host contracts are not measured at FVTPL. Derivatives embedded in financial instruments or other host contracts that are financial assets are not separated; instead, the entire contract is accounted for either at amortised cost or fair value as appropriate.
An embedded derivative is presented as non-current if the remaining maturity of the compound instrument to which the embedded derivative relates is more than 12 months and is not expected to be realised or settled within 12 months.
Borrowing costs
Borrowing costs directly relating to the construction or production of a qualifying capital project under construction are capitalised and added to the project cost during construction until such time as the assets are substantially ready for their intended use, i.e. when they are capable of commercial production. The amount of borrowing costs eligible to be capitalised is reduced by an amount equivalent to any interest income received on temporary reinvestment of those borrowings.
In July 2017 the Group raised $230 million (gross) from the successful placement of the Convertible Bond. The Convertible Bond was issued at par and carried a coupon of 7.5% payable quarterly in arrears. The Convertible Bond was convertible into fully paid Ordinary Shares with the initial conversion price set at $0.52, representing a 25% premium above the placing price of the concurrent equity placement, being £0.32 (converted into US Dollars at a USD/GBP rate of 1.30). The number of potential Ordinary Shares that could be issued if all the Convertible Bonds were converted was 442,307,692 (assuming conversion at the initial conversion price of $0.52). The impact of these potential Ordinary Shares on diluted earnings per share is shown in note 3.1. During 2021, the Group repurchased $151.5 million of nominal Convertible Bonds debt for cash consideration of $131.9 million, including accrued interest of $1.6 million.
On 25 July 2022, the Group repaid in full the outstanding $78.5 million 7.50 per cent Convertible Bonds plus $1.5 million of accrued interest by the maturity date of 24 July 2022. The bonds have now been delisted from The International Stock Exchange and have been cancelled.
The amounts recognised in the Financial Statements related to the Convertible Bond (which, together with leases as disclosed in note 5.2, are the Group's liabilities arising from financing activities) are as follows:
|
|
|
Debt component |
|
Derivative component |
|
Total |
|
|
|
$'000 |
|
$'000 |
|
$'000 |
|
|
|
|
|
|
|
|
|
Carrying value at 1 January 2021 |
|
216,034 |
|
885 |
|
216,919 |
|
Cash interest paid |
|
(17,372) |
|
- |
|
(17,372) |
|
Cash consideration for repurchase of Convertible Bond principal |
|
(130,346) |
|
- |
|
(130,346) |
|
Gain on repurchase |
|
(15,753) |
|
(2,759) |
|
(18,512) |
|
Fair value loss |
|
- |
|
1,901 |
|
1,901 |
|
Interest charged |
|
24,810 |
|
- |
|
24,810 |
|
Carrying value at 31 December 2021 |
|
77,373 |
|
27 |
|
77,400 |
|
Repayment of principal |
|
(78,515) |
|
- |
|
(78,515) |
|
Cash interest paid |
|
(4,416) |
|
- |
|
(4,416) |
|
Fair value gain |
|
- |
|
(27) |
|
(27) |
|
Interest charged |
|
5,558 |
|
- |
|
5,558 |
|
Carrying value at 31 December 2022 |
|
- |
|
- |
|
- |
|
|
|
|
|
|
|
|
|
Fair value at 31 December 2021 |
|
75,449 |
|
27 |
|
75,476 |
|
Fair value at 31 December 2022 |
|
- |
|
- |
|
- |
5.2 Leases
Accounting policy
The Group enters into leases of property, equipment and oil exploration, development and production assets. The most significant leases are the bareboat charter of the Aoka Mizu FPSO, which commenced in May 2019, and the leases of various office properties.
Lease liabilities are initially measured at the present value of lease payments unpaid at the commencement date. Lease payments are discounted using the incremental borrowing rate (being the rate that the lessee would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic environment with similar terms and conditions), unless the rate implicit in the lease is available. The Group currently uses the incremental borrowing rate as the discount rate for all leases. For the purposes of measuring the lease liability, lease payments comprise fixed payments and variable lease payments based on an index or rate.
Right-of-use assets are measured at cost, which comprises the initial measurement of the lease liability, plus any lease payments made prior to lease commencement, initial direct costs incurred and the estimated cost of restoration or decommissioning, less any lease incentives received. The Aoka Mizu FPSO right-of-use asset is depreciated on a unit-of-production basis, the Reserves base of which is proved plus probable Reserves (2P Reserves), as estimated as being recoverable over the assessed lease term. Other right-of-use assets are depreciated over the lease term (or useful life, if shorter). Right-of-use assets are subject to an impairment test if events and circumstances indicate that the carrying value may exceed the recoverable amount.
Lease repayments made are allocated to capital repayment and interest so as to produce a constant periodic rate of interest on the remaining lease liability balance.
Right-of-use assets are presented within property, plant and equipment. Lease liabilities are presented as separate line items on the face of the Statement of Financial Position. In the Cash Flow Statement, lease repayments (of both the principal and interest portions) are presented within cash used in financing activities, except for payments for leases of short-term and low-value assets and variable lease payments, which are presented within cash flows from operating activities or cash used in investing activities in accordance with the relevant Group accounting policy.
Leases of low-value items (such as office equipment) and short-term leases (where the lease term is 12 months or less, which include the rental of drilling rigs) are expensed on a straight-line basis to the Group Statement of Comprehensive Income or capitalised into intangible exploration and evaluation assets and/or oil and gas assets in accordance with the relevant Group accounting policy. Variable lease payments linked to the sale of crude oil are recognised within cost of sales when the associated sale occurs.
The Group does not have any activities as a lessor.
Critical judgement - lease term of the Aoka Mizu
On 25 March 2022, the Group announced that it had signed a contract with Bluewater, for an extension to the Bareboat Charter beyond the previous expiry date of 4 June 2022. Judgement has been applied to determine the lease term of the Aoka Mizu FPSO bareboat charter as the contract includes the option for either party to give six months notice to terminate the charter. The contract is a rolling, evergreen contract so does not contain any extension options. The timing of such termination, and the costs or penalties associated with exercising such options, are included to the extent that the timing is reasonably certain. This assessment can significantly affect the right-of-use asset and lease liability recognised. The lease term for the Aoka Mizu FPSO has been assessed to last until August 2025, the estimated end of the economic life of the Lancaster field given the economic incentive for both the Group and lessor to continue the contract until that point, with the six months notice to terminate the charter being given to align with that.
As at 31 December 2021, the lease term used to determine the right-of-use asset and lease liability recognised was assessed to expire in June 2022 which was the end of contractual period at that date.
Lease liabilities
The amounts recognised in the Financial Statements relating to lease liabilities (which are liabilities arising from financing activities) are as follows:
|
|
Year ended |
Year ended |
|
|
31 Dec 2022 |
31 Dec 2021 |
|
|
$'000 |
$'000 |
|
|
|
|
|
At 1 January |
15,790 |
97,321 |
|
Remeasurement of lease liability |
75,897 |
(67,337) |
|
Cash payments of principal and interest |
(27,837) |
(18,596) |
|
Interest charged |
3,873 |
4,412 |
|
Foreign exchange movements |
(233) |
(10) |
|
At 31 December |
67,490 |
15,790 |
|
|
|
|
|
Of which: |
|
|
|
Current |
27,612 |
13,880 |
|
Non-current |
39,878 |
1,910 |
|
|
67,490 |
15,790 |
The Group's main lease is the bareboat charter of the Aoka Mizu FPSO for which the Group makes fixed payments (which are included within the lease liability measurement) and variable payments (which are based on a percentage of the quantity and price of crude oil sold and recognised as an expense in the period in which the related sales are made - see note 2.2). Under the original terms of the contract, should the Group give notice to terminate the lease (other than by not exercising extension option periods), significant early termination penalties would have applied. The Group was required to set aside amounts to cover a portion of these early termination penalties, the balance of which changed over time in line with the contract, and such balances were classified as restricted cash (see note 4.1).
The lease term for the Aoka Mizu FPSO was previously assessed to have been six years from inception of the lease (to June 2025), taking into account extension options and termination arrangements. On 4 June 2021, the Group announced it had resolved not to exercise its option to extend the bareboat charter of the Aoka Mizu FPSO for a period of three years from June 2022 to June 2025. As the Group elected not to exercise an option previously included in its determination of the lease term, the lease term was subsequently reassessed, for IFRS 16 accounting purposes, to be expiring at the end of the contractual period (being June 2022), and therefore the liability remeasured by discounting the revised lease payments. This resulted in a decrease to the lease liability of $67.3 million, decrease to the associated right-of-use asset cost of $18.2 million and a gain of $49.1 million recognised in Group Statement of Comprehensive Income.
On 25 March 2022, the Group announced that it had signed a contract with Bluewater, for an extension to the bareboat charter beyond the previous expiry date of 4 June 2022. The extension is expected to continue for the remaining economic life of the Lancaster field given the significant economic incentive for both sides to extend the lease based on the current forward price curve and production profiles. In accordance with IFRS 16 the liability was remeasured by discounting the revised lease payments covering the economic life of field. This resulted in an increase to the lease liability of $54.5 million (above) and corresponding increase to the associated right-of-use asset cost of $54.5 million (note 2.3).
On 31 December 2022, the economic life of the Lancaster field was reassessed, and the liability remeasured resulting in a further increase to the lease liability (above) and associated right-of-use asset (note 2.3) of $21.4 million.
Other charges to the Group Statement of Comprehensive Income in respect of leases during the year included the following:
|
|
Year ended |
Year ended |
|
|
31 Dec 2022 |
31 Dec 2021 |
|
|
$'000 |
$'000 |
|
Depreciation charge of right-of-use assets: |
|
|
|
Oil and gas assets (included within cost of sales) |
26,652 |
3,404 |
|
Other fixed assets (included within general and administrative expenses) |
235 |
364 |
|
|
26,887 |
3,768 |
|
|
|
|
|
Provision for impairment of right-of-use assets: |
|
|
|
Oil and gas assets (included within cost of sales) |
− |
- |
|
Other fixed assets (included within general and administrative expenses) |
− |
719 |
|
|
− |
719 |
|
|
|
|
|
Lease interest (included within finance costs) |
3,873 |
4,412 |
|
|
|
|
|
Variable lease payments (included within cost of sales) |
24,822 |
20,454 |
The total gross cash outflow for leases for the year was $52.8 million.
5.3 Maturity analysis of financial liabilities
The maturity analysis of contractual undiscounted cash flows for non-derivative financial liabilities is as follows:
|
|
Less than 6 months |
6-12 months |
1-2 years |
2-5 years |
More than 5 years |
Total |
|
|
$'000 |
$'000 |
$'000 |
$'000 |
$'000 |
$'000 |
|
|
|
|
|
|
|
|
|
Trade and other payables |
15,887 |
- |
- |
- |
- |
15,887 |
|
Lease liabilities |
13,873 |
13,914 |
27,759 |
19,151 |
308 |
75,005 |
|
At 31 December 2022 |
29,760 |
13,914 |
27,759 |
19,151 |
308 |
90,892 |
|
|
Less than 6 months |
6-12 months |
1-2 years |
2-5 years |
More than 5 years |
Total |
|
|
$'000 |
$'000 |
$'000 |
$'000 |
$'000 |
$'000 |
|
|
|
|
|
|
|
|
|
Trade and other payables |
18,843 |
- |
- |
- |
- |
18,843 |
|
Convertible Bond interest |
2,944 |
1,472 |
- |
- |
- |
4,416 |
|
Convertible Bond principal |
- |
78,515 |
- |
- |
- |
78,515 |
|
Lease liabilities |
13,900 |
441 |
499 |
1,038 |
865 |
16,743 |
|
At 31 December 2021 |
35,687 |
80,428 |
499 |
1,038 |
865 |
118,517 |
The maturity analysis for lease liabilities includes only those fixed lease repayments contracted to at the balance sheet date.
5.4 Share capital
|
|
|
|
|
Ordinary Shares |
|
$'000 |
|
At 31 December 2020 |
|
|
|
1,991,871,556 |
|
2,885 |
|
At 31 December 2021 |
|
|
|
1,991,871,556 |
|
2,885 |
|
At 31 December 2022 |
|
|
|
1,991,871,556 |
|
2,885 |
The Company has one class of Ordinary Share, all of which are fully paid and have a par value of £0.001. The rights and obligations of holders of Ordinary Shares are disclosed in the Directors' Report. The Company does not have an authorised share capital.
There are no outstanding warrants or rights relating to the Company's Ordinary Shares.
5.5 Share option reserve
The share option reserve arises as a result of the expense recognised in the Group Statement of Comprehensive Income to account for the cost of share-based employee compensation arrangements.
5.6 Own shares reserve
The own shares reserve represents the cost of Ordinary Shares in Hurricane Energy plc purchased and held by the Group's SIP Trust to satisfy the Group's SIP administered by Global Shares Trustee Company Limited.
The SIP did not acquire any Ordinary Shares in 2022 or 2021. At 31 December 2022 there were 2,113,153 Ordinary Shares held in the SIP Trust (2021: 2,610,286), with 995,684 allocated to participants (2021: 1,872,498).
5.7 Foreign exchange reserve
The foreign exchange reserve arose from the change in the Company's functional and presentation currency from Pounds Sterling to US Dollars on 1 January 2017.
5.8 Capital risk management
The Group's objectives when managing capital are to safeguard its ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders. The Group is not subject to any externally imposed capital requirements.
Capital managed by the Group at 31 December 2022 consists of cash and cash equivalents, borrowings and equity attributable to equity holders of the parent. The capital structure is reviewed by management through regular internal and financial reporting and forecasting. As at 31 December 2022 equity attributable to equity holders of the parent was $195.8 million (2021: $86.9 million), whilst unrestricted cash and cash equivalents and liquid investments amounted to $138.4 million (2021: $68.9 million).
Section 6. Taxation
Accounting policy
Current and deferred tax, including UK corporation tax and overseas corporation tax, are provided at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted by the balance sheet date.
From time to time, entities within the Group may be entitled to claim tax deductions in relation to qualifying expenditure, such as the UK's research and development tax incentive regime. Such allowances are accounted for as tax credits, reducing income tax payable and current tax expense, and are only recognised as current tax receivables when amounts have been agreed with the relevant tax authorities and not at the point that the claims are made. Deferred tax assets are recognised for unclaimed tax credits subject to the conditions outlined below.
Deferred tax assets and liabilities are calculated in respect of temporary differences using a balance sheet liability method. Deferred tax assets and liabilities are recorded for all temporary differences arising between the tax basis of assets and liabilities and their carrying values for financial reporting purposes, except in relation to goodwill or the initial recognition of an asset as a transaction other than a business combination. A deferred tax asset is recorded only to the extent that it is probable that taxable profit will be available against which the deferred tax asset will be realised or if it can be offset against existing deferred tax liabilities.
Deferred tax assets and liabilities are measured at tax rates that are expected to apply to the period when the asset is realised or the liability is settled, based on tax rates that have been enacted or substantively enacted at the balance sheet date.
Critical judgement and key source of estimation uncertainty - recognition of, and estimation of future taxable profits against which to recognise, deferred tax assets
Judgement has been applied in determining whether deferred tax assets are recognised on the Statement of Financial Position (over and above the extent to which they offset deferred tax liabilities). Estimates of future taxable profits were made using the Group's corporate cash flow model. The cash flows included in the corporate model are predominantly derived from future revenue from the Lancaster EPS arising from the currently producing wells, and future spend on currently unsanctioned capital projects. Estimates of future taxable profits were made using the Group's corporate cash flow model, with key judgements and assumptions consistent with those used in testing the Lancaster assets for impairment (note 2.3.1). The results of the review concluded that there would not be sufficient forecast taxable profits at this time to recognise a deferred tax asset in excess of deferred tax liabilities.
Assumptions about the generation of future taxable profits depend on management's estimates of cash flows and taxable income. These estimates are primarily based on forecast cash flows from operations (which are impacted by production and sales volumes, oil and gas prices, hydrocarbon reserves and operating costs), as well as decommissioning estimates, future capital expenditure and capital structure. Should future cash flows and/or taxable income differ significantly from these estimates, the ability of the Group to realise the net deferred tax assets recorded at the reporting date could be impacted.
6.1 Tax charge for the year
|
|
Year ended |
|
Year ended |
|
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
$'000 |
|
$'000 |
|
UK corporation tax |
|
|
|
|
Current tax charge - current year |
(6,199) |
|
_ |
|
Current tax credit - prior year |
4,588 |
|
- |
|
Total current tax charge |
(1,611) |
|
- |
|
|
|
|
|
|
Deferred tax - current year |
(104) |
|
21 |
|
Deferred tax - prior year |
- |
|
5 |
|
Total deferred tax |
(104) |
|
26 |
|
Tax (charge) / credit per Group Statement of Comprehensive Income |
(1,715) |
|
26 |
|
|
|
|
|
|
Profit on ordinary activities before tax |
110,376 |
|
18,210 |
|
Profit on ordinary activities multiplied by standard combined rate of corporation tax in the UK applicable to oil and gas companies of 40% (2021: 40%) |
(44,150) |
|
(7,284) |
|
Effects of: |
|
|
|
|
Expenses not deductible for tax purposes |
(1,155) |
|
(1,934) |
|
Income not chargeable for tax purposes |
1,265 |
|
7,692 |
|
Items taxed at rates other than the standard rate of 40% |
590 |
|
(2,064) |
|
Ring-fence expenditure supplement |
14,825 |
|
20,560 |
|
Prior period deferred tax |
4,588 |
|
5 |
|
Utilisation of amounts not previously recognised/deferred tax assets not recognised |
33,854 |
|
(6,687) |
|
Impact of tax rate change |
- |
|
25 |
|
Chargeable gain |
(5,333) |
|
(10,287) |
|
Energy Profits Levy |
(6,199) |
|
- |
|
Total tax credit/(charge) for the year |
(1,715) |
|
26 |
The tax charge for the period includes a current tax charge of $6.2 million relating predominately to the Energy (Oil and Gas) Profits Levy Act 2022 (EPL), which was introduced and took effect for profits generated from 26 May 2022 onwards at a rate of 25%. An instalment payment of $2.6 million was made in the year against the EPL resulting in a tax liability as at 31 December 2022 of $3.6 million. The amounts not recognised for the period includes $94.7 million of additional deferred tax assets not recognised, in relation to the revaluation of temporary differences (excluding decommissioning liabilities) from 40% to 75% (being the combined RCFT/SC/EPL rate from 1 January 2023) to reflect the increase in tax rate in future periods to 31 March 2028, when the EPL is currently legislated to no longer apply.
6.2 Deferred tax
|
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
$'000 |
|
$'000 |
|
|
|
|
|
|
Accelerated capital allowances |
- |
|
83 |
|
Other temporary differences |
- |
|
21 |
|
Tax losses carried forward |
- |
|
- |
|
Deferred tax asset |
- |
|
104 |
A potential deferred tax asset of $303.6 million in relation to tax losses and allowances available to the main trading entity, Hurricane GLA Limited, has not been recognised, as it has been concluded that it is not appropriate to recognise any of this potential deferred tax asset based on current forecasts of future profitability. There is an additional deferred tax asset of $81.5 million representing pre-trading expenditure not recognised and includes potential claims for ring fence expenditure supplement (RFES). The additional deferred tax asset is calculated primarily at a rate of 40% (2021: 40%) subject to any adjustments required for supplementary charge tax.
6.3 Factors which may affect future tax charges
The Group has ring-fenced trading losses (including certain RDEC credits) of $214.5 million at 31 December 2022 (2021: $381.9 million) and supplementary charge losses and allowances of $629.8 million at 31 December 2022 (2021: $693.0 million), which have no expiry date and would be available for offset against future ring-fenced trading profits. The Group also has unclaimed capital allowances of $333.1 million available to be used against future taxable profits (2021: $328.4 million). Out of these unclaimed capital allowances, $182.0 million are expected to unwind during the period when the EPL applies to the ring fence taxable profits and therefore the tax value of these allowances has been disclosed at the 75% combined EPL rate (from 1 January 2023) rather than the combined RCFT/SC rate of 40%.
In addition to the above, the Group has pre-trading expenditure of $126.4 million (2021: $124.9 million) which is carried forward at 31 December 2022 and tax relief may be available should trading activities commence (this expenditure could also be uplifted by RFES to $77.2 million).
The value of tax attributes as at 31 December 2022 at the currently prevailing tax rates can be summarised as follows:
|
|
Tax attributes |
Tax rate |
Tax value |
|
|
$'000 |
% |
$'000 |
|
|
|
|
|
|
Ring-fence losses |
191,526 |
30% |
57,458 |
|
RDEC not recognised |
22,974 |
40% |
9,190 |
|
Supplementary charge losses |
102,346 |
10% |
10,235 |
|
Investment allowance |
527,505 |
10% |
52,751 |
|
Unclaimed capital allowances |
150,921 |
40% |
60,368 |
|
Unclaimed capital allowances expected to unwinding during the EPL period |
182,211 |
75% |
136,658 |
|
Pre-trading expenditure (including RFES) |
203,622 |
40% |
81,449 |
|
Future decommissioning costs |
47,057 |
40% |
18,823 |
|
Non-ring-fence losses |
5,320 |
25% |
1,330 |
|
Value of tax attributes at prevailing tax rates |
|
|
428,262 |
Oil and gas activity in the UK is subject to Corporation Tax at a combined rate of 40% made up of 30% ring fence corporation tax and 10% supplementary tax charge. The amount of tax loss that is associated with supplementary tax charge is generally lower that ring fence losses as while interest is deductible for ring fence corporation tax purposes, it is not deductible for supplementary charge tax. Ring Fence losses are relievable at 30% and supplementary charge tax losses are relievable at 10%. Once adjusted to take into account interest not deductible for supplementary charge the effective rate of relief is 35.3% relief. Investment allowance is only allowable against supplementary charge tax and attracts relief at 10%. Investment allowance is available after tax losses have been taken into account.
In the Spring Budget 2021, the Government announce that from 1 April 2023 the corporation tax rate will increase to 25%. The increase in rate was substantively enacted on 24 May 2021. Deferred taxes at the balance sheet date have been measured using these enacted rats and where recognised reflected in these financial statements. In the Autumn Statement 2022, amongst other measures, it was confirmed that as already enacted the Corporation Tax will increase to 25% from 1 April 2023.
Section 7. Other disclosures
7.1 Auditor's remuneration
The following is an analysis of the gross fees payable to the Group's auditor, PKF Littlejohn LLP.
|
|
Year ended |
|
Year ended |
|
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
$'000 |
|
$'000 |
|
Audit services |
|
|
|
|
Fees payable to the Company's auditors for: |
|
|
|
|
The audit of the Company's annual accounts * |
165 |
|
247 |
|
The audit of the Company's subsidiaries |
28 |
|
25 |
|
|
193 |
|
272 |
|
Non-audit services |
|
|
|
|
Other services pursuant to legislation - interim review |
28 |
|
25 |
|
Fees payable to previous auditor for audit transition services |
− |
|
9 |
|
|
28 |
|
34 |
|
Total |
221 |
|
306 |
* Fees payable for the audit of the Company's annual accounts for the year ended 31 December 2021 included $104,000 of additional fees paid to Deloitte LLP, the Group's previous auditor, in respect of the 2020 audit.
7.2 Other non-current assets
Accounting policy
Fixed assets, other than oil and gas assets, are depreciated so as to write off the cost, less estimated residual value, of the asset on a straight-line basis over their useful lives of between two and five years.
The accounting policy for leases, including right-of-use assets, is presented in note 5.2.
|
|
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
|
$'000 |
|
$'000 |
|
|
|
|
|
|
|
Other fixed assets: |
|
|
|
|
|
Leased |
|
788 |
|
1,024 |
|
Owned |
|
80 |
|
165 |
|
Prepayments and rent deposits |
|
176 |
|
175 |
|
Emission allowances |
|
− |
|
9 |
|
|
|
1,044 |
|
1,373 |
Other fixed assets held under leases (right-of-use assets) comprise office property leases. During the prior year, a provision for impairment of $0.7 million was made against one such lease. There were no additions or disposals to this class of right-of-use asset during the current or prior year.
Owned other fixed assets include the cost of leasehold improvements, fixtures, office equipment and computer hardware.
7.3 Related parties
The remuneration of the directors, who are considered the Group's key management personnel, is as follows:
|
|
|
Year ended |
|
Year ended |
|
|
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
|
$'000 |
|
$'000 |
|
|
|
|
|
|
|
Salaries, fees, bonuses and benefits in kind * |
|
1,792 |
* |
1,960 |
|
Share-based payment charge |
|
10 |
|
463 |
|
|
|
1,802 |
|
2,423 |
All transactions with the directors will be detailed in the Remuneration Report section of the Governance Report of the full 2022 Annual Report, which shows total fixed and variable payments of £1,465,000 ($1,792,000 as above *) made to directors during the year.
As of 31 December 2022, Crystal Amber Fund Limited ('Crystal Amber') held 28.9% of the Company's Ordinary Shares, and Crystal Amber have classified its investment in Hurricane as an associate. As such, Crystal Amber are considered to be a related party of the Group.
There is no ultimate controlling party of the Group.
7.4 Subsequent events
· On 3 February 2023, the Company's previously held share premium account for value $822.5m was cancelled against the Company's accumulated deficit. This cancellation was approved by the Company's shareholders at a General Meeting held on 11 January 2023, and was subsequently approved by the High Court of England and Wales on 31 January 2023. The cancellation of the share premium and consequent elimination of the accumulated deficit results in reserves being made available for distribution to the Company's shareholders
· On 17 February 2023, the Group relinquished the licence P2308 comprising the Halifax asset. This asset was impaired to nil by 31 December 2022.
· On 16 March 2023, the Company announced that an agreement has been reached on the terms of a recommended acquisition of the entire issued ordinary share capital by Prax Exploration & Production PLC. The terms and details of the recommended offer are set out in the Scheme Document published on 6 April 2023 and available on the Hurricane website. Completion of the acquisition is subject to Court approval.
Appendix A: Glossary
|
1C |
Denotes low estimate of Contingent Resources |
|
1P |
Denotes low estimate of Reserves (i.e. Proved Reserves). |
|
2C |
Denotes best estimate of Contingent Resources |
|
2P |
Denotes the best estimate of Reserves. The sum of Proved plus Probable Reserves |
|
3C |
Denotes high estimate of Contingent Resources |
|
3P
|
Denotes high estimate of Reserves. The sum of Proved plus Probable plus Possible Reserves |
|
4Z
|
The suspended 205/21a-4z well on the Lancaster field, plugged and abandoned during 2021 |
|
The Acquisition
|
The proposed purchase of the entire issued and to be issued ordinary share capital of Hurricane by Prax |
|
AIM |
The AIM market of the London Stock Exchange |
|
AGM |
Annual General Meeting |
|
Aoka Mizu |
The Aoka Mizu FPSO, under lease to the Company from Bluewater |
|
bbl |
Barrel |
|
Bluewater |
Bluewater Energy Services and affiliates |
|
Bondholder |
A holder of one or more the Company's Convertible Bonds |
|
Board |
Board of directors of the Company |
|
bopd |
Barrels of oil per day |
|
BP |
BP Oil International Limited |
|
bubble point |
The pressure at which gas begins to come out of solution from oil within the reservoir |
|
carry |
Payment of a partner's working interest share of costs |
|
CEO |
Chief Executive Officer |
|
CFO |
Chief Financial Officer |
|
CGU |
Cash generating unit |
|
CMED |
Central medical emergency dispatch |
|
CO2e |
Carbon dioxide equivalent |
|
Company |
Hurricane Energy plc and/or its subsidiaries |
|
Companies Act 2006 |
Act of the Parliament of the United Kingdom which forms the primary source of UK company law |
|
Contingent Resources
|
Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable owing to one or more contingencies |
|
Convertible Bond(s)
|
$230.0 million 7.5% convertible bonds issued by the Company in July 2017, of which $78.5 million remain outstanding as at 31 December 2021 |
|
COO |
Chief Operations Officer |
|
CoP |
Cessation of production |
|
COP 21
|
The 21st Conference of the Parties to the United Nations Framework Convention on Climate Change |
|
Court |
High Court of Justice of England and Wales |
|
COVID-19 |
Coronavirus |
|
CPR |
Competent Persons Report |
|
Crystal Amber |
Crystal Amber Fund Limited |
|
DCU |
Deferred Consideration Units |
|
DD&A |
Depreciation, depletion and amortisation |
|
Developed reserves
|
Reserves that are expected to be recovered from existing wells and facilities. Developed reserves may be further sub-classified as producing or non-producing |
|
DRR |
Directors' Remuneration Report |
|
D&O |
Directors and Officers |
|
E&E |
Exploration and Evaluation |
|
E&P |
Exploration and Production/Exploration and Production company |
|
EPL |
Energy (oil & gas) Profits Levy |
|
EPS |
Early Production System |
|
ERCE |
ERC Equipoise Limited |
|
ESG |
Environmental, Social and Governance |
|
ESP |
Electrical submersible pump |
|
FDPA |
Field Development Plan Addendum |
|
FPSO |
Floating production storage and offloading vessel |
|
FRC |
Financial Reporting Council |
|
FSP |
Formal Sale Process |
|
FVLCD |
Fair value less costs of disposal |
|
FVTPL |
Fair value through profit and loss |
|
G&A |
General and Administrative costs |
|
GBP |
British Pounds Sterling |
|
GHG
|
Greenhouse Gas (i.e. Carbon Dioxide, Methane, Nitrous Oxide, Chlorofluorocarbon-12, Hydrofluorocarbon-23, Sulphur Hexafluoride, Nitrogen Trifluoride) |
|
GLA |
Greater Lancaster Area, comprising UKCS licences P1368 Central and P2308 |
|
GRI |
Global Reporting Initiative |
|
Group |
Hurricane Energy plc, together with its subsidiaries |
|
GWA |
Greater Warwick Area, comprising the Lincoln and Warwick fields located on UKCS licences P1368 South and P2294 |
|
HSE |
Health, Safety and Environment |
|
HSEMS |
Health, Safety and Environmental Management System |
|
HSSE |
Health, Safety, Security and Environment |
|
Hurricane |
Hurricane Energy plc, together with its subsidiaries |
|
IAS |
International Accounting Standard |
|
IFRS |
International Financial Reporting Standards |
|
Incoterms |
The internationally recognised set of rules which define the responsibilities of buyers and sellers for the delivery of goods under sales contracts |
|
IPCC |
Intergovernmental Panel on Climate Change |
|
IPIECA |
International Petroleum Industry Environmental Conservation Association |
|
IPO |
Initial Public Offering |
|
ISDA |
International Swaps and Derivatives Association |
|
ISO 14001 |
International Organization for Standardization certification - Environmental Management |
|
ISO 45001
|
International Organization for Standardization certification - Occupational Health and Safety Management |
|
JV |
Joint venture |
|
Kyoto Protocol
|
An international agreement that called for industrialised nations to reduce their greenhouse gas emissions significantly. |
|
KPI |
Key Performance Indicator |
|
LIBOR |
London Interbank Offered Rate |
|
LTIFR |
Lost time incident frequency rate |
|
LTIP |
Long term incentive plan |
|
Mbbl |
Thousand barrels of oil |
|
MER UK |
A government strategy: maximising economic recovery of UK petroleum |
|
MMbbl |
Million barrels of oil |
|
MMstb |
Million stock tank barrels of oil |
|
NSTA |
North Sea Transition Authority (formerly Oil and Gas Authority (OGA)) |
|
Official List |
The list of companies listed in the UK maintained by the Financial Conduct Authority (acting in its capacity as the UK Listing Authority) |
|
OGA |
Oil and Gas Authority (now known as the North Sea Transition Authority (NSTA)) |
|
OEUK
|
Offshore Energies UK; the oil & gas trade association for the United Kingdom (formerly known as OGUK) |
|
OPRED |
Offshore Petroleum Regulator for Environment and Decommissioning |
|
Ordinary Shares |
Ordinary shares in the Company of £0.001 each |
|
OWC |
Oil water contact |
|
P6 |
The 205/21a-6 producer well on the Lancaster field |
|
P7z |
The 205/21a-7z well on the Lancaster field, currently shut-in |
|
P8 |
Proposed side-track of the existing 205/21a-7z well |
|
Performance Measures |
Those KPIs that relate to annual bonuses - inter-year progress measures, ensuring continued progress towards delivery of the Company's strategy on an annual basis |
|
PILON |
Pay in Lieu of Notice |
|
PKF |
PKF Littlejohn LLP, auditor |
|
Prax |
Prax Exploration and Production PLC (a wholly owned subsidiary of State Oil Limited) |
|
Premium Listing |
Listing on the premium segment of a recognised stock exchange |
|
PRMS |
Petroleum Resources Management System |
|
PSP |
Performance Share Plan |
|
psi |
Pounds per square inch unit of pressure |
|
QCA |
Quoted Companies Alliance |
|
QCA Code |
The QCA Corporate Governance Code |
|
R&D |
Research & Development |
|
Regulator
|
The North Sea Transition Authority, the Department for Business Energy and Industrial Strategy, the Offshore Petroleum Regulator for Environment and Decommissioning and/or The Health and Safety Executive |
|
Reserves
|
Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions |
|
RDEC |
Research and Development Expenditure Credit |
|
RFES |
Ring fence expenditure supplement |
|
The Scheme
|
The potential acquisition of Hurricane by Prax by means of a court-sanctioned scheme of arrangement under Part 26 of the Companies Act 2006 between Hurricane and Hurricane Shareholders |
|
Scheme Document
|
Circular in relation to the Scheme setting out the full terms and conditions of the Scheme available on Hurricane's website |
|
SIP |
Share Incentive Plan |
|
SONIA |
Sterling Overnight Index Average |
|
Special dividends |
The transaction dividend and the supplementary dividend |
|
Spirit Energy |
Spirit Energy Limited and affiliates |
|
Supplementary dividend |
Under the terms of the Acquisition, Hurricane Shareholder will be entitled to receive a supplementary dividend of up to 1.87 pence per share in cash conditional on Hurricane receiving cash proceeds from the April oil lifting from the Lancaster field |
|
TCFD |
Task force on climate-related financial disclosures |
|
Threshold Value |
The price used to determine the value of Growth Shares in relation to the VCP: £0.34 per share (the price on date of issue of the Growth Shares), as adjusted |
|
Tier 1 contractors |
Hurricane's major direct contractors |
|
Transaction dividend
|
Under the terms of the Acquisition, Hurricane Shareholder will be entitled to receive a transaction dividend of 3.32 pence per share in cash |
|
TRIR |
Total recordable incident rate |
|
TSR |
Total Shareholder Return |
|
UKCS |
United Kingdom Continental Shelf |
|
USD |
United States Dollars |
|
VCP |
Value Creation Plan |
|
VIU |
Value in use |
|
WOSPS |
West of Shetland Pipeline System |
Appendix B: Non-IFRS measures
Accounting policy for non-IFRS measures
Management believes that certain non-IFRS measures (also referred to as 'alternative performance measures') are useful metrics as they provide additional useful information on performance and trends. These measures are used by management for internal performance analysis and incentive compensation arrangements for directors and employees. The non-IFRS measures presented below are not defined in IFRS or other GAAPs and therefore may not be comparable with similarly described or defined measures reported by other companies. They are not intended to be a substitute for, or superior to, IFRS measures.
Definitions and reconciliations to the nearest equivalent IFRS measure are presented below.
Underlying profit before tax
Underlying profit before tax is defined as profit before tax under IFRS less: fair value gains or losses on the Convertible Bond embedded derivative; fair value gains or losses on unhedged derivative financial instruments; impairment, impairment reversals and write-offs of intangible exploration and evaluation assets and other fixed assets; changes in decommissioning estimates on fully impaired assets; gains or losses on lease remeasurements; gains or losses on repurchase of debt instruments; and gains or losses on disposal of assets or subsidiaries.
Management believes that underlying profit before tax is a useful measure as it provides useful trends on the pre-tax performance of the Group's core business and asset by removing certain non-cash items and transactions within the Group Statement of Comprehensive Income. These are the volatile non-cash impact of the Convertible Bond embedded derivative movement, gains or losses arising from lease remeasurements, write-offs and impairments of assets including movements on decommissioning provisions where assets are fully impaired, accounting gains arising from debt repurchases, and disposals of assets or subsidiaries where they do not reflect the Group's core business.
|
|
|
|
Year ended |
|
Year ended |
|
|
Note |
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
|
|
$'000 |
|
$'000 |
|
|
|
|
|
|
|
|
Profit before tax (IFRS measure) |
|
|
110,376 |
|
18,210 |
|
Add back: |
|
|
|
|
|
|
Fair value loss/(gain) on Convertible Bond embedded derivative |
5.1 |
|
(27) |
|
1,901 |
|
Impairment and write-off of intangible exploration and evaluation assets |
2.4 & 4.3 |
|
4,234 |
|
54,280 |
|
Change in decommissioning estimates on fully impaired assets |
2.5 |
|
(1,032) |
|
1,973 |
|
Impairment of oil and gas assets |
2.3 |
|
- |
|
- |
|
Impairment of other fixed assets and other right-of-use assets |
5.2 |
|
- |
|
719 |
|
Gain on revision of lease term |
5.2 |
|
- |
|
(49,125) |
|
Net gain on repurchase of Convertible Bonds |
5.1 |
|
- |
|
(17,201) |
|
Underlying profit before tax |
|
|
113,551 |
|
10,757 |
Cash production costs
Cash production costs are defined as cost of sales under IFRS, less depreciation of oil and gas assets (including right-of-use assets) and accounting movements of crude oil inventory (including any net realisable value provision movements), plus fixed lease payments payable for leased oil and gas assets. Cash production costs (excluding incentive tariff) are defined as cash production costs less variable lease payments.
Depreciation and movements in crude oil inventory are deducted as they are non-cash accounting adjustments to cost of sales. Fixed lease payments payable for oil and gas assets are added back because, under IFRS 16, the charge relating to fixed lease payments is charged to the Group Statement of Comprehensive Income within both depreciation of oil and gas assets and interest on lease liabilities. They are therefore included within cash production costs as they are considered by management to be operating costs in nature. Fixed lease payments payable for the purposes of this measure are calculated as the day rate charge multiplied by the number of days in the period. Cash production costs (excluding incentive tariff) deduct variable lease payments, as the latter is directly linked to the price of crude oil sold and thus largely outside of management's control. Cash production cost per barrel measures are defined as the relevant cash production cost measure divided by production volumes.
Management believes that cash production costs and cash production costs per barrel (both including and excluding incentive tariff) are useful measures as they remove non-cash elements from cost of sales, assist with cash flow forecasting and budgeting, and provide indicative breakeven amounts for the sale of crude oil.
|
|
|
|
Year ended |
|
Year ended |
|
|
Note |
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
|
|
$'000 |
|
$'000 |
|
|
|
|
|
|
|
|
Cost of sales (IFRS measure) |
2.2 |
|
173,421 |
|
173,125 |
|
Less: |
|
|
|
|
|
|
Depreciation of oil and gas assets - owned |
2.2 |
|
(55,212) |
|
(94,200) |
|
Depreciation of oil and gas assets - leased |
2.3 |
|
(26,652) |
|
(3,405) |
|
Movements in crude oil inventory |
2.2 |
|
(3,553) |
|
10,622 |
|
Add: |
|
|
|
|
|
|
Fixed lease payments payable on oil and gas assets |
|
|
27,381 |
|
19,638 |
|
Cash production costs |
|
|
115,385 |
|
105,780 |
|
Variable lease payments (incentive tariff) |
2.2 |
|
(24,822) |
|
(20,454) |
|
Cash production costs (excluding incentive tariff) |
|
|
90,563 |
|
85,326 |
|
|
|
|
|
|
|
|
Production volumes |
|
|
3,089 Mbbl |
|
3,748 Mbbl |
|
Cash production costs per barrel |
|
|
$37.4/bbl |
|
$28.2/bbl |
|
Cash production costs per barrel (excluding incentive tariff) |
|
|
$29.3/bbl |
|
$22.8/bbl |
Net free cash and net debt
Net free cash is defined as current unrestricted cash and cash equivalents, plus current financial trade and other receivables (which exclude prepayments) and current oil price derivatives, less current financial trade and other payables (which includes accruals) and tax liabilities.
Management believes that net free cash is a useful measure as it provides a view of the Group's available liquidity and resources after settling all its immediate creditors and accruals and recovering amounts due and accrued from joint operation activities, outstanding amounts from crude oil sales and after settling any other financial trade payables or receivables.
Net debt is defined as net free cash less the nominal value of the Convertible Bond, being the total amount repayable on maturity of the Bond debt in July 2022 (unless previously converted, redeemed or purchased and cancelled).
Management believes that net debt is a useful measure as it aids stakeholders in understanding the current financial position and liquidity of the Group.
|
|
Note |
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
|
|
$'000 |
|
$'000 |
|
|
|
|
|
|
|
|
Cash and cash equivalents (IFRS measure) |
4.1 |
|
199,137 |
|
76,792 |
|
Add: |
|
|
|
|
|
|
Trade and other receivables |
4.2 |
|
3,675 |
|
2,591 |
|
Less: |
|
|
|
|
|
|
Restricted cash and cash equivalents |
4.1 |
|
(60,754) |
|
(7,934) |
|
Prepayments |
4.2 |
|
(1,130) |
|
(1,058) |
|
Trade and other payables |
4.3 |
|
(15,887) |
|
(18,843) |
|
Tax liabilities |
6.1 |
|
(3,617) |
|
- |
|
Net free cash |
|
|
121,424 |
|
51,548 |
|
Nominal value of Convertible Bond |
5.1 |
|
− |
|
(78,515) |
|
Net free cash / (Net debt) |
|
|
121,424 |
|
(26,967) |
Free cash flow
Free cash flow is defined as net cash inflow or outflow from operating activities per the Cash Flow Statement, excluding decommissioning spend and including fixed lease repayments, adjusted for other items considered by management to be capital rather than operating in nature. Free cash flow per barrel is calculated as free cash flow divided by production volumes for the year.
Management believes that free cash flow is a useful measure as it shows cash generated from ongoing operations and G&A.
|
|
|
|
Year ended |
|
Year ended |
|
|
Note |
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
|
|
$'000 |
|
$'000 |
|
|
|
|
|
|
|
|
Net cash inflow from operating activities (IFRS measure) |
|
|
203,427 |
|
147,044 |
|
|
|
|
|
|
|
|
Adjustments: |
|
|
|
|
|
|
Decommissioning spend |
|
|
277 |
|
4,824 |
|
Reallocation of items to cash capex |
|
|
- |
|
2,405 |
|
Lease repayments |
5.2 |
|
(27,837) |
|
(18,596) |
|
Free cash flow |
|
|
175,867 |
|
135,677 |
|
|
|
|
|
|
|
|
Free cash flow per barrel |
|
|
$56.9/bbl |
|
$36.2/bbl |
Cash capex
Cash capex is defined as net cash used in investing activities per the Cash Flow Statement, less cash interest received and movement in liquid investment, plus decommissioning spend and adjusted for other items considered by management to be capital rather than operating in nature. Third-party cash capex is defined as cash capex less general and administrative expenditure capitalised into fixed assets.
Management believes that cash capex and third-party cash capex are useful measures as they show overall expenditure on projects and activities considered capital in nature, with and without the impact of internally capitalised general and administrative costs.
|
|
|
|
Year ended |
|
Year ended |
|
|
Note |
|
31 Dec 2022 |
|
31 Dec 2021 |
|
|
|
|
$'000 |
|
$'000 |
|
|
|
|
|
|
|
|
Net cash (from)/used in investing activities (IFRS measure) |
|
|
(30,445) |
|
29,698 |
|
|
|
|
|
|
|
|
Adjustments: |
|
|
|
|
|
|
Interest received |
|
|
1,174 |
|
27 |
|
Increase in liquid investments |
|
|
34,739 |
|
(15,530) |
|
Decommissioning spend |
|
|
277 |
|
4,824 |
|
Reallocation of items from free cash flow |
|
|
- |
|
2,405 |
|
R&D tax refund |
|
|
4,588 |
|
|
|
Cash capex |
|
|
10,333 |
|
21,424 |
|
Less: capitalised general and administrative expenditure |
|
|
|
|
|
|
Capitalised into oil and gas assets |
3.3 |
|
(2,229) |
|
(3,025) |
|
Capitalised into intangible exploration and evaluation assets |
3.3 |
|
648 |
|
(3,456) |
|
Third-party cash capex |
|
|
8,752 |
|
14,943 |
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