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Hurricane Energy PLC (HUR)

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Thursday 28 April, 2022

Hurricane Energy PLC

Full-Year Results 2021

RNS Number : 6180J
Hurricane Energy PLC
28 April 2022
 

28 April 2022

Hurricane Energy plc

("Hurricane", the "Company", or the "Group")

Full-year Results 2021

Hurricane Energy plc, the UK based oil and gas company, announces its full-year results for the period ended 31 December 2021.

 

 

Highlights

Financial results

· Revenues of $240.5 million from seven liftings of Lancaster crude (2020: $180.1 million from 12 liftings)

· Cash production costs of $28.2/bbl (2020: $17.9/bbl)

· Generated $135.7 million of free cash flow†, equivalent to $36.2/bbl (2020: $74.2 million, $14.6/bbl)

· Profit after tax for the period of $18.2 million (2020: loss after tax of $625.3 million)

· Net free cash of $51.5 million (31 December 2020: $111.4 million)

· Net debt of $27.0 million (31 December 2020: $118.6 million)

·Repurchased $151.5 million of Convertible Bonds at average price of 86%, saving $29.5m in future principal and interest

Operations

· Production within guidance with average daily rate of 10,267 bopd (2020: 13,900)

· Excellent operational uptime of 92.3%, covering planned and unplanned events

· Crude oil sales reached over 10 million barrels with 3.6 Mbbls sold across seven cargoes in 2021

· FDPA consent received allowing for production below bubble point

· Following unsuccessful farmout process, JV partners agree surrender of P1368(S) (Lincoln) licence

Corporate

·The Company's proposed financial restructuring was ultimately not pursued following the High Court Judgment that the restructuring should not be implemented

· In June 2021, the incumbent Non-Executive Directors resigned from the board, with John Wright and David Craik appointed to the board as Non-Executive Directors and John Wright assuming the position of Interim Chairman

·    In October 2021, Philip Wolfe was appointed to the board as Independent Non-Executive Director

Outlook

· FPSO Charter extension agreed in March 2022

· Full bond repayment anticipated in July 2022

·  Net free cash of at least $60m projected following bond repayment, assuming production in line with guidance and oil prices of at least $90/bbl

· Focus on efficient capital allocation to deliver most value for shareholders

· Consideration of opportunities within existing portfolio and new assets

 

Antony Maris, CEO of Hurricane, commented:

"This last year has been one of profound change for Hurricane. Despite all the recent volatility in the oil price, with the expectation that oil prices remain over $90/bbl, post bond repayment we forecast to have over $60 million of net free cash†.

The UK Government's renewed emphasis on security of supply is welcome and we are working hard to identify how best to optimise capital allocation in future activities to build further value for our shareholders. We have opportunities both within our existing portfolio, and in new opportunities in the UK oil and gas sector.

Against the backdrop of our demonstrable operational track record, financial discipline, and the significant rise in oil prices, we are preparing Hurricane for the future. Our thoughts are therefore fully focused on building on our position of increasing strength and value."

†Designates a non-IFRS measure. See Appendix B to this announcement for definition and reconciliation to nearest equivalent statutory IFRS measures.

 

The Company has published a presentation on its website to accompany this results announcement.

There will be a webcast/conference call for analysts at 9:30 a.m. BST and a recording of this will be made available on the Company's website later today at https://www.hurricaneenergy.com/investors/presentations.

 

Contacts: 

Hurricane Energy plc

Antony Maris, Chief Executive Officer

[email protected]

 

+44 (0)1483 862 820

Stifel Nicolaus Europe Limited

Nominated Adviser & Joint Corporate Broker

Callum Stewart / Jason Grossman

 

+44 (0)20 7710 7600

Investec Bank plc

Joint Corporate Broker

Chris Sim / Jarrett Silver / Charles Craven

 

+44 (0)20 7597 5970

Vigo Consulting

Public Relations

Patrick d'Ancona / Ben Simons

[email protected]

 

+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.

 

Hurricane also has a 50% interest in the Greater Warwick Area licence, which contains the Lincoln and Warwick assets.

 

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

"A year of profound change"

Dear shareholders,

I am very pleased to introduce this annual report, the first since I took on the role of Chairman of Hurricane in February 2022, having joined the Board in October 2021.

2021 was a year of profound change for Hurricane as it moved from a focus on ensuring its financial survival to a much more upbeat consideration of its positive options for the future. That process has continued in the first part of this year, at a time when a highly volatile macro environment has heavily impacted the backdrop for oil and gas companies.

Hurricane now stands in a much stronger financial position than at this point twelve months ago, largely as a result of a combination of very good operational performance at the Lancaster field and continuing high oil prices resulting both from the easing of pandemic restrictions and, more recently, the terrible events in Ukraine, where we hope to see a peaceful resolution as soon as possible.

Following a number of Board changes in 2021 and welcoming Juan Morera of Crystal Amber Fund Limited in March this year, the Company is clearly focused on determining its future path built upon firm operational and commercial foundations. As the need for domestic oil and gas supplies has been reinforced by the war in Ukraine, the policy and regulatory environment for Hurricane appears to be moving in a more supportive direction. We continue to engage with all our key stakeholders as we determine the most effective way to create value for investors.

Our priorities, as always, are safe, environmentally responsible and effective operations through our offshore and onshore business activities. I am very pleased to report that in 2021 the Company undertook all production, marine and well operations safely against a challenging COVID-19 backdrop.  The focus both offshore and onshore has been to provide a safe working environment throughout the pandemic, with added safeguarding measures where necessary.  The Aoka Mizu FPSO at the Lancaster Field has again performed well with excellent uptime. Our production averaged 10,267 barrels of oil per day ("bopd") in 2021, and in the first quarter of 2022 it has been 9,372 bopd, maintaining this strong performance.  We have, throughout the year, continued with our commitment to regulatory compliance and improved environmental stewardship; to that end we have been able to cut our 2021 Scope 1 GHG emissions intensity on the Aoka Mizu by over 10%.

Our current position contrasts with the challenging situation Hurricane faced a year ago. As a result of the combined impact of reservoir challenges at the Lancaster field identified in 2020, which saw lower than originally predicted production levels due to the field's well performance and markedly lower oil prices following the emergence of COVID-19, the Board believed there was significant doubt over the Company's ability to repay its $230 million Convertible Bond. Therefore, in late 2020, Hurricane commenced engagement with stakeholders, including an ad hoc group of its bondholders (the "Ad Hoc Committee"), to find a way to ensure Hurricane had a viable financial platform on which to operate and potentially invest further based on the Company's anticipated cashflows.

Following those discussions, during the first half of 2021, the Company proposed the implementation of a financial restructuring to its bondholders and shareholders in order to provide the Company and its stakeholders with more financial certainty. Following a hearing at which the views of multiple stakeholders were presented, including shareholders and bondholders, the High Court decided that the restructuring should not be implemented.

In the wake of this decision, the Company's incumbent Chairman, Steven McTiernan, and the other Non-Executive Directors, John van der Welle, Sandy Shaw, Beverley Smith and Dr David Jenkins, resigned from the Board on 29 June 2021. The Board thanks the previous Chairman and the other Non-Executive Directors for their contribution to the Board over their years of service. John Wright and David Craik were appointed to the Board as Non-Executive Directors on 29 June 2021 with Mr Wright assuming the position of Interim Chairman, from which he stood down in February this year. I joined the Board in October 2021 as an Independent Non-Executive Director and was then appointed as Independent Non-Executive Chairman in February 2022, with Mr Wright stepping back to be a Non-Executive Director, and Juan Morera joined as Non-Executive Director in March 2022.

In December 2021, the Company announced the completion of a review, led by the Non-Executive Directors of the Company, of the events leading up to the restructuring plan being rejected by the High Court in June 2021, including decisions made by the Company's previous Board relating to the Company's Convertible Bonds and the restructuring plan. The review, having been requested by some shareholders, was overseen by the Non-Executive Directors and carried out by an independent solicitor assisted by leading counsel. The review concluded that the Company's previous Board discharged their fiduciary duties diligently and in good faith during this time to address the fact that there was projected to be a significant shortfall upon maturity of the bond, and they received extensive advice from outside professionals on whom the Company's previous Board could and did properly rely. The review concluded that no further action was necessary, and that time and resources should now be spent on maximising the future value and potential of the Company.

The Company has been focused on improving its financial situation and commencing in September 2021, the Company undertook a number of bond repurchases, repurchasing approximately 66% of its outstanding bonds at an average price of 86 cents in the dollar. These repurchases have reduced the par value of bonds held by third parties to $78.5 million, resulting in a combined net saving of $29.5 million in debt repayment and interest charges. The Board is now confident that the bond will be repaid in full in July 2022, with the Company forecasting to be holding net free cash of at least $60 million following the repayment, assuming oil prices remain at over $90/bbl.

I believe firmly that the challenges of 2021 are behind us, and the Board's focus is now very much on working with the senior management team to determine the strategy that will create most value for our investors and provide a sustainable and exciting future for the business.

A number of options, by no means mutually exclusive, are under review to take the Company forward, whether by further exploitation of our existing portfolio, or entry to other assets within the UKCS, and ultimately with the aim of building an asset base to support capital returns to our investors. The senior management team is focused on identifying the most effective capital allocation to move Hurricane forward.

I look forward to updating stakeholders on our progress in due course and thank you for your continued support.

I would also like to thank my fellow board members, and all of the executive team and staff for their hard work, commitment and resilience during this very challenging time.

Philip Wolfe

Chairman

 

 

Chief Executive Officer's Review

Introduction

2021 was a challenging year for Hurricane as we considered how best to ensure a sustainable future for the business against a volatile market backdrop, but I am pleased to report that the Company has emerged from a difficult period in a much stronger position than it entered last year, with a solid financial platform coupled with very good operational performance at its Lancaster field. It is a great credit to our team that we have delivered high uptime and output within guidance at Lancaster. We are now able to look forward and are working hard to identify how best to allocate capital to create value for all our stakeholders.

Operational Review 

Greater Lancaster Area ("GLA")

Operationally, 2021 was focused on managing production from the Company's Lancaster field to maximise output via the Aoka Mizu FPSO whilst also continuing our work to mitigate the impact of water cut and pressure decline in the field's main producing well. Our operational team's work resulted in an average production rate of 10,267 bopd for the period.

The production uptime during the year was an excellent 92.3%, covering all planned and unplanned events. Overall, operational performance at Lancaster was very strong, with the team's clear focus on safety and environmental performance underpinning its approach throughout the year.

Some operational challenges had to be overcome but were dealt with effectively and safely. In early June 2021, the electric submersible pump ("ESP") in the P6 well tripped, which led to Lancaster production being temporarily reduced while the root cause of the trip was investigated. The successful restart of the P6 well was announced on 16 June 2021.

During 2021, seven cargoes of Lancaster oil were lifted, totalling 3.6 MMbbls. Post period end, the 27th and 28th cargoes, totalling approximately another 1.05 MMbbls, have already been lifted in January and March respectively. The next cargo is expected to be lifted in May 2022 by which time Lancaster will have produced over 13 million barrels since startup.

In June 2021, the Company received approval of the Lancaster Field Development Plan Addendum (the "FDPA") from the Regulator. The FDPA approval, together with associated production, flare, and vent consents, enables production with the bottom hole flowing pressure up to 300 psi below the bubble point pressure of the fluid (1,605 psia at 1,240 metres TVDSS), subject to the Company ensuring that no incremental liberated gas is produced to surface.

The initial consent was for a three-month period from 16 June 2021 to 15 September 2021. Subsequent renewed production, flare, and vent consents were received, and future consents are expected to be issued on an ongoing three-monthly basis subject to compliance with the terms of the FDPA. During December, the well gauge pressure reached and declined below bubble point, in line with the previously guided timing of this occurring between late December 2021 and mid-February 2022. No production issues arising from reaching bubble point have been observed to date. The Company continues to monitor this issue closely and has continued to receive the required consents from the Regulator on a three-monthly basis.

In July 2021, the FPSO underwent a planned maintenance shutdown which was completed safely with production restarting in a timely manner, at an anticipated elevated production rate leading to the average oil rate for August being higher than in previous months. This then returned, as expected, to the trend seen throughout the rest of the year.

In September 2021, the Company provided production guidance for the six-month period 1 October 2021 to 31 March 2022 of 8,500 - 10,000 bopd, based on FPSO production uptime assumption (excluding annual maintenance shutdown) of 96.5% and production from the P6 well alone on artificial lift via ESP.  Production during this 6-month period was 9,689 bopd, reflecting continued excellent uptime on the FPSO combined with production rates towards the top of the guided range.

Production guidance for the full calendar year 2022 is 7,500 - 8,600 bopd.  This is based on production from the P6 well alone on artificial lift via ESP, an annual maintenance shutdown anticipated to occur during Q3 2022, and overall FPSO production uptime outside of the shutdown window of 96.5%. As of 17 April 2022, Lancaster was producing c.9,150 bopd from the P6 well alone with an associated water cut of c. 43%, in line with guidance.

In June 2021, the Company resolved not to exercise its option to extend the bareboat charter of the Aoka Mizu FPSO for an additional three years to June 2025 as it was deemed at that juncture, from a commercial and fiduciary perspective, not to be in the best interest of the Company or its stakeholders given the significant financial obligations exercising the extension option would have entailed. The initial three-year term was due to expire in June 2022. Hurricane subsequently concluded positive negotiations with Bluewater (Aoka Mizu) B.V. ("Bluewater"), the owner of the Aoka Mizu FPSO, with regards to an alternative 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 bond. Based on the current oil price and field performance predictions we forecast this to be at least 18 months from 4 June 2022.

In addition to the charter extension, the Company also announced that it had negotiated with BP Oil International Limited ("BP"), the purchaser of its crude oil, a facility that will allow for cash to be advanced ahead of a lifting, drawing down against oil produced and held in the FPSO's tanks but not yet lifted. This provides the ability to create more frequent cash receipts and assist with the Company's working capital. The facility incurs a financing fee that is only payable if the Company uses it.

Greater Warwick Area ("GWA")

The GWA JV (Hurricane 50%, Spirit Energy 50%) has reassessed its understanding of the area, evaluating both the basement and the Mesozoic potential of the licences and has considered all options  for further appraisal and routes to  possible development. Owing to the disruption caused by the COVID-19 pandemic, an agreement was reached with the Regulator to extend the deadline for commencement of the Lincoln obligation well ("Lincoln Well") from 31 December 2020 to 30 June 2022.

Following the technical re-evaluation and interpretation of the area, the GWA JV further engaged with the Regulator to seek an appropriate extension to the timeframe for this commitment, beyond 30 June 2022. As announced on 17 December 2021, the Regulator had indicated that in the current circumstances it was not content to support a further deferral of the Lincoln Well.  As such, the GWA JV elected to suspend further funding towards planning and drilling of the obligation Lincoln Well in 2022 while it continued its discussions with the Regulator.

Efforts to realise value for its equity share of the GWA assets, including the possibility of third-party funding for the drilling of the Lincoln Well, were explored by Hurricane with a significant number of external parties, however, these did not result in formalising any interest to secure third party investment in the GWA assets. 

Hurricane has determined that further appraisal and development costs to reach an economic development on Lincoln within acceptable risk and licence timing is not feasible for the Company on a standalone basis. Further to discussions with our JV partner, Spirit Energy, the GWA JV has taken the decision to surrender the Lincoln P1368(S) licence sub area. With access to limited funds, and no reasonable expectation that the Lincoln discovery could generate any meaningful near-term cash realisation in comparison to the other options currently under consideration, voluntarily surrendering the Licence is the right choice. This gives rise to an impairment charge of $54.3 million against the full carrying value of the Lincoln asset in the Company's accounts.

Decommissioning Activities

In July 2021, Hurricane completed the plugging and abandonment ("P&A") of the 205/26b-14 ("Lincoln-14") well, which Hurricane conducted on behalf of the GWA JV. Hurricane contracted the Stena Don semi-submersible rig with the operation completed within both schedule and budget. The GWA JV had a regulatory obligation to P&A the Lincoln-14 well by 31 October 2021, and this obligation was fulfilled in advance of this date.

During November 2021, the Company successfully completed the P&A of the Lancaster 205/21a-4z well for a cost of c.$1 million. $2.2 million of decommissioning security (previously classified as restricted cash) was released back to the Company and used in part to fund this P&A activity.

Subsequent to the year end, 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 2021, Hurricane recorded one Lost Time Incident, when an offshore technician sustained a hand injury whilst undertaking maintenance activities. The individual made a full recovery. The incident was fully investigated by Bluewater and Hurricane.

The Lost Time Incident Frequency rate for 2021 was 1.71, compared to 1.29 for 2020. 

Throughout the year COVID-19 continued to feature highly on Hurricane's risk register. We have continued to work closely with our stakeholders and government authorities to manage the impact of COVID-19 on all aspects of our business during 2021.

Safeguarding measures were put in place to manage the health and safety of offshore personnel. These measures included pre-mobilisation COVID-19 testing, use of face coverings during transit to the FPSO by helicopter, daily COVID-19 health screening on the FPSO and the wearing of face masks offshore, where practicable, to prevent airborne transmission. Our installation operator, Bluewater, has put in place a COVID-19 hazard identification risk assessment aimed at preventing outbreaks of COVID-19 offshore and, if cases occur, managing any outbreaks on the FPSO. Offshore medics have been trained in the use of testing equipment, which has been vital for the early detection, isolation, and repatriation to shore of COVID-19 cases.

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 COVID-19 flying arrangements, with attendant paramedics, have been put in place 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.

ESG and gas export update

In June 2021, Hurricane published its second standalone Environmental, Social and Governance ("ESG") report. The report covered Hurricane's approach to ESG and performance across its operations for the 2020 calendar year. It will publish its third ESG report later this year.

During 2021, our Scope 1 greenhouse gas emissions were 139,584 tonnes CO2e, or 37.2 kg/bbl on an intensity basis. This compared with 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 and are based on Intergovernmental Panel on Climate Change's ("IPCC") Fifth Assessment report, whereas previously, Hurricane reported using IPCC's Fourth Assessment report. Figures for 2020 have therefore been restated and align with the NSTA's reporting metrics. We believe this provides a more complete picture of our emissions performance and will allow for easier annual comparisons in the future.

On the FPSO there has been a particular focus on optimising power generation following successful FPSO power management system testing and a revision to the FPSO's power generation strategy. This has led to a reduction in power generation emissions of 42,727 tonnes CO2 in 2020 to 33,208 tonnes CO2 in 2021.

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 2022 and beyond where it is economically and commercially viable to do so.

Bond tenders

In September 2021, the Company undertook a bond tender exercise, repurchasing approximately 34% of its outstanding bonds at a price of 78 cents in the dollar. This reduced the par value of bonds held by third parties to $152 million, using $62 million of net free cash, inclusive of accrued interest. The Company completed three further repurchases during December 2021: first it completed the repurchase of a further $15.0 million of its bonds for a total consideration of $14.0 million, including accrued interest; then it repurchased an additional $28.5 million for a total consideration of $27.3 million, including accrued interest; and finally it repurchased an additional $30.0 million in aggregate principal for a total consideration of $29.0 million, including accrued interest. The net effect of these purchases was that by the end of 2021, the nominal value of the Company's outstanding bonds had reduced to $78.5 million, and a total of $29.5 million of savings had been achieved.

Reserves and resources

While the Lancaster field EPS was developed on time and on budget with first production achieved in May 2019, the field has significantly underperformed pre-production expectations. Following the full technical review of the Lancaster field and the Company's wider West of Shetland portfolio in 2020 and the independent assessment of the Company's assets, published in April 2021, additional detailed subsurface and reservoir performance analysis has been ongoing throughout the year.

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 in April 2022. Their estimates of Lancaster field Reserves and the Contingent Resources are detailed in the tables below. Year on year comparison shows an increase in developed reserves, in part due to the implications of the Lancaster field's performance during 2021 and in part due to high oil price assumptions.

People and operations

I would also like to express my thanks to all our colleagues whose hard work, professionalism and dedication during a challenging year has ensured Hurricane's operational delivery since start-up of the Lancaster field has been first class. Many months of work on the technical review and development options screening has been compressed into a fraction of that time without compromising on rigour or quality.

The health and safety of our onshore colleagues has also been a priority given the home working arrangements put in place in March 2020 to manage the spread of COVID-19. Our onshore staff have primarily been working from home since that time and, where possible, we actively encouraged flexible working recognising that employees may have responsibility for childcare, home schooling, family members as well as other obligations during the pandemic. We have conducted home working assessments to ensure that our staff have the necessary equipment and appropriate working conditions for safe and effective remote working. We have also introduced initiatives to address staff isolation and encourage contact between colleagues while we are working remotely. 

Feedback from employee engagement suggested that as we returned to the office, our employees wished to preserve some measure of home working, and we have aimed to achieve this where possible. Our offices reopened on 8 November 2021, with the implementation of a trial hybrid working arrangement requiring two days' office attendance per week.  With the resurgence of the COVID-19 Omicron variant, we took the decision to curtail the hybrid working arrangement on 9 December 2021, returning to home working.  Following the Government's relaxation of COVID-19 precautionary measures, we reopened the office in February 2022, returning to the earlier hybrid working arrangement.  We continue to monitor the prevalence of COVID-19 in the workplace and society at large, in order to ensure we apply suitable safeguarding measures to personnel both onshore and offshore.

Outlook

The Company anticipates that production from Lancaster will be in the range of 7,500 - 8,600 bopd during 2022, including a usual period of scheduled maintenance and uptime of 96.5% outside of the maintenance window. We expect water cut to increase and pressure decline to continue but still see the field as highly cash generative at current commodity prices.

With the expectation that oil prices remain over $90/bbl, post bond repayment we forecast to have over $60 million of net free cash†. Our thoughts are therefore fully focused on building on our position of increasing strength and value. Against the backdrop of our demonstrable operational track record, financial discipline, and the significant rise in oil prices, we are preparing Hurricane for the future. The UK Government's renewed emphasis on security of supply is welcome and we are working hard to identify how best to optimise capital allocation in future activities to build further value for our shareholders, whether through further investment in our existing portfolio, new opportunities in the UK oil and gas sector, or both.

Antony Maris

Chief Executive Officer

 

Lancaster Reserves and Resources

While the Lancaster field EPS was developed on time and on budget with first production achieved in May 2019, the field has significantly underperformed pre-production expectations. Following the full technical review of the Lancaster field and the Company's wider West of Shetland portfolio in 2020 and the independent assessment of the Company's assets, published in April 2021, additional detailed subsurface and reservoir performance analysis has been ongoing throughout the year.

Hurricane elected to retain ERCE to update its CPR on the Reserves and Contingent Resources of the Lancaster field, published in April 2022.  ERCE's work has been prepared in accordance with the June 2018 Petroleum Resources Management System (PRMS) as the standard for classification and reporting with an effective date of 31 December 2021.

ERCE's estimates of Lancaster field Reserves and the Contingent Resources are detailed in the tables below. Year on year comparison shows an increase in developed reserves, in part due to the implications of the Lancaster field's performance during 2021 and in part due to higher oil price assumptions.

The Company's ability to monetise its Contingent Resources will require further technical appraisal, a commercially viable development plan to be agreed, sufficient additional funding for further appraisal and development, and regulatory consents. The funding of any appraisal and/or development activity, and the Company's financial planning more broadly, needs to consider the Company's existing financial and contractual obligations, such as decommissioning and costs associated with the charter and operation of the Aoka Mizu.

ERCE's estimates of Reserves for the Lancaster field as of 31 December 2021

(MMbbl)

Gross

Net attributable to Hurricane

 

1P

2P

3P

1P

2P

3P

Developed Reserves (MMbbl)1

4.1

5.8

9.1

4.1

5.8

9.1

 

1. In determining the economic Reserves for the Lancaster field, ERCE has assumed a nominal Brent oil price forecasts as of 31 December 2021 of US$75/bbl in 2022, US$71/bbl in 2023, US$69/bbl in 2024 and US$70/bbl in 2025 and constant thereafter in real terms. In line with PRMS guidelines, the nominal oil prices assumed are those forecasts made as at the effective date of the CPR, being 31 December 2021.  Prices are escalated at 2.0% per annum inflation. 

ERCE's estimates of Contingent Resources for the Lancaster field at 31 December 2021

(MMbbl)

Gross

Net attributable to Hurricane

 

1C

2C

3C

1C

2C

3C

Contingent Resources, Development Unclarified 2

11.3

35.4

86.9

11.3

35.4

86.9

 

2. Contingent Resources, Development Unclarified, assume additional development wells and/or water injection is implemented as part of any further development; and contingent on regulatory consents, funding and execution during the lifetime of the existing Lancaster wells. 

A summary of the movements in net attributable 2P Reserves as compared to the previous CPR (effective date of 31 December 2020) is as follows:

 

 

Net attributable 2P Reserves (MMbbl)

At 31 December 2020

7.1

Produced during the year

(3.7)

Change in assumptions and economic life

2.4

At 31 December 2021

5.8

 

 

Chief Financial Officer's Review

Highlights

 

2021

2020

Production

3,748 Mbbl

5,078 Mbbl

Production rate*

10,300 bopd

13,900 bopd

Sales volumes

3,576 Mbbl

5,112 Mbbl

Revenue

$240.5m

$180.1m

Average sales price realised

$67.3/bbl

$35.2/bbl

Cash production cost per barrel†

$28.2/bbl

$17.9/bbl

Free cash flow†

$135.7m

$74.2m

Free cash flow per barrel

$36.2/bbl

$14.6/bbl

Net free cash†

$51.5m

$111.4m

Net debt†

$27.0m

$118.6m

Underlying profit/(loss) before tax†

$10.8m

$(36.0)m

Statutory profit/(loss) after tax

$18.2m

$(625.3)m

* Rounded to nearest 100 bopd.

† Non-IFRS measures. See Appendix B for definition and reconciliation to nearest equivalent statutory IFRS measures.

Overview

2021 was a year of recovery and consolidation for Hurricane, benefitting from the continuous rise and recovery in the oil price, but also taking steer from the Court's decision not to sanction the proposed financial restructuring and looking to actively manage the Company's net debt position.

Over 3.5 million barrels of Lancaster crude were sold across seven cargoes, generating over $240 million in revenue thanks to the strong oil prices seen in 2021 compared to 2020. This, combined with a continued focus on low operating costs and excellent production efficiency produced free cash flow† of $135.8 million. Cash capex† was $21.4 million, largely comprising previously committed to long-lead items for future tie-back and gas export works, capitalised G&A relating to potential Lancaster enhancement projects, and decommissioning spend primarily on the Lincoln-14 well, which was completed significantly under budget.

In the second half of the year, Hurricane took steps to actively manage its net debt position, spending $132 million to repurchase and cancel just over two-thirds of the outstanding Convertible Bonds, saving $29.5 million in future principal repayments and interest.

Although uncertainties still remain, with oil prices still supportive albeit volatile, and a significantly reduced net debt position, the financial outlook for Hurricane is now significantly improved as we look beyond repayment of the remaining Bond debt and towards new opportunities to deliver value.

Proposed financial restructuring

Towards the end of 2020, following the downgrade of our reserves and the suspension of production guidance, the Company was forecasting a shortfall of over $100 million in relation to its ability to fully repay its bonds at maturity.  Given the magnitude of this shortfall, Hurricane entered into meaningful discussions with the Bondholders regarding the ability to fully repay the Convertible Bond debt due in July 2022. This culminated in a proposed financial restructuring, which would have resulted in reduced and restructured Bonds, dilution for existing shareholders, but greater certainty over Hurricane's solvency, and a potential solution to drill an additional well on the Lancaster field.

Throughout the process up to the Court sanction hearing, the Group's projections were still showing a significant shortfall in being able to fully repay the Convertible Bond. These projections were on the basis of management's production forecasts combined with the best available oil price forecasts, using forward curves and analyst estimates. At the time, none of those forecasts and estimates showed a scenario whereby there would be a full repayment of the Bond; it was not an option to ignore those projections and continue operating as usual in the hope that the best available research and estimates on oil price would turn out to be materially incorrect.

As part of the restructuring process production forecasts were provided covering the period from June 2021 onwards.  In the period from June 2021 to March 2022, cumulative actual production was only marginally (2.7%) above these forecasts. The positive change in the financial circumstances of the Company has been brought about mainly by the continued, significant and unexpected rise in oil prices, but also impacted by the cost cutting measures implemented by the Company and the savings from the bond buy backs.

Revenue

Revenue recognised for the year was $240.5 million (2020: $180.1 million), with an average realised price of $67.3/bbl ($35.2/bbl) across 7 cargoes comprising nearly 3.6 million barrels (2020: 12 cargoes comprising 5.1 million barrels). Whilst the average Dated Brent price for the year was $70.9/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 2021 to minimise transportation costs per barrel.

The average netback to the contractual Brent price was $2.7/bbl (2020: $2.9/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 means that Hurricane has continued to sell all cargoes on time, within specification and contractual terms, maintaining our reputation as a reliable producer. This strong reputation helped in Lancaster crude being sold and delivered to two new refineries during 2021. A growing pool of buyers should result in more competitive bids for Lancaster crude and in turn higher overall realised prices received going forward.

The sales arrangement with BP means that Hurricane receives cash for a sale typically within five days of the lifting occurring. With production continuing to naturally decline, the period between liftings will increase. As such, Hurricane has agreed a facility with BP that will allow for cash to be advanced ahead of a lifting, drawing down against oil produced and held in the FPSO's tanks but not yet lifted, to create more frequent cash receipts and assist with the Company's working capital.  This facility, which takes effect from end of July 2022, incurs a small financing fee that is only payable if the Company uses it.

Cost of sales

Total cost of sales was $173.1 million (2020: $179.8 million), including $97.6 million of DD&A (2020: $96.6 million). Cash production costs† were $105.8 million (2020: $90.6 million), equivalent to $28.2 per barrel (2020: $17.9/bbl).

Excluding the revenue-linked incentive tariff, cash production costs per barrel increased from $14.6/bbl in 2020 to $22.8/bbl in 2021. This increase per barrel was driven by lower average production rates in 2021 and the contractual increase to the FPSO day rate from $25,000/day to $75,000/day effective from June 2021. Excluding the incentive tariff, cash production costs per barrel for H2 2021 (a period wholly including the increased day rate) were $26.8/bbl. With a cost base that is largely fixed, natural decline in production and inflationary cost pressures, we expect cash production costs per barrel to increase during 2022; although we continue to look for cost savings internally and with our key contractors where possible.

Impairment of intangible assets and GWA licences

During the year, the GWA JV was in engagement with the Regulator on the technical re-evaluation and interpretation of the GWA licence potential, and requested a regulatory amendment of the obligation to drill a well on the Lincoln licence, which must be commenced on or before 30 June 2022, to a later commencement date. The Regulator indicated that it was not content to support a deferral of the obligation well. Following discussions within the JV, the partners elected to continue their plans to suspend further funding towards well planning and drilling of the obligation well on Lincoln in 2022; however, funds continued to be made available in 2022 to further evaluate the area's prospectivity. Whilst meaningful discussions were held during the year between Hurricane and potential third parties to enter into the licence, these did not result in any formalised interest.

Having noted the announcements on 8 December 2020 by Spirit Energy and its largest shareholder, Centrica plc, regarding the strategic focus of its remaining UK assets and the limitation of any further investment in exploration and appraisal, and also taking into account Hurricane's financial circumstances and the related challenges of securing additional funding for the Lincoln obligation well, it was concluded that there was a reasonable prospect that the JV would be unable to either spud the obligation well by the required deadline or to obtain a deferral of the obligation well. In addition, Hurricane determined that further appraisal and development costs to reach an economic development on Lincoln within acceptable risk and licence timing is not feasible for the Company on a standalone basis. As such, in April 2022, the JV voted to voluntarily surrender the P1368(S) licence sub area. In anticipation of this, the carrying value of the Lincoln assets has been fully impaired, resulting in an impairment charge of $54.3 million.  

FPSO lease

On 4 June 2021, Hurricane announced that it 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. For the purposes of accounting for the lease under IFRS 16, the lease term was re-assessed to end in June 2022 (previously June 2025). This has resulted in a write-back of the lease liability and corresponding lease asset. As the lease asset had previously been impaired to materially less than the liability, under accounting rules the difference was credited to the income statement, resulting in a non-cash gain of $49.1 million.

In March 2022, Hurricane announced it had concluded an agreement with Bluewater to extend the charter indefinitely beyond June 2022, with either party being able to give six months' notice to terminate the arrangement. The existing day rate and tariff for the vessel remains at $75,000 per day and 8% of revenue respectively, and a secured deposit account of up to $18.7 million for the benefit of Bluewater has been established 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 opportunity and flexibility to cover production from the Lancaster field for its remaining economic life, which is forecast to be at least 18 months from June 2022.

Convertible Bond and debt management

In order to take advantage of the Group's strong cash position and the market price of the Convertible Bonds, in September 2021 Hurricane successfully completed a tender programme for repurchase of some of its bonds, repurchasing $78.0 million of outstanding Convertible Bonds for cancellation at a discount of 78% to face value. During December 2021, a series of additional bond repurchase transactions were made, repurchasing an additional $73.5 million of Bonds at an average discount of 95% to face value. The total amount of Bonds repurchased and cancelled was $151.5 million, for a total cash consideration of $132.0 million (including accrued interest). These buybacks generated a combined net saving of $29.5 million of future principal repayment and interest charges, significantly improving the net debt position and giving the Group clearer line of sight to full Bond repayment. At 31 December 2021, $78.5 million of Convertible Bonds remained outstanding.

The repurchase of the Bonds at a discount gave rise to a gain of $17.2 million (net of transaction costs). The remeasurement of the embedded derivative component of the Convertible Bond gave rise to a fair value loss of $1.9 million.

Other profit and loss

Net general and administrative costs ("G&A") before non-cash items increased from $2.9 million in 2020 to $23.6 million in 2021. This increase was primarily due to the significant expenditures incurred on the proposed financial restructuring (see above), and a higher level of G&A costs capitalised or recharged into projects or cost of sales in 2020 as compared to 2021 (see note 3.3 to the Financial Statements).  Towards the end of the year, the Group moved to identify cost savings through a right-sizing of headcount (via recruitment freezes and targeted redundancies), partially offset by the cost of retention arrangements put in place for remaining key employees. As at April 2022, excluding Non-Executive Directors, the Group's headcount had reduced to 27 employees, compared to an average of 51 throughout 2021.

Cashflow

The Group ended the year with $51.5 million of net free cash†, a decrease of $59.9 million from the position of $111.4 million at 31 December 2020.

Free cash flow† for the year was $135.7 million (2020: $74.2 million), equivalent to $36.2/bbl (2020: $14.6/bbl), driven by higher average realised Brent prices offset by the increase in day rate payable for the Aoka Mizu charter which became effective from June 2021.

Cash capex† in the period was $21.4 million, $4.8 million of which was Hurricane's share of decommissioning costs paid in the year on the Lincoln 14 and Lancaster 4Z wells. The balance of capital expenditure on GLA reflected previously committed to long-lead items for potential additional wells and gas export activity, licences, studies, and capitalised timewriting costs scoping production enhancement and development opportunities for the Lancaster field. Cash capex on GWA comprised Hurricane's share of previously committed to long-lead items for a potential Lincoln tie-back, licences, and the storage and preservation of well spares inventory and tie-back equipment. Given the uncertainty over the timings of future drilling campaigns and well tie-backs, the joint venture is exploring opportunities and options to realise value from the inventory currently held in storage.

Restricted funds

As of 31 December 2021, the Group held $45.7 million of cash and liquid investments within restricted funds, relating to decommissioning security arrangements and amounts set aside to cover potential early termination fees on the FPSO lease.

Under the FPSO charter the Group was required to hold in reserve and escrow accounts the termination costs of the FPSO lease should the Group wish to terminate the charter early. This balance would have had to increase significantly, to $56 million, if the Group exercised the charter's extension option to June 2025, which it would have been required to do by June 2021. Given the Group's financial position and forecasts at the time, combined with the uncertainty over the life of the Lancaster field, it was therefore not appropriate to extend the charter for three years on these terms. As the option was not exercised, the amounts held as restricted funds were able to be released straight line to free cash from between June 2021 and June 2022. The balance classified as restricted cash under this arrangement as at 31 December 2021 was $7.9 million (31 December 2020: $26.5 million). As part of the agreement to extend the FPSO charter, this amount is anticipated to increase to $18.7 million during 2022 and is expected to remain at that level until either party gives six months' notice to terminate the charter.

At the start of the year, the Group held £16.8 million ($22.8 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. This security was posted on a post-tax basis. In April 2021, the Regulator formally notified the Group of its intention to request an increase to the amount of decommissioning security for the Lancaster field, so that it is lodged on a pre-tax basis. Following this request, we agreed with the Regulator to place an additional £11.2 million ($15.5 million) of funds into trust. At 31 December 2021, a total of $37.8 million was held in trust as decommissioning security for the Lancaster EPS. Subsequent to the balance sheet date, an additional $7.7 million was placed into Trust following a request from the Regulator as a result of increases to our decommissioning estimates.

Following the abandonment of the Lancaster 205/21a-4z well during the year, $2.2 million of additional decommissioning security related specifically to this activity was released to free cash.

Decommissioning

The Group holds accounting provisions totalling $49.3 million for the anticipated cost of plugging and abandoning the Lancaster P6 and P7z wells, removing the associated subsea infrastructure and related FPSO costs to the Lancaster EPS and FPSO, for which decommissioning security of $37.8 million is held in trust (subsequently increased by an additional $7.7 million in February 2022). Changes in estimates during the year resulted in a non-cash charge of $2.0 million, being those changes in estimate related to the FPSO and fully impaired assets.

During the year, the abandonment of the Lincoln 205/26b-14 well was completed, as required under our licence obligation, at a gross cost of $8.6 million. This was significantly below the previously provided for cost of $13 million, thanks to the hard work of the contracting and operations team, rig contractor, and the joint venture partner support. During the year the suspended Lancaster 205/21a-4z well was also plugged and abandoned at a cost of $1.3 million.

Tax

The Group recognised a total tax credit for 2021 of $0.03 million, all of which related to deferred tax and was non-cash.

During 2021, Hurricane 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.  Subsequent to the balance sheet date, $4.3 million was received in respect of these claims and will be recognised in 2022.

Tax losses

Due to the nature of the Group's business, it has accumulated significant tax losses since incorporation. The Group has $381.9 million of ring-fenced trading losses and other allowances and supplementary charge losses and investment allowances of $693.0 million, which have no expiry date and would be available for offset against future trading profits, and $328.4 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 $409.7 million. This is the maximum possible theoretical value and is subject to timing and circumstance; and it is unlikely that all of the potential value would be able to be realised. 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. Other tax losses can only be utilised over a longer period of time, and pre-trading expenditure losses will expire should trade not commence in those entities with pre-trading losses within a certain period of time of those losses originally being incurred. At prevailing oil prices, the Group will continue to utilise its existing ring fence losses as the Lancaster EPS generates taxable profits.

Richard Chaffe

Chief Financial Officer

 

Going concern

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 $114.6 million of cash and cash equivalents and liquid investments, of which $68.9 million was unrestricted. After adjusting for working capital items, net free cash† at 31 December 2021 was $51.5 million. The Group's most significant long-term liabilities are the remaining $78.5 million of Convertible Bonds in issue due in July 2022 (with a coupon of 7.5% payable quarterly in arrears) and committed lease liabilities in respect of the Aoka Mizu FPSO.

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 the Group Financial Statements.

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

The Group's base case going concern assessment assumed the following:

· average Dated Brent oil price of $102/bbl and $89/bbl in 2022 and 2023 respectively;

· 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 supported by the most recent CPR.

Under the base case scenario, the Group had sufficient liquidity to fully repay the remaining Convertible Bonds at their maturity in July 2022 with sufficient headroom thereafter for a period of at least 12 months from the date of this report 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 25% reduction to forecast production rates

Under the sensitivity cases above, both individually and in aggregate, the Group is projected to have sufficient cash to fully repay the Convertible Bonds and 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 repay its Convertible Bonds in July 2022. These stress tests indicated that a reduction to the forecast oil price curve by $65/bbl, or a reduction to projected production rates by 60%, would result in the Group having insufficient cash to repay the Convertible Bond in full in July 2022. 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 fully repay the Bonds is unlikely to occur.

Conclusion

As a result of the going concern assessment presented above, the directors have a reasonable expectation that, after also taking into consideration the current macroeconomic situation and uncertainty arising from the COVID-19 pandemic, 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.

 

 

Group Statement of Comprehensive Income

 

 

 

 

 

 

 

 

 

Year ended

 

Year ended

 

Notes

 

31 Dec 2021

 

31 Dec 2020

 

 

 

$'000

 

$'000

 

 

 

 

 

 

Revenue

2.1

 

240,540

 

180,083

Cost of sales

2.2

 

(173,125)

 

(179,816)

Gross profit

 

 

67,415

 

267

General and administrative expenses

3.3

 

(26,749)

 

(4,229)

Gain on revision of lease term

5.2

 

49,125

 

-

Impairment of oil and gas assets

2.3

 

-

 

(519,152)

Change in decommissioning estimates on fully impaired assets

2.5

 

(1,972)

 

-

Impairment of intangible exploration and evaluation assets and exploration expense written off

2.4

 

(54,280)

 

(47,945)

Operating profit/(loss)

 

 

33,539

 

(571,059)

Finance income

3.2

 

27

 

2,696

Finance costs

3.2

 

(30,656)

 

(38,160)

Net gain on repurchase of Convertible Bonds

5.1

 

17,201

 

-

Fair value (loss)/gain on Convertible Bond embedded derivative

5.1

 

(1,901)

 

35,431

Profit/(loss) before tax

 

 

18,210

 

(571,092)

Tax

6.1

 

26

 

(54,233)

Total comprehensive profit/(loss) for the year

 

 

18,236

 

(625,325)

 

 

 

 

 

 

 

 

 

Cents

 

Cents

Earnings per share - basic and diluted

3.1

 

0.92

 

(31.43)

All results arise from continuing operations.

 

Group Balance Sheet

 

 

 

 

 

 

 

Notes

 

31 Dec 2021

 

31 Dec 2020

 

 

 

$'000

 

$'000

Non-current assets

 

 

 

 

 

Intangible exploration and evaluation assets

2.4

 

3,830

 

55,390

Oil and gas assets

2.3

 

98,296

 

208,027

Other non-current assets

 

 

1,373

 

2,605

Deferred tax assets

 

 

104

 

78

Liquid investments

4.1

 

37,783

 

22,811

 

 

 

141,386

 

288,911

Current assets

 

 

 

 

 

Inventory

2.2

 

27,488

 

11,285

Trade and other receivables

 

 

2,591

 

14,524

Cash and cash equivalents

4.1

 

76,792

 

143,703

 

 

 

106,871

 

169,512

Total assets

 

 

248,257

 

458,423

Current liabilities

 

 

 

 

 

Trade and other payables

 

 

(18,843)

 

(16,356)

Lease liabilities

5.2

 

(13,880)

 

(18,479)

Convertible Bond liability

5.1

 

(77,373)

 

-

Convertible Bond embedded derivative

5.1

 

(27)

 

-

Decommissioning provisions

2.5

 

-

 

(15,466)

 

 

 

(110,123)

 

(50,301)

Non-current liabilities

 

 

 

 

 

Lease liabilities

5.2

 

(1,910)

 

(78,842)

Convertible Bond liability

5.1

 

-

 

(216,034)

Convertible Bond embedded derivative

5.1

 

-

 

(885)

Decommissioning provisions

2.5

 

(49,346)

 

(45,675)

 

 

 

(51,256)

 

(341,436)

Total liabilities

 

 

(161,379)

 

(391,737)

Net assets

 

 

86,878

 

66,686

Equity

 

 

 

 

 

Share capital

 

 

2,885

 

2,885

Share premium

 

 

822,458

 

822,458

Share option reserve

 

 

23,321

 

21,443

Own shares reserve

 

 

(845)

 

(923)

Foreign exchange reserve

 

 

(90,828)

 

(90,828)

Accumulated deficit

 

 

(670,113)

 

(688,349)

Total equity

 

 

86,878

 

66,686

 

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 2020

2,883

821,910

20,828

(684)

(90,828)

(63,024)

691,085

Loss for the period

-

-

-

-

-

(625,325)

(625,325)

New shares issued under employee share schemes

2

548

-

(445)

-

-

105

Share-based payments

-

-

615

206

-

-

821

At 31 December 2020

2,885

822,458

21,443

(923)

(90,828)

(688,349)

66,686

Profit for the period

-

-

-

-

-

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

 

Group Cash Flow Statement

 

 

 

 

 

Restated

 

 

 

Year ended

 

Year ended

 

Notes

 

31 Dec 2021

 

31 Dec 2020

 

 

 

$'000

 

$'000

 

 

 

 

 

 

Cash flows from operating activities

 

 

 

 

 

Operating profit/(loss)

 

 

33,539

 

(571,059)

Adjustments for:

 

 

 

 

 

  Depreciation of property, plant and equipment

2.3

 

98,100

 

97,136

  Impairment of oil and gas assets

2.3

 

-

 

519,152

  Change in decommissioning estimates on fully impaired assets

2.5

 

1,972

 

-

  Impairment of intangible exploration and evaluation assets and exploration expense written off

2.4

 

 

54,280

 

 

47,945

  Gain on lease remeasurement

5.2

 

(49,125)

 

-

  Impairment of other right-of-use assets

 

 

719

 

-

  Share-based payment charge

 

 

1,955

 

821

  Purchase of derivative financial instruments

 

 

-

 

(3,420)

  Expenditure on proposed financial restructuring

 

 

15,903

 

1,550

  Decommissioning spend

2.5

 

(4,824)

 

(2,108)

Operating cash flow before working capital movements

 

 

152,519

 

90,017

  Movement in receivables

 

 

579

 

159

  Movement in payables

 

 

5,356

 

(10,352)

  Movement in crude oil, fuel and chemicals inventories

2.2

 

(11,410)

 

1,946

Net cash inflow from operating activities

 

 

147,044

 

81,770

 

 

 

 

 

 

Cash flows from investing activities

 

 

 

 

 

Interest received

 

 

27

 

1,227

Increase in liquid investments

 

 

(15,530)

 

(22,811)

Expenditure on oil and gas assets

 

 

(6,618)

 

(23,396)

Expenditure on other fixed assets

 

 

(2)

 

(69)

Expenditure on intangible exploration and evaluation assets

 

 

(2,782)

 

(35,269)

Movement in spares and supplies inventories

2.2

 

(4,793)

 

(3,286)

Net cash used in investing activities

 

 

(29,698)

 

(83,604)

 

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

 

Repurchases of Convertible Bond principal for cancellation

5.1

 

(130,346)

 

-

Transaction costs

5.1.1

 

(1,311)

 

-

Convertible Bond interest paid

5.1

 

(17,372)

 

(17,250)

Lease repayments

5.2

 

(18,596)

 

(9,658)

Interest and other finance charges paid

 

 

(34)

 

(15)

Expenditure on proposed financial restructuring

 

 

(15,903)

 

(1,550)

New shares issued under employee share schemes

 

 

-

 

105

Net cash used in financing activities

 

 

(183,562)

 

(28,368)

Decrease in cash and cash equivalents

 

 

(66,216)

 

(30,202)

 

 

 

 

 

 

Cash and cash equivalents at beginning of year

4.1

 

143,703

 

171,434

Net decrease in cash and cash equivalents

 

 

(66,216)

 

(30,202)

Effects of foreign exchange rate changes

 

 

(695)

 

2,471

Cash and cash equivalents at end of year

4.1

 

76,792

 

143,703

The presentation of certain comparative lines has been restated - see note 1.4.

Notes

Section 1: General Information

1.1   Basis of preparation

The consolidated Financial Statements of Hurricane Energy plc for the year ended 31 December 2021 were authorised for issue by the directors on 27 April 2022. 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 registered office is Ground Floor, The Wharf, Abbey Mill Business Park, Lower Eashing, Godalming, Surrey, GU7 2QN.

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 international accounting standards in conformity with the requirements of the Companies Act 2006 and in accordance with the requirements of the AIM Rules.

On 31 December 2020, IFRS as adopted by the European Union at that date was brought into UK law and became UK-adopted International Accounting Standards, with future changes being subject to endorsement by the UK Endorsement Board. The Group transitioned to UK-adopted International Accounting Standards (for its consolidated Financial Statements) on 1 January 2021. This change constitutes a change in accounting framework; however, there is no impact on recognition, measurement or disclosure in the period reported as a result of this change. 

The Group has applied new accounting standards, amendments and interpretations for the first time, but their adoption 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:

· COVID-19-Related Rent Concessions - amendments to IFRS 16;

· Interest Rate Benchmark Reform - Phase 2 - amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16;

· Annual Improvements to IFRS Standards 2018-2020; and

· Deferred Tax related to Assets and Liabilities arising from a Single Transaction - amendments to IAS 12

A number of new and amended accounting standards and interpretations have been published that are not mandatory for the Group's financial year ended 31 December 2021, 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.

1.2  Annual report and accounts

The financial information set out within this announcement does not constitute the Company's statutory accounts for the years ended 31 December 2021 or 2020, but is derived from those accounts. A copy of the statutory accounts for 2020 has been delivered to the Registrar of Companies and those for 2021 will be delivered following the Company's annual general meeting. The auditor has reported on the 2021 accounts; their audit report was unqualified, and did not draw any attention to any material uncertainty or other areas by way of emphasis of matter.

Whilst the financial information included in this announcement has been computed in accordance with IFRS, this announcement does not itself contain sufficient information to comply with IFRS.

1.3   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, committed and sanctioned capital expenditure, and the remaining Convertible Bond principal amount due in July 2022. In addition, sensitivity and reverse stress test analyses have been considered. Further details on the going concern assessment undertaken are outlined in the Chief Financial Officer's Review.

1.4  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:

· a significant increase in revenue versus the previous year due to a strong recovery in crude oil prices, with the average realised sales price increasing from $35.2/bbl to $67.3/bbl (note 2.1);

·  the incurrence of $15.9 million of legal and professional costs (for advisers engaged by the Group, bondholders and shareholders) related to the proposed financial restructuring of the Group, originally announced in April 2021, but ultimately not sanctioned by the Court in June 2021;

· a reduction in lease liabilities, right-of-use assets and a non-cash lease remeasurement gain arising from the decision made in June 2021 not to extend the bareboat charter of the Aoka Mizu FPSO beyond June 2022 (notes 2.3 and 5.2);

· the placing of an additional £11.2 million of cash into restricted funds following a formal request by OPRED to increase the amount of decommissioning security for the Lancaster field (note 4.1);

· a significant reduction in Convertible Bond debt and gain on repurchase of Convertible Bonds recognised in the Income Statement following the repurchase of $151.5 million of bonds for cash consideration of $130.3 million (note 5.1); and

· the recognition of an impairment charge of $54.3 million in respect of the Lincoln asset following the decision by the Group and its joint operation partner to relinquish the P1368(S) licence (note 2.3.1).

Amounts relating to the proposed financial restructuring incurred in the prior year have been reclassified from operating activities to financing activities within the Cash Flow Statement and note 4.1 in order to align with the current year classification.

For further discussion about the Group's performance and financial position, see the Chief Executive Officer's Review and Chief Financial Officer's Review.

Section 2:  Oil and gas operations

2.1  Revenue

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 2021

31 Dec 2020

 

$'000

$'000

 

 

 

Oil sales

240,540

180,083

Revenue from contracts with customers

240,540

180,083

 

 

 

Cargoes sold

7

12

Sales volumes (thousand bbl)

3,576

5,112

Average sales price realised ($/bbl)

$67.3/bbl

$35.2/bbl

 

2.2  Cost of sales and inventory

Cost of sales

 

 

Year ended

Year ended

 

 

31 Dec 2021

31 Dec 2020

 

Note

$'000

$'000

 

 

 

 

Operating costs

 

65,688

65,107

2.3

94,200

84,756

2.3

3,405

11,828

Movement in crude oil inventory

 

(10,622)

1,733

Variable lease payments

5.2

20,454

16,392

 

 

173,125

179,816

 

Inventory

 

31 Dec 2021

 

31 Dec 2020

 

$'000

 

$'000

 

 

 

 

Crude oil

13,313

 

2,691

Fuel and chemicals

2,124

 

 1,336

Spares and supplies

12,051

 

7,258

 

27,488

 

11,285

The amount of crude oil inventory recognised as an expense in the year was $140.6 million (2020: $155.2 million).

2.3  Oil and gas assets

 

 

Leased

 

Owned

 

Total

 

Note

$'000

 

$'000

 

$'000

Cost

 

 

 

 

 

 

At 1 January 2020

 

101,347

 

757,424

 

858,771

Additions

 

-

 

23,652

 

23,652

Changes to decommissioning estimates

2.5

474

 

3,482

 

3,956

At 31 December 2020

 

101,821

 

784,558

 

886,379

Additions

 

-

 

4,572

 

4,572

Remeasurement of lease liability

5.2

(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

Depreciation and impairment

 

 

 

 

 

 

At 1 January 2020

 

(8,210)

 

(54,406)

 

(62,616)

Depreciation charge for the year

 

(11,828)

 

(84,756)

 

(96,584)

Provision for impairment

 

(60,166)

 

(458,986)

 

(519,152)

At 31 December 2020

 

(80,204)

 

(598,148)

 

(678,352)

Depreciation charge for the year

 

(3,405)

 

(94,200)

 

(97,605)

Changes to decommissioning estimates expensed

 

(1,961)

 

-

 

(1,961)

At 31 December 2021

 

(85,570)

 

(692,348)

 

(777,918)

Carrying amount at 31 December 2020

 

21,617

 

186,410

 

208,027

Carrying amount at 31 December 2021

 

-

 

98,296

 

98,296

 

Oil and gas assets held under leases comprise solely the Aoka Mizu FPSO bareboat charter, which commenced in May 2019. During the year, this lease term was reassessed, resulting in a decrease in the leased asset value to nil (see note 5.2). Subsequent to the balance sheet date, the Group agreed an extension to the charter (see note 7.2).

The total amount of depreciation charged to oil and gas assets and other fixed assets was $98.1 million (2020: $97.1 million).

2.3.1  Impairment of oil and gas assets

The triggers for the impairment test were the non-sanction of the proposed financial restructuring in June 2021, and the decision not to extend the lease of the Aoka Mizu FPSO beyond June 2022. 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 2022 ERCE CPR; and

· Dated Brent oil price assumptions (in real terms) of $76/bbl average for 2022, $70/bbl in 2023 and $67/bbl in 2024 (being forecasts of future oil prices extant as at 31 December 2021, as required by IAS 36);

· operating cost assumptions based on latest budgets, contracts and information from key suppliers;

·an extension to the Aoka Mizu FPSO charter allowing production to continue until June 2024 (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 9.0%.

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; although this was subject to the key judgement that it would be possible to agree an alternative extension to the bareboat charter beyond June 2022 until such time as, based on management's forecast of production rates, operating costs and oil prices, production became uneconomic.

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

20.2

 

 

Forecast production rates:

 

  5% decrease

-

  10% decrease

5.8

 

 

Cessation of production and FPSO charter end date

 

  October 2022

14.1

  December 2022

3.6

  December 2023

-

 

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.

The triggers for the prior period impairment charges were the downward revision of estimated recoverable reserves as a result of the Technical Review and updated CPR, the decline in oil prices across the first half of 2020 and the market capitalisation of the Group falling below its net assets. The charge was allocated pro-rata to owned and leased assets based on their respective carrying values pre-impairment.

2.4  Intangible exploration and evaluation assets

 

 

 

Year ended

 

Year ended

 

 

 

31 Dec 2021

 

31 Dec 2020

 

Note

 

$'000

 

$'000

 

 

 

 

 

 

At 1 January

 

 

55,390

 

75,874

Additions

 

 

5,235

 

25,623

Provision for impairment and exploration expenditure written off

2.4.1

 

(54,280)

 

(47,476)

Changes to decommissioning estimates

2.5

 

(2,515)

 

1,369

At 31 December

 

 

3,830

 

55,390

 

Intangible exploration and evaluation assets represent the Group's share of the cost of licence interests and exploration and evaluation expenditure within its licensed acreage in the West of Shetland area, which comprise Lincoln (on licence P1368(S)), Warwick (licence P2294) and Halifax (licence P2308).

Additions during the period primarily comprised licence fees, geological and other subsurface studies undertaken, long-lead items ordered in previous years for potential future development activity and capitalised timewriting costs.

2.4.1  Impairment and write-off of intangible exploration and evaluation assets

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 $54.3 million has been recognised against the full carrying amount of exploration and evaluation expenditure attributable to the Lincoln asset on licence P1368(S). The Group and its joint operation partner, Spirit Energy, had a regulatory obligation to commence drilling a well on the P1368(S) licence (the 'obligation well') by 30 June 2022. During the year, the joint operation partners engaged with the Regulator on the technical re-evaluation and interpretation of the licence potential and requested a regulatory amendment of the obligation well to a later commencement date. The Regulator indicated, as part of its considerations, that it was not content to support a deferral of the obligation well unless the joint operation partners satisfy the Regulator that they will be able to fund the obligation well in a timely manner. In December 2021, given the respective partners financial circumstances and related challenges of securing additional funding for the Lincoln obligation well, the joint operation partners elected to continue plans to suspend further funding towards well planning and drilling of the Lincoln obligation well in 2022. In April 2022, the joint operation partners agreed to voluntarily surrender the P1368(S) licence (see note 7.3).

In 2020, following the finalisation of the 2021 CPR, provision for impairment of $35.4 million was recognised against the full carrying amount of exploration and evaluation expenditure attributable to the Halifax licence, as the 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. $12.1 million of exploration and evaluation expenditure was also written off, comprising the Group's share of standby costs for the Paul B Loyd Jr rig, which was on hire but not used for any drilling campaigns during 2020.

2.5   Decommissioning provisions

 

 

 

Year ended

 

Year ended

 

 

 

31 Dec 2021

 

31 Dec 2020

 

 

Note

$'000

 

$'000

 

 

 

 

 

 

At 1 January

 

 

61,141

 

55,673

Net new provisions and changes in estimates

 

 

(1,921)

 

7,459

Utilised in year

 

 

(9,894)

 

(2,108)

Unwinding of discount

 

3.2

20

 

117

At 31 December

 

 

49,346

 

61,141

 

 

 

 

 

 

Of which:

 

 

 

 

 

  Current

 

 

-

 

15,466

  Non-current

 

 

49,346

 

45,675

 

 

 

49,346

 

61,141

 

 

 

 

 

 

Restricted funds held in respect of decommissioning:

 

 

 

 

 

  Restricted cash

 

4.1

-

 

2,244

  Liquid investments

 

4.1

37,783

 

22,811

 

 

 

37,783

 

25,055

 

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 June 2024; being the estimated point at which the EPS becomes uneconomic absent any incremental development. Estimated costs are discounted at a rate of 0.67%.

Changes in estimates in the period have arisen from change in the assumed discount rate, changes in foreign exchange rates, increases to the assumed inflation rate and refined estimates to the expected costs and timing of decommissioning the EPS and FPSO; and actualisation of provisions for the Lincoln and Lancaster 4Z wells.

Of the total net new provisions and changes in estimates, $2.5 million was recorded as non-cash reductions to intangible exploration and evaluation assets, $1.5 million as non-cash additions to oil and gas assets, $2.5 million credited to receivables due from the Group's joint operation partner and $1.6 million charged directly to the Income Statement (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 plugging and abandonment of the Lincoln-14 well, and the Lancaster 4Z wells.

Section 3  Income Statement

3.1  Earnings per share

 

Year ended

 

Year ended

 

 

31 Dec 2021

 

31 Dec 2020

 

 

$'000

 

$'000

 

 

 

 

 

 

Profit/(loss) attributable to holders of Ordinary Shares in the Company used in calculating basic earnings per share (being profit/(loss) after tax)

18,236

 

(625,325)

 

Add back impact of:

 

 

 

 

  Convertible Bond - interest expense

-

 

-

 

  Convertible Bond - fair value gain

-

 

-

 

Profit/(loss) attributable to holders of Ordinary Shares in the Company used in calculating diluted earnings per share

18,236

 

(625,325)

 

 

 

 

 

 

 

Number

 

Number

 

Weighted average number of Ordinary Shares used in calculating basic earnings per share

1,989,927,148

 

1,989,607,524

 

Potential dilutive effect of:

 

 

 

 

  Convertible Bond

-

 

-

 

Weighted average number of Ordinary Shares and potential Ordinary Shares used in calculating diluted earnings per share

1,989,927,148

 

1,989,607,524

 

 

 

 

 

 

 

Cents

 

Cents

 

Basic earnings per share

0.92

 

(31.43)

 

Diluted earnings per share

0.92

 

(31.43)

 

 

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 in 2021.  The impact of the VCP and PSP awards was antidilutive in 2021 because market-based conditions for both schemes was not met at any point throughout the year.

The effect of the conversion feature included within the Convertible Bond, the VCP and PSP share awards and other share options outstanding in 2020 were antidilutive as the Group incurred a loss.

3.2  Finance income and costs

 

Year ended

 

Year ended

 

31 Dec 2021

 

31 Dec 2020

 

$'000

 

$'000

 

 

 

 

Interest income on cash, cash equivalents and liquid investments

27

 

1,227

Net foreign exchange gains

-

 

1,469

Finance income

27

 

2,696

 

 

 

 

Convertible Bond interest expense (note 5.1)

(24,810)

 

(26,680)

Interest on lease liabilities (note 5.2)

(4,412)

 

(7,702)

Fair value losses on oil price derivatives

-

 

(3,420)

Other interest expense and bank charges

(217)

 

(241)

Net foreign exchange losses

(1,197)

 

-

Unwinding of discount on decommissioning provisions (note 2.5)

(20)

 

(117)

Finance costs

(30,656)

 

(38,160)

 

 

 

 

Net finance costs

(30,629)

 

(35,464)

 

3.3   General and administrative expenditure

 

Year ended

 

Year ended

 

31 Dec 2021

 

31 Dec 2020

 

 

 

 

 

$'000

 

$'000

 

 

 

 

Wages and salaries

9,939

 

10,001

Social security costs

1,226

 

937

Defined contribution pension costs

689

 

720

Staff costs

11,854

 

11,658

Non-staff costs

22,958

 

7,409

Gross general and administrative expenditure before recharges

34,812

 

19,067

Capitalised into oil and gas assets

(3,025)

 

(3,499)

Capitalised into intangible exploration and evaluation assets

(3,456)

 

(7,121)

Included within cost of sales

(4,752)

 

(5,591)

Net general and administrative expenditure before non-cash items

23,579

 

2,856

Non-cash general and administrative costs:

 

 

 

  Net share-based payment charge

1,956

 

821

  Depreciation of other fixed assets and other right-of-use assets

495

 

552

  Impairment of other right of use assets

719

 

-

General and administrative expenditure

26,749

 

4,229

 

 

 

 

 

Number

 

Number

Average number of employees

55

 

62

 

Section 4  Cash

4.1  Cash and cash equivalents and liquid investments

 

31 Dec 2021

 

31 Dec 2020

 

Restricted

Unrestricted

Total

 

Restricted

Unrestricted

Total

 

$'000

$'000

$'000

 

$'000

$'000

$'000

Current cash and cash equivalents

7,934

68,858

76,792

 

28,792

114,911

143,703

Non-current cash and equivalents

-

-

-

 

-

-

-

Cash and cash equivalents (per Cash Flow Statement)

7,934

68,858

76,792

 

28,792

114,911

143,703

Liquid investments

37,783

-

37,783

 

22,811

-

22,811

Total cash and cash equivalents and liquid investments

45,717

68,858

114,575

 

51,603

114,911

166,514

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:

 

 

 

Restated

 

Year ended 31 Dec 2021

 

Year ended 31 Dec 2020

 

Restricted

Unrestricted

Total

 

Restricted

Unrestricted

Total

 

$'000

$'000

$'000

 

$'000

$'000

$'000

At 1 January

51,603

114,911

166,514

 

14,843

156,591

171,434

Operating cash flows

-

147,970

147,970

 

--

81,770

81,770

Change in Lancaster EPS decommissioning security arrangements

15,530

(15,530)

-

 

22,811

(22,811)

-

Capital expenditure and other investing cash flows

-

(15,095)

(15,095)

 

-

(60,793)

(60,793)

Financing cash flows

-

(183,562)

(183,562)

 

-

(28,368)

(28,368)

Movement in FPSO early termination reserve

(18,670)

18,670

-

 

14,807

(14,807)

-

Net release of other restricted funds

(2,244)

2,244

-

 

(892)

892

-

Foreign exchange rate changes

(502)

(750)

(1,252)

 

34

2,437

2,471

At 31 December

45,717

68,858

114,575

 

51,603

114,911

166,514

 

The presentation of certain comparative lines has been restated - see note 1.4.

 

Included within restricted cash and cash equivalents is $7.9 million (2020: $26.5 million) set aside in relation to the Aoka Mizu FPSO bareboat charter. Under the terms of the contract, the Group is required to ring-fence amounts to ensure it could meet its liability to pay an early termination fee to the lessor if the contract was terminated by the Group earlier than the expiry of an option period. Under the current lease, this amount will be released into unrestricted cash on a straight-line basis and be fully released at the expiry of the current lease term. Following the agreement in March 2022 to extend the lease (see note 7.2), a secured deposit account of up to $18.7 million will be established and classified as restricted cash.

The $37.8 million restricted liquid investment balance comprises decommissioning security in place for the Lancaster EPS. As part of the original Lancaster Field Development Plan approval, the Group was required to provide security of £16.8 million for its decommissioning liability on the Lancaster field, being the estimated post-tax amount to meet future decommissioning obligations. This security was placed in a decommissioning bond and subsequently released to unrestricted cash during 2019 as the bond conditions were satisfied. Following the downwards revision of Reserves and Contingent Resources in September 2020 and the ongoing uncertainty with regard to oil prices, the bond provider requested that the Company provide cash collateral for 100% of the bond's value. As the Group would derive no benefit from the bond while still paying fees to the bond provider, the decommissioning bond was terminated by mutual agreement and the required security amount was placed back into trust (classified within restricted liquid investments). In June 2021, the Group agreed with the Regulator to place an additional £11.2 million ($15.5 million) into trust, in order to provide security for its decommissioning liability on the Lancaster field on a pre-tax basis.

During 2021, $2.2 million of restricted cash relating to decommissioning security for the suspended Lancaster 205/21a-4z well was released back to the Group following completion of its plug and abandonment.

Section 5  Capital and debt

5.1  Convertible Bond

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 carries a coupon of 7.5% payable quarterly in arrears. The Convertible Bond is 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 is 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. Unless previously converted, redeemed or purchased and cancelled, the Convertible Bond will be redeemed at par on 24 July 2022. The Convertible Bond is subject to a covenant which imposes a restriction on the incurrence of certain indebtedness. This restriction shall not apply in respect of:

· any indebtedness in respect of the Convertible Bond (Bond Debt);

· any other indebtedness where the aggregate principal amount of such other indebtedness, when combined with the aggregate principal amount of all other indebtedness of the Group from time to time (excluding the Bond Debt), would not cause the total indebtedness of the Group on a consolidated basis to exceed $45 million (or the equivalent thereof in other currencies at then current rates of exchange); and

· any permitted indebtedness, being:

any liability in respect of any lease or hire purchase contract which would, in accordance with IFRS, be treated as a finance or capital lease, with respect to the bareboat charter of the Aoka Mizu FPSO;

amounts borrowed, or any guarantee or indemnity given with respect to any security, where required by the Oil and Gas Authority or any other applicable regulator, in relation to suspended wells, decommissioning or other related regulatory obligations of the Group; and

any amount raised under any transaction, having the commercial effect of borrowing, in respect of the deferral of payment of invoices due to Technip UK Limited (or any of its affiliated companies) in connection with the agreement for the provision of subsea umbilical risers and flowlines and subsea production systems for the Company's operations in the Lancaster field.

The conversion feature of the Convertible Bonds is classified as an embedded derivative as the Convertible Bonds can be settled by the Group in cash and hence does not meet the 'fixed for fixed' criteria outlined in IAS 32 for recognition as an equity instrument. It has therefore been measured at fair value through profit and loss. The amount recognised at inception in respect of the host debt contract was determined by deducting the fair value of the conversion option at inception (the embedded derivative) from the fair value of the consideration received for the Convertible Bond. The debt component is then recognised at amortised cost, using the effective interest method, until extinguished upon conversion or at maturity. The effective interest rate applicable to the debt component is 13.5%.

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 2020

 

206,604

 

36,316

 

242,920

Cash interest paid

 

(17,250)

 

-

 

(17,250)

Fair value gain

 

-

 

(35,431)

 

(35,431)

Interest charged

 

26,680

 

-

 

26,680

Carrying value at 31 December 2020

 

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

 

 

 

 

 

 

 

Fair value at 31 December 2020

 

102,615

 

885

 

103,500

Fair value at 31 December 2021

 

75,449

 

27

 

75,476

 

5.1.1  Repurchase of Convertible Bonds

During the year, the Group repurchased $151.5 million of nominal Convertible Bond debt for cash consideration of $131.9 million, including accrued interest of $1.6 million. An initial tender offer in September resulted in $78.0 million of Convertible Bonds being repurchased at a cost of $61.7 million including accrued interest of $0.8 million.  The average price achieved in this tender was 78%. During December 2021, the Company undertook further buybacks, in various tranches. These transactions resulted in $73.5 million of nominal bonds repurchased at a cost of $70.3 million, including $0.8 million accrued interest. The average price achieved of these tranches was 95%. As at 31 December 2021, the nominal value of Convertible Bonds remaining in issue was $78.5 million.

The net gain on the repurchase of the Convertible Bonds is reconciled as follows:

 

$'000

 

 

Carrying value of Convertible Bond debt portion derecognised

146,099

Carrying value of Convertible Bond derivative portion derecognised

2,759

Cash consideration paid

(130,346)

Gross gain on repurchase

18,512

Transaction costs

(1,311)

Net gain on repurchase of Convertible Bonds

17,201

 

5.1.2   Embedded derivative valuation

The embedded derivative component of the Convertible Bond is categorised within Level 3 of the fair value hierarchy, as the derivatives themselves are not traded on an active market and their fair values are determined using a valuation technique that uses one key input that is not based on observable market data, being share price volatility. 

The key inputs used are share price volatility (calculated as the volatility of one Hurricane Ordinary Share over a period equivalent to the remaining expected term to redemption) and the price of one Ordinary Share at 31 December 2021. In determining the fair value of the embedded derivative, the likelihood of the early redemption option being exercised and the likelihood of a change of control of the Group within the life of the Convertible Bond were considered. The likelihood of each was considered to be nil for the purposes of the valuation.

The fair value calculation at 31 December 2021 used a share price volatility assumption of 117.6% (2020: 118.2%) and the price of one Hurricane Energy plc Ordinary Share as at the balance sheet date of £0.038 (2020: £0.025). Given the remaining time to maturity, it is not considered that there is a significant risk of changes to these assumptions resulting in a material adjustment to the carrying amounts of the embedded derivative within the next financial year.

5.2   Leases

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 2021

31 Dec 2020

 

$'000

$'000

 

 

 

At 1 January

97,321

99,186

Remeasurement of lease liability

(67,337)

-

Cash payments of principal and interest

(18,596)

(9,658)

Interest charged

4,412

7,702

Foreign exchange movements

(10)

91

At 31 December

15,790

97,321

 

 

 

Of which:

 

 

  Current

13,880

18,479

  Non-current

1,910

78,842

 

15,790

97,321

 

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). Should the Group give notice to terminate the lease (other than by not exercising extension option periods), significant early termination penalties would apply. The Group is required to set aside amounts to cover a portion of these early termination penalties, the balance of which changes over time in line with the contract, and such balances are 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 profit and loss.

The assumption that the bareboat charter can be extended beyond June 2022 is a critical judgement within the assessment of impairment of oil and gas assets (note 2.3.1). Subsequent to the balance sheet date, an extension to the bareboat charter was agreed (see note 7.2) to cover an indefinite period with both lessor and lessee having the ability to terminate the lease with six months' notice, with the current fixed and variable lease payment structure remaining in place.

Other charges to the Income Statement in respect of leases during the year included the following:

 

Year ended

Year ended

 

31 Dec 2021

31 Dec 2020

 

$'000

$'000

Depreciation charge of right-of-use assets:

 

 

  Oil and gas assets (included within cost of sales)

3,404

11,828

  Other fixed assets (included within general and administrative expenses)

364

340

 

3,768

12,168

 

 

 

Provision for impairment of right-of-use assets:

 

 

  Oil and gas assets (included within cost of sales)

-

60,166

  Other fixed assets (included within general and administrative expenses)

719

-

 

719

60,166

 

 

 

Lease interest (included within finance costs)

4,412

7,702

 

 

 

Variable lease payments (included within cost of sales)

20,454

16,392

 

Following a reduction to staff numbers during the year and a move towards hybrid working arrangements, the Group recognised provision for impairment of $0.7 million in respect of one of its office leases.

The total gross cash outflow for leases for the year was $39.1 million.

In 2020, the Group's share of the expense relating to the short-term lease of the Paul B Loyd Jr rig was recognised within write-off of exploration and evaluation expenditure (see note 2.4.1). The expense relating to low-value leases and other short-term leases recognised in the Income Statement was not material.

Section 6  Taxation

6.1  Tax charge for year

 

Year ended

 

Year ended

 

31 Dec 2021

 

31 Dec 2020

 

$'000

 

$'000

UK corporation tax

 

 

 

Current tax - current and prior years

-

 

-

Total current tax

-

 

-

 

 

 

 

Deferred tax - current year

21

 

(44,501)

Deferred tax - prior year

5

 

(9,732)

Total deferred tax

26

 

(54,233)

Tax credit/(charge) per Income Statement

26

 

(54,233)

 

 

 

 

Profit/(loss) on ordinary activities before tax

18,210

 

(571,092)

Profit/(loss) on ordinary activities multiplied by standard combined rate of corporation tax in the UK applicable to oil and gas companies of 40% (2020: 40%)

(7,284)

 

228,437

Effects of:

 

 

 

Expenses not deductible for tax purposes

(1,934)

 

(4,656)

Income not chargeable for tax purposes

7,692

 

15,138

Items taxed at rates other than the standard rate of 40%

(2,064)

 

(24)

Ring-fence expenditure supplement

20,560

 

22,769

Prior period deferred tax

5

 

(9,732)

Losses not recognised

(6,687)

 

(306,165)

Impact of tax rate change

25

 

-

Chargeable gain

(10,287)

 

-

Total tax credit/(charge) for the year

26

 

(54,233)

 

The chargeable gain in the period arose as a consequence of the repurchase and cancellation of some of the Group's Convertible Bonds (note 5.1.1) due to crystallisation of the underlying embedded derivative. No cash tax has arisen as a consequence of this chargeable gain.

6.2  Factors which may affect future tax charges

The Group has ring-fenced trading losses of $381.9 million at 31 December 2021 (31 December 2020: $468.7 million) and supplementary charge losses and investment allowances of $693.0 million at 31 December 2021 (31 December 2020: $707.8 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 $328.4 million available to be used against future taxable profits at 31 December 2021 ($383.5 million). In addition, the Group has pre-trading expenditure of $124.9 million which is carried forward at 31 December 2021 and tax relief may be available were trading activities to commence in the pre-trading entities. This pre-trading expenditure could also be uplifted by RFES to $183.5 million.

The value of tax attributes as at 31 December 2021 at the currently prevailing tax rates can be summarised as follows:

 

Tax attributes

Tax value

 

$'000

%

$'000

 

 

 

 

Ring-fence losses

381,866

30%

114,560

Supplementary charge losses

261,900

10%

26,190

Investment allowance

431,145

10%

43,114

Unclaimed capital allowances

328,435

40%

131,374

Pre-trading expenditure (including RFES)

183,541

40%

73,416

Future decommissioning costs

49,346

40%

19,738

Non-ring-fence losses

5,128

25%

1,282

Value of tax attributes at prevailing tax rates

 

 

409,674

 

Access to these losses and allowances may be severely restricted at the point at which trading activities end (which would include a 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 Group or entity's trading activities

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 charge tax is generally lower than 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 36.9%. Investment allowance is only allowable against supplementary charge tax and attracts relief at 10%, and is available after tax losses have been taken into account.

During the year, the Group made claims for Small and Medium sized Enterprises (SME) R&D Relief ('SME R&D') (in respect of 2019) and Research and Development Expenditure Credit ('RDEC') (in respect of 2020). Subsequent to the balance sheet date, the Group received a cash repayment of $3.2 million in respect of the SME R&D claim and $1.4 million in respect of the RDEC. The impact of these claims on the 2022 tax position will be a tax credit of $4.6 million in exchange for a surrender of $21.0 million of ring-fence trading losses.

Section 7  Subsequent events

7.1  Decommissioning security

In February 2022, following a request from the Regulator, the Group placed an additional £5.7 million ($7.7 million) into Trust as additional decommissioning security in respect of the Lancaster EPS. These funds will be classified as restricted liquid investments.

7.2  Aoka Mizu charter extension

On 25 March 2022, the Group signed a contract with Bluewater (Aoka Mizu) B.V. ('Bluewater'), the owner of the Aoka Mizu FPSO, for an extension to the Bareboat Charter. Under the terms of the extension, the existing fixed and variable lease payments remain at their current rate and either party can give six months' notice of termination. The Group will also place up to $18.7 million into a secured deposit account (classified as restricted cash) 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 impact of these changes will be reflected in the Group's 2022 Financial Statements.

7.3  P1368(S) licence relinquishment

On 27 April 2022, the Group and its joint operation partner agreed to voluntarily surrender licence P1368(S), comprising the Lincoln asset. An impairment charge of $54.3 million has been recognised against the full carrying amount of exploration and evaluation expenditure attributable to the licence (see note 2.4.1).

 

Appendix A Glossary

1C

Denotes low estimate of Contingent Resources

1P

Denotes low estimate of Reserves (i.e., Proved Reserves). Equal to P1.

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

Ad Hoc Committee

 

 

A group comprising certain of Hurricane's Bondholders, with whom Hurricane announced, on 30 April 2021, it had entered into a lock-up agreement pursuant to the proposed financial restructuring

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

CO2e

Carbon dioxide equivalent

Company

Hurricane Energy plc and/or its subsidiaries

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.

Contingent Resources, Development Unclarified

A discovered accumulation where project activities are under evaluation and where justification as a commercial development is unknown based on available information.

 

Convertible Bond(s)

 

$230 million 7.5% convertible bonds issued by the Company in July 2017, of which $78.5 million remain outstanding as at 31 December 2021

Court

High Court of Justice of England and Wales

COVID-19

Coronavirus

CPR

Competent Persons Report

Crystal Amber

Crystal Amber Fund Limited

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.

E&E

Exploration and Evaluation

E&P

Exploration and Production/Exploration and Production company

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

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

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 Environmental

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

JV

Joint venture

KPI

Key Performance Indicator

Mbbl

Thousand barrels of oil

MMbbl

Million barrels of oil

NSTA

North Sea Transition Authority (formerly Oil and Gas Authority (OGA))

Obligation well

 

The licence requirement to commence drilling a well on the Lincoln subarea of licence P1368 by no later than 31 December 2020 (subsequently deferred to be no later than 30 June 2022)

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

P&A

Plug and abandon

P6

The 205/21a-6 producer well on the Lancaster field

P7z

The 205/21a-7z well on the Lancaster field, currently shut-in

PP&E

Property, Plant and Equipment

Prospective resources
 

Best case prospective resources under the Society of Petroleum Engineers' Petroleum Resources Management System

PRMS

Petroleum Resources Management System

PSP

Performance Share Plan

psia

Pounds per square inch (absolute) unit of pressure

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.

Restructuring Plan

 

 

Implementation of the proposed financial restructuring announced by Hurricane on 30 April 2021 with holders of its Convertible Bonds under Part 26A of the Companies Act 2006; but subsequently not sanctioned by the Court

RDEC

Research and Development Expenditure Credit

RFES

Ring fence expenditure supplement

SIP

Share Incentive Plan

SME R&D

Small and Medium sized Enterprises R&D Relief

SONIA

Sterling Overnight Index Average

Spirit Energy

Spirit Energy Limited and affiliates

Tier 1 contractors

Hurricane's major direct contractors

TVDSS

True Vertical Depth Sub Sea

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

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 Income Statement. 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 2021

 

31 Dec 2020

 

 

 

$'000

 

$'000

 

 

 

 

 

 

Profit/(loss) before tax (IFRS measure)

 

 

18,210

 

(571,092)

Add back:

 

 

 

 

 

  Fair value loss/(gain) on Convertible Bond embedded derivative

5.1

 

1,901

 

(35,431)

  Fair value loss on unhedged derivative financial instruments

3.2

 

-

 

3,420

  Impairment and write-off of intangible exploration and evaluation assets

2.4

 

54,280

 

47,945

  Change in decommissioning estimates on fully impaired assets

2.5

 

1,973

 

-

  Impairment of oil and gas assets

2.3

 

-

 

519,152

  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/(loss) before tax

 

 

10,757

 

(36,006)

 

 

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 Income Statement 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 2021

 

31 Dec 2020

 

 

 

$'000

 

$'000

 

 

 

 

 

 

Cost of sales (IFRS measure)

2.2

 

173,125

 

179,816

Less:

 

 

 

 

 

  Depreciation of oil and gas assets - owned

2.2

 

(94,200)

 

(84,756)

  Depreciation of oil and gas assets - leased

2.3

 

(3,405)

 

(11,828)

  Movements in crude oil inventory

2.2

 

10,622

 

(1,733)

Add:

 

 

 

 

 

  Fixed lease payments payable on oil and gas assets

 

 

19,638

 

9,150

Cash production costs

 

 

105,780

 

90,649

Variable lease payments (incentive tariff)

2.2

 

(20,454)

 

(16,392)

Cash production costs (excluding incentive tariff)

 

 

85,326

 

74,257

 

 

 

 

 

 

Production volumes

 

 

3,748 Mbbl

 

5,078 Mbbl

Cash production costs per barrel

 

 

$28.2/bbl

 

$17.9/bbl

Cash production costs per barrel (excluding incentive tariff)

 

 

$22.8/bbl

 

$14.6/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.

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 2021

 

31 Dec 2020

 

 

 

$'000

 

$'000

 

 

 

 

 

 

Cash and cash equivalents (IFRS measure)

4.1

 

76,792

 

143,703

Add:

 

 

 

 

 

  Trade and other receivables

 

 

2,591

 

14,524

Less:

 

 

 

 

 

  Restricted cash and cash equivalents

4.1

 

(7,934)

 

(28,792)

  Prepayments

 

 

(1,058)

 

(1,644)

  Trade and other payables

 

 

(18,843)

 

(16,356)

Net free cash

 

 

51,548

 

111,435

Nominal value of Convertible Bond

5.1.1

 

(78,515)

 

(230,000)

Net debt

 

 

(26,967)

 

(118,565)

 

 

 

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 2021

 

31 Dec 2020

 

 

 

$'000

 

$'000

 

 

 

 

 

 

Net cash inflow from operating activities (IFRS measure)

 

 

147,044

 

81,770

 

 

 

 

 

 

Adjustments:

 

 

 

 

 

  Decommissioning spend

 

 

4,824

 

2,108

  Reallocation of items to cash capex

 

 

2,405

 

-

  Lease repayments

5.2

 

(18,596)

 

(9,658)

Free cash flow

 

 

135,677

 

74,220

 

 

 

 

 

 

Free cash flow per barrel

 

 

$36.2/bbl

 

$14.6/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 2021

 

31 Dec 2020

 

 

 

$'000

 

$'000

 

 

 

 

 

 

Net cash used in investing activities (IFRS measure)

 

 

29,698

 

83,604

 

 

 

 

 

 

Adjustments:

 

 

 

 

 

  Interest received

 

 

27

 

1,227

  Increase in liquid investments

 

 

(15,530)

 

(22,811)

  Decommissioning spend

 

 

4,824

 

2,108

  Reallocation of items from free cash flow

 

 

2,405

 

-

Cash capex

 

 

21,424

 

64,128

Less: capitalised general and administrative expenditure

 

 

 

 

 

  Capitalised into oil and gas assets

3.3

 

(3,025)

 

(3,499)

  Capitalised into intangible exploration and evaluation assets

3.3

 

(3,456)

 

(7,121)

Third-party cash capex

 

 

14,943

 

53,508

 

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