Half-year Results 2020 & Technical Update

RNS Number : 6811Y

Hurricane Energy PLC

11 September 2020

 

11 September 2020

Hurricane Energy plc

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

Half-year Results 2020

&

Technical Update

Hurricane Energy plc, the UK based oil and gas company focused on hydrocarbon resources in naturally fractured basement reservoirs, provides its 2020 interim report and half-year results for the period ended 30 June 2020. The Company also announces the initial results from the Technical Review of its West of Shetland assets which commenced in June 2020.

2020 Interim results summary

Technical Review

· Since announcing a Technical Review on 8 June 2020, a strengthened Hurricane sub-surface team has performed a comprehensive reassessment of the Lancaster field.

· The Lancaster field is more complex than previously thought. Preliminary analysis suggests that rather than being primarily a basement reservoir, Lancaster has important oil-bearing sandstones onlapping the basement flanks, which may contain significant volumes of oil. Further work is required in order to understand their impact on current reservoir performance and their ultimate potential.

· The Lancaster oil water contact ("OWC") is now estimated to be at 1,330 metres TVDSS, compared to the range of 1,597-1,678 metres TVDSS in the Company's 2017 Competent Person's Report ("2017 CPR"). This shallower OWC is consistent with the observed earlier and higher water production, and more rapid reservoir pressure decline, than was originally anticipated.

· Reflecting these new technical interpretations, the Company's unaudited estimate of recovery from the two existing Lancaster Early Production System ("EPS") wells assuming no further activity has been reduced to 16.0 MMbbls from 37.3 MMbbls. Considering oil produced to end August 2020, remaining 2P reserves at 1 September 2020 are estimated at 9.4 MMbbls (subject to economic limit test).

· Consideration of near-term future activity is being focussed on means to provide reservoir pressure support primarily by water injection, which if successfully implemented could significantly add to reserves, and/or targeted development of the onlapping sandstone reservoirs.

· Reflecting these new technical interpretations, the Company's unaudited estimate of 2C contingent resources in the Lancaster field has been reduced to 58 MMbbls remaining from 486 MMbbls in the 2017 CPR.

· The Company's estimate of the OWC in the Lincoln field is now 1,846 metres TVDSS (± 50 metres), compared to a range of 2,109-2,325 metres TVDSS estimated in the Company's 2017 West of Shetland Assets CPR ("2017 WoS CPR"). Accordingly, the Company's unaudited estimate of 2C contingent resources for the basement alone in the Lincoln field has been reduced to 45 MMbbls gross, compared to 565 MMbbls gross in the 2017 WoS CPR.

· More definitive estimates of the range of reserves and resources will be made available in an updated CPR in Q1 2021.

Operations - Greater Lancaster Area ("GLA")

· Hurricane continues to adhere to the strict procedures in place for UKCS offshore activity during the COVID-19 pandemic, with negligible disruption to the Company's operations during the period.

· The Aoka Mizu FPSO continues to deliver excellent uptime, with an average of 99% in H1 2020.

· Lancaster EPS production averaged 14,600 bopd for both H1 2020 and the year to date ended August 2020. Prior to the recent scheduled shutdown, field production of c.15,000 bopd was from the 205/21a-6 well alone on natural flow, with the 205/21a-7z well currently shut in to manage reservoir voidage and pressure decline.

· In light of the revised interpretation of the OWC, the area of the P1368 Central licence outside the determined Lancaster field area is being voluntarily relinquished and, following relinquishment, the Company will be released of its obligation to drill the Lancaster commitment well.

Operations - Greater Warwick Area ("GWA")

· Interpretation of the results of the 2019 drilling programme and ongoing pressure monitoring of the 205/26b-14 Lincoln well have led to a significant reappraisal of the GWA licence potential.

· The downhole gauges installed in the suspended 205/26b-14 Lincoln well are now yielding potentially important pressure data. Two sets of data have now been retrieved and analysed, providing valuable insight into long distance reservoir behaviour.

· As previously announced, the OGA has agreed to extend the deadline for the GWA licence commitment well from 31 December 2020 to 30 June 2022.

Financial results

· Revenues of $81.9 million in H1 2020 from seven liftings of Lancaster crude (H1 2019: $22.5 million)

· Despite the significant volatility in oil prices during the period, the Company generated $21.9 million (H1 2019: $6.1 million) of operating cash flow due to low cash production costs† of $18.2/bbl (H1 2019: $24.0/bbl)

· Loss after tax for the period of $307.7 million (H1 2019: Loss of $21.4 million), including $238.9 million (H1 2019: $nil) relating to the impairment of the Lancaster field and a $34 million credit (H1 2019 : $23.5 million charge) in relation to the fair value of the Convertible Bond.

· Net free cash† of $106.2 million at 30 June 2020 (31 December 2019: $133.6 million).

· Net debt† of $123.8 million at 30 June 2020 (31 December 2019: $96.4 million)

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

Outlook

· Lancaster EPS production for September to December 2020 is expected to average 12,000-14,000 bopd, based on production from the 205/21a-6 well on natural flow, expected decline rates and 95% FPSO uptime.

· Work continues on a possible 2021 activity programme for Lancaster, including the provision of pressure support via water injection, improved recovery from the existing EPS wells and evaluation of the onlapping sandstones. This planning is expected to be finalised before the end of 2020.

· While no drilling is anticipated on the GWA licence during 2021, Hurricane will continue to work with the GWA stakeholders on possible pathways towards development for the Lincoln discovery. 

· Lower oil prices and reduced production expectations will negatively impact anticipated future cash flows, despite the expected reduction and deferral of licence commitment well spending. Consequently, the Company intends to engage with all key stakeholders regarding its forward work programme, capital allocation and financing arrangements.

Steven McTiernan, Chairman of Hurricane, commented:

"2020 is proving to be a hugely challenging year for Hurricane. We have had to contend with not only a significant fall in oil prices and the effects of the COVID-19 pandemic, but also poorer than expected reservoir performance from the Lancaster EPS.

The EPS was always intended as a long-term production test to establish the size and production characteristics of this unique and pioneering basement play. Basement reservoirs are subject to profound technical risks, with difficult well conditions impacting the effectiveness of evaluation tools, creating uncertainties which can only be resolved by observation of actual production performance.

It is nonetheless disappointing that the Technical Review has so far resulted in significant reductions in reserves and resources. On a more optimistic note, initial studies suggest water injection could partially mitigate the reserves downgrade, and onlapping sandstones at Lancaster could represent material upside potential.

The Board is enormously grateful to Beverley Smith for leading the Technical Review during a period of considerable change for the Company. We are also most fortunate that stewardship of the Company is now passing to Antony Maris, our new Chief Executive Officer, who has significant experience of basement reservoir developments and will provide strong leadership to the refreshed management team."

Antony Maris, Chief Executive Officer Designate of Hurricane, commented:

"Through hard work and dedication, the Hurricane team developed the Lancaster project safely, on time and on budget, and has now successfully operated the Lancaster EPS for 16 months. This capability is a core strength of the business, and I am delighted to be joining this accomplished operating team.

Following the uncertainty of recent months, as the significance of the EPS reservoir performance has become clearer, we must now focus on extracting value from Lancaster and our other discoveries, while optimising the use of our significant installed infrastructure West of Shetland. In particular, the Technical Review has identified upside within sandstone reservoirs on the flanks of the Lancaster field, with the potential for volumes of recoverable oil which are significant in a UKCS context. Furthermore, together with Spirit, we are working towards consideration of a viable development plan for the Lincoln field.

Our near-term priority is further technical work to refine an activity plan for Lancaster, which we expect to be finalised by the end of this year and executed in 2021, with an overarching focus on capital discipline. We will be engaging with all our key stakeholders regarding our forward work programme and financing arrangements and updating the market on these efforts in due course."

Contacts: 

Hurricane Energy plc Antony Maris, Chief Executive Officer Designate Philip Corbett, Head of Investor Relations	[phone]
Stifel Nicolaus Europe Limited Nominated Adviser & Joint Corporate Broker Callum Stewart / Simon Mensley / Ashton Clanfield	[phone]
Morgan Stanley & Co. International plc Joint Corporate Broker Andrew Foster / Tom Perry / Alex Smart	[phone]
Vigo Communications Public Relations Patrick d'Ancona / Ben Simons [e-mail]	[phone]

About Hurricane

Hurricane was established to discover, appraise and develop hydrocarbon resources associated with naturally fractured basement reservoirs. The Company's acreage is concentrated on the Rona Ridge, in the West of Shetland region of the UK Continental Shelf.

The Lancaster field (100% owned by Hurricane) is the UK's first producing basement field. Hurricane is pursuing a phased development of Lancaster, starting with an Early Production System consisting of two wells tied-back to the Aoka Mizu FPSO. Hydrocarbons were introduced to the FPSO system on 11 May 2019 and the first oil milestone was achieved on 4 June 2019.

In September 2018, Spirit Energy farmed-in to 50% of the Lincoln and Warwick assets, committing to a phased work programme targeting sanction of an initial stage of full field development.

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 Beverley Smith, Interim Chief Executive Officer, who is a qualified person for the purposes of the AIM Guidance Note for Mining, Oil and Gas Companies. Ms Smith is a chartered geologist with 30 years' experience in the oil and gas industry.

Standard

Reserves and 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.

Interim Chief Executive Officer's Review

H1 2020 marked the first anniversary of production from the Lancaster EPS. During the period, 2.7 MMbbls of oil was produced from the field, taking total production since field start up in May 2019 to 6.6 MMbbls. During the first half of the year, facility uptime on the Aoka Miza averaged an impressive 99% - continuing the recent trend of excellent FPSO availability, which is testament to the hard work and commitment of Hurricane's operations and development teams and our Tier 1 contractors.

Production during H1 2020 averaged 14,600 bopd. While this represented an increase over H2 2019 levels of 13,600 bopd, production in the first half was lower than expected, primarily due to a shut in of the 205/21a-7z well during May 2020. This action, combined with a consistent increase in water production from this well in particular, led Hurricane's Board to commission a comprehensive technical review of the Lancaster field's geological and reservoir models. The initial conclusions of that review have been announced today, with the results summarised below.

The COVID-19 pandemic has posed significant challenges to UKCS oil and gas operations. In March, a crew member on the Aoka Mizu FPSO was evacuated to the mainland and subsequently tested positive for COVID-19. The individual made a full recovery. The pandemic has restricted crew movements associated with UKCS upstream operations, limiting offshore manning to essential personnel only since March. Hurricane has worked closely with its contractors, suppliers and local authorities to manage the impact of these restrictions on its employees and the Company, and to date has not experienced any adverse operational impact from COVID-19.

Brent oil prices fell from $60/bbl in February 2020 to below $20/bbl in April 2020. While oil prices have recovered to their current level of $40/bbl, the negative impact on the Company's cash flows has resulted in a necessary pivot away from further appraisal and development activity to enhanced capital discipline and preserving liquidity. Low oil prices, future production levels and the scope and timing of future activity on the West of Shetland portfolio may impact the Company's ability to repay or refinance its Convertible Bond debt in full without additional funding and/or potential dilution to shareholders.

In H1 2020, the Company generated revenues of $81.9 million, compared to $22.4 million in H1 2019 when the Lancaster EPS was only onstream for a short period. An operating loss of $274.5 million (H1 2019: $1.2 million operating profit), was primarily driven by a non-cash asset impairment due to lower reserves at Lancaster and lower oil price assumptions. Overall, the Company reported a loss after tax of $307.7 million for H1 2020 (H1 2019: $21.2 million loss), primarily due to the operating loss described above and a decrease in the Company's deferred tax position following a reassessment of future taxable profits.

At 30 June 2020, the Company had net free cash† of $106.2 million, resulting in net debt† of $123.8 million.

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

Technical Review

In June 2020, a Technical Committee of the Board was established to oversee a comprehensive review of the geological and reservoir models of the Lancaster field and the GWA licence (the "Technical Review"). While the review is yet to complete, analysis of production performance and review of earlier well data has led to the following initial conclusions:

Lancaster Oil Water Contact

· The 205/21a-7z well began to produce water shortly after field start up, and the water cut has increased steadily, with water cuts most recently varying between 55-65%. The 205/21a-6 well began to produce water in October 2019, with a water cut (prior to the recent scheduled FPSO maintenance) of 18% associated with a production rate of c.15,000 bopd.

· A material balance analysis of the 1.1 million barrels of water produced from the Lancaster field, with continuing increases in water cut, now demonstrates that this large volume of water is very unlikely to have originated from a "perched water" zone.

· Given the observed water production, all wireline pressure, fluid content and production test data from earlier appraisal wells has been extensively reanalysed and complemented by learnings and calibrations from regional aquifer pressure data and input from third party specialists. The intersection of pressure-depth plots supports an OWC range of 1,320-1,340 metres TVDSS.

· Accordingly, the Company now believes that Lancaster water production is most likely from an underlying aquifer with an OWC at 1,330 metres TVDSS. The observed water production from 205/21a-7z suggests that the deepest part of that well at 1,329 metres TVDSS was just above the updated interpretation of the original OWC.

Geological Model of Lancaster

· Re-evaluation of production test data, and updated mapping after reinterpretation of seismic and log data, suggest that significant oil volumes are potentially present in the Victory and Rona sandstones which onlap the Lancaster fractured basement on the flanks of the structure. An analogous structural setting has been documented at the Clair Field along trend to the north west of Lancaster. Further work is required to assess the size of these volumes.

· The probable structural spill point of these onlapping sandstones on the flanks of Lancaster, based on this updated mapping exercise, is consistent with an initial OWC at 1,330 metres TVDSS.

Lancaster Pressure Behaviour

· Downhole pressure gauges in both Lancaster wells indicate that reservoir pressure has declined by 120 psi after cumulative production of 6.6 million barrels of oil. The pressure decline rate is higher than anticipated in pre-production reservoir modelling and consistent with a significantly shallower OWC and lower volume of oil-in-place than that estimated in the 2017 CPR.

· Pressure gauges in the suspended 205/26b-14 Lincoln well exhibit a 20 psi pressure decline, most likely as a result of production from the Lancaster field, 8 km distant. This important observation demonstrates good regional reservoir connectivity and that the Brynhild fault zone between Lancaster and Lincoln probably does not seal. Retrieval of additional pressure data following the recent scheduled Lancaster maintenance shut-in will be required to prove conclusively that Lancaster is the cause of the depletion.

· While the rate of pressure decline with cumulative production has slowed, based on current trends, well flowing pressure may approach the "bubble point" (the point at which gas is liberated from oil within the reservoir) during H2 2021. This may require the existing production wells to be choked back in order to manage potential excess gas production. Further work is underway to better understand the impact and possible mitigations of gas liberation in the reservoir, which may also have beneficial effects if a stable secondary gas cap emerges.

Lancaster Material Balance and Reservoir Simulation

· Material balance analysis shows a distinctive reduction in the rate of pressure decline with cumulative production, suggesting a complex reservoir system. Energy may be provided by a combination of oil-in-place expansion (within fractured basement and separate sandstone reservoirs), aquifer influx both from below and laterally, a developing secondary gas cap, compaction drive and other possible sources of energy.

· The relative contributions from each source of reservoir energy cannot be uniquely determined from material balance analysis alone. An integrated approach including reservoir modelling and updated structural analysis is therefore being used to refine estimates of oil in place, potential recovery and provide better predictive tools.

· Lancaster is a significantly more complex reservoir system than originally thought, with the onlapping sandstones appearing to represent a significant part of the connected volume indicated by material balance analysis. Further work is required to verify this preliminary finding and potential implications for field development and ultimate recovery.

· Reservoir modelling based on the probable initial OWC at 1,330 metres TVDSS, matched to observed dynamic behaviour, suggests that the OWC may have moved upwards by 10-15 metres since production start and is now within the 205/21a-7z reservoir section. This well is believed to be "coning" oil from above when flowed at higher rates. Water production from 205/21a-6 (which at its deepest point is some 82 metres above the initial OWC) is considered to be "coning" water up from the aquifer and a rate dependent water cut has been observed, as would be expected.

· While work to refine the revised reservoir model is ongoing, there is currently a good fit to observed pressure and water cut performance.

Lancaster EPS Production Forecast - No Further Activity

· On the basis of the 205/21a-6 and 205/21a-7z wells alone, with no further activity, production levels will continue to decline slowly from c.15,000 bopd seen immediately prior to the recent scheduled FPSO shutdown, until well flowing pressure approaches "bubble point" during H2 2021, at which time production levels may need to be reduced.

· While the 205/21a-7z well can produce at high water cuts using the installed Electric Submersible Pump ("ESP"), the optimal near-term production strategy is to produce the 205/21a-6 well on its own under natural flow, leaving 205/21a-7z shut in to minimise water production and manage reservoir voidage and pressure declines.

· Consequently, production guidance for the period 1 September 2020 to 31 December 2020 is 12,000-14,000 bopd, which includes the scheduled annual FPSO shutdown which was completed on 8 September 2020 and a 95% uptime assumption for the balance of the year.

· Assuming production would need to be choked back as well flowing pressure approaches "bubble point" during H2 2021, un-audited 2P estimated ultimate recovery for the Lancaster EPS based on the two current wells and no further activity is 16.0 million barrels, of which 9.4 million barrels remain to be produced (subject to economic limit test).

Lancaster Reserves (existing two wells and no further activity, subject to economic limit test)
Million barrels	1P	2P	3P
Estimated Ultimate Recovery	14.3	16.0	17.7
Reserves remaining (as of 1 September 2020)	7.7	9.4	11.1

Lancaster Remediation Options

· A number of options to mitigate the forecast production and pressure decline rates of the Lancaster EPS are under active evaluation.

· The primary option is to manage reservoir voidage and pressure decline by initiating water injection. Feasibility studies are underway to determine optimum timing, cost, location and design of a water injection well and facilities, including any adaptations required to the existing water injection capabilities on the Aoka Mizu. These studies are targeting a decision on possible 2021 activity by the end of 2020. The Company's preliminary estimate for the cost of a water injection well is $70-80 million gross, which includes drilling, tie-back and FPSO modifications

· Given the constraints on operating West of Shetland during the winter months, the Company does not believe that it will be in a position to commence any activity until Q2 2021 at the earliest.

Lancaster Contingent Resources

· In light of the revised interpretation of the OWC in the Lancaster field, the Company is voluntarily relinquishing the P1368 Central licence acreage outside of the determined Lancaster field area.

· At present, Hurricane has a commitment to drill a well on the Lancaster licence during 2021, with the objective of providing evidence in support of the historical deep OWC model. In light of the revised interpretation of the OWC and pending finalisation of the voluntary relinquishment announced today, the Company will be released of its well obligation, enabling reallocation of this potential cost towards activity focused on enhancing production.

· The Company's estimate of contingent resources in Lancaster has been reduced significantly compared to the 2017 CPR, which assumed significantly deeper OWC cases. Revised contingent resource estimates are provided below:

Lancaster contingent resources
Million barrels	1C	2C	3C
Lancaster	26	58	90

Note: Does not include any economic limit test

Lancaster Production Operations

During the first half of the year, the Lancaster EPS produced 2.7 million barrels of crude, compared to 0.5 million barrels in H1 2019 when the field was only onstream for a short period following production start-up in May 2019. In total, seven cargoes were lifted during the first half of 2020.

The Aoka Mizu FPSO has continued to demonstrate excellent availability, averaging 99% uptime in the first half of 2020 and 96% in total since production commenced in May 2019. A scheduled annual maintenance took place over five days in early September 2020, with production restarted on 8 September 2020.

As previously stated by the Company, the Lancaster EPS is essentially a long-term production test of the Lancaster fractured basement reservoir, with the ultimate objective of gathering data to refine reserves and resources estimates and inform future development phases. During early 2020, the Lancaster EPS production wells underwent a series of tests, firstly to establish the characteristics of the 205/21a-6 well, and then both the 205/21a-6 well and 205/21a-7z well on natural flow to establish a longer-term target rate. Initially, both wells were able to produce at a combined rate of c.20,000 bopd, albeit with increasing water production which had not been expected early in the life of the EPS.

On 22 May 2020, the Company announced the shut in of the 205/21a-7z well following evidence of flow instability, with the 205/21a-6 well maintained on natural flow. In early June 2020 and following a relaxation of COVID-19 restrictions on UKCS activity, Hurricane commenced commissioning of the ESPs installed in the Lancaster production wells, which allowed for the 205/21a-7z well to return to production at a reduced rate.

In August 2020, following a brief controlled shutdown of the Aoka Mizu FPSO for minor repairs, the Company commenced a period of further testing on the 205/21a-6 well to provide additional data in support of the Technical Review. As stated above, the Company plans to produce the 205/21a-6 well on a standalone basis in the near-term, leaving the 205/21a-7z well shut in to minimise water production and maximise pressure support from the aquifer.  

The Lancaster EPS was producing at c.15,000 bopd from the 205/21a-6 well immediately prior to the recent scheduled FPSO maintenance shutdown, and has averaged c.14,500 bopd to date in H2 2020. Based on current plans, the Company expects the Lancaster EPS to produce 12,000 -14,000 bopd from September to December 2020 (inclusive) and intends to give production guidance for 2021 early next year once there is better definition on the 2021 work programme.

Greater Warwick Area

Following the results of the 2019 drilling programme, the GWA JV (Hurricane 50%, Spirit Energy 50%) has spent the first half of 2020 reassessing its understanding of the GWA licence potential. In March 2020, the GWA JV signed a cost allocation agreement, adjusting certain terms relating to Spirit Energy's original farm-in in 2018. The full detail of this agreement can be found in the press release dated 6 March 2020.

In light of the significant restrictions on UKCS activity as a result of the COVID-19 pandemic, the OGA agreed to extend the deadline for the GWA licence commitment well from 31 December 2020 to 30 June 2022.

Lincoln

In July 2020, pressure data from the downhole gauges in the 205/26b-14 well was retrieved, which indicated 20 psi depletion at Lincoln, interpreted to be due to the effect of Lancaster production some 8 km distant. This suggests that the Brynhild fault is not sealing, and that the OWC at Lincoln is likely to be close to the structural closure, as at Lancaster. While limited available data on Lincoln is not definitive, a base case OWC is now estimated to be at 1,846 metres TVDSS (± 50 metres).

As previously announced, the OGA had given notice of a proposed field determination area over local structural closure at the Lincoln discovery, which was subsequently accepted by the GWA JV.

The Company's preliminary contingent resource volumes using the OWC range above are shown below, for the Lincoln basement structure only. 

Indicative basement contingent resources (gross) - Hurricane estimates
Million barrels	1C	2C	3C
Lincoln contingent resources	24	45	79

  Note: Not subject to any economic limit test

Work is ongoing to map the onlapping Mesozoic section on the flanks of the Lincoln basement structure. Contingent resources estimates are subject to revision as this work progresses.

Hurricane continues to work with all GWA stakeholders on the best way forward for the Lincoln discovery. The GWA JV has a commitment to plug and abandon the 205/26b-14 Lincoln well by 30 June 2021 at an estimated total cost of $12 million gross.

Warwick

To date, Hurricane's Technical Review has not incorporated an updated assessment of Warwick. However, the conclusion of the Technical Review is likely to lead to a significant downgrade of the prospective resources attributed to Warwick in the 2017 WoS CPR.

Halifax

To date, the Technical Review has not incorporated an updated assessment of Halifax. However, the conclusion of the Technical Review is likely to lead to a significant downgrade of the 2C resources attributed to Halifax in the 2017 WoS CPR.

Completion of Technical Review and CPR

The Technical Committee's work has yet to be completed and further updates will be announced when appropriate. It is still the Company's intention that the final conclusions will be integrated into an updated Competent Person's Report covering all of its West of Shetland assets, which the Company anticipates will be released no later than the end of Q1 2021.

ESG and Gas Export Update

In April 2020, Hurricane published its first standalone Environmental, Social and Governance report. The ESG report covered Hurricane's approach to ESG and performance across its operations for the 2019 calendar year. It is Hurricane's intention to enhance its ESG disclosures going forward, including but not limited to, aligning its reporting with the Task Force on Climate-related Financial Disclosures' recommendations, alignment of the Company's activities and objectives with the UN's Sustainable Development Goals and meeting the requirements of the UK's Streamlined Energy and Carbon Reporting ("SECR") policy.

Currently, associated gas production from the Lancaster EPS is partially used as fuel gas on the Aoka Mizu FPSO, with the remainder flared under the consent within the approved Field Development Plan. Further development of the Company's West of Shetland licences may require the development of a gas export solution. As part of the first phase of the Spirit Energy farm-in to the GWA licence, long lead items for gas export have been purchased. The Company remains fully committed to reducing its greenhouse gas emissions where it is economically and commercially viable to do so, and fully supports OGUK's commitment for a net zero basin by 2050.

Corporate

On 27 February 2020, it was announced that Chief Financial Officer, Alistair Stobie, had resigned by mutual agreement with the Board. Richard Chaffe, formerly Head of Finance, was appointed Acting CFO and subsequently confirmed as Chief Financial Officer and an executive director of the Company in June 2020.

On 8 June 2020, it was announced that Dr Robert Trice had resigned as Chief Executive Officer and a Director of the Company by mutual consent with the Board. Ms Beverley Smith, a non-executive director of Hurricane, was appointed Interim CEO.

On 8 July 2020, Hurricane was deeply saddened to report that Neil Platt, Chief Operations Officer and executive director of the Company, had passed away. Mr Platt was a hugely respected colleague and his passion, enthusiasm and technical excellence were integral to Hurricane's growth over the past decade. His leadership was pivotal to the successful delivery and operation of the Lancaster EPS.

Steve Holmes, Production Operations Director, was appointed Acting Chief Operations Officer with the Company pleased to confirm his appointment as Chief Operations Officer on 11 September 2020.

On 21 August 2020, it was announced that Antony Maris had been appointed as a Director of the Company and CEO Designate. He formally assumed the role of CEO following the publication of these financial results, with Beverley Smith returning to her non-executive role.

Mr Maris brings 35 years of wide-ranging oil and gas sector technical and business leadership experience to Hurricane. Prior to joining the Company, he spent 15 years with Pharos Energy plc (previously SOCO International plc) where he was Chief Operating Officer from 2012 to early 2020. In this role, he was responsible for the development and operation of several oilfields, in joint venture with local and other parties, including fractured basement reservoirs offshore Vietnam and onshore Yemen. Pharos Energy's Vietnam assets, which delivered 60,000 bopd gross peak volumes, contributed significantly to Vietnam's overall hydrocarbon output. He was awarded the Friendship Order Medal by the Vietnam Government for his significant contribution to exploration and production activities.

Outlook

Hurricane's near-term priority is to evaluate options to mitigate forecast production declines at Lancaster by water injection or other means, and to assess the potential of the sandstones which onlap the Lancaster basement. This work is expected to conclude before the end of 2020 with a strong focus on prudent capital allocation. In addition, work will continue on Lincoln with the objective of considering possible pathways towards development.

The Company will, in parallel, be engaging with its key stakeholders regarding the forward work programme and financing arrangements in order to maximise the value of its assets.

Despite the reductions in Lancaster reserves and resources announced today, Hurricane's asset base remains significant in a wider UKCS context and the Company has a valuable base of installed infrastructure from which to exploit further upside.

Beverley Smith

Interim Chief Executive Officer

10 September 2020

 

Financial Review

Highlights

	First half 2020	Full year 2019	First half 2019
Production	2,658 kbbl	3,030 kbbl	528 kbbl
Production rate*	14,600 bopd	12,900 bopd	10,400 bopd
Sales volumes	2,747 kbbl	2,874 kbbl	356 kbbl
Revenue	$81.9m	$170.3m	$22.5m
Average sales price realised	$29.8/bbl	$59.3/bbl	$63.2/bbl
Cash production cost per barrel†	$18.2/bbl	$21.8/bbl	$24.0/bbl
Operating cash inflow/(outflow)	$21.9m	$112.2m	$6.1m
Closing net free cash†	$106.2m	$133.6m	$48.4m
Net debt†	$123.8m	$96.4m	$181.6m
Underlying profit/(loss) before tax†	$(40.2)m	$30.0m	$4.0m
Profit/(loss) after tax	$(307.8)m	$58.7m	$(21.2)m

* Rounded to nearest 100 bopd; 2019 rates calculated from First Oil in 2019.

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

During the first half of 2020, over 2.7 million barrels of Lancaster crude were sold across seven cargoes, generating $81.9 million in revenue. Despite the low oil prices seen across the period, the Group was still able to generate positive cash flow from operations of $21.9 million, thanks to the low operating costs and production efficiency of the Lancaster EPS. It is also testament to Hurricane's employees and key Tier 1 contractors that despite the ongoing impacts of COVID-19 there was minimal disruption to operations and business both offshore and onshore. The Group exercised tight capital discipline, with $35.8 million spent on capital expenditure.

Revenue

Revenue for the period was $81.9 million, with an average price realised of $29.8/bbl across seven cargoes, versus an average Dated Brent price for the period of $40.1/bbl. Under the sales and marketing agreement with BP, the sale of Lancaster crude is priced at either the first five or last five days of the month of lifting (at buyer's option). In volatile pricing environments, such as was seen during February to April 2020, this meant that the applicable Dated Brent price was, on average, lower than the spot price at date of sale.

The average discount to Brent realized was $4.2/bbl (representing the discount or premium offered by the refinery purchasing the crude, BP's marketing fee, and the freight costs incurred by BP in transporting crude to its ultimate destination). The discounts and premia experienced saw significant variability during the first half of 2020 amid a volatile crude market; but with all cargoes sold to date having been on time, within specification and contractual terms, Hurricane has a growing reputation of being a reliable producer. With crude markets stabilising, average discounts to Brent in the second half of 2020 thus far have been significantly better than the first half of the year.

Cost of sales

Total cost of sales was $101.5 million, including $55.6 million of depreciation charges (calculated on a unit-of-production basis). Cash production costs (which exclude depreciation and accounting movements in inventory but include the fixed lease charges for the Aoka Mizu) were $48.3 million, equivalent to $18.2/bbl versus $21.8/bbl in 2019. The decrease in cash production costs per barrel was primarily due to the revenue-linked incentive tariff for the Aoka Mizu, whereby a reduction in realized sales prices results in a direct reduction in production costs, partially reducing oil price risk exposure to the Group. Excluding the incentive tariff, cash production costs reduced from $16.7/bbl (full year 2019) to $15.2/bbl in 2020, driven by higher production rates in 2020.

Impairment of oil and gas assets

Following the initial conclusions of the Technical Review (see above), the associated downwards revision of estimated recoverable reserves and the decline in oil prices during the year, a non-cash impairment charge of $238.9 million has been recognised against the producing Lancaster oil and gas assets. The impairment charge was calculated based on expected future cashflows from the Lancaster EPS, using a number of forecast production profiles (both with and without the cost and benefits of a water injection programme) and probability weighted according to our best estimates of the most likely outcomes. For further details on the impairment charge, key assumptions and methodology used see notes 1.4.1 and 2.3 to the interim financial statements. These estimates and assumptions are subject to risk and uncertainty, and therefore changes to external factors and internal developments and plans (including the sanction or otherwise of any water injection programme, an updated CPR assessment of the Lancaster field, and any other intervening developments) have the ability to significantly impact these projections, which could lead to additional impairments or future reversals in future periods.  

Impairment of intangible assets

Impairments and write-offs of intangible exploration and intangible assets included $12.5 million relating to Hurricane's share of idle hire costs for the Paul B Loyd Jr rig, which was contracted in anticipation of GWA drilling and/or well abandonment activity in 2020. Following the extension of consents to plug and abandon the 205/26b-14 Lincoln well to June 2021, and to commence drilling the GWA commitment well by 30 June 2022, the JV partners took the decision to terminate the hire of the rig in June 2020, and settle the remaining minimum hire costs with the rig operator.

Other profit and loss

General and administrative costs decreased from $4.5 million in H1 2019 to $3.6 million in H1 2020, primarily due to more staff and administrative costs now included within cost of sales and lower non-cash share-based payment expense.

Convertible Bond accounting

The accounting for the Convertible Bond (issued in July 2017) required the recognition of an embedded derivative liability related to the equity conversion option. The fair value of the embedded derivative is valued using an option pricing model, with the key inputs being the Company's share price and its share price volatility. Any decrease in the liability creates a corresponding non-cash credit in the income statement. See note 5.1 to the Financial Statements for further details.

The gains recognised do not have any impact on the Group's cash position, amounts payable in respect of the Convertible Bond, or on its tax position. On either conversion or repayment of the Bond, the derivative liability will be released to the Income Statement.

The fair value gain recognised during the period in relation to the embedded derivative was $34.0 million, primarily driven by decreases in the Company's share price in the period.

Hedging

In June 2020, Hurricane hedged a portion of its forecast production for the second half of 2020. A total of 1.8MMbbls (equivalent to c.10,000 bopd), was hedged through the purchase of put options with an average strike price of $35/bbl (Dated Brent). The average strike price of $35/bbl represents a floor for the hedged volumes with Hurricane retaining any upside in oil prices above this level. The cost of acquiring the put options was $3.4 million. As oil prices increased in June, a fair value loss on the derivatives was recognised of $0.8 million, included within net finance costs.

Cashflow

At 30 June 2020, the Group had $106.2 million of net free cash† (being unrestricted cash net of payables and accruals and including trade receivables), a decrease of $27.4 million from 31 December 2019.

Even with oil prices at historic lows, the Lancaster EPS was still able to be cash positive. Average realised sales price was $29.8/bbl and cash production costs were $18.2/bbl, generating cash per barrel (before working capital movements) of $11.6/bbl in H1 2020.

Other operating cash outflows included $3.4 million for the purchase of term put options and $2.1 million on decommissioning the previously suspended Halifax and Whirlwind wells. After adjusting for movements in working capital (including proceeds of $17 million from the end of June cargo sale received on 1 July 2020), the Group's operating cash inflow amounted to $21.9 million.

Capital expenditure in the period was $35.8 million. Expenditure on GLA activities related to preparations for gas export work, and long-lead items in preparation for future drilling activity. Net cash outflows relating to GWA represented the Group's share of its costs of the joint operation, including long-lead items relating to a potential future GWA tie-back, idle rig costs of the Paul B Loyd Jr, and the timing impact of expenditure incurred by the Group as operator before recovery of costs from Spirit.

Financing outflows of $13.4 million mainly included coupon payments of the Convertible Bond and fixed lease repayments primarily for the Aoka Mizu.

Following start-up of production from the EPS, the Group is required to set aside a certain amount of cash generated from oil sales to cover some of the termination costs of the FPSO lease should it wish to exit the charter before the end of the contract term. At 30 June 2020, this amounted to $20.1 million and was classified as restricted cash. In addition to the above, the Group currently provides post tax security for its decommissioning liability for the Lancaster field by way of a decommissioning bond.  Should it be necessary to replace this with cash security this would result in up to an additional $36 million of unrestricted cash moving to restricted cash.

Tax

The Group recognised a total tax charge for H1 2020 of $49.3 million, all related to deferred tax. At 31 December 2019, following commencement of production from the Lancaster EPS and estimates of future taxable profits, a deferred tax asset and corresponding deferred tax credit of $54.3 million was recognised in respect of trading losses accumulated to date. As a result of the Technical Review, estimates of future taxable profits have been revised downwards meaning that it is now not forecast that there will be sufficient future taxable profits against which to offset all of these tax losses. The deferred tax asset has therefore been written down to the estimated amount of recoverable tax losses, resulting in a net tax charge of $49.3 million in the period.

Principal risks

There are a number of potential risks and uncertainties which could have a material impact on the Group's performance. Certain of these risks impacted the Company in the first half of 2020 and could continue to impact the Company over the remaining six months of 2020 and could cause actual results to differ materially from expected and historical results. The Group's principal risks are as follows:

· Substantial capital requirements

· Exploration, appraisal and development operational risks

· Production operational risks

· Geological and reservoir risk

· Regulatory

· Oil price fluctuations

· Third-party infrastructure

· Development project delivery

· Health, Safety and Environmental

· Compliance

· Joint venture partners

· Strategy

· Climate change and energy transition

The principal risks and uncertainties, along with the mitigation measures in place to reduce risks to acceptable levels, are consistent with those as at 31 December 2019. The risks associated with COVID-19 (primarily with regards to disruption to operations and adverse impact on commodity prices) and Brexit (primarily with regards to potential regulatory impacts) are included within the existing principal risks above.

Further information on the above principal risks and uncertainties, and the manner in which they are managed and mitigated, is provided on pages 18 to 23 of the Group's 2019 Annual Report and Group Financial Statements. 

Related party transactions

There have been no new material related party transactions in the period and there have been no material changes to the related party transactions described in note 7.3 to the Consolidated Financial Statements contained in the 2019 Annual Report and Accounts.

Going concern

At the time of preparation of these Interim Financial Statements, the Directors have a reasonable expectation that the Group has adequate resources to continue to operate and meet its liabilities as they fall due for the foreseeable future, a period considered to be at least twelve months from the date of signing these Financial Statements. For this reason, they continue to adopt the Going Concern Basis for preparing the Interim Financial Statements. Further details are described in Note 1.2 in the interim financial statements.

Independent Review Report to Hurricane Energy plc

We have been engaged by the Company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2020 which comprises the condensed consolidated statement of comprehensive income, the condensed consolidated balance sheet, the condensed consolidated statement of changes in equity, the condensed consolidated cash flow statement and related notes 1 to 7. We have read the other information contained in the half-yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.

Directors' responsibilities

The half-yearly financial report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half-yearly financial report in accordance with the AIM Rules of the London Stock Exchange.

As disclosed in note 1, the annual financial statements of the Group are prepared in accordance with IFRSs as adopted by the European Union. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34 "Interim Financial Reporting," as adopted by the European Union.

Our responsibility

Our responsibility is to express to the Company a conclusion on the condensed set of financial statements in the half-yearly financial report based on our review.

Scope of review

We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410 "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Financial Reporting Council for use in the United Kingdom. A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2020 is not prepared, in all material respects, in accordance with International Accounting Standard 34 as adopted by the European Union and the AIM Rules of the London Stock Exchange.

Use of our report

This report is made solely to the Company in accordance with International Standard on Review Engagements (UK and Ireland) 2410 "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Financial Reporting Council. Our work has been undertaken so that we might state to the Company those matters we are required to state to it in an independent review report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the Company, for our review work, for this report, or for the conclusions we have formed.

Deloitte LLP

Statutory Auditor

London, UK

10 September 2020

 

Condensed Consolidated Statement of Comprehensive Income

for the 6 months ended 30 June 2020

			6 months ended		6 months ended		12 months ended
	Notes		30 Jun 2020		30 Jun 2019		31 Dec 2019
			$'000		$'000		$'000
Revenue	2.1		81,871		22,462		170,283
Cost of sales	2.2		(101,476)		(16,740)		(118,453)
Gross (loss)/profit			(19,605)		5,722		51,830
General and administrative expenses			(3,552)		(4,542)		(400)
Impairment of oil and gas assets	2.3		(238,853)		-		-
Impairment of intangible exploration and evaluation assets and exploration expense written off	2.4		(12,537)		-		(66,468)
Operating (loss)/profit			(274,547)		1,180		(15,038)
Finance income	3.2		843		619		1,741
Finance costs	3.2		(18,730)		(5,814)		(23,206)
Fair value gain/(loss) on Convertible Bond embedded derivative	5.1		33,956		(23,466)		34,691
Loss before tax			(258,478)		(27,481)		(1,812)
Tax	6.1		(49,262)		6,235		60,487
(Loss)/profit for the period			(307,740)		(21,246)		58,675
			Cents		Cents		Cents
(Loss)/earnings per share (basic)	3.1		(15.47)		(1.08)		2.97
(Loss)/earnings per share (diluted)	3.1		(15.47)		(1.08)		1.70

All results arise from continuing operations.
 

Condensed Consolidated Balance Sheet

as at 30 June 2020

	Notes		30 Jun 2020		30 Jun 2019		31 Dec 2019
			$'000		$'000		$'000
Non-current assets
Intangible exploration and evaluation assets	2.4		88,619		131,537		75,874
Oil and gas assets	2.3		513,614		844,195		796,155
Other non-current assets			2,862		3,391		3,080
Deferred tax assets	6.2		5,048		-		54,311
Cash and cash equivalents	4.1		2,881		2,967		3,065
			613,024		982,090		932,485
Current assets
Inventory	2.2		8,870		11,232		9,945
Trade and other receivables	4.2		36,718		55,144		50,435
Derivative financial instruments	4.4		2,542		-		-
Cash and cash equivalents	4.1		143,223		96,773		168,369
			191,353		163,149		228,749
Total assets			804,377		1,145,239		1,161,234
Current liabilities
Trade and other payables	4.3		(54,952)		(87,404)		(72,369)
Lease liabilities	5.2		(9,463)		(9,482)		(9,501)
Decommissioning provisions	2.5		(12,650)		-		(12,484)
			(77,065)		(96,886)		(94,354)
Non-current liabilities
Lease liabilities	5.2		(88,561)		(90,543)		(89,685)
Convertible Bond liability	5.1		(211,097)		(202,250)		(206,604)
Convertible Bond embedded derivative	5.1		(2,360)		(94,473)		(36,316)
Decommissioning provisions	2.5		(41,437)		(44,401)		(43,190)
			(343,455)		(431,667)		(375,795)
Total liabilities			(420,520)		(528,553)		(470,149)
Net assets			383,857		616,686		691,085
Equity
Share capital	5.4		2,885		2,883		2,883
Share premium			822,458		821,910		821,910
Share option reserve			21,141		26,377		20,828
Own shares reserve			(1,035)		(711)		(684)
Foreign exchange reserve			(90,828)		(90,828)		(90,828)
Accumulated deficit			(370,764)		(142,945)		(63,024)
Total equity			383,857		616,686		691,085

 

Condensed Consolidated Statement of Changes in Equity

for the 6 months ended 30 June 2020

	Share capital		Share premium		Share option reserve		Own shares reserve		Foreign exchange reserve		Accumulated deficit		Total
	$'000		$'000		$'000		$'000		$'000		$'000		$'000
At 1 January 2019	2,843		813,681		24,067		(380)		(90,828)		(121,699)		627,684
Loss for the period	-		-		-		-		-		(21,246)		(21,246)
New shares issued under warrants and rights	39		7,743		-		-		-		-		7,782
New shares issued under employee share schemes	1		486		-		(393)		-		-		94
Share-based payments	-		-		2,310		62		-		-		2,372
At 30 June 2019	2,883		821,910		26,377		(711)		(90,828)		(142,945)		616,686
Profit for the period	-		-		-		-		-		79,921		79,921
Share-based payments	-		-		(5,549)		27		-		-		(5,522)
At 31 December 2019	2,883		821,910		20,828		(684)		(90,828)		(63,024)		691,085
Loss for the period	-		-		-		-		-		(307,740)		(307,740)
New shares issued under employee share schemes	2		548		-		(445)		-		-		105
Share-based payments	-		-		313		94		-		-		407
At 30 June 2020	2,885		822,458		21,141		(1,035)		(90,828)		(370,764)		383,857

 

Condensed Consolidated Cash Flow Statement

for the 6 months ended 30 June 2020

			6 months ended		6 months ended		12 months ended
	Notes		30 Jun 2020		30 Jun 2019		31 Dec 2019
			$'000		$'000		$'000
Cash flows from operating activities
Operating (loss)/profit			(274,547)		1,180		(15,038)
Adjustments for:
Depreciation of property, plant and equipment	2.3		55,881		11,101		63,161
Impairment of oil and gas assets	2.3		238,853		-		-
Impairment of intangible exploration and evaluation assets and exploration expense written off	2.4		12,537		-		66,468
Share-based payment charge/(credit)			407		2,372		(3,150)
Purchase of derivative financial instruments	4.4		(3,420)		-		-
Decommissioning spend	2.5		(2,100)		-		(12)
Operating cash flow before working capital movements			27,611		14,653		111,429
Movement in receivables			(16,932)		(2,968)		(2,559)
Movement in payables			8,169		1,090		8,912
Movement in crude oil, fuel and chemicals inventories			3,041		(6,662)		(5,613)
Net cash from operating activities			21,889		6,113		112,169
Cash flows from investing activities
Interest received			843		619		1,438
Decrease in liquid investments			-		21,668		21,668
Expenditure on oil and gas assets			(12,373)		(30,906)		(52,878)
Expenditure on other fixed assets			(69)		(253)		(289)
Expenditure on intangible exploration and evaluation assets			(21,432)		(4,217)		(2,265)
Movement in spares and supplies inventories			(1,966)		-		239
Tax refund relating to R&D expenditure	6.1		-		6,235		6,235
Net cash used in investing activities			(34,997)		(6,854)		(25,852)
Cash flows from financing activities
Convertible Bond interest paid	5.1		(8,625)		(8,625)		(17,250)
Lease payments	5.2		(4,836)		(701)		(5,556)
Interest and other finance charges paid			(4)		(6)		(1,539)
New shares issued under warrants and rights	5.4		-		7,782		7,782
New shares issued under employee share schemes			105		94		94
Net cash used in financing activities			(13,360)		(1,456)		(16,469)
(Decrease)/increase in cash and cash equivalents			(26,468)		(2,197)		69,848
Cash and cash equivalents at beginning of period			171,434		101,831		101,831
Net (decrease)/increase in cash and cash equivalents			(26,468)		(2,197)		69,848
Effects of foreign exchange rate changes			1,138		106		(245)
Cash and cash equivalents at end of period	4.1		146,104		99,740		171,434

 

Notes to the Interim Financial Statements

Section 1  General information

Hurricane Energy plc is a public company, limited by shares, incorporated and domiciled in the United Kingdom and registered in England and Wales under the Companies Act 2006 (registered company number 05245689). The nature of the Group's operations and its principal activity is exploration, development and production of oil and gas reserves principally on the UK Continental Shelf. The address of Hurricane Energy plc's registered office is The Wharf, Abbey Mill Business Park, Lower Eashing, Godalming, Surrey, GU7 2QN. Hurricane Energy plc's shares are listed on the AIM market of the London Stock Exchange.

This Interim Report and Financial Statements was approved by the Board of Directors and authorised for issue on 10 September 2020.

This set of Interim Financial Statements for the 6 months ended 30 June 2020 is unaudited and does not constitute statutory accounts within the meaning of section 434 of the Companies Act 2006. Audited statutory Financial Statements for the year ended 31 December 2019 were approved by the Board of Directors on 8 April 2020 and have been delivered to the Registrar of Companies. The auditor's report on those Financial Statements was unqualified, did not draw attention to any matters by way of emphasis and did not contain a statement made under Section 498 of the Companies Act 2006.

1.1 Basis of preparation

The Interim Financial Statements for the six months ended 30 June 2020 have been prepared in accordance with International Accounting Standard 34 'Interim Financial Reporting' (IAS 34) as adopted by the European Union and the AIM Rules. These Interim Financial Statements should be read in conjunction with the annual Financial Statements for the year ended 31 December 2019, which have been prepared in accordance with International Financial Reporting Standards as adopted by the European Union (IFRS). The consolidated income statement and related notes represent results arising from continuing operations, there being no discontinued operations in the periods presented. The Interim Financial Statements have been prepared using accounting bases and policies consistent with those used in the preparation of the audited Financial Statements of the Group for the year ended 31 December 2019.

1.2 Going concern

The Group's business activities, together with the factors likely to affect its future development, performance and position are set out in the Interim Chief Executive Officer's review and Financial Review above. The financial position of the Group, its cash flows and liquidity position are set out in these Interim Financial Statements.

The directors have performed a robust assessment, including a review of the budget for the year ending 31 December 2020 and longer-term strategic forecasts and plans, including consideration of the principal risks faced by the Company and taking into account the ongoing impact of the global COVID-19 pandemic on the macroeconomic situation and any potential impact to operations. In particular, the directors considered a number of sensitivities on key assumptions which included downside (reverse stress) sensitivities in relation to production rates, oil price, fixed operating costs and foreign exchange rates, which estimated the extent to which the key assumption would need to be adversely impacted in order to eliminate the forecast headroom. Following this review, the directors are satisfied that, taking into consideration reasonably possible downside sensitivities, the Group has adequate resources to continue to operate and meet its liabilities as they fall due for the foreseeable future, a period considered to be twelve months from the date of signing these Interim Financial Statements. For this reason, they continue to adopt the Going Concern Basis for preparing the Interim Financial Statements.

1.3 Accounting policies

The accounting policies adopted are consistent with those of the annual Financial Statements for the year ended 31 December 2019. New and amended standards that became applicable for the Group in the current reporting period have not resulted in changes to accounting policies or retrospective adjustments.

1.4 Critical accounting judgments and key sources of estimation uncertainty

The critical judgments made in applying those accounting policies and the key sources of estimation uncertainty are the same as those described in the audited Financial Statements of the Group for the year ended 31 December 2019, except as described below.

1.4.1 Key source of estimation uncertainty - Impairment testing of assets

The Group assesses its assets and cash generating units ('CGUs') in each reporting period to determine whether any indicators of impairment exist. Where indicators exist, a formal impairment test is undertaken to estimate the recoverable amount (which is considered to be the higher of fair value less costs of disposal ('FVLCD') and value in use ('VIU')).

At the previous reporting date (31 December 2019), it was concluded that there were no impairment triggers in relation to the Lancaster field and hence no formal impairment test was required. As at 30 June 2020 a number of impairment triggers, including the impact of the COVID-19 pandemic on global crude oil demand, were identified and accordingly a formal impairment assessment was undertaken which resulted in an impairment charge of $238.9 million (see note 2.3).

For the producing Lancaster field, the recoverable amount was based on VIU which was estimated using a discounted cash flow model over the field's life, taking into account the cost of, and upside expected to be generated from, future capital expenditure plans designed to maintain sustainable production. The key assumptions used are based on best estimates using past experience, latest internal technical analysis and external factors, and include:

· production profiles and operating performance based on internal estimates and reservoir simulation models;

· the estimated cost of a water injection capital programme and subsequent forecast increase in production performance due to the additional pressure support (over and above estimated production in a 'no further activity' scenario);

· consideration of the costs of accessing, and potential incremental production from, the field's estimated revised 2C contingent resources;

· Dated Brent oil price assumptions (in real terms) of $45/bbl for the remainder of 2020 and 2021; rising to $50/bbl in 2022 and incrementally upwards to a long-term price of $60/bbl in 2025 and thereafter;

· operating cost assumptions based on latest budgets and information from key contractors;

· foreign exchange rate of 1.3 GBP:USD; and

· a pre-tax real discount rate of 10.3%.

Given the current uncertainty with regards to production guidance, forward plans and the status of the Group's Technical Review of reserves and resources, a number of forecast production profiles were generated, with and without the cost and benefits of a water injection programme, with the results probability weighted using management's best estimates.

These estimates and assumptions are subject to risk and uncertainty, and therefore changes to external factors and internal developments and plans (including the sanction or otherwise of any water injection programme, an updated CPR assessment of the Lancaster field, and any other intervening developments) have the ability to significantly impact these projections, which could lead to additional impairments or future reversals in future periods.

Sensitivity analyses performed indicate that a $5/bbl reduction in the oil price assumption across all periods would result in an additional impairment charge of $87 million, and a 1% increase in the discount rate used would increase the impairment charge by $14 million. It is not practical to provide meaningful sensitivity analysis on the outcome of the Group's Technical Review, given the current status and complexity of that process.

Section 2  Oil and gas operations

2.1 Revenue

All revenue is derived from contracts with customers and is comprised of one category and within one geographical location, being the sale of crude oil from the Lancaster EPS. All sales were made to one external customer (BP Oil International Limited).

	6 months ended		6 months ended		12 months ended
	30 Jun 2020		30 Jun 2019		31 Dec 2019
	$'000		$'000		$'000
Oil sales	81,871		22,462		170,283
Revenue from contracts with customers	81,871		22,462		170,283
Cargoes sold	7		1		7
Sales volumes	2,747 kbbls		356 kbbls		2,874 kbbls
Average sales price realised	$29.8/bbl		$63.2/bbl		$59.3/bbl

2.2 Cost of sales and inventory

Cost of sales

			6 months ended		6 months ended		12 months ended
			30 Jun 2020		30 Jun 2019		31 Dec 2019
	Note		$'000		$'000		$'000
Operating costs			36,170		9,463		44,915
Depreciation of oil and gas assets - owned	2.3		48,348		9,423		54,406
Depreciation of oil and gas assets - leased	2.3		7,258		1,404		8,210
Movement in crude oil inventory			2,113		(5,572)		(4,424)
Variable lease payments	5.2		7,587		2,022		15,346
Cost of sales			101,476		16,740		118,453

 

Inventory

			30 Jun 2020		30 Jun 2019		31 Dec 2019
			$'000		$'000		$'000
Crude oil			2,311		5,572		4,424
Fuel and chemicals			621		1,449		1,549
Spares and supplies			5,938		4,211		3,972
Inventory			8,870		11,232		9,945

No net realisable value provision for inventory was held at the balance sheet dates.

2.3 Oil and gas assets

			Leased		Owned		Total
	Note		$'000		$'000		$'000
Cost
At 1 January 2019			-		727,816		727,816
Additions			96,361		24,334		120,695
Changes to decommissioning estimates	2.5		4,878		1,633		6,511
At 30 June 2019			101,239		753,783		855,022
Additions			-		1,855		1,855
Changes to decommissioning estimates	2.5		108		1,786		1,894
At 31 December 2019			101,347		757,424		858,771
Additions			-		13,762		13,762
Changes to decommissioning estimates	2.5		(228)		(1,616)		(1,844)
At 30 June 2020			101,119		769,570		870,689
Depreciation
At 1 January 2019			-		-		-
Depreciation charge for the period			(1,404)		(9,423)		(10,827)
At 30 June 2019			(1,404)		(9,423)		(10,827)
Depreciation charge for the period			(6,806)		(44,983)		(51,789)
At 31 December 2019			(8,210)		(54,406)		(62,616)
Depreciation charge for the period			(7,258)		(48,348)		(55,606)
Impairment			(31,040)		(207,813)		(238,853)
At 30 June 2020			(46,508)		(310,567)		(357,075)
Carrying amount at 30 June 2019			99,835		744,360		844,195
Carrying amount at 31 December 2019			93,137		703,018		796,155
Carrying amount at 30 June 2020			54,611		459,003		513,614

An impairment charge of $238.9 million was recognised against producing oil and gas assets in the period. The triggers for the impairment test were the downward revision of estimated recoverable reserves as a result of the ongoing Technical Review, the decline in oil prices across the first half of 2020 and the market capitalisation of the Group falling below its net assets. The recoverable amount was determined based on management's best estimate of value in use, using key assumptions, judgements and estimates as outlined in note 1.4.1 above. The charge was allocated pro-rata to owned and leased assets based on their respective carrying values pre-impairment.

Oil and gas assets held under leases comprise the Aoka Mizu FPSO bareboat charter, which commenced in May 2019 (see note 5.2).

Included within the cost of owned oil and gas assets is $42.8 million of capitalised borrowing costs.

The total amount of depreciation charged in the period (comprising depreciation of oil and gas assets above, and depreciation of other fixed assets) was $55.9 million (6 months ended 30 June 2019: $11.1 million; 12 months ended 31 December 2019: $63.2 million)

2.4 Intangible exploration and evaluation assets

			6 months ended		6 months ended		12 months ended
			30 Jun 2020		30 Jun 2019		31 Dec 2019
	Note		$'000		$'000		$'000
At start of period			75,874		131,526		131,526
Additions			24,080		788		6,619
Other movements			-		(806)		-
Impairment			(12,109)		-		(66,468)
Changes to decommissioning estimates	2.5		774		29		4,197
At end of period			88,619		131,537		75,874

Intangible exploration and evaluation assets comprise 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, at 30 June 2020, comprises the Lincoln, Warwick and Halifax licences. The directors have fully considered and reviewed the potential value of licence interests, including carried forward exploration and evaluation expenditure. In doing so, they have considered the Groups' tenure of its licence interests, its plan for further exploration and evaluation activities in relation to these and the likely opportunities for realising the value of those licences, either by farm-out or by development of the assets. After taking into account the specific amounts impaired below, they consider the carrying amount to be appropriate.

Amounts impaired in the period were $12.1 million, comprising the Group's share of standby costs for the Paul B Loyd Jr rig, which was not used for any drilling campaigns following the OGA granting an extension to the licence commitments on the Lincoln field in light of the COVID-19 pandemic. See the Interim Chief Executive Officer's review and Financial Review above for further details.

Exploration expense written off in the period was $0.4 million, relating to changes in decommissioning estimates for the Whirlwind well (which was fully written-off in December 2019).

In August 2020, the P2294 licence that holds the Warwick assets was extended into its second term, and now expires in August 2023. Although the initial term of the P2308 licence that holds the Halifax assets is due to expire in November 2020, the directors expect this licence to be renewed into its second term, having met the required work programmes for the licence within its initial term.

On 12 December 2019, the Group executed a deed of variation with the Oil and Gas Authority (OGA), granting a five-year extension to its P1368 licence (which covered the Lincoln, Lancaster, Whirlwind and Strathmore subareas) to December 2024. As part of this extension agreed with the OGA, the Whirlwind and Strathmore subareas were relinquished resulting in a write-off of $66.5 million, all relating to Whirlwind. The carrying value of intangible exploration and evaluation assets relating to Strathmore was previously fully impaired in 2017.

2.5 Decommissioning provisions

			6 months ended		6 months ended		12 months ended
			30 Jun 2020		30 Jun 2019		31 Dec 2019
			$'000		$'000		$'000
At start of period			55,673		37,657		37,657
Net new provisions and changes in estimates			397		6,540		17,706
Utilised in period			(2,100)		-		(12)
Unwinding of discount			117		204		323
At end of period			54,087		44,401		55,674
Of which:
Current			12,650		-		12,484
Non-current			41,437		44,401		43,190
			54,087		44,401		55,674

The provision for decommissioning relates to the costs required to decommission the suspended wells previously drilled on the Lincoln and Lancaster exploration assets, 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 costs are expected to be incurred during 2021 (for the 205/26b-14 Lincoln well) and towards the end of 2025 (for the Lancaster EPS, Aoka Mizu FPSO and Lancaster exploration well).

Changes in estimates in the period have arisen from a decrease in the assumed discount rate, changes in foreign exchange rates, and changes to the expected costs and timing of decommissioning the 205/26b-14 Lincoln well following the OGA granting an extension of the suspension consent from June 2020 to June 2021.

Of the total net new provisions and changes in estimates, $0.8m was recorded as additions to intangible exploration and evaluation assets, $1.8m as a reduction to oil and gas assets, $1.0m recognised as receivables due from the Group's joint operation partner and $0.4m charged to exploration expenditure written off.

The utilisation of provisions during the period related to the plugging and abandonment of the Halifax and Whirlwind wells. 

2.6 Joint operation

In September 2018 the Group entered into a joint operation with Spirit to share costs and risks associated with the Greater Warwick Area (GWA) in exchange for granting Spirit a 50% interest in the Group's Lincoln (P1368 South) and Warwick (P2294) licences. The phased work programme includes a planned tie-back of a GWA well to the Aoka Mizu FPSO, together with host modifications to the vessel and a gas export tie-in to the West of Shetland Pipeline System ('WOSPS'). This work was initially to be split across Phase 1 (Hurricane fully carried up to a gross cost of $180.6 million) and Phase 2 (Hurricane 50% carried up to a gross cost of $187.5 million). As Phase 2 has not yet commenced, costs incurred from inception above $180.6 million have been shared equally between the joint operation partners.

With effect from 6 March 2020, a new cost allocation framework was implemented whereby the joint operation will build-out the equipment and materials required to tie-back a single well from the GWA to the Aoka Mizu FPSO on a 50:50 basis. On completion, these items will be held in storage until the joint operation sanctions the tie-back of a well to the Aoka Mizu FPSO, with the required regulatory consents to do so.

Hurricane can elect to continue to build-out long-lead items related to the tie-in of the Aoka Mizu FPSO to WOSPS on a sole basis. While Hurricane has no current plans to proceed with the WOSPS installation, in the event that a decision is taken in future to proceed, subject to the required approvals and consents, Hurricane would bear 100% of the associated costs, and would reimburse Spirit for related gas export past costs up to 31 January 2020 (excluding carry) of approximately $18.0 million (only where installation occurs prior to the partners approval of Phase 2).

If at any time Phase 2 is approved and a GWA tie-back to the Aoka Mizu FPSO proceeds, Hurricane will benefit from the original terms of the 2018 farm-in through retrospective application of the carry in the proportions originally agreed.

The Group currently acts as operator of the joint operation and will continue to do so until full field development workstreams commence.

Amounts due from and to the joint operation partner are shown in notes 4.2 and 4.3 respectively.

Further details on the activities and progress of the joint operation are described in the Interim Chief Executive Officer's review above.

2.7 Commitments

	30 Jun 2020		30 Jun 2019		31 Dec 2019
	$'000		$'000		$'000
Contractual commitments for acquisition/construction of oil and gas assets	11,847		1,873		4,299
Contractual commitments for acquisition/construction of intangible exploration and evaluation assets	4,624		-		17,127
Minimum undiscounted value of leases not yet commenced	-		--		20,358

Section 3  Income Statement

3.1 Earnings per share

	6 months ended		6 months ended		12 months ended
	30 Jun 2020		30 Jun 2019		31 Dec 2019
	$'000		$'000		$'000
(Loss)/profit attributable to holders of Ordinary Shares in the Company used in calculating basic earnings per share (being (loss)/profit after tax)	(307,740)		(21,246)		58,675
Add back impact of:
Convertible Bond - interest expense not capitalised	n/a		n/a		16,417
Convertible Bond - depreciation of interest capitalised in the year	n/a		n/a		738
Convertible Bond - fair value gain	n/a		n/a		(34,691)
(Loss)/profit attributable to holders of Ordinary Shares in the Company used in calculating diluted earnings per share	(307,740)		(21,246)		41,139
	Number		Number		Number
Weighted average number of Ordinary Shares used in calculating basic earnings per share	1,989,515,103		1,965,389,894		1,978,513,120
Potential dilutive effect of:
Convertible Bond	n/a		n/a		442,307,692
Weighted average number of Ordinary Shares and potential Ordinary Shares used in calculating diluted earnings per share	1,989,515,103		1,965,389,894		2,420,820,812
					Cents
Basic (loss)/earnings per share	(15.47)		(1.08)		2.97
Diluted (loss)/earnings per share	(15.47)		(1.08)		1.70

The potential effect of the conversion feature included within the Convertible Bond, and the effect of outstanding share awards and options, was antidilutive for the 6 months ended 30 June 2020 and 30 June 2019 as the Group incurred a loss.

For the 12 months ended 2019 the impact of share awards was antidilutive because market-based conditions for both schemes had not been met at the balance sheet date, and the impact of other employee share options was antidilutive as the adjusted exercise prices were in excess of the average market price of Ordinary Shares during the relevant periods.

3.2 Finance income and costs

			6 months ended		6 months ended		12 months ended
			30 Jun 2020		30 Jun 2019		31 Dec 2019
	Note		$'000		$'000		$'000
Interest income on cash, cash equivalents and liquid investments			843		619		1,453
Net foreign exchange gains			-		-		288
Finance income			843		619		1,741
Convertible Bond interest expense	5.1		(13,118)		(12,511)		(25,490)
Interest on lease liabilities	5.2		(3,846)		(1,037)		(4,972)
Unrealised fair value losses on oil price derivatives	4.4		(878)		-		-
Other interest expense and bank charges			(121)		(935)		(1,495)
Net foreign exchange losses			(650)		(201)		-
Unwinding of discount on decommissioning provisions	2.5		(117)		(204)		(323)
Finance costs incurred			(18,730)		(14,888)		(32,280)
Interest capitalised			-		9,074		9,074
Finance costs			(18,730)		(5,814)		(23,206)
Total net finance costs			(17,887)		(5,195)		(21,465)

Section 4  Cash, working capital and financial instruments

4.1 Cash and cash equivalents

		30 June 2020		30 June 2019		31 December 2019
		$'000		$'000		$'000
Unrestricted cash and cash equivalents (current)		123,170		81,399		156,591
Restricted cash and cash equivalents (current)		20,053		15,374		11,778
Current cash and cash equivalents		143,223		96,773		168,369
Restricted cash and cash equivalents (non-current)		2,881		2,967		3,065
Total cash and cash equivalents		146,104		99,740		171,434
Of which:
Unrestricted		123,170		81,399		156,591
Restricted		22,934		18,341		14,843
		146,104		99,740		171,434

Included within restricted cash and cash equivalents is $20.1 million (30 June 2019: $nil; 31 December 2019: $11.7 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 an amount to ensure it could meet its liability to pay an early termination fee to the lessor.

At the end of 2018, as agreed with the OGA, £16.8 million was held in trust to cover the post-tax cost of decommissioning the Lancaster EPS and was accounted for as a non-current restricted liquid investment and recognised within non-current assets. In February 2019, the Group replaced this cash security held in trust with a decommissioning bond of the same value. Under the terms of the agreement with the bond provider, the original funds were able to be released back to the Group in tranches once specific production milestones were met. At 30 June 2019, the funds not yet released were included within current restricted cash and cash equivalents. The required production milestones were all achieved by September 2019, and thus the full £16.8 million ($21.7 million) was released back to unrestricted cash by the end of 2019. Under the terms of the bond, the bond provider can recall all or part of bond at any time if they believe the Company's financial position has deteriorated. Should this occur then the amounts may be recalled, placed back into trust and reclassified as restricted cash.

All the non-current restricted cash and cash equivalents balances are held in escrow for future costs associated with the Group's decommissioning obligations.

The carrying amounts of cash and cash equivalents and liquid investments are considered to be materially equivalent to their fair values.

4.2 Trade and other receivables

			30 Jun 2020		30 Jun 2019		31 Dec 2019
			$'000		$'000		$'000
Receivables due from joint operation partner			17,759		51,509		47,519
Trade receivables			17,414		269		723
Prepayments			1,256		712		1,066
Other receivables			289		2,654		1,127
Trade and other receivables			36,718		55,144		50,435

The carrying amounts of trade and other receivables are considered to be materially equivalent to their fair values and are unsecured. Joint operation receivables represent expenses incurred by the Group as operator of the joint operation which will be recovered from the Group's joint operation partner. Amounts billed to the joint operation partner accrue interest at LIBOR and are generally due for settlement within ten days.

4.3 Trade and other payables

			30 Jun 2020		30 Jun 2019		31 Dec 2019
			$'000		$'000		$'000
Amounts due to joint operation partner			1,120		-		5,371
Trade payables			9,500		27,799		647
Other payables			616		2,237		654
Accruals			43,716		57,368		65,697
Trade and other payables			54,952		87,404		72,369

The carrying amounts of trade and other payables are considered to be materially equivalent to their fair values and are unsecured. Trade and other payables are non-interest bearing and generally payable within 30 days.

Trade and other payables and accruals include the Group's share of joint operation payables, including amounts that the Group settles on behalf of joint operation partners. Accruals includes expenditure relating to joint operations incurred by the Group as operator which have yet to be billed to joint operation partners. Amounts due to the joint operation partner represent cash calls the Group has made as operator in advance of balances relating to the joint operation falling due.

4.4 Derivative financial instruments

In June 2020, the Group hedged a portion of its forecast production for the second half of 2020 via the purchase of put options at a total cost of $3.4 million. The options would result in upside to the Group if the average Dated Brent price over the option term is below the strike price.

The options are classified as Level 2 financial instruments within the IFRS fair value hierarchy and have not been classified as hedging instruments in a hedge relationship under IFRS 9.

				Fair value at
Put option commodity	Term	Notional quantity	Strike price	30 June 2020
		bbl	$/bbl	$'000
Dated Brent	1 July 2020 - 31 December 2020	900,000	34.55	1,270
Dated Brent	1 July 2020 - 31 December 2020	900,000	35.50	1,272
		1,800,000		2,542

The fair value loss of $0.9 million in the period has been recognised within finance costs.

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 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, where applicable, 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's carrying value is split between a debt component (the host contract) measured at amortised cost (with an effective interest rate of 13.5%) and an embedded derivative component measured at fair value.

The amounts recognised in the Financial Statements relating to the Convertible Bond, being all liabilities arising from financing activities, are as follows:

		Debt component		Derivative component		Total
		$'000		$'000		$'000
Carrying value at 1 January 2019		198,364		71,007		269,371
Cash interest paid		(8,625)		-		(8,625)
Fair value loss		-		23,466		23,466
Interest charged		12,511		-		12,511
Carrying value at 30 June 2019		202,250		94,473		296,723
Cash interest paid		(8,625)		-		(8,625)
Fair value gain		-		(58,157)		(58,157)
Interest charged		12,979		-		12,979
Carrying value at 31 December 2019		206,604		36,316		242,920
Cash interest paid		(8,625)		-		(8,625)
Fair value gain		-		(33,956)		(33,956)
Interest charged		13,118		-		13,118
At 30 June 2020		211,097		2,360		213,457
Fair value at 30 June 2019		243,151		94,473		337,624
Fair value at 31 December 2019		235,852		36,316		272,168
Fair value at 30 June 2020		115,000		2,360		117,360

The Convertible Bond contains covenants relating to the restrictions on incurrence of certain indebtedness. These covenants were complied with for the current and prior periods. Further details on the Convertible Bond and its covenants are disclosed in note 5.1 to the Group's 2019 Annual Report and Financial Statements.

The embedded derivative component of the Convertible Bond has been assessed to be a Level 2 financial liability, as the valuation has been calculated using the Black-Scholes option pricing model using direct and indirect observable inputs. The key inputs used are share price volatility (calculated as the volatility of one Hurricane Ordinary Share over two years period to the measurement date) and the price of one Ordinary Share at 30 June 2020. 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 bonds were considered. The likelihood of each was considered to be nil for the purposes of the valuation.

The fair value calculation at 30 June 2020 used a share price volatility assumption of 88.3 % (31 December 2019: n/a; 30 June 2019: 27.5%) and the price of one Hurricane Energy plc Ordinary Share as at the balance sheet date of £0.058 (31 December 2019: £n/a; 30 June 2019: £0.52). The sensitivity of a reasonably possible increase or decrease of those inputs to the Group's profit before tax for the period ended 30 June 2020 is summarised below, assuming all other variables were held constant:

	Gain/(loss)
	$'000
Share price volatility assumption:
20% points increase	(2,818)
20% points decrease	1,752
Share price at balance sheet date:
£0.05 increase	(6,997)
£0.05 decrease	2,352

The valuation as at 31 December 2019 was derived by deducting the estimated fair value of the debt component (using an equivalent bond yield estimated from average adjusted bond yields from similar oil and gas E&P companies) from the quoted market value of the Convertible Bond. The valuation methodology has changed due to the previous methodology not being appropriate where the market value of the Convertible Bond is below its par value.

5.2 Leases

			6 months ended		6 months ended		12 months ended
			30 Jun 2020		30 Jun 2019		31 Dec 2019
			$'000		$'000		$'000
At start of period			99,186		3,323		3,323
New leases			-		96,361		96,361
Cash payments of principal and interest			(4,836)		(701)		(5,556)
Interest charged			3,846		1,037		4,972
Foreign exchange movements			(172)		5		86
At end of period			98,024		100,025		99,186
Of which:
Current			9,463		9,482		9,501
Non-current			88,561		90,543		89,685
			98,024		100,025		99,186

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).

5.3 Maturity analysis of financial liabilities

The maturity analysis of contractual undiscounted cash flows for non-derivative financial liabilities is as follows:

	Less than 6 months	6-12 months	1-2 years	2-5 years	More than 5 years	Total
	$'000	$'000	$'000	$'000	$'000	$'000
Trade payables and accruals	54,952	-	-	-	-	54,952
Convertible Bond interest	8,625	8,625	17,250	4,313	-	38,813
Lease liabilities	4,803	4,778	27,654	83,322	1,446	122,003
At 30 June 2020	68,380	13,403	44,904	87,635	1,446	215,768

	Less than 6 months	6-12 months	1-2 years	2-5 years	More than 5 years	Total
	$'000	$'000	$'000	$'000	$'000	$'000
Trade payables and accruals	87,404	-	-	-	-	87,404
Convertible Bond interest	8,625	8,625	17,250	21,563	-	56,063
Lease liabilities	4,859	4,832	9,594	83,323	29,180	131,788
At 30 June 2019	100,888	13,457	26,844	104,886	29,180	275,255

	Less than 6 months	6-12 months	1-2 years	2-5 years	More than 5 years	Total
	$'000	$'000	$'000	$'000	$'000	$'000
Trade payables and accruals	72,370	-	-	-	-	72,370
Convertible Bond interest	8,625	8,625	17,250	12,938	-	47,438
Lease liabilities	4,843	4,818	18,583	83,469	15,336	127,049
At 31 December 2019	85,838	13,443	35,833	96,407	15,336	246,857

Not included within the tables above is the Convertible Bond principal of $230 million which, unless previously converted into Ordinary Shares, redeemed or cancelled, is due to be redeemed on 24 July 2022 (see note 5.1).

At 30 June 2020, $17.8 million (31 December 2019: $42.5 million) was due from the Group's joint operation partner to settle trade payables and accruals relating to the joint operation (see note 4.3).

5.4 Share capital

				Ordinary Shares		$'000
At 1 January 2019				1,959,551,637		2,843
Shares issued under warrants and rights (at £0.20 per share)				29,860,834		39
Shares issued under employee share schemes				815,582		1
At 30 June 2019 and 31 December 2019				1,990,228,053		2,883
Shares issued under employee share schemes				1,643,503		2
At 30 June 2020				1,991,871,556		2,885

The Company has one class of Ordinary Share, which has a par value of £0.001.

In May 2019, Crystal Amber exercised warrants allowing it to subscribe for 23,333,333 Ordinary Shares at £0.20 per share. Kerogen Capital subsequently exercised a related right to subscribe for 6,527,501 Ordinary Shares at £0.20 per share. The gross proceeds received from these warrants and rights was $7,782,000. No transaction costs were incurred by the Group relating to the issue of these shares. Following the full exercise of these warrants and rights, there are no outstanding warrants or rights relating to the Company's Ordinary Shares.

Section 6  Tax

6.1 Tax charge/credit for the period

	6 months ended		6 months ended		12 months ended
	30 Jun 2020		30 Jun 2019		31 Dec 2019
	$'000		$'000		$'000
UK corporation tax
Current tax - prior years	-		6,235		6,259
Total current tax	-		6,235		6,259
Deferred tax - current year	(49,262)		-		90,226
Effect of changes in tax rates	-		-		(35,998)
Total deferred tax	(49,262)		-		54,228
Tax (charge)/credit per Income Statement	(49,262)		6,235		60,487
Loss on ordinary activities before tax	(258,478)		(27,481)		(1,812)
Loss on ordinary activities multiplied by standard rate of corporation tax in the UK applicable to oil and gas companies of 40%	103,391		10,992		725
Effects of:
R&D tax credit	-		6,235		6,259
Expenses not deductible for tax purposes	(2,432)		(948)		(1,724)
Income not chargeable for tax purposes	6,285		-		4,211
Items taxed at rates other than the standard rate of 40%	(6,946)		-		(278,873)
Ring fence expenditure supplement	-		-		22,057
Recognition of deferred tax not previously recognised	-		-		307,832
Derecognition of losses and losses not recognised	(149,560)		(10,044)		-
Total tax (charge)/credit for the period	(49,262)		6,235		60,487

The tax charge for the period of $49.3 million wholly relates to the derecognition of most of the deferred tax asset previously recognised at 31 December 2019, following a downwards revision to estimated future taxable profits. Estimates of future taxable profits were made using the Group's corporate cash flow model, using assumptions consistent with that used in testing the Lancaster oil and gas assets for impairment (as outlined in note 1.4.1). The results of the review concluded that there would be sufficient forecast taxable future profits to recognise a deferred tax asset of $5.0 million (30 June 2019: $nil; 31 December 2019: $54.3 million), resulting in a deferred tax charge of $49.3 million for the period.

In 2018 the Group made a claim under the SME Research & Development tax relief scheme in respect of the 2016 and 2017 financial years and surrendered the resulting losses for a payable tax credit. $6.2 million was received in respect of this in April 2019, classified within cash flows from investing activities as the original expenditure giving rise to the credit was reported within investing activities.

6.2 Deferred tax

	6 months ended		6 months ended		12 months ended
	30 Jun 2020		30 Jun 2019		31 Dec 2019
	$'000		$'000		$'000
Accelerated capital allowances	(95,482)		216,049		(168,626)
Other timing differences	-		(1)		448
Tax losses carried forward	100,530		216,048		222,489
Deferred tax asset	5,048		-		54,311

Tax losses of $241.2 million (30 June 2019: $540.1 million; 31 December 2019: $487.9 million) have been offset against deferred tax liabilities primarily related to fixed assets. Based on future forecasts of interest expense that is not allowable against profits subject to the supplementary charge a deferred tax asset of $5.0 million has been recognised in relation to supplementary charge losses that will be used to cover this amount. A potential deferred tax asset of $53.9 million has not been recognised, as it has been concluded that it is not appropriate to recognise any of this potential deferred tax asset until the Technical Review has been concluded and there is further certainty over forecast production profiles. A further $38.7 million relates to pre-trading expenditure losses not recognised, and includes potential claims for ring fence expenditure supplement ('RFES'). The recognised and unrecognised potential deferred tax assets relate to different types of tax loss, each being calculated at a different rate, the highest being that applicable to UK ring-fence profits of 30%.

6.3 Factors which may affect future tax charges

The quantum of the deferred tax asset recognised, and corresponding deferred tax charge or credit, is highly dependent on management's estimates of future cash flows and taxable income. Changes to estimates of future taxable profits will occur in future periods due to movements in forecast oil prices, finalisation of estimated reserves and resources, and the sanction or otherwise of capital projects.

The Group has ring-fenced trading losses of $562.3 million at 30 June 2020 and supplementary charge losses and allowances of $820.9 million which have no expiry date and would be available for offset against future trading profits. A potential RFES claim could also be made for the current accounting period which would result in additional trading losses of $56.2 million based on the position at 30 June 2020.

In addition to the above, the Group has pre-trading expenditure of $118.4 million which is carried forward at 30 June 2020, and tax relief will be available when FDP approval is obtained on the remaining licences (this expenditure could also be uplifted by RFES to $145.7 million).
 

Section 7  Other disclosures

7.1 Related party transactions

Related party transactions during the period comprise remuneration and fees paid to directors, who are considered the Group's key management personnel.

In May 2019, Kerogen Investments No. 18 Limited, a company controlled by Kerogen Capital (which is a related party of the Company due to the size of its shareholding and the provision of key management personnel services to the Company), executed a subscription right for 6,527,501 Ordinary Shares in the Company at £0.20 per share.

7.2 Subsequent events

7.2.1 Preliminary conclusions of the Technical Review

The initial results and findings of the Technical Review are included within the Interim Results Summary, Interim Chief Executive Officer's Review, and Technical Review sections of this announcement above.

7.2.2 P2294 licence extension

In August 2020, the P2294 licence (in which the Group has a 50% interest) was extended into its second term. The licence now expires in August 2023.

 

Appendix A: Glossary

2C contingent resources	Best case contingent resources under the Society of Petroleum Engineers' Petroleum Resources Management System
2P reserves	Proved plus probable reserves under the Society of Petroleum Engineers' Petroleum Resources Management System
AIM	The AIM market of the London Stock Exchange
Aoka Mizu	The Aoka Mizu FPSO
Bopd	Barrels of oil per day
Company	Hurricane Energy plc and/or its subsidiaries
CEO	Chief Executive Officer
CFO	Chief Financial Officer
Convertible Bond	$230 million of 7.5% convertible bonds issued by the Company in July 2017
COO	Chief Operating Officer
CPR	Competent Persons Report
EPS	Early production system
ESP	Electrical submersible pump
FDP	Field development plan
FPSO	Floating production storage and offloading vessel
GLA	Greater Lancaster Area, comprising the Lancaster and Halifax fields located on UKCS licences P.1368 Central and P.2308
the Group	Hurricane Energy plc, together with its subsidiaries
GWA	Greater Warwick Area, comprising the Lincoln and Warwick fields located on UKCS licences P.1368 South and P.2294
Hurricane	Hurricane Energy plc and its subsidiaries
IFRS	International Financial Reporting Standards as adopted by the European Union
MMbbls	Million barrels of oil
OGA	Oil and Gas Authority
Onlap	A geological phenomenon where successive wedge-shaped younger rock strata extend progressively further across an erosion surface cut in older rocks
Ordinary Shares	Ordinary shares in the Company of £0.001 each
PP&E	Property, Plant and Equipment
Spirit	Spirit Energy Limited
Tier 1 contractors	Hurricane's major direct contractors
UKCS	United Kingdom Continental Shelf
UOP	Unit of production
WOSPS	West of Shetland Pipeline System

Appendix B: Non-IFRS measures

Management believe s that certain non-IFRS measures (also referred to as 'alternative performance measures') are useful metrics as they provide additional useful information on performance and trends. These measures are used by management for internal performance analysis and incentive compensation arrangements for directors and employees. The non-IFRS measures presented below are not defined in IFRS or other GAAPs and therefore may not be comparable with similarly described or defined measures reported by other companies. They are not intended to be a substitute for, or superior to, IFRS measures.

Definitions and reconciliations to the nearest equivalent IFRS measure are presented below.

Underlying profit before tax

Underlying profit before tax is defined as profit before tax under IFRS, before fair value gains or losses on the Convertible Bond embedded derivative, fair value gains or losses on derivatives not designated as hedging instruments in a hedging relationship, impairment and write-offs of intangible exploration and evaluation assets, impairment of oil and gas assets and gains or losses on disposal of assets or subsidiaries.

Management believe 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 items and transactions within the income statement. These are the volatile non-cash impact of the Convertible Bond embedded derivative movement (the valuation of which is largely outwith management's control); and gains or losses arising from write-offs, impairments and disposals of assets which do not reflect the Group core assets and business. Fair value gains or losses on derivatives not designated as hedging instruments in a hedging relationship have been added to the items excluded from underlying profit before tax as the Group entered into such contracts for the first time during 2020. These fair value movements are excluded from underlying profit before tax as movements are wholly due to movements in oil price which is not within management's control.

			6 months ended		6 months ended		12 months ended
	Note		30 Jun 2020		30 Jun 2019		31 Dec 2019
			$'000		$'000		$'000
Loss before tax (IFRS measure)			(258,478)		(27,481)		(1,812)
Add back:
Fair value (gain)/loss on Convertible Bond embedded derivative	5.1		(33,956)		23,466		(34,691)
Fair value loss on unhedged derivative financial instruments	4.4		878		-		-
Impairment and write-off of intangible exploration and evaluation assets	2.4		12,537		-		66,468
Impairment of oil and gas assets	2.3		238,853		-		-
Underlying (loss)/profit before tax			(40,166)		4,015		29,965

 

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.

Depreciation and movements in crude oil inventory are deducted as they are non-cash accounting adjustments to cost of sales. Fixed lease payments 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 cost per barrel is defined as cash operating costs divided by production volumes.

Management believe that cash production costs, and cash production cost per barrel are useful measures as they remove non-cash elements from cost of sales, assist with cashflow forecasting and budgeting, and provide indicative breakeven amounts for the sale of crude oil.

			6 months ended		6 months ended		12 months ended
	Note		30 Jun 2020		30 Jun 2019		31 Dec 2019
			$'000		$'000		$'000
Cost of sales (IFRS measure)	2.2		101,476		16,740		118,453
Less:
Depreciation of oil and gas assets - owned	2.3		(48,348)		(9,423)		(54,406)
Depreciation of oil and gas assets - leased	2.3		(7,258)		(1,404)		(8,210)
Movements in crude oil inventory	2.2		(2,113)		5,572		4,424
Add:
Fixed lease payments payable for oil and gas assets			4,550		1,161		5,761
Cash production costs			48,307		12,646		66,022
Production volumes			2,658 kbbl		528 kbbl		3,030 kbbl
Cash production cost per barrel			$18.2/bbl		$24.0/bbl		$21.8/bbl

 

Net free cash and net debt

Net free cash is defined as current unrestricted cash and cash equivalents, plus current financial trade and other receivables, current oil price derivatives, less current financial trade and other payables.

Management believe 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 par value of the Convertible Bond; being the total amount repayable on maturity of the Bond in July 2022 (unless previously converted, redeemed or purchased and cancelled).

Management believe that net debt is a useful measure as it aids stakeholders in understanding the current financial position of the Company.

	Note		30 Jun 2020		30 Jun 2019		31 Dec 2019
			$'000		$'000		$'000
Cash and cash equivalents (IFRS measure)	4.1		146,104		99,740		171,434
Add:
Trade and other receivables	4.2		36,718		55,144		50,435
Derivative financial instruments	4.4		2,542		-		-
Less:
Restricted cash and cash equivalents	4.1		(22,934)		(18,341)		(14,843)
Prepayments	4.2		(1,256)		(712)		(1,066)
Trade and other payables	4.3		(54,952)		(87,404)		(72,369)
Net free cash			106,222		48,427		133,591
Par value of Convertible Bond	5.1		(230,000)		(230,000)		(230,000)
Net debt			(123,778)		(181,573)		(96,409)

 

END

 

 

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