Final Results

RNS Number : 3459K

Hurricane Energy PLC

10 April 2018

 

10 April 2018

Hurricane Energy plc

("Hurricane" or the "Company")

Final Results for the Year Ended 31 December 2017

Hurricane Energy plc, the UK based oil and gas company focused on hydrocarbon resources in naturally fractured basement reservoirs, announces its final audited results for the year ended 31 December 2017.

Highlights

·    Transformative year which took the Lancaster Early Production System (EPS) into a project execution phase, targeting first oil in H1 2019

·    Key EPS achievements included: Final Investment Decision (FID) and approval of the Field Development Plan (FDP) by the Oil and Gas Authority (OGA)

·    Published two Competent Person's Reports (CPRs) which independently certified 2.6 billion barrels of oil equivalent of 2P Reserves + 2C Contingent Resources

·    $547 million raised in new equity and convertible bonds (before expenses), fully financing the EPS

·    2017 loss after tax of $7.0 million (2016: profit after tax $0.9 million)

·    Ended 2017 with $360.0 million¹ in cash and liquid investments (2016: $101.5 million²)

¹ $201.9 million of liquid investments is held in term deposits which mature within 12 months. $33.4 million is held within escrow accounts

² $12.2 million is held within escrow accounts

Hurricane's Group Annual Report and Accounts will be published on or around 25 April 2018. The Company has increased the level of disclosure compared to prior years, in line with its intention to transition its disclosure, reporting and corporate governance towards best practice, commensurate with a Premium Listed business. The Company's Annual General Meeting is scheduled for 6 June 2018; further details to be provided in due course.

Dr Robert Trice, Chief Executive of Hurricane, commented:

"Last year saw the Company gain both operational and commercial momentum as it moves toward first production and material cash generation. Accordingly, Hurricane went through a step change in 2017; we booked our first reserves, increased our 2C Contingent Resources by 450% and obtained FDP approval on the first phase of development of our assets."

"First oil on the Lancaster EPS remains on schedule for H1 2019. As we look ahead to this milestone, we are in a position of strength with 100% ownership of a portfolio of assets with resources measured in the billions of barrels and with line of sight on further activity to ultimately achieve monetisation."

Contacts:

Hurricane Energy plc	Dr Robert Trice (Chief Executive Officer)/Alistair Stobie (Chief Financial Officer)	[phone]
Stifel Nicolaus Europe Limited	Nominated Adviser and Corporate Broker Callum Stewart/Nicholas Rhodes/Ashton Clanfield	[phone]
Vigo Communications	Public Relations Patrick d'Ancona/Ben Simons	[phone] [e-mail]

About Hurricane

Hurricane was established to discover, appraise and develop hydrocarbon resources associated with naturally fractured basement reservoirs.

Hurricane's acreage is concentrated on the Rona Ridge, West of Shetland. The Lancaster field, the Company's most appraised asset, has combined 2P Reserves and 2C Contingent Resources of 523 million stock tank barrels of oil. The Company is currently proceeding towards the first phase of development of Lancaster, an Early Production System, with first oil targeted for H1 2019.

During the 2016-2017 drilling campaign, the Company made two significant discoveries* at Halifax and Lincoln. Together, these discoveries* have 2C Contingent Resources of 1,839 million barrels of oil equivalent (mmboe).

Hurricane's other assets include Warwick, which has best case Prospective Resources of 935 million stock tank barrels of oil, Whirlwind, which has 2C Contingent Resources of 205 mmboe (under the Whirlwind oil case) and Strathmore, which has 2C Contingent Resources of 32 million stock tank barrels of oil. Together, this brings Hurricane's total combined 2P Reserves and 2C Contingent Resources to 2.6 billion barrels of oil equivalent.

*Discovery - This classification is consistent with SPE/AAPG/WPC and SPEE guidelines for Petroleum Resource Management - Determination of Discovery Status

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 Dr Robert Trice, who is a qualified person for the purposes of the AIM Guidance Note for Mining, Oil and Gas Companies. Dr Robert Trice, Chief Executive Officer of Hurricane Energy plc, is a geologist and geoscientist with a PhD in geology and has over 30 years' experience in the oil and gas industry. 

Interim Chairman's Statement

This has been a transformative year for the Company. Following the successful $530 million fund raise required to take the Final Investment Decision (FID) on the Lancaster Early Production System (EPS), we were given approval by the Oil & Gas Authority (OGA) of the Field Development Plan (FDP), such that we could then proceed with the execution of the project. Given the challenging oil price environment in mid-2017, this was a great achievement by management. The data generated by the EPS will allow us to progressively evaluate the performance of the Lancaster reservoir system and gain increasing confidence in the volume of oil that we can expect to recover from our Rona Ridge assets. At the time of writing, I am delighted to report that first oil remains on schedule for H1 2019.

Throughout 2017 we continued to engage with industry in line with our stated aim of achieving a farm-out or sale in advance of a full field development. As we have progressed our asset base, we have seen interest build in the West of Shetlands region and also in basement reservoirs in northwest Europe. The rapidity with which Hurricane has advanced Lancaster, from the drilling and testing of the -7 and -7Z wells in late 2016, to a funded and approved FDP with target first oil approaching, is unusual in the industry. Moving at this pace has allowed us to remain at 100% in our licences, as we approach first cash generation. Following first oil, with data from the EPS being generated and no imminent funding hurdles, we will be in a strong position to move towards establishing the value that can be ascribed to our overall acreage holdings.

The positive working relationship between Hurricane and its Tier 1 contractors is a reflection of the Company's contracting strategy. We chose our Tier 1 contractors on the basis of demonstrable industry reputation, technical expertise, health, safety and environmental track record, and supportive contractual structures. We believe that they are best placed, and appropriately incentivized, to take us through engineering and installation, to first oil and into the operations phase. The progress on the upgrade to the Aoka Mizu in Dubai and the excellent working relationship with the Bluewater Energy Services (Bluewater) team, is the most visible reflection of that strategy. We are aligned in wanting to see the vessel sail away on schedule and remain on track to do so. As for the well completion and subsea installation aspects of the development; with both Xmas trees delivered and flowlines, umbilical and manifold in the final stages of fabrication, we now look forward to the start of offshore operations. We secured our major contracts at an opportune moment in the industry cycle, and will continue to strive to minimise finding and development costs as we further explore, appraise and develop our Rona Ridge assets.

Successful delivery of the EPS is a core component of the Group's remuneration strategy, including the Value Creation Plan (VCP). 2017 was the first full year of this five-year long-term scheme introduced in late 2016, concurrent with the November 2016 fundraise. The VCP incentivises management to achieve the Company's strategy of de-risking and monetising its resource base. As operational hurdles are achieved it is increasingly important for management to ensure that this progress is translated into returns for shareholders. The management team personally invested into the plan, yet there is no pay-out until measurable value has been delivered to shareholders. Management are fully aligned with our shareholders as the Company transitions to becoming cash generative, and in ultimately monetising the Company's assets.

At the beginning of 2016, Hurricane was an exploration and appraisal company, with processes and procedures that were fit for purpose at that time. The completion of our 2016/17 drilling campaign and obtaining FDP approval for the EPS means that Hurricane has evolved as a company. Our focus has extended beyond drilling additional exploration and appraisal wells, when funding allows, to transitioning towards organic cash generation. This evolution has required an upgrade to our organisational structure, processes and procedures. Initial work on gap analysis commenced following the July 2017 fund raise and the Listing and Governance Committee (LGC) of the board was formed to coordinate the work streams that will prepare the Company for the next phase of its development. The appointment of a new Chairman, following Dr Robert Arnott's resignation, and subsequently one or more additional non-executive directors, will ensure that the composition of the board of directors of the Company (Board) and its committees are fully compliant with the Financial Reporting Council's UK Corporate Governance Code (the Code), a standard not required of AIM-quoted companies. The newly constituted board will evaluate the appropriateness and timing of an application for admission of the Company's ordinary shares to a premium segment of a recognised stock exchange (Premium Listing). Notwithstanding those decisions, it is the Board's view that the Company should act as if it were Premium Listed. We have taken a number of those steps already and will continue to ensure that your Company becomes and thereafter remains Code compliant.

2017 was indeed a fabulous year for progressing Hurricane's operations and my thanks go to all those who helped make it happen, regulators who supported our drilling and early development activities, our contractors, who have been working collaboratively with us, and of course all the Hurricane staff, who have worked tirelessly throughout.

I expect to be able to pass on the role of Chairman very shortly and then return to my non-executive role as Senior Independent Director.

It has been an honour to be your Interim Chairman. My interest in the Rona Ridge and its basement reservoirs started many years ago. Hurricane is now poised to demonstrate the potential of the Lancaster reservoir, a key step to providing the understanding which will underpin the development and monetisation of its assets.

Dr David Jenkins
Interim Chairman

Chief Executive Officer's Review

The year was marked by the significant progress made on the EPS, the first stage of development of our Rona Ridge assets. We completed the required financing, took FID, and received FDP approval. The scale of this achievement cannot be overstated, Lancaster is the first standalone FDP approval in the UK sector since Culzean in 2015 and involved the largest ever AIM capital raise for an oil exploration and production (E&P) company. These achievements were made against a back-drop of volatile and low oil prices, and a resultant low level of investor interest in the E&P sector.

The Group's loss after tax for the year was $7.0 million (2016: profit after tax $0.9 million). This loss was driven by increased operating expenses, predominantly related to increased corporate activity, and write-offs/impairments connected with our non-core assets (the relinquished Typhoon and Tempest assets and the Strathmore asset). The loss was offset by a fair value gain on derivative financial instruments related to the Convertible Bond issued during the year and foreign exchange gains. The Group ended the year with cash, cash equivalents and liquid investments of $360.0 million, on a firm footing for the remaining costs expected in the run up to first oil on the EPS.

The purpose of the EPS is to provide the necessary reservoir understanding to progress to a phased development of our Rona Ridge assets, whilst generating significant cash flow to commence the next phase of appraisal and development. At the time of writing, the EPS remains on track and on budget.

FID and FDP approval bisected the year. Prior to these events, the Company was focused on the numerous work streams that culminated in being able to pass these milestones; exploration, appraisal and development drilling, front end engineering and design (FEED) studies, detailed engineering, contracting and funding. Following FID and FDP approval, Hurricane is now very much in project execution mode. This mode includes upgrade and life extension work on the Floating, Production, Storage and Offloading vessel (FPSO), the Aoka Mizu, which commenced in earnest in Dubai, following the vessel's arrival in September. TechnipFMC's fabrication facilities have been equally busy fabricating the Xmas trees and the subsea umbilical, risers, and flexibles (SURF). I have been able to witness personally the excellent progress of the construction phase of the EPS by visiting these facilities, and look forward to well completion and installation activities commencing shortly.

Our extensive exploration, appraisal and development drilling campaign in 2016/2017 resulted in two Competent Persons Reports (CPRs) being published during the year in review. The Lancaster field CPR, published in May 2017, assigned the Company proved plus probable (2P) reserves of 37.3 million stock tank barrels of oil, based on just a six-year EPS duration (this would increase to 62.1 million stock tank barrels of oil in the event Hurricane extended the EPS duration to 10 years, the maximum duration of the Aoka Mizu contract). In addition, a further 486.1 million stock tank barrels of oil were assigned as 2C Contingent Resources.

In December 2017, we published a further CPR, incorporating the results of our Lincoln and Halifax exploration wells. This attributed 2C Contingent Resources of 604 million barrels of oil equivalent to Lincoln and 1,235 million barrels of oil equivalent to Halifax. The sum of our Rona Ridge 2C Contingent Resources is in excess of 2.5 billion barrels of oil equivalent. The challenge to the Company is clear; demonstrate that the reservoir information obtained during the EPS, and any additional appraisal drilling, de-risks the Company's significant resources such that they are appropriately valued.

The 2016/17 wells on Lincoln and Halifax were a very successful first step. As clarity around the timing of first oil becomes apparent in H2 2018, and we complete the necessary studies on the data obtained from our drilling campaign, we will set-out plans for further appraisal and future development phases utilising projected organic cash flow. Efficient development of a resource base as large as ours will necessarily involve significantly greater surface infrastructure than included for the EPS, and associated investment that exceeds the funding capacity currently available to Hurricane on a sole basis. Whilst plans for such broader development phases are being formulated, we will be working towards getting the most out of our existing facility, the Aoka Mizu. To make use of the full throughput capacity of 30,000 barrels of oil per day, and vessel life of 10 years, a key next step is FPSO debottlenecking and implementing a gas export or disposal solution.

Whilst the focus of the Company during the year has been on the EPS, the success of the Halifax exploration well in Q1 delivered another leg of our Rona Ridge exploration, appraisal and development strategy. The Halifax well was the last of the four wells drilled through 2016/2017 with the Transocean Spitsbergen drilling rig. As with our other exploration wells, the Halifax well was drilled in close proximity to a previous well which had indicated the presence of hydrocarbons in the basement, in this case, a well drilled by Arco in 1998. For this reason, its success was not a surprise but this does not reduce its significance. The well encountered an oil column of approximately 1,000m true vertical thickness (TVT) with a similar oil-down-to (ODT) to Lancaster, indicating that the Rona Ridge between the Brynhild and Westray fault zones could be a single hydrocarbon accumulation (a distance of approximately 35km). In aggregate, 2C Contingent Resources across Lancaster and Halifax are in excess of 1.7 billion barrels of oil equivalent; a world-class prize. As we describe in the Review of Operations, our inability to bring hydrocarbons to surface was a result of formation damage caused by drilling operations. This occurred because of a combination of over-pressured drilling mud and chemical additives in the mud. As we learn from the Halifax data and focus on the next phase of exploration, appraisal and development we will determine the most appropriate method of revisiting the Halifax well.

Fractured basements are a global phenomenon which have been produced successfully for extended periods in multiple locations around the world. However, in the UK they represent a new play type for a sector of the oil industry which has historically focused on sandstone reservoirs. Accordingly, Hurricane has maintained licence and field operatorship and ownership for longer, and at greater levels, than would be typical with more traditional reservoir types. We believe that this strategy has preserved shareholder value. As we move into subsequent phases of appraisal and development, Hurricane expects to bring in a partner to share in future appraisal and development campaigns, and the funding of these.

The low oil price environment since 2014, and its effect on a cyclical industry, proved to be a blessing which allowed us to complete 265 days of consecutive drilling operations in 2016/2017 and to progress the EPS with engineering 'A teams', at prices which would have been unachievable only a few years previously. Leasing an FPSO to operate West of Shetland was, until this recent oil price reversal, restricted to the majors. Hurricane has shown that, using appropriate contract structures, a sufficiently attractive project can take advantage of these conditions and proceed to development on an independent basis.

Whilst the Halifax well was being drilled and logged in Q1 2017, the EPS project and commercial teams were being resourced and the key contracts for the EPS negotiated. At its core, the EPS is a straightforward development comprising two previously drilled and tested wells, tied back to an existing FPSO whose processing facilities require little in the way of changes to be able to accommodate Lancaster's crude. The Company's strategy was to lock-in the costs of the engineering, procurement, construction, installation and commissioning (EPCIC) phase via lump sum contracts with our Tier 1 contractors wherever possible; 75% of pre-first oil capital expenditure is locked-in in this way. With the installation phase of the EPS contract to come we are comfortable that the EPS is both on time and on budget for first oil in H1 2019. Our contracts with Bluewater reflects the need for risk sharing between the service sector and producers. We are delighted with the working relationship with them - they make money when we make money. There is no better incentive to be on time and on budget. We are not surprised to see this approach being replicated elsewhere.

Bluewater's delivery performance has been excellent to date, as has the performance of their selected yard, Dubai Drydocks World. We have long flagged the arrival of the buoy and mooring as being a key deliverable to allow TechnipFMC to complete the installation of the SURF and buoy and mooring installation in Q3 2018. Following a successful 'dry' trial of the buoy in February 2018, Bluewater is on track to deliver the buoy to TechnipFMC in Lerwick, Shetland Isles, to allow installation activities to commence on schedule.

Furthermore, the Xmas tree systems are ready for loading onto the rig for the EPS well completions. The Group has contracted Transocean's Paul B. Loyd Jr., a harsh environment semi-submersible rig for this work. Loading of the rig, transit to field and commencement of well completion operations is expected to take place in Q2 2018. We committed to the Xmas trees in December 2016, the longest of our long lead items; their timely delivery marks a step towards the start of 2018 SURF and mooring installation operations, allowing TechnipFMC to continue to work to the schedule of completing these operations in Q3 2018.

Much has been written on the new price and value discipline within the industry. Suffice to say that Hurricane's view on future prices does not assume that things will be different this time. The first indications of price inflation are visible, for example in the harsh environment rig market where forecast rates are double that which Hurricane achieved in its 2016/2017 drilling campaign. As we look beyond the EPS, our challenge is to ensure that appraisal and development costs reflect ongoing oil price uncertainty and strive to deliver value throughout the cycle as either sellers or holders of our Rona Ridge assets.

The Company implemented a new long-term incentive scheme in November 2016, the VCP. This scheme incentivises management to monetise the Company's reserves and resources against clearly defined milestones of financing, exploration, appraisal, development, production and potential sale. Management has delivered on a number of these milestones, including drilling the Lancaster -7 and -7Z wells, and raising funding for the EPS. Timely first oil and successful and safe operations should position the Company well to begin to monetise its assets, and management are incentivised to bring this about.

We are very aware that the environment West of Shetland is precious. Hurricane is dedicated to safe, environmentally responsible and sound operations. As CEO, I take personal responsibility for all environmental matters. Neil Platt, COO, takes the lead on all operational safety issues. We do not need to be financially incentivised to focus on these issues, however, any failures would have a significant negative impact on our annual and long-term remuneration.

Hurricane went through a step change in 2017; we booked our first reserves, increased our 2C Contingent Resources by 450% and obtained FDP approval on the first phase of development of our assets. We also added to our team, by filling in gaps across the Company as we move rapidly towards first oil and upgrading our systems and procedures to reflect our size and stage of development. The decision whether to move to a Premium Listing and the timing of such a move has yet to be made. As previously announced, the Board decided, following the mid-year capital raise, that the Company needed to adopt the standards required of a Premium Listed business. We are on our way, and once our Chairman and non-executive director recruitment has been completed, the Company will be Code compliant. From a day-to-day business point of view, we have spent the time since the capital raise updating our systems and procedures across the Company. We are now ready for the next stage in our development.

Finally, my thanks go to the Hurricane team, both employees and contractors. 2017 was another extraordinary year - everyone was pushed hard and I am delighted to say that all stepped up to the mark and delivered.

I look forward to first oil.

Dr Robert Trice

Chief Executive Officer

Review of Operations

The year in review commenced with both offshore drilling operations, West of Shetland, and front-end engineering and design (FEED) studies for the EPS ongoing. The Lincoln well was completed at the end of 2016, with results being analysed as the rig relocated to Halifax to drill the fourth and final well in a campaign that lasted 265 days. In parallel, the development and operations teams were focused on delivering the EPS. Transitioning this project from a planning and contracting phase, to project execution is a landmark achievement for Hurricane. At the same time, the Company's organisation was supplemented by a number of new positions as we move from being an exploration and appraisal (E&A) company to being an exploration and production (E&P) company.

The achievements below represent some of the highlights for the year. Of particular importance from Hurricane's perspective, is that these were achieved with no major HSE incidents, despite expending more than half a million man-hours between Hurricane and its primary contractors both on and offshore.

Subsurface

Lincoln well

Hurricane's exploration model was that Lincoln represented a similar reservoir to Lancaster and would contain a hydrocarbon column height of at least 455m, based on the ODT from offset well data. To evaluate Lincoln's potential, an exploration well was planned to drill to a depth of 2,135m true vertical depth subsea (TVDSS) and detect the presence of hydrocarbons through a detailed mudlogging and wireline programme.

The well was drilled to the target depth of 2,135m TVDSS. On evaluating the available data, it was concluded that the wellbore had not encountered a water leg and so the well was deepened to 2,325m TVDSS. Drilling was terminated before an oil water contact had been identified due to time constraints and the requirement to undertake Halifax operations.

A hydrocarbon column has been detected in the range of 2,109 - 2,325m TVDSS, indicating a minimum hydrocarbon column height of between 444m and 660m TVT. The depth of the penetrated hydrocarbon column is indicative that Lancaster and Lincoln are not in pressure communication and therefore the two assets exist as separate hydrocarbon accumulations.

Analysis of gas isotope data indicated that the encountered hydrocarbon is sourced from the same 'kitchen' area as Lancaster and is therefore most likely to be a light oil of a similar API gravity to Lancaster. This interpretation is corroborated by gas chromatography, wireline and core data, all of which indicate that the encountered hydrocarbon is a light oil.

Lincoln has the potential to be similar to Lancaster in productivity. The first step in realising this potential is for an appraisal well to be drilled to confirm hydrocarbon type and the ability for the reservoir to deliver a flow rate commensurate with commercial productivity. Depending on distance from the FPSO, an appraisal well has the potential to be tied back to the EPS infrastructure.

Halifax well

Hurricane's exploration model was that Halifax and Lancaster form part of the same accumulation, the Greater Lancaster Area (GLA) and that the Halifax well would encounter a hydrocarbon column with a height of at least 980m TVT (based on the Lancaster maximum ODT). To evaluate the Halifax potential, an exploration well was planned to drill to a depth of 1,800m TVDSS and the presence of hydrocarbons detected by drill stem testing and a detailed mudlogging and wireline programme. The specific objectives of the well were to:

i.     Demonstrate the presence of mobile oil and an oil water contact below structural closure as mapped

ii.    Bring an oil sample to surface

The reservoir section was drilled to 1,801m TVDSS and then tested, after which additional drilling deepened the well to 2,004m TVDSS. The well was a discovery, encountering a hydrocarbon column of approximately 1 kilometers TVT. Testing was unable to acquire a representative reservoir fluid sample to surface and consequently the oil type cannot be verified. Despite the challenges in testing the formation, the analysis of gas chromatography, wireline and core data indicated that the encountered hydrocarbon is most likely a light oil.

The inability to flow the well during testing was due to near-wellbore formation damage caused by the use of over-weighted drilling mud and chemical additives in the drilling brine during well operations. The near-wellbore formation damage was further compounded by a bullheading operation (forcibly pumping fluids into the well bore) applied during testing in an attempt to clean up the formation. In fact, the bullheading forced drill cutting material (a combination of rock cuttings, rock flour, and chemically enhanced drilling brine) further into the formation, thus drastically reducing near-wellbore permeability.

The well has been suspended and therefore has the potential to be re-entered for the purpose of further drill stem testing and/or deepening. A decision to re-enter the well will be based on ongoing technical work and the Group's Rona Ridge asset appraisal strategy.

The Halifax discovery has the potential to be similar to Lancaster in productivity potential. The first step in realising this potential is for an appraisal well to be drilled to confirm hydrocarbon type and the ability for the reservoir to deliver a flow rate commensurate with commercial productivity. Further appraisal work will also be required to test the Company's exploration model that Halifax and Lancaster are part of a single hydrocarbon accumulation.

Lancaster CPR findings

A CPR was issued for Lancaster in 2017 as an update to the previous CPR released in 2013. The 2017 CPR supports the Company's view of an extensive oil column on Lancaster and the basement reservoir being productive. The range of oil water contacts has narrowed on Lancaster since 2013 as a result of the 2016 Lancaster drilling campaign. The previous 2C depth of 1597m TVDSS has become the new 1C depth, and the 3C contact is now 103m shallower compared to 2013 at 1678m TVDSS.

RPS assigns 2P reserves of 37.3 million stock tank barrels of oil attributed to the initial six‐year period of the planned EPS. An additional 486 million stock tank barrels of 2C contingent resources are based on a recovery factor of 22.5%. Combined, this is an increase of 162% compared to the 2013 estimate of 200 million stock tank barrels of oil. Should Hurricane extend the EPS to ten years, 2P reserves volume would rise to 62.1 million barrels. The expectation is that within the six‐year base case duration of the EPS, full field planning and development will be undertaken. However, should it be commercially attractive, the Company has the ability to extend the contract duration with Bluewater for the Aoka Mizu for a further four years.

Halifax CPR findings

A second CPR was issued by RPS in 2017 covering the Halifax and Lincoln discoveries, as well as including the Whirlwind and Strathmore discoveries as reported in 2013.

RPS has agreed with Hurricane's view that Halifax has comparable reservoir properties to Lancaster. RPS states that the drill stem test carried out on the Halifax well was compromised by induced formation damage, as discussed above, rather than limited flow being a function of reservoir quality. RPS is supportive of the observation that no data so far acquired indicates that there are any significant differences in oil type between Lancaster and Halifax. Halifax water properties are also comparable to Lancaster, indicating the potential for a common aquifer. RPS also recognise that the difference in oil water contact depths between Lancaster and Halifax does not preclude them from being part of the same structure. However, as an alternative model to a single accumulation at Lancaster and Halifax, a major fault that bisects the Rona Ridge to the east of Lancaster and southwest of Halifax could act as a boundary between the two accumulations.

Halifax has been assigned 2C contingent resources of 1,235 million barrels of oil equivalent.

Lincoln CPR findings

As with Halifax, RPS is supportive of Hurricane's interpretation of basement reservoir properties at Lincoln being comparable with Lancaster. Oil properties are also recognised as being likely to be the same as Lancaster. Due to the presence of deep oil on the Lincoln structure, RPS recognises that a seal must exist between Lancaster and Lincoln and agree that Hurricane's interpretation that the Brynhild Fault Zone is the most likely candidate for the seal is robust. Although RPS believes there is the potential for Warwick and Lincoln to be part of the same accumulation, it has conservatively assigned them as two separate accumulations constrained by regional faulting. A successful exploration well on Warwick followed up by appraisal drilling will ultimately be required to determine if Lincoln and Warwick are connected.

Lincoln has been assigned 2C contingent resources of 604 mmboe, and Warwick has been assigned prospective resources of 935 mmboe.

Review of operations - project / development

FEED and long lead items

During 2017, the Group completed Front End Engineering and Design (FEED) work in relation to the key elements of the EPS development. This included FEED work in relation to:

i.     upgrade and life extension of the Aoka Mizu FPSO, and fabrication of a new turret mooring system buoy, with Bluewater;

ii.    SURF, and Subsea Production System (SPS) with TechnipFMC; and

iii.   well completions with Petrofac Facilities Management Limited (PFML).

The results of these studies allowed detailed budgeting to take place, which informed our mid-year capital raise and formed the basis for the Board to be able to take FID in mid-2017.

To maintain the target first oil date of H1 2019, whilst taking advantage of the market conditions at the time, Hurricane had identified and placed orders for certain schedule-critical long lead items using the results of initial FEED work in 2016. During 2017, in parallel with ongoing FEED studies, the Group continued to place orders, carry out surveys and make milestone payments on these pre-sanction items. In particular, we placed orders for the TechnipFMC Xmas trees and subsea control modules in late 2016. This enabled both Xmas trees and their respective control modules to be delivered ex-works in time for the commencement of the planned completion campaign in Q2 2018.

Contracting

The Group had chosen three Tier 1 contractors for the EPS, with each having primary responsibility for a specific key area of operations.

Bluewater is responsible for provision of the project's FPSO upgrade scope of work and associated turret mooring system under an engineering, procurement and construction (EPC) Contract. Under the agreement, Bluewater Energy Services is contracted to fabricate and deliver a new mooring system and buoy and the upgrade, hook up and testing of the FPSO. Following first oil, the Bluewater group entities will be responsible for the operation, maintenance and decommissioning of the FPSO, and the operation and maintenance of the subsea pipeline, pursuant to the terms of a Production Operating Services Agreement (POSA). A Bluewater group entity, Bluewater Lancaster Production (U.K.) Limited, has also been approved as installation operator and pipeline operator.

TechnipFMC is responsible for the fabrication, installation, testing and commissioning of the subsea equipment, including the SURF and SPS under the terms of the TechnipFMC Integrated engineering, procurement, construction and installation (EPCI) Contract and the installation of the mooring system and buoy.

Responsibility for Hurricane's well integrity, future drilling activities and EPS well completions and a number of well control packages, including variable speed drives, subsea control modules lies with PFML. The Group has a longstanding relationship with PFML, which in this role has been nominated as Hurricane's well operator and well management services provider in relation to the EPS, as well as our broader appraisal and exploration programme.

Hurricane believes that its approach to contracting has helped to reduce schedule and budget risk to the project, thereby maximising chance of success. The Group focussed on a small number of highly competent contractors, reducing interfaces and giving each a meaningful stake in the project. In the case of Bluewater and TechnipFMC, large lump sum components were included, thereby passing back a large portion of the cost risk and meaning that Hurricane's contingency within the budget is applicable to only the remaining costs, which represent less than 25 per cent of the total.

In another example of innovative contracting, Bluewater is incentivised to reach first oil and deliver stable production through an incentive tariff. This is based on a percentage of the sale price of each barrel of oil, after deducting certain costs and is higher for the first two years (in exchange for a reduced day rate), encouraging prompt commissioning.

In addition to external contracting, Hurricane has also expanded its internal organisation structure to suit its role as licence operator and expanded the operations team to satisfy the roles required by the EPS development. These enhancements have been made in a targeted manner, to avoid potential inefficiency from overlapping with our Tier 1 contractors, whilst also enabling Hurricane to effectively coordinate the development.

Regulatory approval

The Group's regulatory approvals passed a critical juncture with the approval of the Group's FDP in September 2017. This was the culmination of a period of extensive engagement both directly with regulators and with other stakeholders, including via a public consultation on the Environmental Statement.

The FDP approval for the EPS was the first approval for a standalone development in the UKCS since Culzean in 2015. It is also the first ever approval of a basement development in the UK. The ability of the project to reach sanction whilst so few other developments are doing so illustrates the attractiveness of the Lancaster field and of fractured basement on the Rona Ridge as a whole.

We would like to extend our thanks to the Oil and Gas Authority, the Department for Business, Energy, Industrial Strategy, and the Health and Safety Executive and all other consultees for their support in Hurricane progressing to this stage.

Development progress

Hurricane's progress towards first oil on the EPS is unmistakeably evident at Dubai Drydocks World, the yard selected by Bluewater for the upgrade and life extension of the Aoka Mizu and the fabrication of the buoy for the turret mooring system. The Aoka Mizu FPSO arrived at the facility on 30 September 2017 and has already undergone its two planned drydock phases and a significant portion of additional work. The buoy has been fabricated in parallel and following the success of trial fit operations in February, is expected to depart Dubai for Lerwick on the Shetland Isles in order to arrive by the end of H1 2018.

Hurricane has permanent representatives onsite in Dubai and has been pleased with the standard of safety and operations at the facility. Together with Bluewater, Hurricane has operated an HSSEQ incentive programme and is pleased with the number of awards and overall HSSEQ performance to date. The vessel remains on track for sail away to the field by the end of Q3 2018.

Progress towards subsea installation by TechnipFMC and its subcontractors has also been substantial. The second of the two horizontal Xmas trees and associated structures were delivered ex-works in March 2018 and fabrication of the umbilical, risers and flowlines remains on schedule. Following a programme of boulder relocation during 2017, ahead of schedule, everything remains on track for summer 2018 installation.

Hurricane has shown that it has an effective working relationship with Petrofac Facilities Management Limited and Transocean on previous drilling campaigns, and is looking forward to using the Paul B. Loyd Jr. rig for well completions later this year.

Future operations

In parallel with the focus on delivering first oil from the EPS, Hurricane's well operations teams continue to work closely with Hurricane's subsurface team to study future well opportunities, whilst the facilities engineering team are engaged in looking at future gas export and tie-back options, FPSO debottlenecking opportunities and performance improvements from the existing EPS design.

Financial Review

Overview

In 2017, Hurricane transitioned from being a pure exploration and appraisal company to one that is undertaking a significant development project and fast approaching first oil. Having raised the required funding and taken FID on the EPS, the Group is now looking forward to organic cash generation.

The first half of the year was focussed on positioning the Group to be able to take FID. To this end the Group raised a total of $547 million in two fund raises (before expenses). The first of which, occurring in May 2017, raised $17 million enabling the Group to maintain the existing schedule for the EPS and continue to drive towards FID. The more significant raise, in July 2017, raised a total of $530 million, split between $300 million of equity and $230 million of convertible bonds. This was one of the key requirements allowing the Group to take FID in the second half of the year. The raise was an outstanding achievement for a company of Hurricane's size, particularly in the prevailing oil price environment.

As the Group worked through the EPS contracting strategy in 2017, we were able to agree lump sum prices for the majority of the capital expenditure. Over 75% of the total EPS capital costs are fixed, with the risk of overruns lying with the contractor. This has enabled Hurricane to manage the risk of cost overruns, limiting it mainly to the subsea and mooring installation phase of the project. The project remains on budget and on schedule with first oil, and the related cash inflows, expected in H1 2019.

Throughout the year, and into early 2018, the foreign exchange rate between the Pound Sterling (GBP) and the US Dollar (USD) has fluctuated significantly. The contracting strategy adopted for the EPS has allowed us to reliably forecast the project expenditure in both GBP and USD. Therefore, the Group purchased the required USD at the time of the July capital raise in order to match our currency exposures and thereby mitigate the foreign currency risk on the project.

The Group's loss after tax for the year was $7.0 million (2016: profit after tax $0.9 million). This loss was driven by increased operating expenses, predominantly related to increased corporate activity, and write-offs/impairments connected with our non-core assets. These charges were partially offset by a fair value gain on derivative financial instruments related to the Convertible Bond and foreign exchange gains.

At the beginning of 2017, the functional currency for each entity and the presentation currency for the Group as a whole was reviewed. Due to the increase in the Group's level of expenditure in USD and the upcoming start of production on the EPS, the revenues for which will be denominated in USD, the functional currency of many of the entities within the Group was changed to be USD. The presentation currency for the consolidated accounts has also been changed to USD which will also improve the ability to compare the Group's financial results with other companies within the oil and gas industry. This has led to a restatement of prior period comparatives and a $(92.7) million foreign exchange reserve being recognised within equity on the Balance Sheet.

Our principal financial goals are to manage the existing funds held by the Group to deliver the EPS on schedule and on budget. This will bring us to the point where the EPS begins to generate free cash which can be directed to deliver the Group's long-term strategy.

Use of funds

In 2017 the Group's primary use of funds were:

i.     Halifax exploration well, $30.9 million - drilled in Q1, discovering oil in the Halifax prospect;

ii.    Development expenditure on the EPS, $234.8 million - this includes the pre- and post-FID expenditure incurred in the year;

iii.   Operating cash outflow, $8.1 million (2016: $5.6 million) - this increase on the prior year reflects the increase in the level of activity through the year, including the preparation for the fund raising and the additional work undertaken as the Group evolves into a larger entity; and

iv.   Convertible Bond coupon payments, $4.3 million.

Income Statement

The Group's loss after tax for the year is $7.0 million (2016: profit after tax $0.9 million). The loss for the year was partly driven by increased operating expenses, but also impacted by foreign exchange gains of $8.0 million due to the strengthening of Sterling against the US dollar, a fair value gain on derivative financial instruments related to the Convertible Bond and the write-off of the relinquished Typhoon and Tempest exploration and evaluation assets and the full impairment of the Strathmore asset.

The increase in other operating expenses from $8.9 million in 2016 to $14.6 million in 2017 reflects the increased level of corporate activity in the year and the work done in preparation for the fund raising. Whilst the average headcount has increased from 15 to 21 since the prior year, the overall cash staff cost (excluding share based payment expense) is largely unchanged (2017: $5.2 million, 2016 $5.6 million, both before amounts capitalised).

The accounting for the Convertible Bond (issued in July 2017) required the recognition of an embedded derivative related to the deemed equity conversion option. The fair value of this embedded derivative was calculated on the date of issue of the bonds and at the 31 December 2017. The movement of $10.4 million in this fair value has been recognised as a gain in the Income Statement in the year. Transaction costs relating to the Convertible Bond have been apportioned between the host debt contract and the embedded derivative. Those transactions costs apportioned to the embedded derivative have been recognised in the Income Statement ($1.2 million). Interest costs of $10.4 million for the Convertible Bond during the year have been capitalised.

In December 2017, the Group took the decision to relinquish the Typhoon and Tempest licences to focus both time and funds on its Rona Ridge assets. As a direct consequence the related capitalised assets (within intangible exploration and evaluation assets) have been written off. In addition to this, the Group has also fully impaired the carrying value of its Strathmore asset as there are no plans to undertake any significant activity on this prospect in the near future. The $10.4 million write off / impairment is not a cash cost in the year but is included as an expense in the Income Statement.

Due to the nature of the Group's business, it has accumulated significant tax losses since incorporation. Upon receipt of FDP approval in September 2017, for tax purposes, the Group is considered to have commenced trading. This has crystallised the pre-trading revenue expenses of $21.6 million (2016: $23.9 million), covering the period from 2011 onwards, and pre-trading capital expenditure of $191.1 million (2016: $257.1 million) which was available for tax relief on commencement of trade for UK tax purposes. Additional pre-trading capital expenditure of $83.5 million is carried forward at 31 December 2017 and tax relief will be available once the FDP approval is received on the remaining licences. The Group has trading losses of $393.6 million at 31 December 2017, which would be available for offset against future trading profits. A potential Ring Fence Expenditure Supplement claim could also be made which would result in additional trading losses of $65.0 million.

No asset has been recognised in the Financial Statements for a potential deferred tax asset, at the UK ring-fence tax rate of 40%, of $16.1 million (2016: $12.4 million) resulting from the effect of carried forward trading losses, after offsetting $141.2 million (2016: $11.2 million) against a deferred tax liability. The directors have concluded it is not appropriate to recognise any of the potential deferred tax asset until the EPS has begun production and hence demonstrated an ability to generate taxable profits.

Exploration and evaluation assets and property, plant and equipment

In September 2017 the Group obtained FDP approval from the Oil and Gas Authority and as such reclassified $335.9 million, being all intangible exploration and evaluation assets that related to the Lancaster Field, to property, plant and equipment. Following this reclassification, a further $109.4 million was included in property, plant and equipment relating to the EPS.

In total, additional expenditure of $169.1 million was included in intangible exploration and evaluation assets in the year relating to the drilling of the Halifax well and pre-FDP expenditure on the EPS. Taking into account the reclassification of Lancaster assets to property, plant and equipment and the write off / impairment of Typhoon/Tempest and Strathmore has resulted in an overall decrease in the Group's intangible exploration and evaluation assets of $176.1 million.

Cash and debt

The Group finished the year with a closing cash position of $326.6 million in usable funds (including cash and cash equivalents and liquid investments, but excluding cash held in escrow accounts). The mid-year capital raise included the issue of $230 million in convertible bonds with a coupon of 7.5% per annum. Under the terms of the Convertible Bond, the first two years of coupon payments have been placed in escrow, of which $4.3 million was paid out by the year-end. The maturity date of the Convertible Bond is July 2022, although bond holders have the option to convert the bonds to Ordinary Shares before that time. The initial conversion price on the bonds was set at $0.52, representing a 25% premium to the share price fixed at the time of issue (being £0.32 converted into USD at a rate of $1.30).

The Convertible Bond is recorded on the Balance Sheet, and is split between the host debt contract and the embedded derivative related to the equity conversion option. At the Balance Sheet date the fair value of the embedded derivative was $28.6 million and the carrying value of the host debt contract at amortised cost was $191.1 million. The Group recognised a $10.4 million gain on derivative financial instruments from the Convertible Bond's issue to the balance sheet date.

Cash flow

Net cash outflow from operating activities of $8.1 million is an increase from $5.6 million in 2016, largely due to the increase in the level of activity through the year. This included the preparation for the fund raising and the additional work undertaken as the Group evolves into a larger entity. The combined expenditure on intangible exploration and evaluation assets and property, plant and equipment in the year of $265.7 million (2016: $63.5 million) was primarily the expenditure on the EPS and the Halifax well.

The net cash provided by financing activities was $524.4 million. This was from the capital raises in May and July and the Convertible Bond issue in July. This was partly offset by the first quarterly coupon payment on the Convertible Bond of $4.3 million.

The net increase in cash, cash equivalents, and liquid investments in the year was $258.5 million (including the effects of foreign exchange rate changes).

Going concern and long-term viability

The directors have considered both the going concern of the Group and its long-term viability (LTV). Based on their assessment (see details of going concern in note 2 below), the directors have a reasonable expectation that the Group will be able to continue and meet its liabilities as they fall due for the periods shown.

Alistair Stobie

Chief Financial Officer

Group Statement of Comprehensive Income

			Year Ended		Year Ended
	Notes		31 Dec 2017		31 Dec 20161
			$'000		$'000
Write off / impairment of intangible exploration and evaluation assets	5		(10,412)		-
Other operating expenses			(14,586)		(8,865)
Operating loss			(24,998)		(8,865)
Interest income			880		89
Foreign exchange gains			8,020		2,493
Finance costs			(1,322)		(88)
Fair value gain on derivative financial instruments			10,416		-
Loss before tax			(7,004)		(6,371)
Tax			-		7,272
(Loss) / profit for the period			(7,004)		901
Exchange difference on translation			-		(56,330)
Total comprehensive loss			(7,004)		(55,429)
(Loss) / Earnings per share, basic and diluted	3		(0.46 cents)		0.10 cents

1. Balances have been restated to US Dollars. See Note 2.2 for details

All of the Group's operations are classed as continuing.

Group Balance Sheet

	Notes		31 Dec 2017		31 Dec 20161		1 Jan 20161
			$'000		$'000		$'000
Non-current assets
Property, plant and equipment	4		445,291		18		133
Intangible exploration and evaluation assets	5		126,365		302,539		260,555
Other receivables			202		161		193
Other non-current assets	6		16,089		2,875		3,431
			587,947		305,593		264,312
Current assets
Inventory			1,434		443		607
Trade and other receivables			4,737		7,273		622
Liquid investments	6		201,973		-		-
Cash and cash equivalents	6		141,956		98,607		11,284
			350,100		106,323		12,513
Total assets			938,047		411,916		276,825
Current liabilities
Trade and other payables			(28,833)		(26,338)		(401)
Derivative financial instruments			(11)		-		-
			(28,844)		(26,338)		(401)
Non-current liabilities
Convertible loan liability	7		(191,102)		-		-
Derivative financial instruments	7		(28,622)		-		-
Decommissioning provisions			(7,023)		(5,959)		(4,768)
Total liabilities			(255,591)		(32,297)		(5,169)
Net assets			682,456		379,619		271,656
Equity
Share capital			2,843		1,860		1,082
Share premium			813,496		508,510		347,815
Share option reserve			19,477		15,648		12,876
Own shares held by SIP Trust			(323)		(366)		(314)
Equity shares to be issued			-		-		801
Foreign exchange reserve			(92,659)		(92,659)		(36,329)
Accumulated deficit			(60,378)		(53,374)		(54,275)
Total equity			682,456		379,619		271,656

1. Balances have been restated to US Dollars. See Note 2.2 for details

Group Statement of Changes in Equity

	Share capital		Share premium		Share option reserve		Own shares held by SIP Trust		Equity Shares to be issued		Foreign exchange reserve		Accumulated deficit		Total
	$'000		$'000		$'000		$'000		$'000		$'000		$'000		$'000
At 1 January 20161	1,082		347,815		12,876		(314)		801		(36,329)		(54,275)		271,656
Shares allotted	778		160,695		-		-		-		-		-		161,473
Share options charge	-		-		2,772		-		-		-		-		2,772
Own shares held by SIP Trust	-		-		-		(52)		-		-		-		(52)
Equity shares to be issued	-		-		-		-		(801)		-		-		(801)
Profit for the period	-		-		-		-		-		-		901		901
Other comprehensive loss for the period			-		-		-		-		(56,330)		-		(56,330)
At 31 December 20161	1,860		508,510		15,648		(366)		-		(92,659)		(53,374)		379,619
Shares allotted	983		319,873		-		-		-		-		-		320,856
Transaction costs	-		(14,887)		-		-		-		-		-		(14,887)
Share option charge	-		-		3,829		-		-		-		-		3,829
Own shares held by SIP Trust	-		-		-		43		-		-		-		43
Loss for the period	-		-		-		-		-		-		(7,004)		(7,004)
At 31 December 2017	2,843		813,496		19,477		(323)		-		(92,659)		(60,378)		682,456

1. Balances have been restated to US Dollars. See Note 2.2 for details

The share option reserve arises as a result of the expense recognised in the income statement to account for the cost of share-based employee compensation arrangements.

Group Cash Flow Statement

			Year Ended		Year Ended
	Notes		31 Dec 2017		31 Dec 20161
			$'000		$'000
Net cash outflow from operating activities	8		(8,088)		(5,577)
Investing activities
Interest received			885		78
Increase in liquid investments2			(201,973)		-
Expenditure on property, plant and equipment			(85,062)		(17)
Expenditure on intangible exploration and evaluation assets			(180,612)		(63,459)
Expenditure on inventory			(991)		-
Net cash used in investing activities			(467,753)		(63,398)
Financing activities
Interest paid / bank charges			(15)		(5)
Net proceeds from borrowings3			223,095		-
Additional borrowing transaction costs3			(303)		-
Interest payments (Convertible Bond)			(4,313)		-
Net proceeds from issue of share capital and warrants4			313,895		162,474
Additional equity issue transaction costs4			(7,976)		(1,739)
Deferred bonus arrangements settled in cash			-		(253)
Net cash provided by financing activities			524,383		160,477
Net increase in cash and cash equivalents			48,542		91,502
Cash and cash equivalents at the beginning of the period5			101,482		14,715
Net increase in cash and cash equivalents			48,542		91,502
Effects of foreign exchange rate changes			8,021		(4,735)
Cash and cash equivalents at the end of the period5	6		158,045		101,482

1.     Balances have been restated to US Dollars. See Note 2.2 for details.

2.     Liquid investments comprise short term liquid investments of between 3 and 12 months maturity while cash and cash equivalents comprise cash at bank and other short term highly liquid investments of less than three months maturity. The combined cash and cash equivalents and liquid investments balance at 31 December 2017 was $360,018,000 (2016: $101,482,000)

3.     Total transaction costs relating to borrowings were $7,208,000 (2016: $nil) of which $6,905,000 (2016: $nil) were netted off against gross proceeds of $230,000,000 (2016: $nil).

4.     Total transaction costs relating to equity raises were $14,887,000 (2016: $6,691,000) of which $6,911,000 (2016: $4,952,000) were netted off against gross proceeds of $320,806,000 (2016: $167,426,000).

5.     Cash and cash equivalents includes $16,089,000 (2016: $2,875,000) of cash held in escrow which has been included in the Balance Sheet in other non-current assets.

Notes to the Consolidated Financial Information

1.    General information

The financial information set out above does not constitute the Company's statutory accounts for the years ended 31 December 2017 or 2016, but is derived from those accounts. A copy of the statutory accounts for 2016 has been delivered to the Registrar of Companies and those for 2017 will be delivered following the Company's annual general meeting. The auditors have reported on those accounts; their reports were unqualified, did not draw attention to any matters by way of emphasis without qualifying their report and did not contain statements under section 498(2) or (3) of the Companies Act 2006. Whilst the financial information included in this announcement has been computed in accordance with International Financial Reporting Standards (IFRS), this announcement does not itself contain sufficient information to comply with IFRS. The financial statements are presented in US Dollars.

2.    Significant accounting policies

2.1 Basis of preparation and going concern

The financial information has been prepared under the historical cost convention, except for share-based payments and financial instruments, in accordance with International Financial Reporting Standards as adopted by the European Union (IFRS), and in accordance with the requirements of the AIM Rules.

The Group has no source of operating revenue prior to first oil from the EPS (currently anticipated to occur in H1 2019) and currently obtains working capital primarily through equity and debt financing. During the year, the Group raised gross funds of $547 million (before expenses), split between $317 million of Ordinary Shares in the Company and $230 million from the issue of convertible bonds.

The Directors have performed a robust assessment, including a review of the budget for the year ending December 2019 and longer-term strategic forecasts and plans, including consideration of the principal risks faced by the Company. In particular, the Directors considered a number of scenarios which included the impact of a delay in first oil from the Lancaster EPS, cost and schedule overruns during the installation period and, following first oil, downside sensitivities in relation to production rates, operational uptime, oil price, operating expenditure and foreign exchange rates. Following this review, the Directors are satisfied that, taking into consideration reasonably foreseeable downside sensitivities, the Company and the Group have adequate resources to continue to operate and meet their liabilities as they fall due for the foreseeable future, a period considered to be at least twelve months from the date of approving this Financial Information. For this reason, they have prepared the financial information on a going concern basis.

2.2 Changes in functional and presentation currency

On 1 January 2017, the functional currency of Hurricane Energy plc changed from Pounds Sterling to US Dollars. This change was triggered by the intention to proceed with the EPS in 2017 which will lead to an increased level of expenditure being incurred in US Dollars and ultimately the receipt of revenues which are expected to be almost exclusively in US Dollars.

On 1 January 2017, the presentation currency of Hurricane Energy plc was also changed from Pounds Sterling to US Dollars.

The change in presentation currency is to better reflect the Group's business activities and to improve investors' ability to compare the Company's financial results with other publicly traded businesses in the oil and gas industry. In making this change to the US Dollar presentation currency, the Company followed the guidance in IAS 21 The Effects of Changes in Foreign Exchange Rates and have applied the change retrospectively. For the 2016 comparative balances, assets and liabilities have been restated into the presentation currency (US Dollars) at the rate of exchange prevailing at the respective Balance Sheet date, with equity balances restated at historical rates on the date of issue of said equity instrument. The comparative income statements and cash flow statements were restated at the average exchange rates for the reporting period. The average rates for the reporting period approximated the exchange rates as at the date of the transactions. Exchange differences arising on translation were taken to the foreign exchange reserve in shareholders' equity. The Company has presented a third statement of financial position as at 1 January 2016 in accordance with IAS 8 Accounting Policies, Changes in Accounting Estimates and Errors. The resulting effect of the change in presentation currency of $92,659,000 on the comparative figures is reflected in the foreign exchange reserve.

Exchange rates used	USD / GBP 1.355 1.480 1.234
Year ending 31 December 2016 average rate
Spot rate at 1 January 2016
Spot rate at 31 December 2016

3.    Earnings per Share

The basic and diluted (loss) / earnings per share has been calculated using the loss for the year ended 31 December 2017 of $7,004,000 (2016: profit for the year of $901,000). The loss per share is calculated using a weighted average number of Ordinary Shares in issue less treasury shares.

	Year Ended		Year Ended
	31 Dec 2017		31 Dec 20161
	$'000		$'000
(Loss) / profit after tax	(7,004)		901
	Number of shares		Number of shares
Weighted average shares in issue (basic)	1,583,803,716		889,529,040
Effect of dilutive potential Ordinary Shares:
Warrants	-		15,022,831
Weighted average shares in issue (diluted)	1,583,803,716		904,551,871
	Cents		Cents
(Loss) / earnings per share (basic and diluted)	(0.46)		0.10

1. Balances have been restated to US Dollars. See Note 2.2 for details

The effective of the warrants, options and Convertible Bond outstanding in 2017 was anti-dilutive as the Group incurred a loss and all interest on the Convertible Bond was capitalised.

4.    Property, plant and equipment

	Oil and gas properties		Other fixed assets		Total
	$'000		$'000		$'000
Cost
At 1 January 20161	-		979		979
Additions	-		16		16
At 31 December 20161	-		995		995
Additions	109,381		58		109,439
Transfer from intangible assets	335,856		-		335,856
At 31 December 2017	445,237		1,053		446,290
Depreciation
At 1 January 20161	-		(869)		(869)
Charge for the year	-		(108)		(108)
At 31 December 20161	-		(977)		(977)
Charge for the year	-		(22)		(22)
At 31 December 2017	-		(999)		(999)
Carrying amount at 31 December 20161	-		18		18
Carrying amount at 31 December 2017	445,237		54		445,291

1. Balances have been restated to US Dollars. See Note 2.2 for details

Property, plant and equipment (other fixed assets) comprises the Group's investment in leasehold improvements, fixtures, office equipment and computer hardware. In 2017 $nil (2016: $58,000) of depreciation has been capitalised into the Group's intangible exploration and evaluation expenditure in accordance with the Group's overhead allocation policy.

On 24 September 2017 approval was granted for the EPS field development. As a result, $335,856,000 of intangible exploration and evaluation assets were reclassified as property, plant and equipment.

Depreciation of the oil and gas properties will commence once production begins and will be on a unit of production (UOP) basis.

Included within additions is $6,039,000 of borrowing costs that have been capitalised in the year (see note 7).

Included within transfer from intangible assets is $4,409,000 of borrowing costs that were previously capitalised within intangible exploration and evaluation assets.

5.    Intangible exploration and evaluation assets

	Year Ended		Year Ended
	31 Dec 2017		31 Dec 20161
	$'000		$'000
At 1 January	302,539		260,555
Effects of translation of currency	-		(43,336)
Additions	169,113		83,411
Effects of additions / changes to decommissioning estimates	981		1,909
Impairment of intangible exploration and evaluation assets	(1,971)		-
Write off of intangible exploration and evaluation assets	(8,441)		-
Transfer to property, plant and equipment	(335,856)		-
At 31 December	126,365		302,539

1. Balances have been restated to US Dollars. See Note 2.2 for details

Intangible exploration and evaluation expenditure comprises the book cost of licence interests and exploration and evaluation expenditure within the Group's licensed acreage in the West of Shetlands.

On 24 September 2017 approval was granted for the EPS field development. As a result, $335,856,000 of intangible assets were reclassified as Oil and Gas properties in property, plant and equipment.

Included within additions, and also within the transfer to property, plant and equipment, is $4,409,000 of borrowing costs that have been capitalised in the year (see note 7).

The directors have fully considered and reviewed the potential value of licence interests, including carried forward exploration and evaluation expenditure. The directors have considered the Group's tenure to its licence interests, its plans for further exploration and evaluation activities in relation to these and the likely opportunities for realising the value of the Group's licences, either by farm-out or by development of the assets. Given the Group's focus on its Rona Ridge assets, and the fact that it has no current plans to drill on its Strathmore prospect in the near future, the directors have fully impaired the intangible exploration and evaluation assets relating to Strathmore, being $1,971,000.

On the 8 December 2017 the Group relinquished its P1485 and P1835 licences (Typhoon and Tempest). As such the intangible exploration and evaluation assets relating to those licences of $8,441,000 have been fully written off.

6.    Cash and cash equivalents and liquid investments

	31 Dec 2017		31 Dec 20161		1 Jan 20161
	$'000		$'000		$'000
Unrestricted funds	124,629		89,275		11,284
Current restricted funds	17,327		9,332		-
Current cash and cash equivalents	141,956		98,607		11,284
Non-current restricted funds	16,089		2,875		3,431
Total cash and cash equivalents	158,045		101,482		14,715
Liquid investments	201,973		-		-
Total cash and cash equivalents and liquid investments	360,018		101,482		14,715

1. Balances have been restated to US Dollars. See Note 2.2 for details

At 31 December 2017 the current restricted funds of $17,327,000 (2016: $9,332,000) are held in escrow relating to coupon payments under the terms of the Convertible Bond and for future expected costs related to the current EPS project. The amounts held in escrow can only be withdrawn on the consent of both the relevant third party and the Company.

At 31 December 2017 $3,151,000 (2016: $2,875,000) of the non-current restricted funds are held in escrow for future expected costs associated with the Group's decommissioning obligations. $12,938,000 (2016: $nil) of the non-current restricted funds are held in escrow relating to coupon payments under the terms of the Convertible Bond. The amounts held in escrow can only be withdrawn on the consent of both the relevant third party and the Company. These funds have been included in the Balance Sheet in other non-current assets.

Liquid investments comprise short term liquid investments of between 3 and 12 months maturity (fixed term deposit accounts) to take advantage of higher interest rates. Cash and cash equivalents comprise cash at bank and other short term highly liquid investments of less than three months maturity.

7.    Borrowings

In July 2017 the Group raised $230 million (gross) from the successful placement of the Convertible Bond. The Convertible Bond was issued at par and 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 USD/GBP 1.30). Unless previously converted, redeemed or purchased and cancelled, the Convertible Bond will be redeemed at par on 24 July 2022.

The Convertible Bond contains a covenant relating to a restriction on incurrence of indebtedness. This restriction shall not apply in respect of:

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

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

·     any permitted indebtedness, being:

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

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

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

The conversion feature of the Bonds is classified as an embedded derivative liability as the Bonds can be settled by the Group in cash and hence does not meet the 'fixed for fixed' criteria for a compound instrument outlined in IAS 39. It has therefore been measured at fair value through profit and loss. The amount recognised at inception in respect of the host debt contract was determined by deducting the fair value of the conversion option at inception (the embedded derivative) from the fair value of the consideration received for the convertible loan notes. The debt component is then recognised at amortised cost, using the effective interest method until extinguished upon conversion or at the instrument's maturity date.

				Year Ended		Year Ended
				31 Dec 2017		31 Dec 2016
				$'000		$'000
Proceeds of issue of Convertible Bond				230,000		-
Transaction costs				(7,208)		-
Net proceeds on issue of convertible loan notes				222,792		-
Transaction costs relating to liability component				5,984		-
Transaction costs relating to derivative liability				1,224		-
Total transaction costs				7,208		-
Liability component at date of issue (net of transaction costs)				(184,967)		-
Interest charged				(10,448)		-
Interest paid				4,313		-
Liability at 31 December				(191,102)		-
Derivative liability at date of issue				(39,049)		-
Change in fair value recognised in the income statement				10,427		-
Derivative liability at 31 December				(28,622)		-

The interest expensed in the year is calculated by applying an effective interest rate of 13.5% to the liability component from 24th July to 31st December. The liability component is measured at amortised cost. The difference between the carrying amount of the liability component at the date of issue and the amount reported in the balance sheet at 31 December 2017 represents the interest charged at the effective interest rate less interest paid to that date. All of the interest charge has been capitalised within property, plant and equipment as it is considered to relate to the development of the Lancaster Field, a qualifying asset.

At inception and at the Balance Sheet date, the fair value of the embedded derivative contained within the Convertible Bond was calculated based on the conversion option contained within. 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 derivatives that are a part of the Convertible Bond issue have been assessed to be a Level 3 financial liability. This is because the derivatives themselves are not traded on an active market and their fair values are determined by a valuation technique that uses one key input that is not based on observable market data, being share price volatility.

Volatility is a key input in the valuation of the Convertible Bond embedded derivative. Volatility is a measure of the variability or uncertainty in return for a given underlying derivative. It represents an estimate of how much a particular instrument, parameter or index (in this case share price) will change in value over time. The valuation technique was based on a simulation model and the volatility was calculated as a blended average of the trading history of the Group's own shares and shares in a relevant peer group, for a period of 6 months prior to the measurement date.

The fair value calculation at 31 December 2017 used a share price volatility assumption of 23.6%. A 5% increase to 28.6% would cause a $7.4 million increase in the fair value recognised at 31 December 2017. A 5% decrease in the share price volatility to 18.6% would cause a decrease of $7.2 million in the fair value. As movements in the fair value are recognised directly in the income statement these changes would directly affect the profit after tax by the same amount.

8.    Reconciliation of operating costs to net cash outflow from operating activities

	Year Ended		Year ended
	31 Dec 2017		31 Dec 20161
	$'000		$'000
Operating loss	(24,998)		(8,865)
Adjustments for:
Depreciation of property, plant and equipment	22		54
Impairment / write off of intangible exploration and evaluation assets	10,412		-
Share based payment charge	3,922		2,827
Operating cash outflow before working capital movements	(10,642)		(5,984)
Increase in receivables	(3,370)		(1,046)
Increase in payables	64		542
Cash used in operating activities	(13,948)		(6,488)
Corporation tax received2	5,860		911
Net cash outflow from operating activities	(8,088)		(5,577)

1.     Balances have been restated to US Dollars. See Note 2.2 for details

2.     Corporation tax received is a research and development tax credit claimed under the SME Research & Development tax relief scheme.

Changes in liabilities arising from financing activities during the year were as follows:

	1 Jan 2017		Cash flows		Fair value gains		Interest charges		Transaction costs expensed		31 Dec 2017
	$'000		$'000		$'000		$'000		$'000		$'000
Convertible loan liability	-		180,654		-		10,448		-		191,102
Derivative financial instruments	-		37,825		(10,416)		-		1,224		28,633
Total financing related liabilities	-		218,479		(10,416)		10,448		1,224		219,735

9.    Capital Commitments

As at 31 December 2017 the group had capital commitments of $199.7 million (2016: $7.4 million).

10.  Subsequent Events

Share incentive plan

On 24 January 2018, Global Shares Trustee Company Limited (formally MM&K Plan Trustees Limited), trustee of the HMRC approved Hurricane Energy plc SIP, awarded 474,006 Ordinary Shares to participants in the SIP at a price of £0.39 per share. The SIP award has been satisfied by the issue of 341,301 new Ordinary Shares issued to the SIP at a subscription price of £0.39 per share plus 132,705 Ordinary Shares already held in the plan.

 

END

 

 

FR SSUESUFASELL