Rockhopper Regulatory News (RKH)

19 April 2018 

Rockhopper Exploration plc

("Rockhopper" or the "Company")

Full-year results for the year ended 31 December 2017

Rockhopper Exploration plc (AIM: RKH), the oil and gas company with key interests in the North Falkland Basin and the Greater Mediterranean region, is pleased to announce its audited results for the year ended 31 December 2017.

2017 Highlights

Funding package for the Sea Lion Phase 1 development progressing; working towards final investment decision by year end 2018

· Estimated capex to first oil reduced from US$1.8 billion to US$1.5 billion

· Life of field costs down to less than US$35 per barrel

· Letters of Intent signed with contractors for a range of services and vendor financing

· Discussions progressing with senior debt providers including commercial banks and export credit agencies

· Field Development Plan substantially agreed with the Falkland Islands Government

· Environmental Impact Statement public consultation process completed

Building a material production base in the Greater Mediterranean to maintain balance sheet strength and fund future growth

· Material increase in production - net working interest production averaged 1.2 kboepd in 2017 (2016: 0.8 kboepd)

· Revenue up 40% to US$10.4 million (2016: US$7.4 million)

· Cash operating costs of US$9.5 per boe - maintaining a low cost base

· Continued management of G&A costs - US$5.3 million - down over 50% in 3 years

· G&A costs covered by operating cash flows

· Sale of non-core interests in Italy - US$9.5 million of future decommissioning costs removed from balance sheet upon completion

· Initiated international arbitration against Republic of Italy to seek significant monetary damages in relation to Ombrina Mare

· Balance sheet strength maintained with cash resources of US$51 million at 31 December 2017 and no debt

Outlook

· Progress Sea Lion towards final investment decision by year end 20181

· Four well drilling campaign in Egypt to commence in Q2 2018

· Ombrina Mare arbitration hearing date set for early February 2019

· Continued pursuit of new venture opportunities to add production and cash flow

1 Operator estimate 

David McManus, Chairman of Rockhopper, commented:

"Significant progress has been made in 2017 to advance and execute the contracting strategy and financing plan for the Sea Lion Phase 1 development.

"In the Greater Mediterranean, the Company has successfully established a portfolio that provides a low-cost, short-cycle production base which has delivered record revenues and operating cash flows in 2017 and more than covered the Group's substantially reduced G&A costs. On a highly selective basis, we continue to seek to further expand our Greater Mediterranean production base with the aim of generating additional free cash flow to invest in future exploration and value‐accretive growth opportunities both in the Falklands and elsewhere.

"As we advance through 2018, Rockhopper is highly focused on securing the funding required to be in a position to reach a final investment decision on the Sea Lion project by the end of the year and move into the development phase. With Brent oil prices currently above US$70 per barrel, combined with the cost efficiencies secured through FEED and engagement with the contractors, the economics for the project are highly attractive."

Enquiries:

Rockhopper Exploration plc

Sam Moody - Chief Executive

Stewart MacDonald - Chief Financial Officer

Tel. +44 (0) 20 7830 9704 (via Vigo Communications)

Canaccord Genuity Limited (NOMAD and Joint Broker)

Henry Fitzgerald-O'Connor/James Asensio

Tel. +44 (0) 20 7523 8000

Peel Hunt LLP (Joint Broker)

Richard Crichton

Tel. +44 (0) 20 7418 8900

Vigo Communications

Patrick d'Ancona/Ben Simons

Tel. +44 (0) 20 7830 9704

Note regarding Rockhopper oil and gas disclosure

This announcement has been approved by Rockhopper's geological staff which includes Lucy Williams (Geoscience Manager) who is a Chartered Geologist, a Fellow of the Geological Society of London and a Member of both the Petroleum Exploration Society of Great Britain and American Association of Petroleum Geologists, with over 25 years of experience in petroleum exploration and management and who is the qualified person as defined in the Guidance Note for Mining, Oil and Gas Companies issued by the London Stock Exchange in respect of AIM companies.

The information contained within this announcement is deemed by the Company to constitute inside information as stipulated under the Market Abuse Regulations (EU) No. 596/2014 ("MAR").

CHAIRMAN AND CHIEF EXECUTIVE OFFICER'S REPORT

Rockhopper has made good progress across its portfolio in 2017, against a backdrop of challenging markets in the upstream oil and gas exploration and production sector, largely attributable to continued volatility in commodity prices.

Over the course of 2017, Rockhopper has continued to balance the progression of its world-class Sea Lion project in the North Falkland Basin with an ongoing focus on cost control.

Material progress has been made on Sea Lion Phase 1 - in which Rockhopper has a 40% working interest - on a range of commercial, fiscal and financing matters with the operator, Premier Oil, recently confirming that it is working towards a final investment decision by the end of 2018 with financial close expected in H1 2019.

Our Greater Mediterranean portfolio continues to meet its primary objective, namely to provide a production and cash flow base to fund our corporate and operating costs and protect our balance sheet. Balance sheet cash is preserved for capital investment, primarily in the Falkland Islands.

We maintain ambitions to further expand our Greater Mediterranean production base thereby generating additional free cash flow to invest in future exploration and value‐accretive growth opportunities both in the Falklands and elsewhere.

Funding package for the Sea Lion development progressing; operator working towards final investment decision by year end 2018

Front End Engineering and Design ("FEED") for the Sea Lion Phase 1 project was largely completed in 2016.

Following a comprehensive tendering exercise, across a range of supply chain contractors, conducted through 2017, estimated gross capex to first oil reduced from US$1.8 billion to US$1.5 billion with life-of-field costs (capex, opex and Floating Production Storage and Offloading ("FPSO") vessel lease) now estimated at less than US$35 per barrel.

Principal commercial terms for the provision of services and vendor financing have been agreed with selected preferred contractors and Letters of Intent ("LOIs") signed. Under the terms of the LOIs, an exclusivity period has been granted to each contractor during which the joint venture will negotiate binding documentation based on principles for the provision of both services and vendor financing. The joint venture is seeking approximately US$400 million of vendor financing from the preferred contractors.

In 2017, Portland Advisers, a specialist project finance adviser was appointed by the Sea Lion joint venture to support the financing process for the project. Discussions are advancing with a range of potential senior debt providers including export credit and commercial bank lenders.

Following a comprehensive commercial bank engagement process, a number of banks have indicated their desire to support the project and the appointment of a lead bank is expected shortly. In order to support the lender due diligence process, technical advisers for subsurface and environmental matters have been selected.

Engagement continues with the Falkland Islands Government ("FIG") on a range of environmental, fiscal and regulatory matters with a view to obtaining the consents and agreements necessary to be in a position to reach a final investment decision by the end of 2018. Following submission of a revised Field Development Plan ("FDP") to FIG in March 2018, the FDP is now considered substantially agreed. The Environmental Impact Statement ("EIS") public consultation process concluded in March 2018 with no material objections received. A number of constructive comments identified through the public consultation process will now be incorporated into the final EIS document for FIG's consideration and approval.

Building a material production base in the Greater Mediterranean to protect balance sheet and fund future growth

In our Greater Mediterranean portfolio, we have benefited from a material increase in production following the acquisition of a portfolio of interests in Egypt during the second half of 2016. Production during 2017 averaged 1.2 kboepd net to Rockhopper, a 50% increase over the prior period (2016: 0.8 kboepd). As a result of increasing production and revenue, and the measures taken to reduce costs (outlined below), operating cash flows more than covered the Group's general and administration ("G&A") costs during 2017.

In April 2017, the Company announced the commencement of a two‐well drilling campaign on the Abu Sennan concession in Egypt, in which Rockhopper has a 22% working interest. While it is disappointing that the Al Jahraa‐9 well was water‐wet, the deep oil shows were an encouraging indication of the additional potential at these deeper levels in other areas of the concession. The initial exploration target of the Al Jahraa SE‐2X well was dry but the side‐track confirmed oil pay and was put onto production at a tubular and pump constrained rate of approximately 250 boepd gross. A full review of the prospect and lead inventory for the Abu Sennan concession was completed in November 2017 which has high graded a number of targets for future exploratory drilling.

Additionally, through 2017 and the beginning of 2018, the Company has seen a material improvement in the payment situation in Egypt and a significant decline in outstanding receivables owed by Egyptian General Petroleum Corporation ("EGPC").

Rockhopper commenced international arbitration proceedings against the Republic of Italy in relation to the Ombrina Mare field in March 2017. A Request for Arbitration was formally lodged with the International Centre for Settlement of Investment Disputes ("ICSID") in April 2017 and the Procedural Hearing took place in November 2017. The Company submitted its memorial (our representations and evidence), witness statements and expert reports in December 2017 and the hearing has been scheduled for early February 2019. Rockhopper believes it has strong prospects of recovering very significant monetary damages - on the basis of lost profits - as a result of the Republic of Italy's breaches of the Energy Charter Treaty. All costs associated with the arbitration are funded on a non-recourse ("no win - no fee") basis from a specialist arbitration funder.

Portfolio management and corporate cost reduction initiatives

Over the last three years, a corporate cost reduction programme has been implemented across the Group which has resulted in a decline of more than 50% in the Group's net G&A cost. In 2017, G&A costs were reduced to US$5.3 million compared with US$7.4 million in 2016, US$9.4 million in 2015 and US$10.8 million in 2014.

In June 2017, the Company announced the disposal of a portfolio of non-core interests onshore Italy to Cabot Energy plc. The rationale for the transaction was to streamline the Group's Italian interests, focus on material assets, remove future decommissioning liabilities and further right-size our cost base. The transaction is now expected to complete during 2018.

Board changes

In July 2017, Fiona MacAulay, Chief Operating Officer, stepped down from the Board to take up the role of Chief Executive Officer of an AIM‐listed exploration company. The Board thanks Fiona for her significant contribution to the Company and we wish her well in her new role. Fiona's day‐to‐day responsibilities have been assumed by senior members of the Company's technical team, namely, Alun Griffiths (Petroleum Engineering Manager and Falkland Asset Manager), Lucy Williams (Geoscience Manager) and Paul Culpin (Development Manager). Alun has worked with Rockhopper since 2010, while Lucy and Paul have worked with Rockhopper since 2011; and each has over 25 years of oil and gas industry experience in their respective fields.

John Martin, previously chairman of FOGL, has elected to step down at the forthcoming AGM, in order to pursue his other business interests. Given our focus on corporate costs, we are content with the size of the reduced board and there is no current intention to replace either John or Fiona.  We thank John for his significant contribution to the Company over the last two years.

Outlook

2018 has the potential to be transformational for Rockhopper with all efforts focused on securing the funding required to sanction the Sea Lion project and move into the development phase.

With Brent oil prices currently above US$70 per barrel, combined with the cost efficiencies secured through FEED and engagement with the contractors, the economics for the project are highly attractive.

Our Greater Mediterranean portfolio, which can be characterised as low-cost and short-cycle, provides more than the necessary operating cash flow to fund corporate costs while providing low-risk exploration upside opportunities. The Board believes that this production and cash flow, when combined with our continued focus on costs, helps secure the long-term sustainability of the Company. On a highly selective basis, we seek to further expand our Greater Mediterranean production base with the aim of generating additional free cash flow to invest in future exploration and value‐accretive growth opportunities both in the Falklands and elsewhere.

David McManus Samuel Moody

Chairman Chief Executive Officer

18 April 2018 

OPERATIONS REVIEW

Sea Lion, North Falkland Basin

Following the Company's acquisition of FOGL in early 2016, Rockhopper became the leading acreage holder in the North Falkland Basin with a material working interest in all key licences.

The overall strategy to develop the North Falkland Basin remains a phased development solution, starting with Sea Lion Phase 1, which will develop 220 mmbbls in PL032 (in which Rockhopper has a 40% working interest). A subsequent Phase 2 development will recover a further 300 mmbbls from the remaining resources in PL032 and the satellite accumulations in the north of PL004 (in which Rockhopper has a 64% working interest). In addition, there is a further 200 mmbbls of low risk, near field exploration potential which could be included in either the Phase 1 or Phase 2 developments. Phase 3 will entail the development of the Isobel/Elaine fan complex in the south of PL004, subject to further appraisal drilling.

The resources in Sea Lion Phase 1 will be commercialised utilising a conventional FPSO development scheme with approximately 23 wells. Through the FEED process, which commenced in January 2016 and which is substantially complete, the joint venture team of Premier Oil ("Premier") and Rockhopper have worked collaboratively to support and challenge the design specifications and installation methodology leading to significant savings to both capital and operating costs. Significant reductions in estimates of field support services, including supply boats, helicopters and shuttle tankers have been seen and, as a result, estimates for field operating costs were reduced to less than US$15 per bbl, down from over US$20 per bbl. Estimated gross capex to first oil is US$1.5 billion.

Through 2017, work focused on securing agreements with key supply chain contractors and, as a result, Letters of Intent have been signed with a number of contractors for the provision of a range of services and vendor financing.

In parallel, discussions continued with FIG on a range of fiscal, environmental and regulatory matters. Following the submission of a revised draft FDP to FIG in early March 2018, the FDP is now considered substantially agreed with a final FDP submission expected in the lead-up to sanction. With the FDP and EIS substantially complete, a 42-day public consultation on the EIS commenced in January 2018. No material objections were raised through the consultation process and various comments identified through the process will be addressed in the final EIS. Engagement with FIG continues with a view to obtaining the consents and agreements necessary to be in a position to reach FID on the project in 2018.

In addition, conceptual studies have commenced to examine potential development schemes for the remaining resources in PL032 and the satellite accumulations in the north of PL004 (Phase 2) and for the Isobel/Elaine fan complex in the south of PL004 (Phase 3). In this regard, Phase 2 static and dynamic modelling is progressing, and current subsurface studies will explore locations for future appraisal wells aimed at both further characterising existing discoveries whilst also targeting exploration objectives.

South and East Falkland Basin (100% working interest)

Through the acquisition of FOGL, Rockhopper acquired a 52% interest in Noble Energy operated acreage to the South and East of the Falkland Islands. Following the results of the Humpback well, Noble and Edison gave notice to withdraw from this acreage (although they retain an interest in PL001 in the North Falkland Basin). As a result, during 2017 Rockhopper became operator of the South and East Falkland Basin acreage with a 100% working interest. No outstanding financial or operational commitments exist in relation to the Company's South and East Falkland Basin interests.

Abu Sennan, Egypt (22% working interest)

Operated by Kuwait Energy, the Abu Sennan concession is located in the Abu Gharadig basin in the Western Desert. The concession was signed in June 2007 with first commercial production achieved during 2012. In August 2016, Rockhopper completed the acquisition of Beach Petroleum (Egypt) Pty Limited ("Beach Egypt"), as a result acquiring a 22% interest in the Abu Sennan concession and a 25% interest in the El Qa'a Plan concession.

Production from the six development leases within the Abu Sennan concession increased during 2017 with production during the period averaging approximately 3,460 boepd gross (760 boepd net to Rockhopper). Production levels were enhanced in the second half of the year as a result of numerous work over and production optimisation operations primarily at the El Salmiya field.

The 2017 drilling campaign on the Abu Sennan concession commenced in April.

Al Jahraa SE-2X

Exploration well Al Jahraa SE-2X, situated on the Abu Sennan-5 (Al Jahraa South East) Development Lease, was spudded on 25 April 2017.

The primary target of the well was the Cretaceous Abu Roash-C ("AR-C") reservoir in the fault block immediately to the south of the Al Jahraa South East field. The target reservoir was dry, but the well was successfully side-tracked northwards into the Al Jahraa SE field and oil pay was confirmed from wireline logging in both the AR-C and Abu Roash-E ("AR-E") reservoirs. The well was subsequently completed in the deeper AR-E and put onto production at a tubular and pump constrained rate of approximately 250 boepd gross. Following depletion of the AR-E reservoir the well will be re-completed in the AR-C.

Al Jahraa-9

Development well Al Jahraa-9 was spudded on 10 June 2017. The well penetrated 5 metres of reservoir sand in the primary AR-C reservoir. Wireline logging and a well test across the interval confirmed that, while the sand is water wet, the reservoir pressure is in line with the producing AR-C reservoir in the Al Jahraa and Al Jahraa SE fields, indicating a common aquifer. The well also encountered the deepest known oil shows in the Abu Roash-D and AR-E reservoirs, demonstrating further potential at these levels elsewhere in the concession. During 2018, it is planned that the Al Jahraa-9 well will be converted to a water injection well.

2018 outlook

A full review of the prospect and lead inventory for the Abu Sennan concession was completed in November 2017 and through that review a number of exploration targets have been high graded for exploratory drilling.

Post period end, an active programme has been agreed for 2018. An exploration well is to be drilled on "Prospect S" - located in the adjacent fault block to the Al Jahraa field. Prospect S has a similar tilted fault block trap and is targeting the same Abu Roash reservoirs that produce at Al Jahraa.

The development programme at Al Jahraa includes the drilling of two infill development wells and the initiation of a water injection programme designed to increase reserves and field production rates.

Subject to securing a suitable rig, drilling is expected to commence mid 2018.

Guendalina, Italy (20% working interest)

Operated by Eni, the Guendalina gas field, located in the Northern Adriatic, has been in production since October 2011.

Guendalina continued to produce to forecast during 2017 and production over the period averaged 47,000 standard cubic metres ("scm") per day net to Rockhopper (approximately 290 boe per day). Plant availability over the period continued to be strong with production from the side-track well drilled in 2015 continuing to make a material contribution to field production.

New static and dynamic models for the Guendalina field that incorporate new well data suggest the gas initially in place is larger than previous estimates with studies supporting a small increase in the estimate of ultimately recoverable volumes.

In addition, Rockhopper has worked closely with the operator throughout 2017 to reduce operating costs at the field primarily through optimisation of water disposal.

Civita, Italy (100% working interest)

Operated by Rockhopper, the Civita gas field located onshore Abruzzo, came into production in November 2015.

During 2017, production from the field averaged approximately 21,000 scm per day (approximately 130 boe per day). Gas compression was successfully commissioned at the site in December 2016.

However, in early February 2018, a depressurisation event occurred at the Civita pipeline and as a result production is temporarily suspended. Work has commenced to remedy the issue with production estimated to resume mid year.

As described later in the Financial Review, the Company agreed in June 2017 the terms for the disposal of a package of non-core interests in Italy, including the Civita field, to Cabot Energy plc. Rockhopper and Cabot Energy remain focused on the completion of the previously announced transaction which is now expected during H2 2018.

Ombrina Mare, Italy (100% working interest)

Following the decision in February 2016 by the Italian Ministry of Economic Development not to award the Company a Production Concession covering the Ombrina Mare field, a decision was made to plug and abandon ("P&A") the existing OM-2 well and remove the tripod structure which had been constructed in 2008 with the intention of forming part of the future production facilities on the field.

The P&A operation was completed without incident in August 2016 using the Attwood Beacon rig. The safe and successful decommissioning and removal of the tripod structure took place in October 2017 - Rockhopper will seek to recover both the costs of the P&A operation and the tripod removal through the international arbitration process, details of which are included in the Financial Review.

Monte Grosso, Italy (23% working interest)

Operated by Eni, the Serra San Bernado permit which contains the Monte Grosso oil prospect is located in the Southern Apennine thrust-fold belt on trend with Val D'Agri and Tempa Rossa, in the largest onshore oil production and development area in Western Europe. Monte Grosso remains one of the largest undrilled prospects onshore Western Europe.

Rockhopper transferred the operatorship of the Serra San Bernado permit to Eni during 2016. Eni is exploring options for the design of a well on the Monte Grosso prospect, whilst working in parallel to secure the necessary regulatory and permitting approvals to drill.

El Qa'a Plain, Egypt (25% working interest)

Operated by Dana Petroleum, the El Qa'a Plain concession is located on the eastern shore of the Gulf of Suez. The concession was signed in January 2014. In 2015/16, the first 3D seismic in the El Qa'a Plain concession was acquired and processed, in addition to a number of new 2D lines. Horizon mapping on the new data has been integrated with vintage data, and a basin modelling study has been completed across the concession.

As a result, and following joint venture approval, commitment well Raya-1X is expected to be spudded in April or early May 2018. This well will target the Nukhul Formation reservoir, known from the Gulf of Suez, in a tilted fault block structure, close to where oil has been tested from the same formation.

FINANCIAL REVIEW

OVERVIEW

During 2017, significant progress was made to advance and execute the contracting strategy and financing plan for the Sea Lion Phase 1 development.

Our Greater Mediterranean portfolio provides a low-cost, short-cycle production base which has delivered record revenues and operating cash flows for the Group which have more than covered the Group's substantially reduced G&A costs. 

Efforts have continued to streamline the Group's portfolio to focus on material assets, remove future decommissioning liabilities and streamline the organisation with a resultant reduction in corporate costs.

In addition, significant time continues to be dedicated to new venture activity with a view, on a highly selective basis, to growing our production base whilst maintaining a strong balance sheet.

RESULTS SUMMARY

RESULTS FOR THE year

For the year ended 31 December 2017, the Group reported revenues of US$10.4 million and a loss after tax of US$6.1 million.

REVENUE

The Group's revenues of US$10.4 million (2016: $7.4 million) during the year relate entirely to the sale of oil and natural gas in the Greater Mediterranean (Egypt and Italy). The increase in revenues from the comparable period reflects (i) the acquisition of production assets in Egypt, which completed in August 2016; and (ii) the increase in realised oil and gas prices.

Working interest production averaged approximately 1,184 boepd during 2017, a material increase over the comparable period (2016: 838 boepd) reflecting the full year benefit of the acquisition of production assets in Egypt.

During the period, the Group's gas production in Italy was sold under short-term contract with an average realised price of €0.19 per standard cubic meter ("scm") (2016: €0.15 per scm), equivalent to US$6.0 per thousand standard cubic feet ("mscf"). Gas is sold at a price linked to the Italian "PSV" (Virtual Exchange Point) gas marker price.

In Egypt, all of the Group's oil and gas production is sold to EGPC. The average realised price for oil was US$52.3 per barrel, a small discount to the average Brent price over the same period. Gas is sold at a fixed price of US$2.65 per million British thermal units ("mmbtu").

OPERATING COSTS

Cash operating costs, excluding depreciation and impairment charges, amounted to US$4.1 million (2016: US$4.4 million). Cash operating costs on a per barrel of oil equivalent basis reduced from US$14.4 per boe in 2016 to US$9.5 per boe in 2017, reflecting the full year impact of our low-cost Egyptian operations.

The Group continues to manage corporate costs having achieved an approximate 50% reduction in G&A cost, excluding non-recurring expenses related to restructuring and acquisitions, during the three years to end 2017. G&A costs in 2017 amounted to US$5.3 million, a further reduction compared to the comparable period (2016: US$7.4 million).

Following the decision in February 2016 by the Ministry of Economic Development not to award the Group a Production Concession covering the Ombrina Mare field, in March 2017 the Group commenced international arbitration proceedings against the Republic of Italy. All costs associated with the arbitration are funded on a non-recourse ("no win - no fee") basis from a specialist arbitration funder.

CASH MOVEMENTS AND CAPITAL EXPENDITURE

At 31 December 2017, the Group had cash and term deposits of US$50.7 million (31 December 2016: US$81.0 million) and no debt.

Cash and term deposit movements during the period:

Falkland Islands spend of US$22 million relates primarily to the close-out costs associated with the 2015/16 drilling campaign (US$15 million), as well as spend relating to the pre-development activities on Sea Lion (US$7 million). Drilling campaign close out costs going forward are expected to be minimal.

Spend in the Greater Mediterranean largely relates to the Abu Sennan drilling campaign and the decommissioning of the Ombrina Mare tripod (the costs of which the Group will seek to recover through the international arbitration against the Republic of Italy).

Other cash outflows include foreign exchange, movements in working capital balances as well as payments due to Beach Energy related to the Company's acquisition of Beach Egypt in 2016.

IMPAIRMENT OF OIL AND GAS ASSETS

Rockhopper has tested the carrying value of its assets for impairment. Carrying values are compared to the value in use of the assets based on discounted cash flow models. Future cash flows were estimated using an oil price assumption equal to the Brent forward curve during the period 2018 to 2020, with a long-term price of US$70/bbl (in "real" terms) thereafter. A post-tax nominal discount rate of 12.5% was used for the Group's Falkland Islands assets. 

With no cash flow generation expected from Sea Lion until 2021 at the earliest, the impact of the Brent forward curve during the period 2018 to 2020 on the fair value calculation is limited. As such, no impairment arises on the Sea Lion project. A range of sensitivities have been considered as part of the impairment testing process. Even in the event of a US$20 per barrel reduction in the Group's long-term oil price assumption, no impairment on Sea Lion arises. Equally, no impairment would arise even if the Group assumed project sanction was delayed by 7 years.

MERGERS, ACQUISITIONS AND DISPOSALS

On 8 June 2017, Rockhopper announced the disposal of a portfolio of non-core interests onshore Italy to Northern Petroleum Plc ("Northern"). Northern has subsequently undertaken a corporate name change to Cabot Energy plc ("Cabot").

The transaction is structured as the sale of Rockhopper Civita Limited ("Rockhopper Civita"), a subsidiary company which at completion will hold the following Petroleum Licences:

· Scanzano Concession (100% interest)

· Monte Verdese Concession (60% interest)

· Torrente Celone Concession (50% interest)

· Aglavizza Concession (100% interest)

· Civita Permit (100% interest)

· San Basile Concession (85% interest)

Under the terms of the transaction, Cabot will acquire all the assets of the Petroleum Licences (31 December 2017: US$3.8 million) and assume all future abandonment and decommissioning liabilities (31 December 2017: US$9.5 million). In consideration, Rockhopper will make a cash payment to Cabot at completion of US$1.6 million plus the usual working capital adjustments.

The effective date for the transaction is 1 January 2017 and, under the terms of the transaction, Rockhopper retains the benefit of a €1.2 million Italian VAT refund which was received during Q1 2018. The transaction is expected to complete before the end of 2018.

In August 2016, Rockhopper completed the acquisition of Beach Egypt. Under the terms of the transaction, a proportion of any payments received by Rockhopper from EGPC were payable to Beach Energy until their historic receivable position (US$8.6 million as at 31 December 2015) was satisfied. Following payments received from EGPC in February 2018, no further payments are due to Beach Energy.

TAXATION

On the 8 April 2015, the Group agreed binding documentation ("Tax Settlement Deed") with the Falkland Islands Government in relation to the tax arising from the Group's farm out to Premier Oil.

The Tax Settlement Deed confirms the quantum and deferment of the outstanding tax liability and is made under Extra Statutory Concession 16.

As a result of the Tax Settlement Deed, the outstanding tax liability was confirmed at £64.4 million and is payable on the earlier of: (i) the first royalty payment date on Sea Lion; (ii) the date of which Rockhopper disposes of all or a substantial part of the Group's remaining licence interests in the North Falkland Basin; or (iii) a change of control of Rockhopper Exploration plc.

During the first half of 2017, as a result of the Group receiving the full Exploration Carry from Premier during the 2015/16 drilling campaign, the Falkland Islands Commissioner of Taxation agreed to reduce the tax liability in line with the terms of the Tax Settlement Deed. As such, the tax liability has been revised downwards to £59.6 million with a tax credit being recognised in the period of US$2.8 million.

In spite of the aforementioned reduction in the tax liability, due to the movement in the Sterling:US dollar exchange rate, the outstanding tax liability in US dollar terms has increased to US$80.6 million (31 December 2016: US$78.7 million).

The outstanding tax liability is classified as non-current and is discounted to a period-end value of US$40.1 million.

Full details of the provisions and undertakings of the Tax Settlement Deed were disclosed in the Group's 2014 Annual Report and these include "creditor protection" provisions including undertakings not to declare dividends or make distributions while the tax liability remains outstanding (in whole or in part). 

LIQUIDITY, COUNTERPARTY RISK AND GOING CONCERN

The Group monitors its cash position, cash forecasts and liquidity on a regular basis and takes a conservative approach to cash management, with surplus cash held on term deposits with a number of major financial institutions.

Following the Group's acquisition of production and exploration assets in Egypt, the Group is exposed to potential payment delay from EGPC, which is an issue common to many upstream companies operating in the country. As at 31 March 2018, Rockhopper's EGPC receivable balance was US$4.6 million (unaudited). The Group maintains an active dialogue with EGPC and has seen a material increase in monthly payments, having received in aggregate US$8.6 million gross during 2017. Throughout 2017, payments from EGPC were received in US dollars directly to bank accounts held in the UK.

The Directors have assessed that the cash balance held provides the Group with adequate headroom over forecasted expenditure for the following 12 months - as a result, the Directors have adopted the going concern basis of accounting in preparing the annual financial statements.

PRINCIPAL RISK AND UNCERTAINTIES

A detailed review of the potential risks and uncertainties which could impact the Group are outlined elsewhere in this Strategic Report. The Group identified its principal risks at the end of 2017 as being:

· sustained low oil price;

· joint venture partner alignment and funding issues, both of which could ultimately create a delay to the Sea Lion Final Investment Decision; and

· insufficient liquidity and funding capacity in the event of a protracted delay to the Sea Lion Final Investment Decision.

Stewart MacDonald

Chief Financial Officer

18 April 2018

Group income statement

for the YEAR ended 31 DeCEMBER 2017

All operating income and operating gains and losses relate to continuing activities.

Group statement of comprehensive income

for the YEAR ended 31 DECEMBER 2017

Group balance sheet

as at 31 DECEMBER 2017

These financial statements were approved by the directors and authorised for issue on 18 April 2018 and are signed on their behalf by:

STEWART MACDONALD

CHIEF FINANCIAL OFFICER

Group statement of changes in equity

for the YEAR ended 31 DECEMBER 2017

Group cash flow statement

for the YEAR ended 31 DECEMBER 2017

Notes to the group financial statements

for the Year ended 31 DECEMBER 2017

1 Accounting policies

1.1 GROUP AND ITS OPERATIONS

Rockhopper Exploration plc, the 'Company', a public limited company quoted on AIM, incorporated and domiciled in the United Kingdom ('UK'), together with its subsidiaries, collectively 'the 'Group' holds certain exploration licences for the exploration and exploitation of oil and gas in the Falkland Islands. In 2014, it diversified its portfolio into the Greater Mediterranean through the acquisition of an exploration and production company with operations principally based in Italy and during 2016 augmented this through the acquisition of exploration and production assets in Egypt. The registered office of the Company is 4th Floor, 5 Welbeck Street, London, W1G 9YQ.

1.2 Statement of compliance

The consolidated financial statements are prepared in compliance with International Financial Reporting Standards (IFRS) as adopted by the European Union and applied in accordance with UK company law. The consolidated financial statements were approved for issue by the board of directors on 18 April 2018 and are subject to approval at the Annual General Meeting of shareholders on 18 May 2018.

1.3 Basis of preparation

The results upon which these financial statements have been based were prepared using the accounting policies set out below. These policies have been consistently applied unless otherwise stated.

These consolidated financial statements have been prepared under the historical cost convention except, as set out in the accounting policies below, where certain items are included at fair value.

Items included in the results of each of the Group's entities are measured in the currency of the primary economic environment in which that entity operates (the "functional currency").

All values are rounded to the nearest thousand dollars ($'000) or thousand pounds (£'000), except when otherwise indicated.

1.4 change in accounting policy

Changes in accounting standards

In the current year new and revised standards, amendments and interpretations were effective and are applicable to the consolidated financial statements of the Group but did not affect amounts reported in these financial statements.

At the date of authorisation of this report the following standards and interpretations, which have not been applied in this report, were in issue but not yet effective.

‐ IFRS9 Financial Instruments (effective date for annual periods beginning on or after 1 January 2018);

‐ IFRS15 Revenue from Contracts with customers (effective date for annual periods beginning on or after 1 January 2018);

‐ IFRS16 Leases (effective date for annual periods beginning on or after 1 January 2019);

Management does not believe that the application of these standards will have a material impact on the financial statements.

1.5 Going concern

At 31 December 2017, the Group had available cash and term deposits of $51 million. In addition the first phase of the Group's main development, Sea Lion, is fully funded from sanction through a combination of Development Carries and a loan facility from the operator.

It is for these reasons that the board is of the opinion, at the time of approving the financial statements, that the Group and Company has adequate resources to continue in operational existence for the foreseeable future, being at least twelve months from the date of approval of the financial statements. For this reason, the board has adopted the going concern basis in preparation of the financial statements.

1.6 Significant accounting policies

(a) Basis of accounting

The Group has identified the accounting policies that are most significant to its business operations and the understanding of its results. These accounting policies are those which involve the most complex or subjective decisions or assessments, and relate to the capitalisation of exploration expenditure. The determination of this is fundamental to the financial results and position and requires management to make a complex judgment based on information and data that may change in future periods.

Since these policies involve the use of assumptions and subjective judgments as to future events and are subject to change, the use of different assumptions or data could produce materially different results. The measurement basis that has been applied in preparing the results is historical cost with the exception of financial assets, which are held at fair value.

The significant accounting policies adopted in the preparation of the results are set out below.

(b) Basis of consolidation

The consolidated financial statements include the results of Rockhopper Exploration plc and its subsidiary undertakings to the balance sheet date. Where subsidiaries follow differing accounting policies from those of the Group, those accounting policies have been adjusted to align with those of the Group. Inter-company balances and transactions between Group companies are eliminated on consolidation, though foreign exchange differences arising on inter-company balances between subsidiaries with differing functional currencies are not offset.

(c) Segmental reporting

Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision maker as required by IFRS8 Operating Segments. The chief operating decision maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the board of directors.

The Group's operations are made up of three segments, the oil and gas exploration and production activities in the geographical regions of the Falkland Islands and the Greater Mediterranean region as well as its corporate activities centered in the UK.

(d) Oil and Gas Assets

The Group applies the successful efforts method of accounting for exploration and evaluation ("E&E") costs, having regard to the requirements of IFRS6 - 'Exploration for and evaluation of mineral resources'.

Exploration and evaluation ("E&E") expenditure

Expensed exploration & evaluation costs

Expenditure on costs incurred prior to obtaining the legal rights to explore an area, geological and geophysical costs are expensed immediately to the income statement.

Capitalised intangible exploration and evaluation assets

All directly attributable E&E costs are initially capitalised in well, field, prospect, or other specific, cost pools as appropriate, pending determination.

Treatment of intangible E&E assets at conclusion of appraisal activities

Intangible E&E assets related to each cost pool are carried forward until the existence, or otherwise, of commercial reserves have been determined, subject to certain limitations including review for indications of impairment. If commercial reserves have been discovered, the carrying value, after any impairment loss, of the relevant E&E assets, are then reclassified as development and production assets within property plant and equipment. However, if commercial reserves have not been found, the capitalised costs are charged to expense.

The Group's definition of commercial reserves for such purpose is proved and probable reserves on an entitlement basis. Proved and probable reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty (see below) to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50% statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proved and probable. The equivalent statistical probabilities for the proven component of proved and probable reserves are 90%.

Such reserves may be considered commercially producible if management has the intention of developing and producing them and such intention is based upon:

- a reasonable assessment of the future economics of such production;

- a reasonable expectation that there is a market for all or substantially all the expected hydrocarbon production;

- evidence that the necessary production, transmission and transportation facilities are available or can be made available; and

- the making of a final investment decision.

Furthermore:

(i) Reserves may only be considered proved and probable if producibility is supported by either actual production or a conclusive formation test. The area of reservoir considered proved includes: (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, or both; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geophysical, geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are only included in the proved and probable classification when successful testing by a pilot project, the operation of an installed programme in the reservoir, or other reasonable evidence (such as, experience of the same techniques on similar reservoirs or reservoir simulation studies) provides support for the engineering analysis on which the project or programme was based.

Development and production assets

Development and production assets, classified within property, plant and equipment, are accumulated generally on a field-by-field basis and represent the costs of developing the commercial reserves discovered and bringing them into production, together with the E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets.

Depreciation of producing assets

The net book values of producing assets are depreciated generally on a field-by-field basis using the unit-of-production method by reference to the ratio of production in the year and the related commercial reserves of the field, taking into account the future development expenditure necessary to bring those reserves into production.

Disposals

Net cash proceeds from any disposal of an intangible E&E asset are initially credited against the previously capitalised costs. Any surplus proceeds are credited to the income statement.

Decommissioning

Provision for decommissioning is recognised in full when the related facilities are installed. The amount recognised is the present value of the estimated future expenditure. A corresponding amount equivalent to the provision is also recognised as part of the cost of the related oil and gas property. This is subsequently depreciated as part of the capital costs of the production facilities. Any change in the present value of the estimated expenditure is dealt with prospectively as an adjustment to the provision and the oil and gas property. The unwinding of the discount is included in finance cost.

(E) Capital commitments

Capital commitments include all projects for which specific board approval has been obtained up to the reporting date. Projects still under investigation for which specific board approvals have not yet been obtained are excluded.

(F) Foreign currency translation

Functional and presentation currency:

Items included in the results of each of the Group's entities are measured using the currency of the primary economic environment in which the entity operates, the functional currency. The consolidated financial statements are presented in US$ as this best reflects the economic environment of the oil exploration sector in which the Group operates. The Group maintains the accounts of the parent and subsidiary undertakings in their functional currency. Where applicable, the Group translates subsidiary accounts into the presentation currency, US$, using the closing rate method for assets and liabilities which are translated at the rate of exchange prevailing at the balance sheet date and rates at the date of transactions for income statement accounts. Differences are taken directly to reserves.

Transactions and balances:

Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year end exchange rates of monetary assets and liabilities denominated in foreign currencies are capitalised in the income statement, except when deferred in equity as qualifying cash flow hedges and qualifying net investment hedges.

The period end rates of exchange actually used were:

(g) Revenue and income

(i) Revenue

Revenue arising from the sale of goods is recognised when the significant risks and rewards of ownership have passed to the buyer, which is typically at the point that title passes, and the revenue can be reliably measured. Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for goods provided in the normal course of business, net of discounts, customs duties and sales taxes.

(ii) Investment income

Investment income consists of interest receivable for the period. Interest income is recognised as it accrues, taking into account the effective yield on the investment.

(h) NON-DERIVATIVE Financial instruments

Financial assets and financial liabilities are recognised on the Group's balance sheet when the Group has become a party to the contractual provisions of the instrument.

(i) Other receivables

Other receivables are classified as loans and receivables and are initially recognised at fair value. They are subsequently measured at their amortised cost using the effective interest method less any provision for impairment. A provision for impairment is made where there is objective evidence that amounts will not be recovered in accordance with original terms of the agreement. A provision for impairment is established when the carrying value of the receivable exceeds the present value of the future cash flow discounted using the original effective interest rate. The carrying value of the receivable is reduced through the use of an allowance account and any impairment loss is recognised in the income statement.

(ii) Term deposits

Term deposits are disclosed separately on the face of the balance sheet when their term is greater than three months and they are unbreakable.

(iii) Restricted cash

Restricted cash is disclosed separately on the face of the balance sheet and denoted as restricted when it is not under the exclusive control of the Group.

(iv) Cash and cash equivalents

Cash and cash equivalents comprise cash in hand and at bank and other short-term deposits held by the Group including breakable and unbreakable deposits with terms of less than three months and breakable term deposits of greater terms than three months where amounts can be accessed within three months without material loss. They are stated at carrying value which is deemed to be fair value.

(v) Financial liabilities and equity

Financial liabilities and equity instruments are classified according to the substance of the contractual arrangements entered into. An equity instrument is any contract that evidences a residual interest in the assets of the Group after deducting all of its liabilities.

(vi) Account and other payables

Account payables are initially recognised at fair value and subsequently at amortised cost using the effective interest method.

 (vii) Equity instruments

Equity instruments issued by the Company are recorded at the proceeds received, net of direct issue costs.

(I) INCOME TAXES AND DEFERRED TAXATION

The current tax expense is based on the taxable profits for the period, after any adjustments in respect of prior years. Tax, including tax relief for losses if applicable, is allocated over profits before tax and amounts charged or credited to reserves as appropriate.

Deferred taxation is recognised in respect of all taxable temporary differences that have originated but not reversed at the balance sheet date where a transaction or events have occurred at that date that will result in an obligation to pay more, or a right to pay less or to receive more, tax, with the exception that deferred tax assets are recognised only to the extent that the directors consider that it is probable that there will be suitable taxable profits from which the future reversal of the underlying temporary differences can be deducted.

Deferred tax is measured on an undiscounted basis at the tax rates that are expected to apply in the periods in which temporary differences reverse, based on tax rates and laws enacted or substantively enacted at the balance sheet date.

(j) Share based remuneration

The Group issues equity settled share based payments to certain employees. Equity settled share based payments are measured at fair value (excluding the effect of non market based vesting conditions) at the date of grant. The fair value determined at the grant date of the equity settled share based payments is expensed on a straight line basis over the vesting period, based on the Group's estimate of shares that will eventually vest and adjusted for non market based vesting conditions.

Fair value is measured by use of either Binomial or Monte-Carlo simulation. The main assumptions are disclosed in note 9.

Cash settled share based payment transactions result in a liability. Services received and liability incurred are measured initially at fair value of the liability at grant date, and the liability is remeasured each reporting period until settlement. The liability is recognised on a straight line basis over the period that services are rendered.

2 Use of estimates, assumptions and judgements

The Group makes estimates, assumptions and judgements that affect the reported amounts of assets and liabilities. Estimates, assumptions and judgements are continually evaluated and based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances.

The key assumptions concerning the future, and other key sources of estimation uncertainty at the balance sheet date, that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below.

Carrying value of intangible exploration and evaluation assets (note 14) and property, plant and equipment (note 15)

The amounts for intangible exploration and evaluation assets represent active exploration and evaluation projects. These amounts will be written off to the income statement as exploration costs unless commercial reserves are established or the determination process is not completed and there are indications of impairment in accordance with the Group's accounting policy.

In addition for assets under evaluation where discoveries have been made, such as Sea Lion, and property plant and equipment assets their carrying value is checked by reference to the net present value of future cashflows which requires key assumptions and estimates in relation to: commodity prices that are based on forward curves for a number of years and the long-term corporate economic assumptions thereafter, discount rates that are adjusted to reflect risks specific to individual assets, the quantum of commercial reserves and the associated production and cost profiles. Future development costs are estimated taking into account the level of development required to produce the reserves by reference to operators, where applicable, and internal engineers.

Carrying value of goodwill (note 16)

Following the acquisition of Mediterranean Oil & Gas plc during 2014, Rockhopper recognised goodwill in line with the requirements of IFRS 3- Business Combinations. Management performs annual impairment tests on the carrying value of goodwill and the Greater Mediterranean CGU that the goodwill is attributed to. The calculation of the recoverable amount is based on the likely future economic benefits of the exploration and evaluation assets in the acquired portfolio and is based on estimated value of the potential and actual discoveries as noted above.

Decommissioning costs (note 23)

Decommissioning costs are uncertain and cost estimates can vary in response to many factors, including changes to the relevant legal requirements, the emergence of new technology or experience at other assets. The expected timing, work scope and amount of expenditure may also change. Therefore significant estimates and assumptions are made in determining the provision for decommissioning. The estimated decommissioning costs are reviewed annually by an external expert and the results of the most recent available review used as a basis for the amounts in the Financial Statements. Provision for environmental clean-up and remediation costs is based on current legal and contractual requirements, technology and price levels.

3 REVENUE AND SEGMENTAL INFORMATION

YEAR ENDED 31 DECEMBER 2017

Year ended 31 December 2016

4 Cost of sales

5 exploration and evaluation expenses

6 Administrative expenses

The average number of staff employed during the year was 24 (31 December 2016: 31). The relative decrease between years reflects the continued restructuring of the Greater Mediterranean operation. As at 31 December 2017 the number of staff employed had reduced to 21.

Amounts reallocated relate to the costs of staff and associated overhead in relation to non administrative tasks. These costs are allocated to exploration and evaluation expenses or capitalised as part of the intangible exploration and evaluation assets as appropriate.

7 directors' remuneration

The total remuneration of the highest paid director was:

Interest in outstanding share options and SARs, by director, are separately disclosed in the directors' remuneration report.

8 Auditor's remuneration

9 Share based Payments

The charge for share based payments relate to options granted to employees of the Group.

The models and key assumptions used to value each of the grants and hence calculate the above charges are set out below:

Long term incentive plan

During 2013 a long term incentive plan ("LTIP") was approved by shareholders. The LTIP is operated and administered by the Remuneration Committee. During the year a number of LTIP awards ('Awards'), structured as nil cost options, were granted to executive directors and senior staff.

LTIP awards will generally only vest or become exercisable subject to the satisfaction of a performance condition measured over a three year period ("Performance Period") determined by the Remuneration Committee at the time of grant. The performance conditions must contain objective conditions, which must be related to the underlying financial performance of the Company. The current performance condition used is based on Total Shareholder Return ("TSR") measured over a three-year period against the TSR of a peer group of at least 9 other oil and gas companies comprising both FTSE 250, larger AIM oil and gas companies and Falkland Islands focused companies ("Peer Group"). The Peer Group for the Awards may be amended by the Remuneration Committee at their sole discretion as appropriate.

Performance measurement for the Awards are based on the average price over the relevant 90 day dealing period measured against the 90 dealing day period three years later. Awards will typically vest on a sliding scale from 35% to 100% for performance in the top two quartiles of the Peer Group. Certain awards can have an escalator applied which means that they vest in excess of 100% if the Company is the top or second highest performer in the Peer Group. No awards will vest for performance in the bottom two quartiles.

The Awards granted on 8 October 2013 and 10 March 2014 had an additional performance condition so that no awards would vest if the Company's share price did not exceed £1.80 based on the average price over the 90 day dealing period up to 31 March 2016. The Remuneration Committee has exercised its discretion to vary the performance condition so that the period for achievement of the£1.80 hurdle rate is extended to 31 March 2023. As a result, any LTIP awards that would have vested on 31 March 2016 will not be exercisable unless the Company's share price exceeds £1.80 based on an average price over any 90 day dealing period up to 31 March 2023. At the same time, the Remuneration Committee agreed to remove its discretion to allow vesting for performance in the third quartile for all existing and future LTIP awards.

The LTIP has been valued using a Monte Carlo model the key inputs of which are summarised below

The following movements occurred during the year:

Share incentive plan

The Group has in place an HMRC approved Share Incentive Plan ("SIP"). The SIP allows the Group to award Free Shares to UK employees (including directors) and to award shares to match Partnership Shares purchased by employees, subject to HMRC limits.

Throughout this and the prior year the Group issued two Matching Shares for every Partnership Share purchased.

In the year the Group made a free award of £41,997 (year ended 31 December 2016 £50,997) worth of Free Shares to eligible employees.

This resulted in 154,826 (year ended 31 December 2016: 177,772) Free Shares and under the SIP scheme matching and partnership shares issued were 302,622 (year ended 31 December 2016: 216,778) in the period.

The fair value of the shares awarded will be spread over the expected vesting period.

Share appreciation rights

A share appreciation right ("SAR") is effectively a share option that is structured from the outset to deliver, on exercise, only the net gain in the form of new ordinary shares that would have been made on the exercise of a market value share option.

No consideration is payable on the grant of a SAR. On exercise, an option price of 1 pence per ordinary share, being the nominal value of the Company's ordinary shares, is paid and the relevant awardee will be issued with ordinary shares with a market value at the date of exercise equivalent to the notional gain that the awardee would have made, being the amount by which the aggregate market value of the number of ordinary shares in respect of which the SAR is exercised, exceeds a notional exercise price, equal to the market value of the shares at the time of grant (the "base price"). The remuneration committee has discretion to settle the exercise of SARs in cash.

The following movements occurred during the period on SARs:

10 FOREign Exchange

11 FINANCE INCOME AND EXPENSE

12 Taxation

On the 8 April 2015 the Group agreed binding documentation ("Tax Settlement Deed") with the Falkland Island Government ("FIG") in relation to the tax arising from the Group's farm out to Premier Oil plc ("Premier"). As such the Group is able to defer this tax liability under Extra Statutory Concession 16. As it is deferred, the liability is classified as non-current and discounted. Additional information is given in Note 22 Tax payable.

The total carried forward losses and carried forward pre trading expenditures potentially available for relief are as follows:

In Egypt under the terms of the PSC any taxes arising are settled by EGPC on behalf of the Group. Consequently, any carried forward losses would have no impact on the reported profits of the Group.

No deferred tax asset has been recognised in respect of temporary differences arising on losses carried forward, outstanding share options or depreciation in excess of capital allowances due to the uncertainty in the timing of profits and hence future utilisation. Losses carried forward in the Falkland Islands includes amounts held within entities where utlisation of the losses in the future may not be possible.

13 Basic and diluted loss per share

The average market value of the Company's shares for the purpose of calculating the dilutive effect of share options was on quoted market prices for the year during which the options were outstanding. The calculation of loss per share is based upon the loss for the year and the weighted average shares in issue. As the Group is reporting a loss in the year then in accordance with IAS33 the share options are not considered dilutive because the exercise of the share options would have the effect of reducing the loss per share.

14 intangible exploration and evaluation assets

FALKLAND ISLANDS LICENCES

The additions during the period of $7.4 million relate principally to the Sea Lion development.

The Acquisition during the prior period of $170 million reflects the fair value of the licences held by Falkland Oil & Gas Limited and its subsidiary, principally being its 40% interest in the PL004 licences.

The carrying value of phase 1 of the Sea Lion Development, a discovered asset still under evaluation was checked for impairment by reference to a discounted cashflow model. The key inputs to this model were a 2018 real terms oil price of $70/bbl, a post-tax discount rate of 12.5% and utilising the operator's current estimates of capital and operating costs and production profiles. The project is targeting project sanction decision at the end of 2018 (with such decision dependent on funding) and is expected to take three and half years from sanction to first oil. The remaining barrels in Sea Lion are expected to be recovered along with those in near field discoveries in a second phase of development. This second phase has been checked for impairment in a similar manner.

Sensitivity analysis was performed by, in turn, reducing oil price by $10/bbl, reducing production by 10%, increasing capital expenditure by 10%, increasing operating expenditure by 10% and delaying the development by one year. None of these sensitivities would have led to an impairment charge in the year.

Costs associated with Isobel/Elaine discoveries and a potential phase 3 development are carried at cost and no indication of impairment currently exist although the assets require further appraisal.

GREATER MEDITERRANEAN LICENCES

The $1.3 million additions during the period predominantly relate to work on the Egyptian license interests. An impairment of $2.3 million was recognised during the year against the Abu Sennan concession in Egypt following confirmation of the Al Jahraa-9 well being water wet.

The asset additions in the prior period ($5.8 million) relate to the Egyptian exploration assets acquired as part of the acquisition of Beach Petroleum (Egypt) Pty Limited.

At the end of the prior year, following a review of the operator's technical evaluation of the Maltese assets, the decision was made to relinquish the licence. This was the main component of the $3.5 million written off to exploration costs in the Greater Mediterranean region as all costs associated with the licence were written off.

15 property, plant and equipment

All oil and gas assets relate to the Greater Mediterranean region, specifically producing assets in Italy and Egypt.

Prior year asset additions relate almost entirely to the addition of the Abu Sennan production asset in Egypt which was acquired as part of the acquisition of Beach Petroleum (Egypt) Pty Limited.

Impairment testing was performed across the Group's oil and gas assets and was calculated by comparing the future discounted cash flows expected to be derived from production of commercial reserves (the value in use being the recoverable amount) against the carrying value of the asset. The future cash flows were estimated using a realised oil and gas price assumption equal to existing contracts in place and relevant forward curve in 2018 and 2019, and an oil price of $70/bbl and a gas price of €0.25/sm3 in 2018 real terms thereafter and were discounted using a post-tax rate of 10%. Assumptions involved in the impairment measurement include estimates of commercial reserves and production volumes, future oil and gas prices and the level and timing of expenditures, all of which are inherently uncertain. No impairment was recognised in the period (2016: $nil).

16 GOODWILL

Goodwill relates to the corporate acquisition of Mediterranean Oil & Gas plc ("MOG") during the period ended 31 December 2014. This goodwill is fully allocated to the Italian CGU and more specifically to Monte Grosso and Ombrina Mare, which have the optionality and potential to provide value in excess of this fair value as well as the strategic premium associated with a significant presence in a new region. The functional currency of MOG is euros. As such the goodwill is also expressed in the same functional currency and subject to retranslation at each reporting period end. The increase in the period of $1,350,000 (2016: $364,000 reduction) is entirely due to this foreign currency difference. None of the goodwill recognised is expected to be deductible for tax purposes.

The Group tests goodwill annually for impairment or more frequently if there are indicators goodwill might be impaired. The recoverable amounts are determined by reference to a value in use calculation. Future cashflows are estimated using long term realised gas price of €0.25/sm3 and a realised long-term oil price of $70/bbl in 2018 real terms and were discounted using a post-tax rate of 10%. Assumptions involved in the impairment measurement include estimates of commercial reserves and production volumes, future oil and gas prices and the level and timing of expenditures, all of which are inherently uncertain.

17 OTHER Receivables

The carrying value of receivables approximates to fair value. The decrease in receivables in the year is due to the reduction of the receivable due from EGPC. At 31 December 2017, the receivable balance due from EGPC was $7.6 million of which net $6.9 million was due to Rockhopper after offsetting the amount payable to the former parent company, Beach Energy Limited. This reduction has been in part offset by an increase in the IVA tax receivable balance due from the Italian tax authorities.

18 Restricted cash

19 Term Deposits

Term deposits are disclosed separately on the face of the balance sheet when their term is greater than three months and they are unbreakable.

20 Disposal group held for sale

On 8 June 2017, the Group announced the disposal of a portfolio of non-core interests in onshore Italy. As at 31 December 2017, the disposal group comprised assets of $3.8 million less liabilities of $9.5 million, detailed as follows.

21 Other payables and accrualS

Accruals have decreased due to the prior year including costs associated with the close out of the 2015/16 North Falkland Basin drilling campaign. The decrease in other creditors in the year is due to the reduction of a payable balance due to the former parent company Beach Energy Limited related to the associated receivable from EGPC (see note 17). The balance outstanding as at 31 December 2017 was $0.7 million.

All amounts are expected to be settled within twelve months of the balance sheet date and so the book values and fair values are considered to be the same.

22 Tax payable

On the 8 April 2015, the Group agreed binding documentation ("Tax Settlement Deed") with the Falkland Island Government ("FIG") in relation to the tax arising from the Group's farm out to Premier Oil plc ("Premier").

The Tax Settlement Deed confirms the quantum and deferment of the outstanding tax liability and is made under Extra Statutory Concession 16.

As a result of the Tax Settlement Deed the outstanding tax liability was confirmed at £64.4 million and payable on the first royalty payment date on Sea Lion. Currently the first royalty payment date is anticipated to occur within six months of first oil production which itself is estimated to occur approximately three and a half years after project sanction. As such the tax liability has been reclassified as non-current and discounted at 15%. The tax liability has been revised downwards in the year ended 31 December 2017 to £59.6 million, due to the full benefit of the exploration carry being received from Premier on the 2015/16 drilling campaign and the Falkland Islands Commissioner of Taxation agreeing to reduce the liability on that basis in line with the terms of the Tax settlement Deed. A foreign exchange loss of US$3.8 million (2016: US$8.3 million gain) has also been recognised in the year.

23 Provisions

The abandonment provision relates to the Group's licences in the Greater Mediterranean region. The provision covers both the plug and abandonment of wells drilled as well as any requisite site restoration. Assumptions, based on the current economic environment, have been made which management believe are a reasonable basis upon which to estimate the future liability. These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning works required which will reflect market conditions at the relevant time. Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce at economically viable rates. This in turn will depend upon future oil and gas prices, which are inherently uncertain.

Other provisions include amounts due to employees for accrued holiday and leaving indemnity for staff in Italy, that will become payable when they cease employment.

24 deferred tax liability

The deferred tax liability arises due to temporary differences associated with the intangible exploration and evaluation expenditure. The majority of the balance relates to historic expenditure on licences in the Falklands, where the tax rate is 26%, being utilised to minimise the corporation tax due on the consideration received as part of the farm out disposal during 2012.

Total carried forward losses and carried forward pre-trading expenditures available for relief on commencement of trade at 31 December 2017 are disclosed in note 12 Taxation. No deferred tax asset has been recognised in relation to these losses due to uncertainty that future suitable taxable profits will be available against which these losses can be utilised. The potential deferred tax asset at the 31 December 2017 would be $176 million (31 December 2016: $59 million).

25 Share capital

For details of all movements during the year, see note 13.

26 reserves

Set out below is a description of each of the reserves of the Group:

27 Lease commitments

The future aggregate minimum lease payments under non-cancellable operating leases in respect of land and buildings were as follows:

28 CAPITAL COMMITMENTS

Capital commitments represent the Group's share of expected costs in relation to its interests in joint ventures net of any carry arrangements that are in force.

As at the date of these account the Group committed to fund its share of the approved work programs and budgets for our licence interests in the calendar year ending 31 December 2018 of US$10 million.

29 Related Party Transactions

The remuneration of directors, who are the key management personnel of the Group, is set out below in aggregate. Further information about the remuneration of individual directors is provided in the Directors' Remuneration Report on pages 35 to 45.

30 Risk management policies

Risk review

The risks and uncertainties facing the Group are set out in the risk management report. Risks which require further quantification are set out below.

Foreign exchange risks: The Group's functional currency is US$ and as such the Group is exposed to foreign exchange movements on monetary assets and liabilities denominated in other currencies, in particular the tax liability with the Falkland Island Government which is a GB£ denominated balance. In addition a number of the Group's subsidiaries have a functional currency other than US$, where this is the case the Group has an exposure to foreign exchange differences with differences being taken to reserves.

Asset balances include cash and cash equivalents, restricted cash and term deposits of $51.3 million of which $46.3 million was held in US$ denominations. The following table summarises the split of the Group's assets and liabilities by currency:

The following table summarises the impact on the Group's pre-tax profit and equity of a reasonably possible change in the US$ to GB£ exchange rate and the US$ to euro exchange: