Final Results for the year ended 31 December 2018

RNS Number : 7631U

Rockhopper Exploration plc

02 April 2019

2 April 2019

Rockhopper Exploration plc

("Rockhopper" or the "Company")

Full-year results for the year ended 31 December 2018

Rockhopper Exploration plc (AIM: RKH), the oil and gas exploration and production 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 2018.

Highlights

Sea Lion Phase 1 development - securing senior debt funding represents last major milestone to achievement of FID

· Front End Engineering and Design completed in Q1 2019

· Process to progress contractor LOIs to full agreements well advanced

· Field Development Plan and Environmental Impact Statement substantially agreed with the Falkland Islands Government - final approval expected at sanction

· Good progress made with the Falkland Islands Government on Sea Lion royalty and fiscal terms

· Financing structure progressed - extensive due diligence and assurance process underway

· Vendor financing - contractors have agreed to provide up to US$400 million of funding for the project

· Project momentum building with budget approved in Q3 2018 to increase activity and expand the Operator's project development team

Greater Mediterranean portfolio continues to deliver stable production with exploration upside

· Net working interest production averaged 1.1 kboepd in 2018

· Multiple oil and gas discoveries as a result of the 2018 drilling campaign at Abu Sennan, Egypt

o Successful infill drilling and implementation of a water injection programme at the Al Jahraa field to enhance production and maximise recoverability

o Oil discovery in the Bahariya de-risks future exploration at this level across the concession

Strong financial performance with continued focus on managing costs

· Revenue of US$10.6 million; operating costs US$4.6 million; cash flow from operations US$5.4 million

· Cash operating costs of US$11.7 per boe - maintaining a low cost base

· Continued management of G&A costs - US$5.3 million - down over 50% since 2014

· G&A costs covered by operating cash flows

· Cash resources of US$40.4 million at 31 December 2018 and no debt

Corporate

· International arbitration hearing in relation to Ombrina Mare took place in February 2019

· Alison Baker appointed as Independent Non-Executive Director in September 2018

Outlook

· Joint venture to submit formal senior debt funding application on Sea Lion Phase 1 in Q2 2019

· Outcome in relation to Ombrina Mare arbitration expected in late Q3 or early Q4 2019 - seeking significant monetary damages

· Active drilling campaign at Abu Sennan, Egypt with four wells planned during 2019

· Appointment of Keith Lough as Non-Executive Chairman following the retirement of David McManus at Company's forthcoming AGM

· Continued pursuit of new venture opportunities to supplement production, enhance cash flow and strengthen balance sheet

Sam Moody, Chief Executive Officer of Rockhopper Exploration, commented:

"Sea Lion has the potential to be transformational for Rockhopper and the Falkland Islands as a whole. Securing funding is the last remaining major milestone before Sea Lion can reach FID and all efforts are focused on securing such financing to allow the project to move into the development phase.

"The outcome of our international arbitration against the Republic of Italy is expected later this year and following the hearing in February we remain confident that we have strong prospects of recovering very significant monetary damages.

"I would again like to thank David McManus for his efforts as both a Director and latterly as Chairman, throughout a period in which the Company undertook transactions in the Falklands and the Mediterranean and continued to advance the world class Sea Lion development."

Enquiries:

Rockhopper Exploration plc

Sam Moody - Chief Executive

Stewart MacDonald - Chief Financial Officer

Tel. +44 (0) 20 7390 0234 (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 7390 0234

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's strategy is to build a well-funded, full-cycle, exploration led E&P company.

Against a backdrop of volatile commodity prices, 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.

Sea Lion has the potential to be transformational for Rockhopper and the Falkland Islands as a whole. Securing funding is the last remaining major milestone before Sea Lion can reach FID and all efforts are focused on securing such financing to allow the project to move into the development phase.

In the Greater Mediterranean, our portfolio continues to meet its primary objective, namely to provide a production and cash flow base to fund our corporate and operating costs and support our balance sheet.

We maintain ambitions to further expand our production base thereby generating additional free cash flow to strengthen our balance sheet and invest in future exploration or other value-accretive growth opportunities both in the Falklands and elsewhere.

Sea Lion Phase 1 - FEED completed; formal funding application to be submitted Q2 2019

Material progress continues to be made across a range of commercial, fiscal and funding matters as we work towards a final investment decision on the Phase 1 development of the Sea Lion field.

During 2018, FEED contracts were awarded for all the outstanding elements of the project scope with a corresponding increase in activity, expenditure and expansion of the Operator's project development team. Although FEED concluded in March 2019 increased activity levels are expected to be maintained throughout 2019 in the lead up to project sanction. The process to agree fully termed documentation for the provision of contractor services and vendor finance is well advanced and letters of award will be issued as we go through the sanction gate.

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. Following submission of a revised Field Development Plan ("FDP") to FIG in March 2018, the FDP is considered substantially agreed. The Environmental Impact Statement ("EIS") public consultation process concluded in March 2018 with no material objections received. The final EIS document has been submitted to FIG. Formal approval of the EIS and FDP are expected at sanction.

Good progress has been made with FIG on the royalty and fiscal terms which will apply to the first phase of development of the Sea Lion field. A public consultation on a number of technical tax matters associated with oil field development in the Falklands was concluded in the third quarter of 2018 with a number of technical amendments and clarifications being implemented. These amendments and clarifications provided definition on a number of important regulatory and tax matters which were critical to enabling the project to progress.

The Sea Lion financing plan comprises funding elements including senior project finance debt (likely involving a combination of export credit financing and project bank funding), vendor financing from contractors and equity from the joint venture. Rockhopper's share of the joint venture equity is to be funded through the carry arrangements with Premier. The joint venture continues to lead engagement with a wide range of stakeholders to obtain the support required to secure senior project finance debt, which represents the core of the project's funding strategy. With initial debt feasibility and structuring now progressed, the joint venture expects to submit the Project Information Memorandum ("PIM") and formal funding application during Q2 2019. On the vendor financing side, the project contractors have undertaken an extensive due diligence and assurance process and, subject to the finalisation of documentation, have agreed to provide up to US$400 million of funding for the project.

Greater Mediterranean portfolio continues to deliver stable production with exploration upside

Our Greater Mediterranean portfolio continued to perform well with production growth in Egypt broadly offsetting declining production in Italy. Production during 2018 averaged 1.1 kboepd net to Rockhopper, with operating cash flows again covering the Group's G&A costs.

In June 2018, the Company announced the commencement of a four-well drilling campaign across its Egyptian portfolio, including three wells at Abu Sennan and one at El Qa'a Plain. Whilst the Raya commitment well on the El Qa'a Plain concession encountered good quality sands, no hydrocarbons were encountered.

Within the Abu Sennan concession, successful infill oil producers were drilled at Al Jahraa-6 and Al Jahraa-10 as well as a successful exploration well at ASZ-1X. At Al Jahraa-6, success occurred in both the primary objective, being the Abu Roach-C reservoir, and with a new oil discovery in the deeper Bahariya section. The Bahariya formation was subsequently put into production and continues to make a meaningful contribution to overall volumes from the concession.

During 2018 the Company continued to see a material improvement in the payment situation in Egypt with a significant decline in outstanding receivables owed by Egyptian General Petroleum Corporation ("EGPC").

Corporate matters

Rockhopper commenced international arbitration proceedings against the Republic of Italy in relation to the Ombrina Mare field in March 2017. The hearing took place in early February 2019 in Paris. Rockhopper continues to believe 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.

As part of the Board's long-term succession planning, and having served on the Board for nearly nine years, the past three as Non-Executive Chairman, David McManus will be retiring as a Director with effect from the Company's 2019 Annual General Meeting ("AGM"). David will be succeeded as Non-Executive Chairman by Keith Lough, currently the Senior Independent Director and a Non-Executive Director of the Company since January 2014.

In September 2018, Alison Baker was appointed as an Independent Non-Executive Director. Alison has nearly 25 years' experience in the provision of audit, capital markets and advisory services, having led the UK and EMEA Oil and Gas practice at PricewaterhouseCoopers and prior to that the Energy, Utilities and Mining Assurance practice at Ernst & Young. Alison is currently an Independent Non-Executive Director of KAZ Minerals PLC and Centamin plc. Alison will replace Keith as Chairman of the Audit and Risk Committee, also with effect from the 2019 AGM.

Accordingly, following the Company's 2019 AGM, the Board will comprise six Directors - two Executive Directors and four Non-Executive Directors, including the Chairman. However, as part of the Board's long-term succession planning and given our continued focus on corporate costs, the aim remains to further reduce the size of the Board over time. In this regard, and as previously announced, it is anticipated that Tim Bushell will step down from the Board at or before the Company's AGM in 2020.

From 28 September 2018, all AIM companies are required to state which recognised corporate governance code the Board has decided to apply and to explain how the Company complies with that code. Following a review of the alternative codes available, the Board decided to adopt the Quoted Companies Alliance Corporate Governance Code (the "QCA Code") and suitable disclosures will be made going forward.

Following the conclusion of a formal tender process, the Board has approved the proposed appointment of PricewaterhouseCoopers as the Company's auditor for the financial year commencing 1 January 2019. This appointment is subject to approval by shareholders of the Company at the 2019 AGM.

Outlook

Sea Lion has the potential to be transformational for Rockhopper and all efforts remain focused on securing the requisite stakeholder support and funding to allow sanction to occur.

With Brent oil prices currently above US$65 per barrel, the economics for the Sea Lion project remain robust. It is in this context that the Board remains confident that the requisite stakeholder support and funding will be secured. Whilst PIM and formal funding application submission represent a significant milestone in the financing process, the timetable and process to secure such funding remains outside our control.

The outcome of the international arbitration against the Republic of Italy is expected later this year and following the hearing in February we remain confident that we have strong prospects of recovering very significant monetary damages.

Our Greater Mediterranean portfolio continues to provide the necessary operating cash flow to fund corporate costs while providing low-risk exploration upside opportunities. On a highly selective basis, the Company will seek to further expand the 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
Non-Executive Chairman	Chief Executive Officer
1 April 2019

OPERATIONAL REVIEW

Sea Lion, North Falkland Basin

Rockhopper is 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 approximately 220 mmbbls in PL032 (in which Rockhopper has a 40% working interest). A subsequent Phase 2 development will develop 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 subsea wells. Estimated gross capex to first oil remains US$1.5 billion. The Sea Lion financing plan comprises funding elements including senior project finance debt, vendor financing from contractors and equity from the joint venture. Rockhopper's share of the joint venture equity is to be funded through the carry arrangements with Premier.

Through 2017 and 2018, work focused on securing agreements with key supply chain contractors and, as a result, LOIs have been signed for the provision of key services, including the FPSO, the drilling rig, well services, subsea production systems and helicopter services, as well as vendor funding. The process to convert the LOIs into fully termed executed contracts is well advanced and letters of award will be issued as we go through the sanction process.

Through 2018, 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 largely 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 have been addressed in the final EIS submission. Engagement with FIG continues with a view to obtaining the consents and agreements necessary to be in a position to reach a final investment decision.

The Sea Lion Discovery Area is due to expire on 15 April 2020. The submission of the final Field Development Plan for FIG approval is expected before that date and therefore no further license extension is currently thought to be required from FIG.

South and East Falkland Basin (100% working interest)

Through the acquisition of Falkland Oil and Gas ("FOGL") in 2016, 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 and, 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 Basins' interests.

Abu Sennan, Egypt (22% working interest)

Production from the six development leases within the Abu Sennan concession increased during 2018 with production during the period averaging approximately 813 boepd net to Rockhopper (2017: 760 boepd).

In July 2018, Rockhopper was pleased to announce the commencement of the 2018 drilling campaign on the Abu Sennan concession which included the drilling of two development wells ("Al Jahraa-6" and "Al Jahraa-10"), one exploration well ("ASZ-1X"), and a water injection programme targeting the Al Jahraa field.

Al Jahraa-6

The Al Jahraa-6 development well spudded on 4 July 2018 and reached total depth of 3,935m MD (-3,623m tvdss) in the Kharita Formation on 19 August 2018. Mudlogs indicated the presence of oil in the Abu Roash C, D, E and G levels and the deeper exploration target in the Bahariya Formation. The Bahariya formation was put on test on 22 September 2018 and, after clean-up, is producing in excess of 550 barrels of oil per day ("bopd") with a stable water cut of 22%. This represents the first commercial oil production from the Bahariya formation within the Abu Sennan concession. The well has been completed to allow potential future production from Abu Roash G and C levels. The Company believes that the Bahariya discovery de-risks additional exploration targets at the same level elsewhere in the concession.

Al Jahraa-10

The Al Jahraa-10 development well reached total depth on 16 October 2018 in the Abu Roash-F Formation. Oil pay was calculated in the Abu Roash-C and Abu Roash-D levels. Following testing operations, the well was brought into production from Abu Roash-C at a rate of 130 bopd gross, and subject to further increase. Upside potential exists in Abu Roash-D which is being evaluated for possible acid stimulation.

ASZ-1X

Exploration well ASZ-1X located on Prospect S was spudded on 8 November 2018 and was the first of two commitment wells to be drilled in the first phase of the new concession. An oil discovery was made in the Abu Roash-C level. The award of a development lease over the discovery has recently been approved by EGPC and production has commenced.

Water injection

The water injection programme in Al Jahraa began on 14 July 2018. Injection rates have increased steadily over time, with an accompanying reduction in wellhead pressure, indicating that reservoir injectivity has become established. Injection rates into the Al Jahraa-9 well are currently averaging approximately 2,000 barrels of water per day, which is sufficient to re-pressurise the reservoir.

2019 drilling campaign

Following joint venture approval, an active drilling programme has been agreed for 2019 including the drilling of one exploration well (SW-ASH-1X), two in-fill oil producer wells (Al Jahraa-11 and Al Jahraa-7) and a second water injection well on the Al Jahraa field. Activity in 2019 continues the planned development programme in the Al Jahraa field, as well as further exploration on the concession.

The Al Jahraa-11 development well, the first in the 2019 programme, was spudded on 13 March 2019 and is targeting the AR-C and Bahariya reservoirs. The well is expected to take approximately two months to complete.

Guendalina, Italy (20% working interest)

Production decline at Guendalina continued to be broadly in line with expectations during 2018 with production over the period averaging approximately 30,000 standard cubic metres ("scm") per day of gas net to Rockhopper (approximately 180 boe per day). Plant availability over the period continued to be strong with production from the side-track well in 2015 continuing to make a material contribution to field production. Efforts continue with the operator to manage declining production levels as well as reduce operating costs.

Civita, Italy (100% working interest)

In February 2018, a depressurisation event occurred at the Civita pipeline and, as a result, production was suspended. Following remedial works and reinstatement of the pipeline, production recommenced in July 2018 at pre-incident levels of approximately 20,000 scm per day of gas (approximately 130 boe per day).

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. However, following failure to satisfy all relevant conditions precedent, including receipt of requisite regulatory approvals in Italy, the Company and Cabot have mutually agreed not to proceed with the transaction.

Monte Grosso, Italy (23% working interest)

Rockhopper transferred the operatorship of the Serra San Bernado permit (which contains the Monte Grosso prospect) to Eni during 2016. Since that time, options for the design of a well on the Monte Grosso prospect have been explored and work undertaken to secure the permits and approvals required to drill a well.

However, on 12 February 2019, the Italian government introduced certain further changes to oil and gas law through the "Sustainable Energy Bill". These changes include, amongst other things, a temporary suspension on exploration activities including the drilling of exploration wells. Discussions are ongoing between the Serra San Bernado joint venture partners to agree a forward plan.

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

Exploration commitment well Raya-1X in the El Qa'a Plain concession was spudded on 17 June 2018 and reached TD approximately two weeks later. At the primary Nukhul Formation objective, wireline logging confirmed the presence of good porosity sands, although no hydrocarbons were encountered. The well has been plugged and abandoned and the concession relinquished.

FINANCIAL REVIEW

Overview

During 2018, significant progress was made to advance and execute the financing plan for the Sea Lion Phase 1 development. Submission of the PIM and formal funding application for senior project finance debt, expected in Q2 2019, represents a material milestone in the funding process.

Our Greater Mediterranean portfolio continues to provide a low-cost, short-cycle production base which has delivered strong revenues and operating cash flows for the Company which have more than covered the Group's G&A costs.

RESULTS SUMMARY

US$m (unless otherwise specified)	2018	2017
Production (kboepd)	1.1	1.2
Revenue	10.6	10.4
Cash operating costs	4.6	4.1
Recurring administrative expenses ("G&A")	5.3	5.3
Loss after tax	(7.1)	(6.1)
Cash in flow from operating activities	5.4	1.6
Cash resources	40.4	50.7
Net assets	415.3	420.6

Results for the year

For the year ended 31 December 2018, the Group reported revenues of US$10.6 million and cash from operating activities of US$5.4 million.

Revenue

The Group's revenues of US$10.6 million (2017: $10.4 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 an increase in realised oil and gas prices, offset by a modest reduction in production (due to natural field decline at Guendalina and pipeline issues at Civita).

Working interest production averaged approximately 1,064 boepd during 2018, a small reduction over the comparable period (2017: 1,184 boepd).

During the year, the Group's gas production in Italy was sold under short-term contract with an average realised price of Euro 0.25 per scm (2017: Euro 0.19 per scm), equivalent to US$8.2 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$68.4 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$4.6 million (2017: US$4.1 million). The small increase in underlying cash operating costs is primarily due to the costs associated with the development wells and water injection programme being carried out at Abu Sennan as well as incremental operating costs at Guendalina. Cash operating costs on a per barrel of oil equivalent basis remain attractive at US$11.7 per boe.

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, since 2014. G&A costs in 2018 amounted to US$5.3 million, flat with the comparable year (2017: US$5.3 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 2018, the Group had cash resources of US$40.4 million (31 December 2017: US$50.7 million) and no debt.

Cash resources movements during the year:

	US$m
Opening cash balance (31 December 2017)	51
Revenues	11
Cost of sales	(5)
Falkland Islands	(11)
Greater Mediterranean	(4)
Admin and miscellaneous	(2)
Closing cash balance (31 December 2018)	40

Falkland Islands spend of US$11.0 million relates primarily to pre-development activities on Sea Lion (2017: US$6.7 million).

Spend in the Greater Mediterranean largely relates to the Egyptian drilling campaigns at Abu Sennan and El Qa'a Plain.

Admin and miscellaneous includes G&A, foreign exchange, movements in working capital balances as well as a non-recurring VAT credit received during the period.

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 10% and 12.5% was used for the Group's Greater Mediterranean and Falkland Islands assets respectively.

With no cash flow generation expected from Sea Lion until 2022 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 seven years.

Mergers, acquisitions and disposals

On 8 June 2017, Rockhopper announced the conditional 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").

Following failure to satisfy all relevant conditions precedent, including receipt of requisite regulatory approvals in Italy, the Company and Cabot have mutually agreed not to proceed with the transaction. As a result, Rockhopper retains the benefit of the positive cash flows generated from the Civita portfolio which, had the transaction proceeded, would have been paid to Cabot.

Taxation

On the 8 April 2015, the Group agreed binding documentation ("Tax Settlement Deed") with the FIG 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.

Due to the movement in the Sterling:US dollar exchange rate, the outstanding tax liability in US dollar terms has reduced to US$76.1 million (31 December 2017: US$80.6 million). The outstanding tax liability is classified as non-current and is discounted to a year-end value of US$37.9 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).

Brexit

It is the view of the Board that, given the Group's focus on the North Falkland Basin and Greater Mediterranean region, Rockhopper's business, assets and operations will not be materially affected by Brexit. Rockhopper derives a significant proportion of its revenue from crude oil, a globally traded commodity priced in US dollars.

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 which has historically been common to many upstream companies operating in the country. As at 31 December 2018, Rockhopper's EGPC receivable balance was approximately US$1.3 million.

Cash forecasts are regularly produced based on, inter alia, the Group's production and expenditure forecasts and management's best estimates of future commodity prices. Sensitivities are run to reflect different scenarios including changes in production rates, possible reductions in commodity prices and increased costs. Management's base case forecast assumes an oil price of US$65/bbl in 2019 and 2020, production in line with prevailing rates and expenditures in line with approved budgets. The Group has run downside scenarios, where oil prices are reduced by a flat $10/bbl throughout the going concern period and where cost expenditures have increased by 5%.

Under the base case forecast and the downside scenarios run, the Group will have sufficient financial headroom to meet forecast cash requirements for the 12 months from the date of approval of the 2018 financial statements. However, beyond the 12 month going concern assessment depending on the timing of sanction for the Sea Lion development, in the absence of any mitigating actions, the Group may have insufficient funds to meet its forecast cash requirements.Potential mitigating actions could include non-core asset disposals, collection of arbitration award proceeds, deferral of expenditure or raising additional equity.

Accordingly, after making enquiries and considering the risks described above, 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 2018 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

1 April 2019

Group income statement

for the YEAR ended 31 DeCEMBER 2018

		Year ended 31 Dec 18	Year ended 31 Dec 17
	Notes	$'000	$'000
Revenue		10,580	10,401
Other cost of sales		(4,563)	(4,100)
Depreciation and impairment of oil and gas assets		(3,968)	(5,473)
Total cost of sales	4	(8,531)	(9,573)
Gross profit/(loss)		2,049	828
Exploration and evaluation expenses	5	(5,014)	(3,422)
Costs in relation to acquisition and group restructuring		(58)	-
Recurring administrative costs		(5,328)	(5,282)
Total administrative expenses	6	(5,386)	(5,282)
Charge for share based payments	9	(1,478)	(864)
Other income		943	-
Foreign exchange movement	10	1,208	(966)
Results from operating activities and other income		(7,678)	(9,706)
Finance income	11	825	783
Finance expense	11	(253)	(39)
Loss before tax		(7,106)	(8,962)
Tax	12	(25)	2,823
LOSS FOR THE YEAR ATTRIBUTABLE TO THE EQUITY SHAREHOLDERS OF THE PARENT COMPANY		(7,131)	(6,139)
Loss per share: cents
Basic	13	(1.57)	(1.34)
Diluted	13	(1.57)	(1.34)

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

Group statement of comprehensive income

for the YEAR ended 31 DECEMBER 2018

	Year ended 31 Dec 18	Year ended 31 Dec 17
	$'000	$'000
Loss for the year	(7,131)	(6,139)
Exchange differences on translation of foreign operations	371	(1,151)
TOTAL COMPREHENSIVE LOSS FOR THE YEAR	(6,760)	(7,290)

Group balance sheet

as at 31 DECEMBER 2018

		31 Dec	31 Dec
		2018	2017
	Notes	$'000	$'000
NON CURRENT ASSETS
Exploration and evaluation assets	14	447,035	432,147
Property, plant and equipment	15	11,836	11,585
Goodwill	16	10,308	10,789
CURRENT ASSETS
Inventories		1,779	1,621
Other receivables	17	9,510	16,840
Restricted cash	18	568	540
Term deposits	19	30,000	30,000
Cash and cash equivalents		10,426	20,729
Assets held for sale	20	-	3,814
TOTAL ASSETS		521,462	528,065
CURRENT LIABILITIES
Other payables	21	15,148	12,772
NON-CURRENT LIABILITIES
Tax payable	22	37,860	40,057
Provisions	23	13,888	5,986
Deferred tax liability	24	39,223	39,202
Liabilities directly associated with assets held for sale	20	-	9,450
TOTAL LIABILITIES		106,119	107,467
EQUITY
Share capital	25	7,205	7,200
Share premium	26	3,422	3,282
Share based remuneration	26	5,103	5,609
Own shares held in trust	26	(3,369)	(3,383)
Merger reserve	26	74,332	74,332
Foreign currency translation reserve	26	(9,748)	(10,119)
Special reserve	26	456,680	460,077
Retained losses	26	(118,282)	(116,400)
ATTRIBUTABLE TO THE EQUITY SHAREHOLDERS OF THE COMPANY		415,343	420,598
TOTAL LIABILITIES AND EQUITY		521,462	528,065

These financial statements were approved by the directors and authorised for issue on 1 April 2019 and are signed on their behalf by:

STEWART MACDONALD

CHIEF FINANCIAL OFFICER

Group statement of changes in equity

for the YEAR ended 31 DECEMBER 2018

						Foreign
				Shares		currency
	Share	Share	Share based	held	Merger	translation	Special	Retained	Total
	capital	premium	remuneration	in trust	reserve	reserve	reserve	losses	Equity
	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000
Balance at 31 December 2016	7,194	3,149	6,251	(3,407)	74,332	(8,968)	462,549	(114,106)	426,994
Total comprehensive loss for the year	-	-	-	-	-	(1,151)	-	(6,139)	(7,290)
Share based payments	-	-	864	-	-	-	-	-	864
Share issues in relation to SIP	6	133	-	(109)	-	-	-	-	30
Other transfers	-	-	(1,506)	133	-	-	(2,472)	3,845	-
Balance at 31 December 2017	7,200	3,282	5,609	(3,383)	74,332	(10,119)	460,077	(116,400)	420,598
Total comprehensive loss for the year	-	-	-	-	-	371	-	(7,131)	(6,760)
Share based payments (see note 9)	-	-	1,478	-	-	-	-	-	1,478
Share issues in relation to SIP	5	140	-	(118)	-	-	-	-	27
Other transfers	-	-	(1,984)	132	-	-	(3,397)	5,249	-
Balance at 31 December 2018	7,205	3,422	5,103	(3,369)	74,332	(9,748)	456,680	(118,282)	415,343

Group cash flow statement

for the YEAR ended 31 DECEMBER 2018

		Year ended 31 Dec 18	Year ended 31 Dec 17
	Notes	$'000	$'000
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss before tax		(7,106)	(8,962)
Adjustments to reconcile net losses to cash:
Depreciation	15	4,111	5,687
Share based payment charge	9	1,478	864
Exploration impairment expenses	14	3,884	2,321
Finance expense		253	40
Finance income		(825)	(783)
Foreign exchange	10	(2,256)	3,331
Operating cash flows before movements in working capital		(461)	2,498
Changes in:
Inventories		(23)	-
Other receivables		7,029	(964)
Payables		(103)	110
Movement on other provisions		(1,012)	(14)
Cash from/(utilised by) operating activities		5,430	1,630
CASH FLOWS FROM INVESTING ACTIVITIES
Capitalised expenditure on exploration and evaluation assets		(13,940)	(25,366)
Purchase of property, plant and equipment		(1,844)	(1,451)
Acquisition of Beach Egypt		(658)	(6,266)
Interest		750	566
Investing cash flows before movements in capital balances		(15,692)	(32,517)
Changes in:
Restricted cash		(28)	(45)
Cash flow from investing activities		(15,720)	(32,562)
CASH FLOWS FROM FINANCING ACTIVITIES
Share incentive plan		27	30
Finance expense		(9)	(43)
Cash flow from financing activities		18	(13)
Currency translation differences relating to cash and cash equivalents		(31)	655
Net cash flow		(10,272)	(30,945)
Cash and cash equivalents brought forward		20,729	51,019
CASH AND CASH EQUIVALENTS CARRIED FORWARD		10,426	20,729

Notes to the group financial statements

for the Year ended 31 DECEMBER 2018

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 1 April 2019 and are subject to approval at the Annual General Meeting of shareholders on 15 May 2019.

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.

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

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

1.5 Going concern

At 31 December 2018, the Group had available cash and term deposits of $40 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.

Under the base case forecast and the downside scenarios run, the Group will have sufficient financial headroom to meet forecast cash requirements for at least the 12 months from the date of approval of the 2018 financial statements.

However, beyond the 12 month going concern assessment depending on the timing of sanction for the Sea Lion development, in the absence of any mitigating actions, the Group may have insufficient funds to meet its forecast cash requirements.

Potential mitigating actions could include non-core asset disposals, collection of arbitration award proceeds, deferral of expenditure or raising additional equity.

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.

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 indicators 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:

	31 Dec 2018	31 Dec 2017
£ : US$	1.28	1.35
€ : US$	1.15	1.20

(g) Revenue and income

(i) Revenue

Revenue arising from the sale of goods is recognised when control over a product or service is transferred to a customer, 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 2018

	Falkland	Greater
	Islands	Mediterranean	Corporate	Total
	$'000	$'000	$'000	$'000
Revenue	-	10,580	-	10,580
Cost of sales	-	(8,531)	-	(8,531)
Gross profit	-	2,049	-	2,049
Exploration and evaluation expenses	(253)	(3,682)	(1,079)	(5,014)
Costs in relation to acquisition and group restructuring	-	(58)	-	(58)
Recurring administrative costs	-	(1,406)	(3,922)	(5,328)
Total administrative expenses	-	(1,464)	(3,922)	(5,386)
Charge for share based payments	-	-	(1,478)	(1,478)
Other income	-	943	-	943
Foreign exchange gain/(loss)	2,197	(100)	(889)	1,208
Results from operating activities and other income	1,944	(2,254)	(7,368)	(7,678)
Finance income	-	8	817	825
Finance expense	-	(254)	1	(253)
Loss before tax	1,944	(2,500)	(6,550)	(7,106)
Tax	-	(25)	-	(25)
Profit/(loss) for year	1,944	(2,525)	(6,550)	(7,131)
Reporting segments assets	440,314	41,992	39,156	521,462
Reporting segments liabilities	76,996	18,183	10,940	106,119
Depreciation	-	3,991	120	4,111

Year ended 31 December 2017

	Falkland	Greater
	Islands	Mediterranean	Corporate	Total
	$'000	$'000	$'000	$'000
Revenue	-	10,401	-	10,401
Cost of sales	-	(9,573)	-	(9,573)
Gross profit	-	828	-	828
Exploration and evaluation expenses	-	(2,369)	(1,053)	(3,422)
Costs in relation to acquisition and group restructuring	-	-	-	-
Other administrative costs	(7)	(1,487)	(3,788)	(5,282)
Total administrative expenses	(7)	(1,487)	(3,788)	(5,282)
Charge for share based payments	-	-	(864)	(864)
Foreign exchange movement	(3,791)	366	2,459	(966)
Results from operating activities and other income	(3,798)	(2,662)	(3,246)	(9,706)
Finance income	-	-	783	783
Finance expense	-	(30)	(9)	(39)
Loss before tax	(3,798)	(2,692)	(2,472)	(8,962)
Tax	2,866	(43)	-	2,823
Loss for year	(932)	(2,735)	(2,472)	(6,139)
Reporting segments assets	425,971	51,647	50,447	528,065
Reporting segments liabilities	80,462	19,551	7,454	107,467
Depreciation	-	5,498	189	5,687

4 Cost of sales

	Year ended 31 Dec 18	Year ended 31 Dec 17
	$'000	$'000
Cost of sales	4,563	4,100
Depreciation of oil and gas assets (see note 15)	3,968	5,473
	8,531	9,573

5 exploration and evaluation expenses

	Year ended 31 Dec 18	Year ended 31 Dec 17
	$'000	$'000
Allocated from administrative expenses (see note 6)	891	597
Capitalised exploration costs impaired (see note 14)	3,884	2,321
Other exploration and evaluation expenses	239	504
	5,014	3,422

6 Administrative expenses

	Year ended 31 Dec 18	Year ended 31 Dec 17
	$'000	$'000
Directors' salaries and fees, including bonuses (see note 7)	1,727	1,934
Other employees' salaries	2,638	2,604
National insurance costs	637	651
Pension costs	164	260
Employee benefit costs	88	92
Total staff costs (including group restructuring costs)	5,254	5,541
Amounts reallocated	(2,105)	(2,200)
Total staff costs charged to administrative expenses	3,149	3,341
Auditor's remuneration (see note 8)	251	244
Other professional fees	1,058	992
Other	1,648	1,481
Depreciation	143	214
Amounts reallocated	(863)	(990)
	5,386	5,282

The average number of staff employed during the year was 20 (31 December 2017: 24). The relative decrease between years reflects the continued restructuring of the Greater Mediterranean operation. As at 31 December 2018 the number of staff employed had reduced to 19.

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

	Year ended 31 Dec 18	Year ended 31 Dec 17
	$'000	$'000
Executive salaries	912	1,141
Executive bonuses	250	267
Company pension contributions to money purchase schemes & pension cash allowance	137	104
Benefits	28	37
Non-executive fees	400	385
	1,727	1,934

The total remuneration of the highest paid director was:

	Year ended 31 Dec 18	Year ended 31 Dec 17
	£	£
Annual salary	373,000	362,100
Bonuses	93,000	108,600
Money purchase pension schemes	55,900	36,900
Benefits	11,200	10,904
	533,100	518,504

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

8 Auditor's remuneration

	Year ended 31 Dec 18	Year ended 31 Dec 17
	$'000	$'000
KPMG LLP
Fees payable to the Company's auditor for the audit of the Company's annual financial statements	128	117
Fees payable to the Company's auditor and its associates for other services:
Audit of the accounts of subsidiaries	72	63
Half year review	38	45
Tax compliance services	13	19
	251	244

9 Share based Payments

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

	Year ended 31 Dec 18	Year ended 31 Dec 17
	$'000	$'000
Charge for the long term incentive plan options	1,360	768
Charge for shares issued under the SIP throughout the year	118	96
	1,478	864

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. 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

Grant date:	23 April 2018	16 June 2017	22 Apr 2016	13 Apr 2015
Closing share price	25.7p	21.25p	31.5p	64.0p
Number granted	7,000,000	6,700,000	10,047,885	4,111,838
Weighted average volatility	44.4%	53.3%	60.4%	44.5%
Weighted average volatility of index	64.0%	71.4%	71.2%	55.8%
Weighted average risk free rate	0.90%	0.18%	0.58%	0.70%
Correlation in share price movement with comparator group	13.0%	15.3%	27.5%	33.5%
Exercise price	0p	0p	0p	0p
Dividend yield	0%	0%	0%	0%

The following movements occurred during the year:

		At 31 December			At 31 December
Issue date	Expiry date	2017	Issued	Lapsed	2017
8 October 2013	8 October 2023	546,145	-	-	546,145
10 March 2014	10 March 2024	70,391	-	-	70,391
13 April 2015	13 April 2025	2,977,944	-	(2,977,944)	-
22 April 2016	22 April 2026	6,017,850	-	-	6,017,850
16 June 2017	16 June 2027	6,700,000	-	-	6,700,000
23 April 2018	23 April 2028	-	7,000,000	-	7,000,000
		16,312,330	7,000,000	(2,977,944)	20,334,386

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 2017 £41,997) worth of Free Shares to eligible employees.

This resulted in 156,268 (year ended 31 December 2017: 154,826) Free Shares and under the SIP scheme matching and partnership shares issued were 223,131 (year ended 31 December 2017: 302,622) in the period.

	31 Dec	31 Dec
	2018	2017
The average fair value of the shares awarded (pence)	28	23
Vesting	100%	100%
Dividend yield	Nil	Nil
Lapse due to withdrawals	Nil	Nil

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:

		Exercise price	At 31 Dec			At 31 Dec
Issue date	Expiry date	(pence)	2017	Exercised	Lapsed	2018
22 November 2008	22 November 2018	19.25	355,844	(355,844)	-	-
3 July 2009	3 July 2019	30.87	103,368	-	-	103,368
11 January 2011	11 January 2021	372.75	196,712	-	(21,664)	175,048
14 July 2011	14 July 2021	239.75	43,587	-	-	43,587
16 August 2011	16 August 2021	237.00	17,035	-	-	17,035
13 December 2011	13 December 2021	240.75	29,594	-	-	29,594
17 January 2012	17 January 2022	303.75	269,026	-	(24,485)	244,541
30 January 2013	30 January 2023	159.00	317,845	-	(40,683)	277,162
			1,333,011	(355,844)	(86,832)	890,335

10 FOREign Exchange

	Year ended 31 Dec 18	Year ended 31 Dec 17
	$'000	$'000
Foreign exchange gain/(loss) on Falkland Islands tax liability (see note 22)	2,197	(3,791)
Foreign exchange gain on term deposits, cash and restricted cash	59	460
	2,256	(3,331)
Foreign exchange on operating activities	(1,048)	2,365
Total net foreign exchange gain/(loss)	1,208	(966)

11 FINANCE INCOME AND EXPENSE

	Year ended 31 Dec 18	Year ended 31 Dec 17
	$'000	$'000
Bank and other interest receivable	825	783
Total finance income	825	783

Unwinding of discount on decommissioning provisions (see note 23)	244	(4)
Other	9	43
Total finance expense	253	39

12 Taxation

	Year ended 31 Dec 18	Year ended 31 Dec 17
	$'000	$'000
Current tax:
Overseas tax	-	(14)
Adjustment in respect of prior years	-	(2,866)
Total current tax	-	(2,880)

Deferred tax:
Overseas tax	25	57
Total deferred tax - note 24	25	57
Tax on profit on ordinary activities	25	(2,823)
Loss on ordinary activities before tax	(7,106)	(8,962)
Loss on ordinary activities multiplied at 26% weighted average rate (31 December 2017: 26%)	(1,848)	(2,330)
Effects of:
Income and gains not subject to taxation	(2,528)	(1,884)
Expenditure not deductible for taxation	1,688	3,005
Depreciation in excess of capital allowances	1,050	(722)
IFRS2 Share based remuneration cost	384	189
Losses carried forward	1,275	1,656
Effect of tax rates in foreign jurisdictions	(21)	134
Adjustments in respect of prior years	25	(2,866)
Other	-	(5)
Tax charge/(credit) for the year	25	(2,823)

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:

	Year ended 31 Dec 18	Year ended 31 Dec 17
	$'000	$'000
UK	66,740	62,033
Falkland Islands	592,483	576,121
Italy	75,278	61,961

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

	31 Dec 18	31 Dec 17
	Number	Number
Shares in issue brought forward	457,116,500	456,659,052
Shares issued
- Issued under the SIP	379,399	457,448
Shares in issue carried forward	457,495,899	457,116,500
Weighted average number of Ordinary Shares for the purposes of basic earnings per share	457,369,112	456,945,871
Effects of dilutive potential Ordinary shares
Contingently issuable shares	-	-
	457,369,112	456,945,871

	$'000	$'000
Net loss after tax for purposes of basic and diluted earnings per share	(7,131)	(6,139)
Loss per share - cents
Basic	(1.57)	(1.34)
Diluted	(1.57)	(1.34)

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	Greater
	Islands	Mediterranean	Total
	$'000	$'000	$'000
As at 31 December 2016	418,584	7,835	426,419
Additions	7,387	1,317	8,704
Written off to exploration costs	-	(2,321)	(2,321)
Transfer to assets held for sale (see note 20)	-	(824)	(824)
Foreign exchange movement	-	169	169
As at 31 December 2017	425,971	6,176	432,147
Additions	14,595	3,364	17,959
Written off to exploration costs	(252)	(3,632)	(3,884)
Transfer from assets held for sale (see note 20)	-	834	834
Foreign exchange movement	-	(21)	(21)
As at 31 December 2018	440,314	6,721	447,035

FALKLAND ISLANDS LICENCES

The additions during the period of $14.6 million relate principally to the Sea Lion development.

In assessing whether it is necessary to undertake a detailed impairment test, management consider whether there are any triggers, e.g. a significant change in the view on long term oil pricing or project cost, that would suggest such a detailed test is necessary. Management do not consider there to be any such triggers.

Nevertheless, management, as a matter of good practice, run their cashflow model regularly. At the year end, the key inputs to this model were a 2019 real terms Brent 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 2019 (with such decision dependent on securing 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.

Sensitivity analysis is 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 exists although the assets require further appraisal.

GREATER MEDITERRANEAN LICENCES

The $3.6 million additions during the period predominantly relate to work on the Egyptian license interests. An impairment of $3.4 million was recognised during the year in respect of the Raya-1X exploration commitment well in the El Qa'a Plain concession which encountered no hydrocarbons.

15 property, plant and equipment

	Oil and gas	Other		Oil and gas	Other
	assets	assets	31 Dec 18	assets	assets	31 Dec 17
	$'000	$'000	$'000	$'000	$'000	$'000
Cost brought forward	31,043	1,134	32,177	32,378	1,096	33,474
Additions	1,996	25	2,021	970	17	987
Foreign exchange	(762)	(10)	(772)	2,524	21	2,545
Disposals	-	(271)	(271)	-	-	-
Transfer from/(to) assets held for sale	4,891	-	4,891	(4,829)	-	(4,829)
Cost carried forward	37,168	878	38,046	31,043	1,134	32,177
Accumulated depreciation and impairment loss brought forward	(19,751)	(841)	(20,592)	(14,831)	(618)	(15,449)
Current year depreciation charge	(3,968)	(143)	(4,111)	(5,473)	(214)	(5,687)
Foreign exchange	611	7	618	(1,790)	(9)	(1,799)
Disposals	-	271	271	-	-	-
Transfer (from)/to assets held for sale	(2,396)	-	(2,396)	2,343	-	2,343
Accumulated depreciation and impairment loss carried forward	(25,504)	(706)	(26,210)	(19,751)	(841)	(20,592)

Net book value brought forward	11,292	293	11,585	17,547	478	18,025
Net book value carried forward	11,664	172	11,836	11,292	293	11,585

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

Asset additions relate almost entirely to the addition of the Abu Sennan production asset in Egypt.

Consistent with the approach taken to assess whether the Falkland Island licences should be subject to impairment testing, management did not identify any triggers that would require a formal impairment calculation to be undertaken. Therefore, no impairment was recognised in the period (2017: $nil).

Nonetheless, similar to the Falkland Islands licences future discounted cash flows expected to be derived from production of commercial reserves (the value in use being the recoverable amount) were compared 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 2019 and 2020, and a Brent oil price of $70/bbl and a gas price of €0.25/sm3 in 2019 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 impairments were identified in this process.

16 GOODWILL

				Greater
				Mediterranean
				$'000
As at 31 December 2017				10,789
Foreign exchange movement				(481)
As at 31 December 2018				10,308

Goodwill relates to the corporate acquisition of Mediterranean Oil & Gas plc ("MOG") during the period ended 31 December 2014. This goodwill is included in the Greater Mediterranean segment and allocated to the Italian CGU which have the optionality and potential to provide value in excess of this fair value as well as representing 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 reduction in the period of $481,000 (2017: $1,350,000 increase) 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 a long term realised gas price of €0.25/sm3 and a realised long-term oil price of $70/bbl in 2019 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

	31 Dec 18	31 Dec 17
	$'000	$'000
Current
Receivables	3,811	9,826
Prepayments	332	473
Accrued interest	396	323
Income tax	81	85
Other	4,890	6,133
	9,510	16,840

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 2018, the receivable balance due from EGPC was $1.3 million which is due solely to Rockhopper following the settlement of the amount which was payable to the former parent company of Rockhopper Egypt Pty. Limited, Beach Energy Limited.

Other receivables predominantly relate to IVA balances due from the Italian tax authorities which are in the process of being reclaimed.

18 Restricted cash

	31 Dec 18	31 Dec 17
	$'000	$'000
Charged accounts	568	540
	568	540

19 Term Deposits

	31 Dec 18	31 Dec 17
	$'000	$'000
Maturing after the period end:
Within three months	10,000	10,000
Six to nine month	10,000	10,000
Nine months to one year	10,000	10,000
	30,000	30,000

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. Following failure to satisfy all relevant conditions precedent, including receipt of requisite regulatory approvals in Italy, the Group has decided not to proceed with the transaction.

21 Other payables and accrualS

	31 Dec 18	31 Dec 17
	$'000	$'000
Accounts payable	2,462	2,551
Accruals	12,246	8,654
Other creditors	440	1,567
	15,148	12,772

Accruals have increased due to costs associated with the Sea Lion development.

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

	31 Dec 18	31 Dec 17
	$'000	$'000
Current tax payable	-	-
Non current tax payable	37,860	40,057
	37,860	40,057

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 was 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 gain of US$2.2 million (2017: US$3.8 million loss) has been recognised in the year.

23 Provisions

	Abandonment	Other
	provision	provisions	31 Dec 18	31 Dec 17
	$'000	$'000	$'000	$'000
Brought forward	5,892	94	5,986	14,914
Amounts utilized	(854)	(27)	(881)	(1,704)
Amounts arising in the period	-	10	10	11
Unwinding of discount	247	-	247	-
Transfer from/(to) liabilities associated with assets held for sale	8,750	-	8,750	(8,772)
Foreign exchange	(220)	(4)	(224)	1,537
Carried forward at period end	13,815	73	13,888	5,986

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

	31 Dec 18	31 Dec 17
	$'000	$'000
At beginning of period	39,202	39,145
Movement in period	21	57
At end of period	39,223	39,202

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 2018 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 2018 would be $185 million (31 December 2017: $176 million).

25 Share capital

	31 Dec 2018		31 Dec 2017
	$'000	Number	$'000	Number
Called up, issued and fully paid: Ordinary shares of £0.01 each	7,205	457,495,899	7,200	457,116,500

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:

Share premium	Amount subscribed for share capital in excess of its nominal value.
Share based remuneration	The share incentive plan reserve captures the equity related element of the expenses recognised for the issue of options, comprising the cumulative charge to the income statement for IFRS2 charges for share based payments less amounts released to retained earnings upon the exercise of options.
Own shares held in trust	Shares held in trust represent the issue value of shares held on behalf of participants in the SIP by Capita IRG Trustees Limited, the trustee of the SIP as well as shares held by the Employee Benefit Trust which have been purchased to settle future exercises of options.
Merger reserve	The difference between the nominal value and the fair value of shares issued on acquisition of subsidiaries.
Foreign currency translation reserve	Exchange differences arising on consolidating the assets and liabilities of the Group's subsidiaries are classified as equity and transferred to the Group's translation reserve.
Special reserve	The reserve is non distributable and was created following cancellation of the share premium account on 4 July 2013. It can be used to reduce the amount of losses incurred by the Parent Company or distributed or used to acquire the share capital of the Company subject to settling all contingent and actual liabilities as at 4 July 2013. Should not all of the contingent and actual liabilities be settled, prior to distribution the Parent Company must either gain permission from the actual or contingent creditors for distribution or set aside in escrow an amount equal to the unsettled actual or contingent liability.
Retained losses	Cumulative net gains and losses recognised in the financial statements.

27 Lease commitments

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

	31 Dec 18	31 Dec 17
	$'000	$'000
Total committed within 1 year	504	569
Total committed between 1 and 5 years	351	1,285
	855	1,854

28 CAPITAL COMMITMENTS

Capital commitments represent the Group's share of expected costs in relation to its licence interests 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 2019 of US$18 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.


	Year ended 31 Dec 18	Year ended 31 Dec 17
	$'000	$'000
Short term employee benefits	1,636	1,875
Pension contributions	137	59
Share based payments	742	120
	2,515	2,054

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 is exposed to foreign exchange movements on monetary assets and liabilities denominated in currencies other than US$, in particular the tax liability with the Falkland Island Government which is a GB£ denominated balance. In addition a number of the Group's subsidiaries have a functional currency other than US$, 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 $41.0 million of which $35.3 million was held in US$ denominations. The following table summarises the split of the Group's assets and liabilities by currency:

Currency denomination of balance	$	£	€	EGP £	CAD $
	$'000	$'000	$'000	$'000	$'000
Assets
31 December 2018	491,148	2,440	27,234	640	-
31 December 2017	495,535	2,989	29,496	22	-

Liabilities
31 December 2018	51,200	38,346	16,518	-	55
31 December 2017	47,087	42,031	18,349	-	-

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:

	Pre tax profit		Total equity
	+10% US$ rate increase	-10% US$ rate decrease	+10% US$ rate increase	-10% US$ rate decrease
	$'000	$'000	$'000	$'000
US$ against GB£
31 December 2018	(3,591)	3,591	(3,591)	3,591
31 December 2017	(3,904)	3,904	(3,904)	3,904

US$ against euro
31 December 2018	1,072	(1,072)	1,072	(1,072)
31 December 2017	1,117	(1,117)	1,117	(1,117)

Capital risk management: the Group manages capital to ensure that it is able to continue as a going concern whilst maximising the return to shareholders. The capital structure consists of cash and cash equivalents and equity. The board regularly monitors the future capital requirements of the Group, particularly in respect of its ongoing development programme.

Credit risk; the Group recharges partners and third parties for the provision of services and for the sale of Oil and Gas. Should the companies holding these accounts become insolvent then these funds may be lost or delayed in their release. The amounts classified as receivables as at the 31 December 2018 were $3,948,000 (31 December 2017: $9,826,000). Credit risk relating to the Group's other financial assets which comprise principally cash and cash equivalents, term deposits and restricted cash arises from the potential default of counterparties. Investments of cash and deposits are made within credit limits assigned to each counterparty. The risk of loss through counterparty failure is therefore mitigated by the Group splitting its funds across a number of banks, two of which are part owned by the British government.

Interest rate risks; the Group has no debt and so its exposure to interest rates is limited to finance income it receives on cash and term deposits. The Group is not dependent on its finance income and given the current interest rates the risk is not considered to be material.

Liquidity risks; the Group makes limited use of term deposits where the amounts placed on deposit cannot be accessed prior to their maturity date. The amounts applicable at the 31 December 2018 were $30,000,000 (31 December 2017: $30,000,000).

Glossary:

2C	best estimate of contingent resources
2P	proven plus probable reserves
3C	a high estimate category of contingent resources
AGM	Annual General Meeting
Beach Energy	Beach Petroleum (Egypt) Pty Limited
Best	a best estimate category of Prospective Resources also used as a generic term to describe a best, or mid estimate
Board	the Board of Directors of Rockhopper Exploration plc
boe	barrels of oil equivalent
bopd	barrels of oil per day
boepd	barrels of oil equivalent per day
Capex	capital expenditure
Cash resources	Cash and term deposits
Company	Rockhopper Exploration plc
E&P	exploration and production
EGPC	Egyptian General Petroleum Company
EIS	Environmental Impact Statement
ERCE	ERC Equipoise Limited
Farm-down	to assign an interest in a licence to another party
FEED	Front End Engineering and Design
FDP	Field Development Plan
FID	Final Investment Decision
FIG	Falkland Islands Government
FOGL	Falkland Oil and Gas Limited
FPSO	Floating Production, Storage and Offtake vessel
G&A	General and administrative costs
Group	the Company and its subsidiaries
High	high estimate category of Prospective Resources also used as a generic term to describe a high or optimistic estimate
IFRS	International Financial Reporting Standard
kboepd	thousand barrels of oil equivalent per day
Low	a low estimate category of Prospective Resources also used as a generic term to describe a low or conservative estimate
LOI	Letter of Intent
mmbbls	million barrels
mmboe	million barrels of oil equivalent
mmbtu	million British thermal units
MMstb	million stock barrels (of oil)
mscf	thousand standard cubic feet
net pay	the portion of reservoir containing hydrocarbons that through the placing of cut offs for certain properties such as porosity, water saturation and volume of shale determine the productive element of the reservoir
P&A	plug and abandon
PIM	Project Information Memorandum
Premier	Premier Oil plc
PSV	virtual exchange point
scm	standard cubic metre
STOIIP	stock-tank oil initially in place
SURF	Subsea, Umbilicals, Risers and Flowlines
tvdss	true vertical depth subsea

This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact rns@lseg.com or visit www.rns.com.

END

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