Final Results

RNS Number : 1427X

Lekoil Limited

26 August 2020

 

26 August 2020

Lekoil Limited

("LEKOIL" or the "Company")

FY 2019 Audited Final Results

LEKOIL (AIM: LEK), the oil and gas exploration and production company with a focus on Nigeria and West Africa, announces its final audited results for the year to 31 December 2019.

Operational Highlights

Otakikpo

· Production levels averaged approximately gross 5,305 bopd (2,122 bopd net to LEKOIL Nigeria)

· Updated Competent Person's Reports announcing a significant upgrade to 2P oil reserves estimates and prospective resources (unrisked) for LEKOIL Nigeria's working interest in the field

· Field Licence renewed

· Phase Two plans underway, subject to the securing of funding, for a five to seven well drilling programme, targeting the increase of production to around gross 15,000 to 20,000 bopd (6,000 - 8,000 bopd net to LEKOIL Nigeria)

OPL 310

· Advanced plans for the Ogo appraisal drilling programme with well locations selected. Funding discussions currently underway with industry partners

· LEKOIL executed a legally binding Cost and Revenue Sharing Agreement ("CRSA") to progress the appraisal and development programme activities at the OGO discovery and conversion to an Oil Mining Licence ("OML")

· OPL 310 Licence extended to 2 August 2022, following the payment of an extension fee by LEKOIL

OPL 276

· Acquired 45% participating interest in the Production Sharing Contract ("PSC") in relation to the Oil Prospecting Licence 276 from Newcross Petroleum Limited (subject to receipt of required consents)

· Preliminary resource estimates by Newcross, based on four wells resulting in four discoveries, reported gross recoverable volumes of 29 million barrels of oil and 333 Bcf of gas, upside of 33 million barrels of oil and 476 Bcf of gas (recoverable)

OPL 325

· Execution of the PSC in relation to the Oil Prospecting Licence 325 expected to occur in 2020

· On executing the PSC, LEKOIL intends to farm-down a portion of interest following a detailed prospect and lead risking study

Financial Highlights

· Equity crude sales proceeds of US$42.0 million

· Total production from the Otakikpo marginal field for the year at 759,666 barrels net to LEKOIL Nigeria

· The Group lifted 677,788 barrels for the year 2019, realizing an average sales price of approximately US$62 per barrel

· Loss for the year of US$12.0 million (2018: loss of US$7.8 million)

· Cash and bank balances of US$2.7 million as at 31 December 2019 (31 December 2018: US$10.4 million). Cash balance at 31 July 2020 of US$0.6 million

· As at 31 December 2019, total outstanding debt financing, net of cash, was US$16.5 million (31 December 2018: US$10.1 million)

· Target an immediate reduction of at least 40% in general and administrative expenses annually following the significant drop in oil prices in the first half of 2020

LEKOIL's annual report and accounts for the year ended 31 December 2019, together with the Notice of Annual General Meeting will be posted to shareholders shortly and a further announcement will be made as and when this has occurred. The Company also intends to publish an operational update and financial guidance for FY 2020 in short order.

Lekan Akinyanmi, LEKOIL's CEO, commented, "The priority for 2020 is to advance towards the start of the drilling programmes at both Otakikpo and Ogo in OPL 310. The next two years will prove to be transformative and provide key catalysts for value appreciation for shareholders through the drill bit as we advance in building a leading Africa-focused exploration and production business."

The information contained within this announcement is deemed by the Company to constitute inside information stipulated under the Market Abuse Regulation (EU) No. 596/2014.  Upon the publication of this announcement via the Regulatory Information Service, this inside information is now considered to be in the public domain.

For further information, please visit www.lekoil.com or contact:

LEKOIL Limited Ore Bajomo, Investor Relations	[phone]
Strand Hanson Limited (Financial & Nominated Adviser) James Spinney / Ritchie Balmer / Georgia Langoulant	[phone]
Mirabaud Securities Limited (Joint Broker) Peter Krens / Edward Haig-Thomas	[phone] / [phone]
SP Angel Corporate Finance LLP (Joint Broker) Richard Hail / Stuart Gledhill / Sam Wahab	[phone]
Instinctif (Financial PR) Mark Garraway / Dinara Shikhametova / Sarah Hourahane	[phone] [e-mail]

Chairman's and CEO's Statement

2019 was a pivotal year for LEKOIL in terms of achieving some of our critical targets and setting the tone for the transformation we expect to see in 2020. We achieved full alignment with the Nigerian Government and our joint venture partners and saw the resolution of the regulatory delays on OPL 310.

Accelerating our diversified asset strategy

Following engagements with our partners and the regulatory authorities, we secured the outstanding regulatory approvals and a pathway to commencing the Ogo appraisal well programme. The Group is focused on pursuing its diversified asset strategy, advancing the appraisal assets (OPL276 and OPL310), exploration assets (OPL325) and moving Otakikpo, the producing asset, onto its next phase.

Otakikpo - producing asset

Five to seven new wells drilling and processing infrastructure expansion programmes underway

In 2019, production levels at Otakikpo averaged approximately gross 5,305 bopd (2,122 bopd net to LEKOIL Nigeria). Preparations for Phase Two development commenced with the acquisition of 3D seismic in February. Plans are underway, subject to the necessary financing being secured, for a five to seven well drilling programme. The programme aims to increase production to around gross 15,000 to 20,000 bopd, and secure further investment in infrastructure facilities for crude oil evacuation.

In 2019, total production from Otakikpo was approximately 759,666 barrels for the full year. The Group had equity crude sales proceeds of US$42.0 million from 677,788 barrels lifted during the year. LEKOIL realised an average sales price of approximately US$62.0 per barrel.

In June, we released an updated report on Otakikpo, announcing a significant upgrade to 2P oil reserves estimates and prospective resources (unrisked) for LEKOIL Nigeria's 40% participating interest in the field. The report highlighted 48.6 million barrels gross 2P reserves, of which 19.4 million barrels corresponding to a 2P NPV10 of US$226 million, after income taxes net to LEKOIL.

In July, the Otakikpo Joint Venture between Green Energy International Limited (GEIL) and LEKOIL signed a Memorandum of Understanding (MOU) with Schlumberger and the subsidiary of a major international oil company which has been operating in Nigeria for more than half a century. The development plan consists of drilling up to seven new wells in Otakikpo and expanding processing infrastructure.

In October, the Otakikpo Joint Venture announced that Phase Two of the Otakikpo field plan has been sanctioned. Concurrently, the Joint Venture also renewed the field Licence. Schlumberger, in its role as non-financial, project execution partner has assessed the capability of the infrastructure on site, and believes it is capable, with some debottlenecking, to produce up to 12,000 bopd gross (4,800 bopd net to LEKOIL).

OPL 310 - appraisal and exploration asset

Full alignment with the Nigerian Government and JV partners

On March 28, 2019, the Federal High Court, sitting in Ikoyi, Lagos State, Nigeria ruled that LEKOIL's purported acquisition of shares in Afren Investment Oil and Gas (Nigeria) Limited ("AIOGNL") and by that, the 22.86% interest in OPL 310, is inchoate and invalid given that the Company is yet to obtain Ministerial Consent in respect of the transfer of the said shares. The Judge also ruled that pursuant to Articles 13.1.4 and 13.1.5 of the Joint Operating Agreement (JOA) between Optimum and AIOGNL, Optimum's consent is required to effect a transfer of AIOGNL's interest in OPL 310, or any part thereof, to LEKOIL. The 17.14% interest in OPL 310, held through Mayfair Assets & Trusts Limited, was not affected by the ruling.

The implication of the Judge's pronouncement that LEKOIL 310 Limited (a subsidiary of LEKOIL) has not acquired the shares of AIOGNL is that, pending receipt of Ministerial consent to the acquisition, AIOGNL retains its 22.86% participating interest in OPL 310.

LEKOIL 310 Limited had initially filed an appeal against the decision of the Federal High Court, but decided to withdraw legal action following receipt of a letter dated 8 May 2019 from the Ministry of Petroleum Resources relating to an application for an extension (re-award) to the OPL 310 Licence (the "Letter"). The Letter stated that the Government has noted that the OPL 310 Licence expired on 10 February 2019 and ownership of OPL 310 has accordingly reverted to the Government in line with Petroleum Act. The Letter further set out that the re-award would not be considered by the Honourable Minister of Petroleum Resources ("HMPR") until such point as the suit filed by LEKOIL against the HMPR is withdrawn by LEKOIL and the other parties. Failure by LEKOIL and others to withdraw the suit within 30 days of the Letter forecloses any consideration of re-award to Optimum Petroleum Development Limited, LEKOIL and their affiliates or subsidiaries.

LEKOIL 310 Limited decided to withdraw legal action on 16 May 2019. On 30 August 2019, Optimum and LEKOIL jointly announced the execution of a legally binding Cost and Revenue Sharing Agreement ("CRSA") to progress the appraisal and development programme activities at the Ogo discovery and conversion to an Oil Mining Licence ("OML"). In a letter dated 4 September 2019, the Federal Government of Nigeria and the Ministry of Petroleum Resources approved the extension of the OPL 310 Licence for three years, subject to the holders of the Licence paying an extension fee of US$7.5 million. LEKOIL paid the extension fee on behalf of the holders of the Licence and received a confirmation that the Licence is in force for an extended period to 2 August 2022.

OPL 276 - appraisal and exploration asset

45% interest in offshore licence with significant resource potential acquired from Newcross

In August 2019, LEKOIL agreed to acquire, subject to the receipt of the required consents, a 45% participating interest in the Production Sharing Contract ("PSC") in relation to the Oil Prospecting Licence 276 from Newcross Petroleum Limited ("Newcross"), covering a territory located onshore in the eastern Niger Delta basin. The Licence is covered by approximately 150 sq. km of 3D seismic, shot in 2008 by BGP Inc., a subsidiary of China National Petroleum Company, as well as various 2D seismic surveys. It is near three existing producing fields, all less than 20 kilometres away. Newcross has previously identified ten prospects and seven leads in the area covered by the Licence. Four wells have been drilled in the Licence area, resulting in four discoveries (two oil and two gas).

Preliminary resource estimates by Newcross, based on data from these four wells, reported gross recoverable volumes of 29 million barrels of oil and 333 Bcf of gas, upside of 33 million barrels of oil and 476 Bcf of gas (recoverable). LEKOIL has verified these estimates internally, but also intends to commission an independent Competent Persons Report in due course. LEKOIL sees a clear opportunity for re-entering one or more of these discovery wells, with the potential for rapid monetisation of resources thanks to the proximity to existing export facilities nearby.

The acquisition represents an excellent opportunity to further build our growing production base in line with our stated strategy to create a balanced portfolio of assets. We are optimistic about these prospects, which have shallow reservoirs and are cost-efficient to develop.

The acquisition is conditional upon, among other things, the extension of the term of the Licence and the PSC, obtaining the consent of the Nigerian National Petroleum Corporation ("NNPC") and obtaining the approval of the Minister of Petroleum Resources of the Federal Republic of Nigeria.

The application for extension has been filed with NNPC and awaits approval from both NNPC and ultimately the Minister of Petroleum Resources.

OPL 325 - exploration asset

On track with development and farm-down

OPL 325 is located in the offshore Dahomey Basin, some 50km to the south of OPL 310. We believe that the deep water turbidite fan play is particularly exciting for OPL 325 in which we have a significant interest via our subsidiary, Ashbert Oil and Gas Limited. In January 2018, an independent technical study prepared by Lumina Geophysical affirmed preliminary reviews of oil in place volumes of 5.7 billion Boe as an Unrisked Best Estimate case. It further underlined our belief in the prospectivity of this asset that was part of LEKOIL's original Dahomey Basin study.

Terms for a PSC in relation to OPL 325 have been negotiated and agreed between the NNPC and the contractor parties which is made up of the National Petroleum Development Company ("NPDC") and Local Content Vehicles. Execution of the PSC is expected to occur in 2020. On executing the PSC, we intend to farm-down a portion of our interest following a detailed prospect and lead risking study which is currently underway.

Financial review

In the year ended 31 December 2019, LEKOIL recorded a loss of US$12.0 million (2018: loss of US$7.8 million) and ended the period with cash and bank balances of US$2.7 million (31 December 2018: US$10.4 million). Total outstanding debt financing net of cash was US$16.5 million (2018: US$10.1 million)

In March 2019, documentation for the partial refinancing and re-denomination of the outstanding Naira Debt Facilities, totalling N3.1 billion, into one new US$8.6 million facility with FBNQ MB was completed. The new facility priced at LIBOR + 10%, had a six-month principal repayment moratorium effective June 2018 followed by quarterly principal repayments. As part of the transaction, the tenor on facilities with FBNQ MB (including the existing USD facility, amounting to US$5.0 million) was extended to 30 June 2021 from 30 June 2019. This partial refinancing and re-denomination transaction was performed to reduce the high financing costs of local currency debt.

Further debt capital of US$11.5 million was raised in October 2019 to fund Licence extension fees on OPL 310 and OPL 276 and to fully repay the outstanding balance on Shell Western Supply and Trading Limited Prepayment Facility. The facility has a maturity of four years and is repayable quarterly with a margin of LIBOR + 10%.

With the significant drop in oil prices in the first half of the year 2020, the Board approved the immediate annual reduction of US$8.0 million or at least 40% in general and administrative expenses which is on track to be executed in the second half of the year.

The Board and Management regularly monitors the Company's cashflow projections. The cash balance as at the end of July 2020 was US$0.6 million.

In August 2020, it was announced that the existing three interest-bearing term bank loans were restructured into one secured loan with FBNQuest Merchant Bank. The restructuring provided an extension of loan tenor with new term loan maturity date of 31 March 2024 representing an increase on the average maturity of the three existing bank loans by 15 months. A cash saving of over US$3.0 million over the next 15 months was also delivered from the new sculpted loan principal repayment schedule compared to the previous loan structure.

Board and Management update

In May 2019 we announced Lisa Mitchell's departure as the Company's Chief Financial Officer.

Gregory Eckersley, a Non-Executive Director who was the Chairman of LEKOIL's Remuneration Committee and a member of the Company's Audit and Risk Committee, assumed the role of interim Chief Financial Officer. In this role, with the support of the Company's financial controller, he oversaw the Company's finance function, following publication of the 2018 annual report and accounts. In January 2020, upon completion of his six-month term in the position, Gregory Eckersley stepped down from his previous role on LEKOIL's Board as a Non-Executive Director.

The Company's finance function is being overseen by a recently appointed Chief Financial Officer of Nigerian operations.

At the beginning of 2020, following the departure of Non-Executive Directors, John van der Welle and Gregory Eckersley, the Board was joined by Rt. Hon. Mark Simmonds and Mr. Anthony Hawkins as Non-Executive Directors. As the former Foreign & Commonwealth Office Minister with responsibilities for Africa, the Caribbean, UK Overseas Territories, International Energy and Conflict Prevention, Mr. Simmonds brings a deep knowledge of the economic and political composition of African Governments, countries and regions. Mr. Hawkins brings twenty years' experience in English and Australian law, having worked in both private practice and corporate roles. He was previously the Chief Executive Officer at Columbus Energy Resources plc. In April 2020, Thomas Schmitt and Hezekiah Adesola Oyinlola resigned from the Board. Following the changes in the Board composition, Mr. Anthony Hawkins assumed the role of Chair of the Audit and Risk Committee and Mrs Aisha Muhammed-Oyebode retained the role of Chair of the Remuneration Committee.

Outlook

Creating long-term value for our shareholders is our focus and therefore our priority for 2020 is to advance towards the start of the appraisal drilling programme on Ogo in OPL 310. We will continue to work with our joint venture partner, Optimum, and negotiate agreements that will allow us to make progress on the block, after securing all relevant regulatory extensions and approvals.

At Otakikpo we seek to grow production volumes with Phase Two development and expect to reach gross volumes of 15,000 to 20,000 bopd. While we have achieved the first step through acquiring 3D seismic data, with interpretation now completed, the focus is to secure funding to enable the commencement of the upstream drilling programme.

The COVID-19 pandemic during the first half of 2020 has been truly unprecedented. The health and safety of our employees and stakeholders is our priority, and LEKOIL is ensuring that best-practices procedures are followed. As we continue to work hard to advance our appraisal and exploration assets, and Otakikpo through its Phase 2, the Company is increasingly focused on upholding the highest standards of Environmental, Social & Corporate Governance. Developing our fields in the most responsible way, environmentally and socially, is fundamental to LEKOIL and all key stakeholders in Nigeria as we unlock the significant value they present for the country.

On 2 January 2020, the Company announced that it had secured funding for the appraisal drilling and the initial development programme on the Ogo field through a loan agreement with the Qatar Investment Authority ("QIA"). However, the Company discovered on 13 January 2020 that the loan agreement was instead signed with certain individuals falsely purporting to represent the QIA. As such, there was no valid loan agreement entered into with the QIA. To respond to this, the Board established an independent committee to investigate the origination of the loan agreement and commenced steps to recover the funds paid for its execution to an intermediary. A detailed review of the Company's wider corporate governance practices and procedures for the approval of major transactions was also conducted. As a priority, the Board will improve its standards of corporate governance and has already begun to implement the received recommendations.

The next two years will prove to be transformative and provide key catalysts for value appreciation for shareholders through the drill bit as we move forward in building a leading Africa-focused exploration and production business.

We continue to strive to be responsible with our communities and efficient in our operations, acknowledging the importance of gas in our portfolio to solve energy solutions in a sustainable manner.

Finally, we would like to thank the LEKOIL team for their ongoing commitment and efforts, as well as for the continued contributions of all Board members, and crucially, for the continued support of our valued shareholders.

Samuel Adegboyega     Olalekan Akinyanmi

Non-Executive Chairman    Chief Executive Officer

20 August 2020    20 August 2020

LEKOIL - Asset Overview

Otakikpo Marginal Field - Producing Asset

Situated in a swamp area in OML 11, LEKOIL farmed-in to Otakikpo Marginal Field ("Otakikpo") in May 2014. Otakikpo commenced commercial production in February 2017 and reached approximately gross 7,600 bopd (net with cost recovery barrels 6,688) in December of that year.

Status	Production
Participating interest	40.0%*
Operator	Green Energy International Limited ("GEIL")
Gross 2P reserves	48.6 MMboe
P50 gross aggregate stock tank oil in place (STOIIP) prospective volumes	331.6 MMboe
Contract type	Marginal Field

*Participating interest of 40% is held through LEKOIL Oil and Gas Investments Limited ("LOGL").

In 2019, production averaged gross 5,305 bopd with 2,122 bopd net to LEKOIL Nigeria (2018: 5,345 bopd with 2,076 bopd net to LEKOIL Nigeria) for the year and total production was approximately 759,666 barrels of oil (2018: 780,500 barrels of oil).

For the next phase of development, targeting a gross production of 15,000 to 20,000 bopd (6,000 to 8,000 bopd net to LEKOIL), the joint venture executed a Memorandum of Understanding ("MOU") with Schlumberger and a subsidiary of a major international oil company which has been operating in Nigeria for more than fifty years. The MOU covers a project to provide comprehensive infrastructure sharing and a drilling programme around a group of marginal field assets, including Otakikpo. The phased development plan of the project consists of drilling up to seven new wells, expanding processing infrastructure to comprise a new onshore terminal, to be located outside the Otakikpo field operations area, and the construction of an export pipeline connecting the onshore terminal with an offshore buoy.

Under the terms of the initial MOU, the consortium of the Otakikpo Joint Venture and Schlumberger will form multidisciplinary project management teams in which Schlumberger will act as project execution partner to provide oilfield services and project management services to assist in ramping up production and long-term field management.

An updated Competent Person's Report ("CPR"), to support the next phase of development at Otakikpo, was released on 26 June 2019 detailing recoverable volumes expected within the field. The CPR, prepared by McDaniel Associates & Consultants Ltd. ("McDaniel"), focused on the discovered conventional oil accumulations only. McDaniel carried out a comprehensive review of the surface and subsurface data provided by the Otakikpo Joint Venture following the completion of the recent 3D seismic data that was acquired and interpreted in 2018.

The highlights of the CPR are:

· 48.6 million barrels gross 2P reserves (previous CPR in 2015 of 15 million barrels), of which 19.4 million barrels is net to LEKOIL Nigeria;

· 331.6 million barrels of gross aggregate stock tank oil in place (STOIIP) prospective volumes on a P50, unrisked basis, mean estimate (previous CPR 163.0 million barrels), of which 132.6 MMbbl is net to LEKOIL Nigeria;

· 2P NPV10 of US$226 million, after income taxes, net to LEKOIL Nigeria

The Joint Venture have renewed the field Licence.

Ogo Discovery and OPL 310 - Appraisal Asset and Exploration

LEKOIL originally commissioned a regional basin study and identified the Dahomey Basin block OPL 310 as a key target. The OPL 310 is located within the Cretaceous fairway that runs along the West African Transform Margin. The block extends from the shallow water continental shelf close by the City of Lagos, Nigeria into deeper water. The main prospects within the Licence area are in water depths ranging from 100 to 800 metres and are within proximity to the West Africa Gas Pipeline.

Status	Appraisal & Exploration
Participating interest	17.14% held through Mayfair Assets & Trust Limited 22.86% held by Afren Investments Oil and Gas (Nigeria) Limited ("AIOGNL") *
AIOGNL role	Technical and Financial Partner
Operator	Optimum Petroleum Development Limited
P50 Gross Risked Prospective Resources	>774.0 MMboe
Contract type	Sole Risk
Expiry	August 2022

*   LEKOIL entered into a Share Purchase Agreement to acquire the entire issued share capital of AIOGNL which owned a 22.86% participating interest in OPL 310. However, pursuant to a ruling of the Federal High Court sitting in Lagos on 28 March 2019, the share acquisition transaction is inchoate and invalid given that Ministerial Consent to the transaction has not been obtained. Pending the receipt of the said Ministerial Consent to the transaction, LEKOIL 310 Limited has not acquired the shares of AIOGNL, which remains with Afren Nigeria Holdings Limited. LEKOIL has negotiated a Cost and Revenue Sharing Agreement with Optimum that enables parties to continue work on OPL 310 pending receipt of Ministerial Consent.

In the last year, we were dedicated to advancing plans for the Ogo appraisal drilling programme, readying operations throughout the year. Rig contracting due diligence work commenced, logistical plans were put in place and long lead items such as well heads and OCTG equipment were ordered.

Despite progressing exploration and appraisal activities on OPL 310, as LEKOIL had not yet been granted Ministerial Consent for its acquisition of the additional 22.86% interest in OPL 310 during the 24 months since its application and given the impending expiration of the OPL 310 Licence, LEKOIL took the decision at the end of March 2018 to apply to the Federal High Court of Nigeria for a declaration that was expected to expedite the consent process, and preserve the unexpired tenure in the Licence (due to expire in February 2019).

Following a series of adjournments, a Federal High Court sat in Ikoyi, Lagos State, Nigeria, on 7 February 2019 delivered its ruling on 28 March 2019, stating that the Company's purported acquisition of shares in AIOGNL and by that, the transfer of interest in OPL 310, was inchoate and invalid given the failure to obtain Ministerial Consent in respect of the transfer of the said shares. The Judge also ruled that pursuant to Articles 13.1.4 and 13.1.5 of the JOA between Optimum and AIOGNL, Optimum's consent was required to effect a transfer of AIOGNL's interest in OPL 310 or any part thereof to LEKOIL. LEKOIL had initially filed an appeal against the decision of the Federal High Court but decided to withdraw legal action following receipt of a letter dated 8 May 2019 from the Ministry of Petroleum Resources relating to an application for an extension (re-award) to the OPL 310 Licence (the "Letter").

The Letter stated that the Government had noted that the OPL 310 Licence expired on 10 February 2019 and ownership of OPL 310 had accordingly reverted to the Government in line with the Petroleum Act. The Letter further set out that the re-award will not be considered by the Honourable Minister of Petroleum Resources ("HMPR") until the suit filed by LEKOIL against the HMPR was withdrawn by LEKOIL and other parties to the action. Failure by LEKOIL and others to withdraw the suit within 30 days of the Letter dated 8 May 2019, would have foreclosed any consideration of re-award to Optimum Petroleum Development Limited, LEKOIL and their affiliates or subsidiaries.

The implication of the Judge's pronouncement that LEKOIL 310 Limited has not acquired the shares of AIOGNL is that, pending the receipt of Ministerial consent to the acquisition, the 22.86% participating interest in OPL 310 is still held by AIOGNL.

On 30 August 2019, Optimum and LEKOIL jointly announced the execution of a legally binding Cost and Revenue Sharing Agreement ("CRSA") to progress the appraisal and development programme activities at the Ogo discovery and conversion to an Oil Mining Licence ("OML") as soon as practicable. The agreement covered a two-well appraisal programme to occur over twelve to eighteen months commencing from August 2019. Two additional appraisal - development wells, contingent on the results of the initial two well appraisal campaign and the associated extended well tests to be undertaken. All wells planned to be designed to be compatible with an early production scheme. Optimum and LEKOIL further agreed to use the 22.86% equity stake in the Block as a potential funding and security vehicle for the accelerated development of the Block by an industry partner or a third party that elects to farm-in to the Block to fund field development. This potential Funding Partner may be sourced by either Optimum or LEKOIL.

The agreement did not address the recovery of the US$13.0 million consideration previously paid by LEKOIL with respect to the acquisition of the shares of AIOGNL in 2015 (which held the 22.86% participating interest in OPL 310). Discussions remain ongoing between LEKOIL and Optimum on a resolution of this matter alongside the possible allocation of the 22.86% to a potential Funding Partner.

As part of the agreement, LEKOIL agreed to pay outstanding G&A owed to Optimum of approximately US$3.0 million and US$5.0 million upon receipt of the Licence extension as an Operator's fee in connection with LEKOIL's 17.14% participating interest. These payments made to and on behalf of Optimum are cost recoverable and will be recovered with a mark-up of 150% plus an additional compounding of 5% per annum in respect of LEKOIL's cost of capital from a portion of Cost Oil defined as 70% of net production (revenue less royalty).

With regards to the Licence extension, in a letter dated 4 September 2019, the Federal Government of Nigeria and the Ministry of Petroleum Resources approved the extension of the OPL 310 Licence for three years, subject to the holders of the Licence paying an extension fee of US$7.5 million within 90 days effective from 2 August 2019. On 31 October 2019, LEKOIL paid the extension fee on behalf of the holders of the Licence. On 15 November 2019, the Federal Government of Nigeria and Ministry of Petroleum Resources acknowledged the receipt of the OPL 310 Licence extension fee and that the Licence is in force for an extended period to 2 August 2022.

On 31 October 2019, LEKOIL paid in full the balance of outstanding G&A arrears. Following an agreement between Optimum and LEKOIL, LEKOIL also paid US$1.0 million of the US$5.0 million Operator's fee which was due upon receipt of the License extension. The balance of US$4.0 million was agreed to be deferred to 2 February 2020.

On 21 January 2020, pursuant to the Cost and Revenue Sharing Agreement, LEKOIL was required to pay US$5.6 million which represents a portion of Optimum's sunk costs. Optimum and LEKOIL agreed for this payment and the balance of consent fees (US$4.0 million) which comes to a total of US$9.6 million to be deferred such that US$2.0 million and US$7.6 million is paid by the 20 March 2020 and 2 May 2020 respectively.

Following the payment to Optimum due in March 2020 of US$2.0 million, Optimum and LEKOIL further agreed to a deferred payment schedule for the final payment due in May 2020 of US$7.6 million as follows:

· The sum of US$1.0 million to be paid on or before 15 July 2020;

· The sum of US$2.0 million to be paid on or before 30 September 2020; and

· The sum of US$4.6 million to be paid on or before 30 November 2020

OPL 276 - Development Asset

Located in the eastern Niger Delta basin in the estuary of the Calabar River, within a transition zone, consisting of dry, flat land, freshwater rain forest swamps, mangrove swamps and beaches in Akwa Ibom State. The asset is partly onshore (land and swamp) and partly shallow marine (tidal river estuary) block, comprising 524 sq. km, of which approximately 250 sq.km is located offshore and 274 sq.km is located onshore. The Licence area is within 20 kilometres from three existing producing fields: Effiat-Abana, Stubb Creek and Uquo.

Status	Appraisal & Exploration
Participating interest	45%*
Contractor Partners	Newcross Petroleum Limited and Albright Waves Petroleum Development Limited as the Local Content Vehicle
Gross recoverable volumes	29 MMbbl of Oil and 333 Bcf of gas**
Contract type	Production Sharing Contract
Expiry	Process to extend the PSC in progress***

*   Participating interest of 45% in the Production Sharing Contract is held through LEKOIL 276 Limited, a wholly owned subsidiary of LEKOIL Nigeria.

**Preliminary resource estimate by Newcross.

***The application for extension of the PSC has been filed with NNPC and awaits approval from both NNPC and ultimately the Minister of Petroleum Resources.

In August 2019, LEKOIL entered into an agreement with Newcross to acquire, subject to the receipt of the required consents, a 45% participating interest in the PSC in relation to the Oil Prospecting Licence 276.

The Licence was formerly operated by Shell Petroleum Development Corporation ("SPDC") as OML 14 until 2004, and in 2006, it was signed as a PSC. The asset is covered by approximately 150 sq. km of 3D seismic, shot in 2008 by BGP Inc., a subsidiary of China National Petroleum Company (CNPC), as well as various 2D seismic surveys.

Four discoveries have previously been made in the Licence area (Uda, Okposo-Ease, Mbo and Davy Bank) with the preliminary resource estimates by Newcross, based on data from the four discoveries, reporting gross recoverable volumes of 29 million barrels of oil and 333 Bcf of gas, upside of 33 million barrels of oil and 476 Bcf of gas (recoverable).

LEKOIL sees a clear opportunity for re-entering one or more of these discovery wells, with the potential for rapid monetisation of resources thanks to the proximity of existing export facilities. LEKOIL intends to start facilitating this process by commissioning an independent Competent Persons Report.

The agreed acquisition from Newcross is for a total staged consideration of US$5.0 million, payable subject to the extension of the term of the Licence and the PSC, obtaining the approvals by the NNPC and the Minister of Petroleum Resources of the Federal Republic of Nigeria. The application for the extension of the PSC has been filed with the NNPC. Following this acquisition, the contractor parties will be LEKOIL (45%), Newcross (45%) and Albright Waves Petroleum Development Limited (10%).

The consideration is payable as follows:

· US$0.75 million to be held in escrow starting from the extension of the term of the Licence and to be released upon receipt of the Ministerial Approval;

· US$2.75 million to be paid after the Ministerial Approval is obtained and upon occurrence of the conversion of the Licence to Oil Mining Lease ("OML"); and

· US$1.5 million to be paid within three months after the receipt of first crude oil sale proceeds from continuous commercial production from the PSC

The costs associated with the PSC and attributable to both Newcross and Albright Waves Petroleum Development Limited ("Albright") will be carried and recovered by LEKOIL (through LEKOIL 276 Limited) from crude oil sale proceeds of 80% and 70% of Newcross and Albright's Cost Oil and Profit Oil, respectively.

OPL 325 - Exploration Asset

OPL 325 was also identified as a target in LEKOIL's regional basin study covering the Dahomey Basin. The OPL 325 Licence area is situated in the offshore Dahomey Basin within the cretaceous wrench zone that straddles the western Niger Delta and is located 50km south of OPL 310.

Status	Exploration
Participating interest	62%*
Partner	National Petroleum Development Company Ltd and Local Content Vehicle
Gross STOIIP unrisked prospective resources	5-6 billion Boe
Contract type	Production Sharing Contract
Expiry	PSC in progress**

*via LEKOIL's majority stake in Ashbert Oil & Gas Limited, which holds 70% working interest in OPL 325 and is Operator.

** The PSC terms have been negotiated and the document awaits signatures. Until the PSC is issued and completely signed, we do not believe a right, power or interest in a petroleum asset exists as outlined in the original Letter of Award that would trigger a requirement for consent. LEKOIL is prepared to address the consent requirements for OPL 325 when Ashbert either transfers interest in the PSC directly to LEKOIL or farms down to a third party.

We had access to 3D seismic data covering over 800 sq km, and we are encouraged by the results of our current technical evaluation. In January 2018, we announced the completion of a thorough independent Technical Evaluation Report for OPL 325, which is available on our web site. The Report was compiled by independent oil and gas industry specialists Lumina Geophysical who carried out a geophysical evaluation of the 3D seismic data provided by LEKOIL. The study prepared for LEKOIL, confirmed their preliminary estimate of oil in place volumes of 5.7 billion Boe as an Unrisked Best Estimate case. Within the study, Lumina identified and reported on a total of eleven prospects and leads on the block. Focus was primarily on the Paleocene section of the block, generating new structural and stratigraphic maps using 3D pre-stack time migrated seismic data. These maps were used in a volumetric approach to assess potential resources in OPL 325.

Market Overview

LEKOIL maintains a sustainable business portfolio of high-quality assets across Nigeria. Since its establishment, the company has invested in its assets in order to consistently grow oil and gas production capacities in line with its diversified asset strategy, advancing our appraisal assets (OPL276 and OPL310), exploration assets (OPL325) and moving our Otakikpo producing asset to the next phase. This diversified portfolio approach helps us mitigate the impact of price volatility. Our asset base comprises high quality fields that offer substantial future upside potential in both oil and gas resources which provides a solid platform for growth as we explore the world class opportunities within Nigeria. Our annual planning cycle aims to ensure that our levels of capital investment and operating expenses are appropriate in the context of a volatile price environment. We also aim to maintain a strong balance sheet to provide resilience against weak market prices.

Natural gas has the enormous potential to diversify and grow the economy, and although the country has one of the largest yet least developed gas resources on the continent. Today, the country produces about 7 billion cubic feet of natural gas per day with more than 40% being exported and 18% being used domestically for power generation and industrial activities, while the rest is either reinjected into a reservoir for higher oil recovery, used as fuel in the field or flared. Of the 1.2 billion cubic feet of gas supplied domestically, up to 70% is used for power generation and the rest is utilised for other industrial activities. Today, natural gas provides up to 80% of the country's power generation and most of the remainder comes from water dams (hydro). The country currently has about 200 trillion cubic feet of proven gas reserves and over 600 trillion cubic feet of unproven potential resources, however, up until now, this gas has been largely undeveloped. The Nigerian government is currently focused on utilising more efficiently its vast gas reserves and Africa's largest resources to stimulate economic growth, which is expected to lead significant positive changes in the sector and will contribute to the industrial development, as well as expansion of the gas network to industrial hubs. With domestic demand growing faster than ever, and given an increasing export potential, we expect our assets OPL 310 and OPL 276 to become key in the national ambition to dominate the market share on the African continent.

Corporate & Social Responsibility

LEKOIL's high, ethical standards in its business activities are reflected in the Company's respect for all our people regardless of age, designation and gender. We work in an environment that fosters effective communication and we deal courteously with all stakeholders, respecting the customs and rules of the countries in which we operate.

We act responsibly, promoting accountability as individuals and as a company. We operate with ethics and fairness and comply with all required rules and regulations.

We are committed to the welfare and development of the communities around our operations. In our relations with the local communities surrounding our producing asset, Otakikpo, LEKOIL's corporate and social responsibility ("CSR") plan continues to focus on three strategic objectives:

i)  Education,

ii)  Economic and social empowerment (including women and children) and,

iii)  Environmental and social sustainability.

We are part of the communities in which we operate. In the coastal town of Ikuru, close to Otakikpo, we recognised the need for community support for our work and, to that end, LEKOIL has been helping improve the quality of life of residents. We signed a land lease agreement with the people of Ikuru backed by a memorandum of understanding, which holds us responsible for sustainable development. As a cluster, other coastal communities of Ugama Ekede, Ayama Ekede, Asuk Ama and Asuk Oyet have a similar memorandum of understanding.

Through the memoranda of understanding, we have demonstrated our commitment to the principles of Free, Prior and Informed Consent and have established Incorporated Communities' Trust Funds with annual appropriation. These trusts have proven to be veritable vehicles for consultation and participation of informed communities, whereby they analyse their needs as part of their governance processes, make decisions on annual programmes based on an analysis of their needs and available resources, as well as determine the priorities for sustainable development. These programmes and activities cover the following:

i)  Infrastructure, including construction of school buildings, roads and bridges, public toilets, markets, water reticulation projects, etc.;

ii)  Scholarship and bursaries for secondary, undergraduate and graduate students;

iii)  Entrepreneurship and skills acquisition support for the youths and women; and

iv)  Community health projects, as well as safety and security projects.

LEKOIL is actively helping the communities surrounding our first development, Otakikpo. We support initiatives aimed at improving education and skills development for our colleagues and communities, especially in the field of Science, Technology, Engineering and Mathematics ("STEM"), in order to increase employment opportunities. We also support programmes geared towards elevating the status of women and their contribution to nation building, increasing ratio of female entrepreneurs as well as women in senior leadership positions in corporate organisations. Among such initiatives are the WIMBIZ (Women in Business) and ENACTUS (details are outlined below).

We promote diversity and equality by supporting the WIMBIZ initiative, a Nigeria based non-profit organisation with an overriding vision "to be the catalyst that elevates the status and influence of women and their contribution to nation building". The WIMBIZ conference is an opportunity to take part in equipping participants with the tools and skills to harness and embrace opportunities in Nigeria to become forerunners of change.

LEKOIL also supports ENACTUS, an international non-profit organisation with a community of students, academic and business leaders. ENACTUS is committed to harness the power of entrepreneurship to transform lives and shape a better and more sustainable world by providing a platform for teams of outstanding university students to create community development projects that put people's own ingenuity and talents at the centre of improving their livelihoods.

In addition, LEKOIL supports humanitarian response initiatives in partnership with the Murtala Muhammed Foundation ("MMF"), a non-profit organisation. The mission is to improve the living conditions of Africans by helping to reduce poverty and eliminate conflict, while promoting self-reliance and self-realisation. MMF strives to become an institution that transcends all boundaries dedicated to the socio-economic development of Africa. The MMF monitors disasters as they arise and assess their impact and the needs of the victims in order to determine how they can be addressed, to provide relief and to find solutions in addressing consequences.

Environment

In accordance with Nigeria's Environmental Impact Assessment Act ("EIAA"), a company whose activity or project is likely to have a significant environmental impact must conduct an environmental impact assessment programme prior to the commencement of the project.

LEKOIL is committed to demonstrating leadership in environmental management and in accordance with the requirements and regulations in Nigeria, as well as in any other territory in which we operate. We believe we have demonstrated this commitment in our operations in the communities surrounding our Otakikpo development.

These outcomes are the result of the technical expertise of our people and partners, our strong leadership team, and the adherence to our core values - especially our ability to think outside the box.

Financial Review

For the year ended 31 December 2019

Overview

LEKOIL reports an average production volume of 2,122 bopd, net for the year ended 31 December 2019 (2018: 2,076 bopd, net). The year saw a deliberate effort to reduce the cost of sales to achieve a lower cost of production at the Otakikpo marginal field which remains the sole revenue source. In 2019, underlying cost of sales were reduced by 22%. LEKOIL intends to progress the work programmes in OPL 310 and OPL 276 to bring them to commercial production.

In October 2019, LEKOIL raised further debt capital of US$11.5 million to fund Licence extension fees on OPL 310 and OPL 276 and to fully repay the outstanding quarterly repayments (including principal and interest) due as part of the Advance Payment Facility held with Shell Western Supply and Trading Limited ("SWST").

The Group recorded a total comprehensive loss of US$12.0 million for the year ended 31 December 2019 (2018: loss of US$7.8 million). Cash and cash balances at the end of the year were US$2.7 million (2018: US$10.4 million), with total outstanding debt financing net of cash increased to US$16.5 million (2018: US$10.1 million).

In US '000s Dollars	2019	2018	2017
Cash and cash balances	2,733	10,423	6,922
Outstanding debt financing less cash	16,465	10,062	22,587
Working Interest Revenue	42,027	48,687	30,848
Profit/ (loss) for the year	(12,033)	(7,783)	6,496
Profit/ (loss) per share	(0.02)	(0.02)	0.01
Cash flow generated from / (used in) operations	14,952	(1,569)	(11,712)

Production and Revenues

Total production from the Otakikpo marginal field for the year attributable to LEKOIL Nigeria was approximately 759,666 barrels (2018: 780,500 barrels). Total revenue for the year was US$42.0 million, down 13% from the previous year of US$48.7 million. This decrease was mainly due to lower crude liftings and production occurring in 2019. The Group lifted 677,788 barrels in equity crude for the year 2019 (2018: 739,106 barrels). The Group's realised oil price was US$62.0 per barrel for the year. The Group does not currently have oil price hedging in place apart from amounts required under the current debt facilities, however, as part of the Company's risk management strategy this approach is currently under review.

Cost of sales, depreciation, impairments and administrative expenditure

Underlying cost of sales were US$14.1 million or US$18.6/bbl (2018: US$18.1 million or US$23.2/bbl). The decrease in cost per barrel was largely due to a full year impact of the cost savings achieved from the cessation of rental charges for production facilities in 2019. The permanent EPF ("PEPF") was commissioned in the second quarter of 2018. Depletion and amortisation costs on oil and gas assets were US$6.2 million or US$8.2/bbl (2018: US$7.9 million and US$10.1/bbl).

Operating expenses were US$7.7 million or US$10.2/bbl (2018: US$7.9 million and US$10.2/bbl). Operating expenses captures the Group's share of expenditure incurred on production operation support activities such as accommodation for field personal. This was marginally lower in 2019, largely due to lower production volumes.

General and administrative expenses were US$21.4 million compared to US$19.1 million for the same period in 2018. Despite the Group's concerted efforts in bringing down travel costs and legal and consultancy expenses, the increase in 2019 was driven by significant increases in amortisation expenses on intangible assets, as well as marginal year on year increases in personnel, rent and facility management expenses. In line with previous announcements and with the significant drop in oil prices in the first half of 2020, the Board approved on 3 April 2020, the immediate and accelerated implementation of cost reduction measures aimed at targeting an annual reduction of US$8.0 million or at least 40% in general and administrative expenses.

Capital investment

The Group's capital expenditure for the year was US$29.7 million (2018: US$12.3 million), focused largely on OPL 310 obligation of US$22.6 million funded on behalf of Optimum, production facilities in the Otakikpo marginal field of US$3.4 million, Licence renewal fees in OPL 310 and Otakikpo of US$1.3 million and US$0.4 million respectively, investment in enterprise management system of US$0.3 million and exploration and appraisal activities of the Group's interests in OPL 310 of US$0.6 million.

Taxes

As a Nigerian producing business, the Group is subject to the Petroleum Profit Tax Act of Nigeria (PPTA) and the Company Income Tax Act of Nigeria (CITA). Tax expense for year was US$7.1 million. (2018: tax expense of $10.1 million.) The variance year on year is due to lower earnings and assessable profit including deferred tax expense charges in 2019 relative to 2018.

Profit/ (loss) for the year and loss per share

The Group recorded a total comprehensive loss of US$12.0 million for the year to 31 December 2019 (2018: loss of US$7.8 million) and a basic and diluted loss per share of US$2 cents (2018: loss of US$2 cent).

Cash and bank balances

The Group had cash and bank balances of US$2.7 million as at 31 December 2019 (2018: US$10.4 million). Restricted cash of US$1.1 million (2018: US$3.2 million), represents cash funding of the debt service reserve accounts of FBN Capital Facilities and bank guarantee for MT Nox and Busy Snail contract. Restricted cash has been reported as part of other assets.

Loans and borrowings

The Group had the following debt facilities in place at year end:

In US$'000	Interest rate p.a.	2019	2018
US$10 million FBNC Capital Dollar Facility	10% + LIBOR	2,957	4,831
US$8.55 million FBN MB Facility	10% + LIBOR	5,236	8,191
US$15 million Shell Facility	10% + LIBOR	-	7,463
US$11.5 million FBN MB Facility	10% + LIBOR	11,005	-
Total		19,198	20,485
Less borrowings, current		(7,149)	(11,439)
Borrowings, non-current		12,049	9,046

Please refer to note 27 in the financial statements for a further breakdown.

Assets and liabilities

The Group's non-current assets were US$206.1 million as at 31 December 2019 (US$194.9 million at 31 December 2018), reflecting expenditure incurred on behalf of JV partner in OPL 310 in spite of depreciation, depletion and amortisation of oil and gas assets during the year, and reduction in deferred tax assets to US$13.6 million (2018: US$18.3 million). Current assets, which represent the Group's cash resources, other assets and other receivables, decreased significantly from US$31.5 million as at 31 December 2018 to US$11.4 million as at 31 December 2019. The decrease is a result of a reduction in year-end cash balance and nil trade receivables balance in 2019 relative to 2018, in spite of the increase in inventory due to the absence of crude lifting in December 2019. Inventories which consist of the Group's share of crude stock increased from US$1.6 million as at 31 December 2018 to US$2.8 million as at 31 December 2019.

Current liabilities consist of the loan facilities set out above due within twelve months, amounting to US$7.1 million (31 December 2018: US$11.4 million), trade and other payables amounting to US$20.6 million (31 December 2018: US$13.6 million) and income tax payable amounting to US$1.1 million (31 December 2018: US$5.1 million). Despite a concerted effort during the year to pay off vendor financing from prior periods, there was a slight increase in liabilities due to the agreed payments to Optimum pursuant to the Cost and Revenue Sharing Agreement ("CRSA") executed by the partners to progress the appraisal and development programme activities on OPL 310. (Total liabilities US$43.2 million in 2019, up from US$41.0 million in 2018).

Dividend

The Directors do not recommend the payment of a dividend for the year ended 31 December 2019 (2018: Nil).

Accounting policies

The Group's significant accounting policies and details of the significant judgments and critical accounting estimates are disclosed within the notes to the financial statements. The Group adopted IFRS 16 during the year, though there was no impact to the financial statements.

Liquidity risk management and going concern

At 31 December 2019, the Group had liquid resources of approximately US$2.7 million in the form of cash and bank balances available to meet capital, operating and administrative expenditure.

The Group concluded the refinance and redenomination of the outstanding Naira debt facilities during the year and raised further debt capital of US$11.5 million to fund Licence extension fees on OPL 310 and OPL 276 and to fully repay the outstanding quarterly repayments (including principal and interest) due as part of the Advance Payment Facility held with SWST.

The steps taken by the Group to reduce overheads as announced in the 2018 annual report resulted in the marginal decrease of overheads by 2%. LEKOIL is taking further action to manage these expenses to reduce them to its target levels. Board remuneration has been reduced by 18% year on year.

There is however material uncertainty that can cast significant doubt on the Group's ability to continue operating as a going concern which is discussed below.

The Directors draw the attention of the recurring losses after tax of US$12 million incurred in the current year (2018: US$7.8 million). The Group has a negative working capital position of US$17.5 million (2018: Positive working capital of US$1.3 million) which is an indicator of a possible liquidity concern.

In addition to the Group's current working capital deficiency, the Directors are cognisant of the potential impacts of COVID-19 on the Group as there are unprecedented market conditions with significant oil price volatility following the demand implications driven by COVID-19. The Group will not be able to meet its financial obligations if the price of crude oil should drop as low as US$25 per barrel. Considering there is no price hedging currently in place, we have concluded that there is a material uncertainty that may cast significant doubt on the Group's ability to continue operating as a going concern.

The Group closely monitors and carefully manages its liquidity risk. Cash forecasts are regularly produced, and sensitivities run for different scenarios including, but not limited to, changes in commodity prices and different production rates from the Group's producing asset. Cash forecasts have been updated in light of the oil price volatility seen in early 2020. The Group's base assumptions show that it will be able to operate within its contractual debt facility taking into consideration the Group's debt restructure agreement announced on 17 August 2020 as well as its costs reduction strategy and as such have sufficient financial headroom for the 12 months from the date of approval of the 2019 Annual Report and Accounts.

The Group continues to closely monitor cash flow forecasts and would take mitigating actions in advance including further reducing its operational costs; deferment of capital activities on OPL 310 and other capital projects until it has raised the required funds to execute them; to further renegotiate its debt obligation; and to raise additional funds if the need arise from either the equity or debt markets.

Notwithstanding the material uncertainty, the Directors' confidence in the Group's forecasts and the mitigating actions above, supports the preparation of the financial statements on a going concern basis of accounting, which assumes the Group will continue in operation for the foreseeable future and be able to realise its assets and discharge its liabilities and commitments in the normal course of business.

This Strategic Report has been approved by the Board and signed, on its behalf, by:

Olalekan Akinyanmi

Chief Executive Officer

20 August 2020

Statement of Directors' Responsibilities in relation to the consolidated financial statements

The Directors of Lekoil Limited ("the Company") and its subsidiaries (together referred to as "the Group") are responsible for the preparation of the consolidated financial statements that give a true and fair view of the financial position of the Group as at 31 December 2019, and the results of its operations, cash flows and changes in equity for the year then ended, in compliance with International Financial Reporting Standards ("IFRS").

In preparing the financial statements, the Directors are responsible for:

• properly selecting and applying accounting policies;

• presenting information, including accounting policies, in a manner that provides relevant, reliable, comparable and understandable information;

• providing additional notes when compliance with the specific requirements in IFRSs are insufficient to enable users to understand the impact of particular transactions, other events and conditions on the Group's financial position and financial performance; and

• making an assessment of the Group's ability to continue as a going concern.

The Directors are also responsible for:

• designing, implementing and maintaining an effective and sound system of internal controls throughout the Group;

• maintaining adequate accounting records that are sufficient to show and explain the Group's transactions and disclose with reasonable accuracy at any time, the financial position of the Group and which enable them to ensure that the financial statements of the Group comply with IFRS;

• taking such steps as are reasonably available to them to safeguard the assets of the Group; and

• preventing and detecting fraud and other irregularities.

Going concern:

The Directors have made an assessment of the Group's ability to continue as a going concern and as disclosed in Note 2(b), they believe the Group will remain a going concern in the year ahead.

The consolidated financial statements for the year ended 31 December 2019 were approved by the Directors on 20 August 2020 and signed on its behalf by:

Olalekan Akinyanmi

Chief Executive Officer

Independent Auditor's Report

To the Shareholders of LEKOIL Limited

Report on the Audit of the Annual Report and Consolidated Financial Statements

Opinion

We have audited the consolidated financial statements of Lekoil Limited ("the Company") and its subsidiaries (together referred to as "the Group")  which comprise the consolidated statement of financial position as at 31 December 2019, and the consolidated statement of profit or loss and other comprehensive income, the consolidated statement of changes in equity and the consolidated statement of cash flows for the year then ended, and the notes to the consolidated financial statements, including a summary of significant accounting policies.

In our opinion, the consolidated financial statements give a true and fair view of the financial position of Lekoil Limited as at 31 December 2019, its financial performance and cash flows for the year then ended in accordance with the International Financial Reporting Standards (IFRS) as adopted by the European Union (EUIFRS).

Basis for Opinion

We conducted our audit in accordance with International Standards on Auditing (ISAs). Our responsibilities under those standards are further described in the Auditor's Responsibilities for the Audit of the Consolidated Financial Statements section of our report. We are independent of the Group in accordance with the International Ethics Standards Board for Accountants' (IESBA) International Code of Ethics for Professional Accountants (including International Independence Standards) (IESBA code). We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

Material Uncertainty Related to Going Concern

We draw attention to Note 2(b) to the consolidated financial statements which indicates that the Group incurred recurring losses after tax of US$12 million in the current year (2018: US$7.8 million) and has negative working capital of US$17.5 million  (2018:Positive working capital of US$1.3 million).These events  and the other conditions as set forth in Note 2(b), indicate that a material uncertainty exists that may cast significant doubt on the Group's ability to continue as a going concern. However, the Group's base case assumptions show that it will be able to operate within its contractual debt facility taking into consideration its debt restructure agreement executed on 21 July 2020 as well as its costs reduction strategy and as such, have sufficient financial headroom for the 12 months from the date of approval of the 2019 Annual Report and Accounts hence our opinion is not modified in respect of this matter.

Key Audit Matter

Key audit matter is the matter that, in our professional judgment, was of most significance in our audit of the consolidated financial statements of the current year. This matter was addressed in the context of our audit of the consolidated financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on this matter. In addition to the matter described in the Material Uncertainty Related to Going Concern section, we have determined the matter described below to be the key audit matter to be communicated in our report.

Key Audit Matter	How the matter was addressed in the audit
Impairment of Oil and Gas Assets
Management and the Directors are required to assess whether there are potential indicators of impairment of the Group's oil and gas assets at each reporting period and, if potential indicators of impairment are identified, management are required to perform a full assessment of the recoverable value of the oil and gas assets in accordance with the requirements of the relevant accounting standard. Management identified an impairment indicator on its producing oil and gas assets at Otakikpo and performed an impairment test. Based on that impairment test, management concluded that no impairment was required. The assessment of the recoverable value of the oil and gas assets required judgments and estimates by Management and the Directors regarding the inputs applied in the impairment model including future oil and gas prices, production and reserves, operating costs and discount rate. Accordingly, the impairment test performed on the Group's oil and gas assets in the current year is considered a key audit matter.	We performed the following procedures in respect of the impairment of the Group's oil and gas assets: • We obtained and reviewed management's impairment test assessments and agreed with their conclusion that a potential indicator of impairment was present; • We obtained and reviewed the management's discounted cash flow model and performed arithmetical accuracy on the data in the model; • We determined whether the basis of preparation of the model aligned with the applicable accounting standard (IAS 36); • We critically challenged the NPV model, focusing on the appropriateness of estimates with specific emphasis on the following assumptions: oil and gas prices, reserves and production levels, operating costs and discount rate; • We evaluated management's conclusion of the potential impact of Covid-19 and that the impact represented a non-adjusting subsequent event against the relevant accounting standard (IAS 10); and • We reviewed the disclosures in the financial statements to ensure compliance with the requirements of the relevant accounting standard (IAS 36). We found the management's impairment test of its oil and gas assets reasonable and as such, an impairment provision is not required.

Other Information

The Directors are responsible for the other information. The other information comprises the Chairman's and CEO's Statements, Financial Review, Directors' Report and Remuneration Committee's Report, which we obtained prior to the date of this auditor's report. The other information does not include the consolidated financial statements and our auditor's report thereon.

Our opinion on the consolidated financial statements does not cover the other information and we do not express any form of assurance conclusion thereon.

In connection with our audit of the consolidated financial statements, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the consolidated financial statements or our knowledge obtained in the audit, or otherwise appears to be materially misstated.

If based on the work we have performed on the other information that we obtained prior to the date of this auditor's report, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard.

Responsibilities of the Directors for the Consolidated Financial Statements

The Directors are responsible for the preparation and fair presentation of the consolidated financial statements in accordance with International Financial Reporting Standards, and for such internal control as the Directors determine is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the consolidated financial statements, the Directors are responsible for assessing the Group's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the Directors intend to liquidate the Group or to cease operations, or have no realistic alternative but to do so.

Auditor's Responsibilities for the Audit of the Consolidated Financial Statements

Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with ISAs will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these consolidated financial statements.

As part of an audit in accordance with ISAs, we exercise professional judgment and maintain professional skepticism throughout the audit. We also:

• Identify and assess the risks of material misstatement of the consolidated financial statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.

• Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Group's internal control.

• Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by the Directors.

• Conclude on the appropriateness of the Directors' use of the going concern basis of accounting and based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Group's ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor's report to the related disclosures in the consolidated financial statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor's report. However, future events or conditions may cause the Group to cease to continue as a going concern.

• Evaluate the overall presentation, structure and content of the consolidated financial statements, including the disclosures, and whether the consolidated financial statements represent the underlying transactions and events in a manner that achieves fair presentation.

• Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Group to express an opinion on the consolidated financial statements. We are responsible for the direction, supervision and performance of the group audit. We remain solely responsible for our audit opinion.

We communicate with the Audit Committee regarding and the Directors, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.

We also provide the Audit Committee and Directors with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, actions taken to eliminate threats or safeguards applied.

From the matters communicated with the Audit Committee and/or the Directors, we determine the matter that was of most significance in the audit of the consolidated financial statements of the current year and is therefore the key audit matter. We describe this matter in our auditor's report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication.

Olufemi Abegunde FCA

FRC/2013/ICAN/000000004507

for: Deloitte & Touche

Chartered Accountants

Lagos, Nigeria

Consolidated statement of profit or loss and other comprehensive income

For the year ended 31 December

	Notes	2019 US$'000	2018 US$'000
Revenue	8	42,027	48,687
Cost of sales	9	( 14,133 )	(18,118)
Gross profit		27,894	30,569
Operating expenses	10	( 7,734 )	(7,942)
Exploration & evaluation expenses		-	(1,287)
General and administrative expenses	11	( 21,436 )	(19,133)
Operating (loss)/ profit		(1,276)	2,207
Finance income	12	238	7,151
Finance expense	12	( 3,877 )	(7,064)
Net finance (expense)/ income		(3,639)	87
(Loss)/ profit before income tax		(4,915)	2,294
Income tax expense	13 (d)	(7,118)	(10,077)
Loss for the year		(12,033)	(7,783)
Total comprehensive loss		(12,033)	(7,783)
Attributable to:
Owners of the Company		(11,578)	(7,924)
Non-controlling interests		(455)	141
		(12,033)	(7,783)
Total comprehensive loss for the year		(12,033)	(7,783)
Loss per share:
Basic loss per share ($)	14 (a)	(0.02)	(0.02)
Diluted loss per share ($)	14 (b)	(0.02)	(0.02)

The notes below are an integral part of these consolidated financial statements.

Consolidated statement of financial position

As at 31 December

	Notes	2019 US$'000	2018 US$'000
Non-current assets
Property, plant just and equipment	15	35,242	38,436
Exploration and evaluation assets	16	131,832	131,822
Intangible assets	17	2,869	4,629
Deferred tax assets	13(c)	13,580	18,296
Other receivables	20	-	1,708
Other assets	21	22,603	-
		206,126	194,891
Current assets
Inventories	18	2,777	1,639
Trade receivables	19	-	8,814
Other receivables	20	4,283	5,783
Other assets	21	1,577	3,864
Pre-paid development costs	22	-	931
Cash and bank balances	23	2,733	10,423
		11,370	31,454
Total assets		217,496	226,345
Current liabilities
Trade and other payables	24	20,563	13,623
Current tax payables	13(e)	1,126	5,124
Loans and borrowings	27	7,149	11,439
		28,838	30,186
Non-current liabilities
Provision for Asset Retirement Obligation	25	2,265	1,808
Loans and borrowings	27	12,049	9,046
		14,314	10,854
Total liabilities		43,152	41,040
Net assets		174,344	185,305
Capital and reserves
Share capital	28(a)	27	27
Share premium	28(b)	264,004	264,004
Accumulated deficit		(95,226)	(83,648)
Other reserves		22	22
Share based payment reserve		9,921	8,849
Equity attributable to owners of the Company		178,748	189,254
Non-controlling interests	29	(4,404)	(3,949)
Total equity		174,344	185,305

These consolidated financial statements were approved by the Board of Directors on 20 August 2020 and signed on its behalf by:

Olalekan Akinyanmi - Chief Executive Officer

The notes below are an integral part of these consolidated financial statements.

Consolidated statement of changes in equity

For the year ended 31 December

	Notes	Share capital US$'000	Share premium US$'000	Accumulated deficit US$'000	Other reserves US$'000	Share-based payments reserve US$'000	Total US$'000	Non-controlling interests US$'000	Total equity US$'000
Balance at 1 January 2018		27	264,004	( 61,855 )	22	7,675	209,873	( 4,090 )	205,783
Adjustment on adoption of IFRS 9, net of tax		-	-	(13,869)	-	-	(13,869)	-	(13,869)
Total comprehensive income for the year
(Loss)/ profit for the year		-	-	(7,924)	-	-	(7,924)	141	(7,783)
Transactions with owners of the Company
Share-based payment- personnel expenses	30	-	-	-	-	1,174	1,174	-	1,174
Balance at 1 January 2019		27	264,004	(83,648)	22	8,849	189,254	(3,949)	185,305
Total comprehensive income for the year
Loss for the year		-	-	(11,578)	-	-	(11,578)	(455)	(12,033)
Transactions with owners of the Company
Share-based payment- personnel expenses	30	-	-	-	-	1,072	1,072	-	1,072
Balance at 31 December 2019		27	264,004	(95,226)	22	9,921	178,748	(4,404)	174,344

The notes below are an integral part of these consolidated financial statements.

Consolidated statement of cash flows

For the year ended 31 December

	Notes	2019 US$'000	2018 US$'000
Operating activities
Loss for the year		(12,033)	(7,783)
Adjustments to loss for the year:
- Equity-settled share-based payment		1,072	1,174
- IFRS 9 adjustments		-	(13,869)
- Pre-paid development costs restatement		-	10,615
- Prep-aid development costs carried interest		-	(299)
- Derecognition of E&E asset		-	837
- Finance cost		3,463	4,717
- Revaluation adjustments for loans and borrowings	27	435	142
- Deferred tax		4,716	4,953
- Depreciation and amortization	15 &17	8,917	9,875
Cash flow generated from operations before working capital adjustments		6,570	10,362
Changes in:
Inventory		(1,138)	(549)
Deferred income		-	(6,685)
Trade and other payables		(791)	(18,852)
Other assets		2,287	(4,094)
Trade and other receivables		12,022	15,037
Income taxes		2,402	5,124
Cash generated from operations		21,352	343
Income taxes paid	13(e)	(6,400)	(1,912)
Net cash generated from/ (used in) operating activities		14,952	(1,569)
Investing activities
Acquisition of property, plant and equipment	15	(3,362)	(10,395)
Pre-paid development costs	22	-	(2,839)
Optimum and Third party funded obligation		(13,032)	-
Intangible asset	17	(678)	-
Recoveries from pre-paid development costs	22	931	34,055
Acquisition of exploration and evaluation assets	16	(1,850)	(1,886)
Net cash (used in)/ generated from investing activities		(17,991)	18,935
Financing activities
Proceeds from issue of loan note	27	11,500	7,000
Repayment of loan	27	( 12,614 )	(17,558)
Interest costs related to loan	27	(3,230)	(3,307)
Transaction costs related to loan	27	(307)	-
Net cash used in financing activities**		(4,651)	(13,865)
(Decrease)/increase in cash and bank balances		(7,690)	3,501
Cash and bank balances at 1 January	23	10,423	6,922
Cash and bank balances at 31 December	23	2,733	10,423

**Changes in liabilities arising from financing activities have been disclosed in note 27(e).

The notes below are an integral part of these consolidated financial statements.

Notes to the financial statements

1 Reporting entity

LEKOIL Limited (the "Company" or "LEKOIL") is a company domiciled in the Cayman Islands with registration number WK- 248859. The address of the Company's registered office is Intertrust Group, 190 Elgin Avenue, Georgetown, Grand Cayman, Cayman Islands. These consolidated financial statements comprise the Company and its subsidiaries (together referred to as the "Group" and individually as "Group entities"). The Group's principal activity is exploration and production of oil and gas.

2 Basis of preparation

(a)  Statement of compliance

These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as adopted by the European Union (EU). The consolidated financial statements were authorised for issue by the Board of Directors on 20 August 2020 .

The consolidated financial statements comprise:

-  Consolidated statement of profit or loss and other comprehensive income

-  Consolidated statement of financial position

-  Consolidated statement of changes in equity

-  Consolidated statement of cash flows and

-  Notes to the consolidated financial statements

(b) Material uncertainty related to Going concern basis of accounting

These consolidated financial statements have been prepared on the going concern basis of accounting, which assumes that the Group will continue in operation for the foreseeable future and be able to realise its assets and discharge its liabilities and commitments in the normal course of business. There is however a material uncertainty that can cast significant doubt on the Group's ability to continue as a going concern which is discussed below.

The Directors of the Group draw the users' attention to the recurring losses after tax of US$12 million incurred in the current year (2018: US$7.8 million). The Group also has a negative working capital position of US$17.5 million (2018: Positive working capital of US$1.3 million) and this is an indicator of a possible liquidity concern.

In addition to the Group's current working capital deficiency, the Directors are cognisant of the potential impacts of COVID-19 on the Group as there are unprecedented market conditions with significant oil price volatility following the demand implications driven by COVID-19. The Group will not be able to meet its financial obligations if the price of crude oil should drop as low as US$25 per barrel. Considering there is no price hedging currently in place, we have concluded that there is a material uncertainty that may cast significant doubt on the Group's ability to continue as a going concern.

The Group closely monitors and carefully manages its liquidity risk. Cash forecasts are regularly produced, and sensitivities run for different scenarios including, but not limited to, changes in commodity prices and different production rates from the Group's producing asset. Cash forecasts have been updated in light of the oil price volatility seen in early 2020, with base case run using a forward curve of US$35/bbl. for 2020 and US$40 for 2021, and a downside sensitivity run at US$30/bbl. for both 2020 and 2021.

The Group's base assumptions show that it will be able to operate within its contractual debt facility taking into consideration the Group's debt restructure agreement executed on 21 July 2020 as well as its costs reduction strategy and as such have sufficient financial headroom for the 12 months from the date of approval of the 2019 Annual Report and Accounts.

The Group continues to closely monitor cash flow forecasts and would take mitigating actions in advance including further reducing its operational costs; deferment of capital activities on OPL 310 and other capital projects until it has raised the required funds to execute them; to further renegotiate its debt obligation; and to raise additional funds if the need arise from either the equity or debt markets.

Notwithstanding the material uncertainty, the Directors' confidence in the Group's forecasts and the mitigating actions above, supports the preparation of the financial statements on a going concern basis.

(c)  Basis of measurement

These consolidated financial statements have been prepared on the historical cost basis except for financial instruments and share based payments which are measured at fair values.

(d)  Functional and presentation currency

These consolidated financial statements are presented in US Dollars   which is the Company's functional currency. All amounts have been rounded to the nearest thousands of dollars (1,000), unless otherwise indicated.

(e)  Use of estimates and judgments

In the application of the Group's accounting policies, which are described in Note 3, management is required to make judgements, estimates and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other factors that are considered relevant. Actual results may differ from these estimates.

The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period, or in the period of the revision and future periods if the revision affects both current and future periods.

(i) Judgments

Information about judgments made in applying accounting policies that have the most significant effects on the amounts recognised in the consolidated financial statements is included in the following notes:

- Note 2(b) - Going concern basis of accounting.

- Determination of Joint control and classification of a joint arrangement - Judgment is required to determine when the Group has joint control over an arrangement, which requires an assessment of the relevant activities and when the decisions in relation to those activities require unanimous consent. The Group has determined that the relevant activities for its joint arrangements are those relating to the operating and capital decisions of the arrangement, including the approval of the annual capital and operating expenditure work programme and budget for the joint arrangement, and the approval of chosen service providers for any major capital expenditure as required by the joint operating agreements applicable to the Group's joint arrangements.

Judgment is also required to classify a joint arrangement. Classifying the arrangement requires the Group to assess their rights and obligations arising from the arrangement. Specifically, the Group considers:

· The structure of the joint arrangement - whether it is structured through a separate vehicle

· When the arrangement is structured through a separate vehicle, the Group also considers the rights and obligations arising from:

§ The legal form of the separate vehicle;

§ The terms of the contractual arrangement; and

§ Other facts and circumstances, considered on a case by case basis.

- Note 16(d) - Exploration and evaluation accounting judgment. The Group policy is to capitalise all expenditure incurred during the exploration and appraisal phase until the determination process has been completed or until such point as commercial reserves have been established. Exploration and evaluation assets are expected to be recouped in future through successful development and exploitation of the area of interest.

- Note 21 - The Group's assumption that Optimum funded obligation will be recovered through successful development of OPL 310.

- Note 21 - On the basis that the Group requires Ministerial Consent to take control of the OPL 310 oil mineral rights interest held by Afren Oil and Gas, the Group has not consolidated Afren Oil and Gas and has accounted for payments made in respect of the Afren Oil and Gas acquisition as other assets. However, with the implementation of IFRS 9, these balances were impaired.

(ii) Assumptions and estimation uncertainties

Information about assumptions and estimation uncertainties that have a significant risk of resulting in a material adjustment to the carrying amounts of assets and liabilities   in the year ending 31 December 2019 is included in the following notes:

Note 2(b) - Going concern. Key assumptions made, and judgment exercised by the Directors in preparing the Group's cash forecast.

Note 13(c) - Recognised deferred tax assets. Availability of future taxable profit against which carry forward losses can be utilised.

Note 15 - Impairment of oil and gas assets

Note 25 - Provisions for asset retirement obligation. Key assumptions underlying the asset retirement obligation as at year end.

Note 33 - Financial commitments and contingencies. Key assumptions about the likelihood and magnitude of future outflow of economic resources.

3 Significant accounting policies

The Group has consistently applied the following accounting policies to all periods presented in these consolidated financial statements.

(a) Basis of consolidation and Business combinations and Interests in joint operations

(i) Basis of consolidation

The consolidated financial statements incorporate the financial statements of the Company and entities controlled by the Company (its subsidiaries) made up to 31 December each year. Control is achieved when the Company:

· has the power over the investee;

· is exposed, or has rights, to variable returns from its involvement with the investee; and

· has the ability to use its power to affects its returns.

The Company reassesses whether or not it controls an investee if facts and circumstances indicate that there are changes to one or more of the three elements of control listed above.

When the Company has less than a majority of the voting rights of an investee, it considers that it has power over the investee when the voting rights are sufficient to give it the practical ability to direct the relevant activities of the investee unilaterally. The Company considers all relevant facts and circumstances in assessing whether or not the Company's voting rights in an investee are sufficient to give it power, including:

· the size of the Company's holding of voting rights relative to the size and dispersion of holdings of the other vote holders;

· potential voting rights held by the Company, other vote holders or other parties;

· rights arising from other contractual arrangements; and

· any additional facts and circumstances that indicate that the Company has, or does not have, the current ability to direct the relevant activities at the time that decisions need to be made, including voting patterns at previous shareholders' meetings.

Consolidation of a subsidiary begins when the Company obtains control over the subsidiary and ceases when the Company loses control of the subsidiary. Specifically, the results of subsidiaries acquired or disposed of during the year are included in profit or loss from the date the Company gains control until the date when the Company ceases to control the subsidiary.

Where necessary, adjustments are made to the financial statements of subsidiaries to bring the accounting policies used into line with the Group's accounting policies.

All intragroup assets and liabilities, equity, income, expenses and cash flows relating to transactions between the members of the Group are eliminated on consolidation.

Non-controlling interests in subsidiaries are identified separately from the Group's equity therein. Those interests of non-controlling shareholders that are present ownership interests entitling their holders to a proportionate share of net assets upon liquidation may initially be measured at fair value or at the non-controlling interests' proportionate share of the fair value of the acquiree's identifiable net assets. The choice of measurement is made on an acquisition-by-acquisition basis. Other non-controlling interests are initially measured at fair value. Subsequent to acquisition, the carrying amount of non-controlling interests is the amount of those interests at initial recognition plus the non-controlling interests' share of subsequent changes in equity.

Profit or loss and each component of other comprehensive income are attributed to the owners of the Company and to the non-controlling interests. Total comprehensive income of the subsidiaries is attributed to the owners of the Company and to the non-controlling interests even if this results in the non-controlling interests having a deficit balance.

Changes in the Group's interests in subsidiaries that do not result in a loss of control are accounted for as equity transactions. The carrying amount of the Group's interests and the non-controlling interests are adjusted to reflect the changes in their relative interests in the subsidiaries. Any difference between the amount by which the non-controlling interests are adjusted and the fair value of the consideration paid or received is recognised directly in equity and attributed to the owners of the Company.

When the Group loses control of a subsidiary, the gain or loss on disposal recognised in profit or loss is calculated as the difference between (i) the aggregate of the fair value of the consideration received and the fair value of any retained interest and (ii) the previous carrying amount of the assets (including goodwill), less liabilities of the subsidiary and any non-controlling interests. All amounts previously recognised in other comprehensive income in relation to that subsidiary are accounted for as if the Group had directly disposed of the related assets or liabilities of the subsidiary (i.e. reclassified to profit or loss or transferred to another category of equity as required/permitted by applicable IFRS Standards). The fair value of any investment retained in the former subsidiary at the date when control is lost is regarded as the fair value on initial recognition for subsequent accounting under IFRS 9 when applicable, or the cost on initial recognition of an investment in an associate or a joint venture.

(ii) Business combinations

The Group accounts for business combinations using the acquisition method when control is transferred to the Group. The consideration transferred in the acquisition is generally measured at fair value, as are the identifiable net assets acquired. Any goodwill that arises is tested annually for impairment. Any gain on a bargain purchase is recognised in profit or loss immediately. Transaction costs are expensed as incurred, except if related to the issue of debt or equity securities.

The consideration transferred does not include amounts related to the settlement of pre-existing relationships. Such amounts are generally recognised in profit or loss.

When the consideration transferred by the Group in a business combination includes a contingent consideration arrangement, the contingent consideration is measured at its acquisition-date fair value and included as part of the consideration transferred in a business combination. Changes in fair value of the contingent consideration that qualify as measurement period adjustments are adjusted retrospectively, with corresponding adjustments against goodwill. Measurement period adjustments are adjustments that arise from additional information obtained during the 'measurement period' (which cannot exceed one year from the acquisition date) about facts and circumstances that existed at the acquisition date.  

(iii) Interest in joint operations

A joint operation is a joint arrangement whereby the parties that have joint operation of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require unanimous consent of the parties sharing control.

When a Group entity undertakes its activities under joint operations, the Group as a joint operator recognises in relation to its interest in a joint operation:

· its assets, including its share of any assets held jointly;

· its liabilities, including its share of any liabilities incurred jointly;

· its revenue from the sale of its share of the output arising from the joint operation;

· its share of the revenue from the sale of the output by the joint operation; and

· its expenses, including its share of any expenses incurred jointly.

The Group accounts for the assets, liabilities, revenue and expenses relating to its interest in a joint operation in accordance with the IFRS Standards applicable to the particular assets, liabilities, revenue and expenses.

The Group has interests in the following joint operations:

· Otakikpo marginal field

The Otakikpo marginal field lies in a coastal swamp location in OML 11, adjacent to the shoreline in the south-eastern part of the Niger Delta.

The Group farmed-in to Otakikpo in May 2014 for the acquisition of 40 percent participating interest from Green Energy International Limited ("GEIL"), the operator of the field. The consideration paid to GEIL for the acquisition of the interest comprised a signature bonus of US$7 million and a production bonus of US$ 4 million.

Commercial production commenced in February 2017 and the asset has been producing steadily till date.

· OPL 310

OPL 310 is located in the Dahomey Basin on the West African Transform Margin. The block extends from the shallow water continental shelf close by the City of Lagos, into deeper water.

The Group farmed-in to OPL 310 in 2013 for a 17.14 percent participating interest but received the consent of the Minister of Petroleum Resources of Nigeria for the approval of the acquisition of the 17.14 participating interest on 9 June 2017.

The operator of the field is Optimum Petroleum Development Limited having 60 percent participating interest while the remaining 22.86 percent is held by Afren Investments Oil and Gas (Nigeria) Limited.

The Federal Government of Nigeria granted during the year, an extension of the asset's licence for additional 3 years effective 2 August 2019. The asset is at appraisal and exploration stage.

· OPL 325

OPL 325 is located in the offshore Dahomey Basin within the wrench zone that straddles the western Niger Delta and is located 50km to the south of OPL 310.

In October 2015, the Group entered into an agreement with Ashbert Limited to acquire, via Lekoil Exploration and Production Nigeria Limited, 88.57 percent of the issued share capital of Ashbert Oil and Gas Limited, which was awarded the OPL 325 licence for an initial consideration of US$16.1 million, with other payments due at development milestones totaling US$24.1 million. Ashbert Oil and Gas Limited has 70 percent participating interest in the OPL 325.

The other licence partners to OPL 325 are National Petroleum Development Company Limited (NPDC) that has 20 percent working interest and Local content vehicle that has 10 percent working interest.

The Production Sharing Contract is yet to be finalised.

(b) Foreign currency

The US Dollar is the presentation currency of the Group.

Transactions in foreign currencies are recorded at the rates of exchange ruling at the transaction dates. Monetary assets and liabilities are translated into functional currency at the exchange rate ruling at the balance sheet date, with a corresponding charge or credit to the profit or loss account.

Non-monetary assets and liabilities that are measured at fair value in a foreign currency are translated into the functional currency at the exchange rate when the fair value was determined. Non-monetary items that are measured based on historical cost in a foreign currency are translated at the exchange rate at the date of the transaction.

However, foreign currency differences arising from the translation of the following items are recognised in Other Comprehensive Income ("OCI"):

- a financial liability designated as a hedge of the net investment in a foreign operation to the extent that the hedge is effective; and

- exchange differences on transactions entered into to hedge foreign currency risks.

(c) Revenue

(i) Sale of crude

Revenue represents sales value of Group's share of liftings in the year. Revenue is recognised when or as the Group satisfies a performance obligation by transferring control of a promised good or service to a customer. The transfer of control of oil usually coincides with title passing to the customer and the customer taking physical possession.

When, or as a performance obligation is satisfied, the Group recognises as revenue the amount of the transaction price that is allocated to that performance obligation. The transaction price is the amount of consideration to which the Group expects to be entitled.

(ii) Costs of sales

Production expenditure, crude treatment and processing expenditure, crude evacuation and lifting expenditure, depreciation, depletion and amortisation of oil and gas assets and crude handling expenditure are reported as costs of sales.

(iii) Interest income

Interest income, including income arising from finance leases and other financial instruments, is recognised using the effective interest method.

(iv) Overlift and underlift

Lifting or offtake arrangements for oil and gas production in certain of the Group's jointly owned operations are such that each participant may not receive and sell its precise share of the overall production in each period. The resulting imbalance between cumulative entitlement and cumulative production less stock is underlift or overlift. Underlift and overlift are valued at market value and included within receivables and payables respectively. Movements during an accounting period are adjusted through cost of sales such that gross profit is recognised on an entitlement's basis.

In respect of redeterminations, any adjustments to the Group's net entitlement of future production are accounted for prospectively in the period in which the make-up oil is produced. Where the make-up period extends beyond the expected life of a field, an accrual is recognised for the expected shortfall.

(d) Share capital

(i) Ordinary shares

Ordinary shares are classified as equity. Incremental costs directly attributable to the issue of ordinary shares are recognised as a deduction from equity, net of any tax effects.

(e)  Financial instruments

Financial assets and financial liabilities are recognised in the Group's statement of financial position when the Group becomes a party to the contractual provisions of the instrument.

Financial assets and financial liabilities are initially measured at fair value. Transaction costs that are directly attributable to the acquisition or issue of financial assets and financial liabilities (other than financial assets and financial liabilities at fair value through profit or loss ("FVTPL")) are added to or deducted from the fair value of the financial assets or financial liabilities, as appropriate, on initial recognition. Transaction costs directly attributable to the acquisition of financial assets or financial liabilities at FVTPL are recognised immediately in profit or loss.

Financial assets

Financial assets are classified in the following categories:

(i)  financial assets measured at amortised cost;

(ii)  financial assets measured at fair value through other comprehensive income ("FVTOCI"); and

(iii)  financial assets measured at FVTPL.

At initial recognition, a financial asset is measured at its fair value; at initial recognition, trade receivables that do not have a significant financing component are measured at their transaction price. After initial recognition, financial assets whose contractual terms give rise to cash flows that are solely payments of principal and interest on the principal amount outstanding are measured at amortised cost. For financial assets measured at amortised cost, interest income determined using the effective interest rate, foreign exchange differences and any impairment losses are recognised in the profit or loss account.

Conversely, financial assets that are debt instruments are measured at FVTOCI. In these cases: (i) interest income determined using the effective interest rate, foreign exchange differences and any impairment losses are recognised in the profit or loss account; (ii) changes in fair value of the instruments are recognised in equity, within other comprehensive income. The accumulated changes in fair value, recognised in the equity reserve related to other comprehensive income, is reclassified to the profit and loss account when the financial asset is derecognised.

Financial assets that do not meet the criteria for being measured at amortised cost or FVTOCI are measured at FVTPL. Financial assets at FVTPL are measured at fair value at the end of each reporting period, with any fair value gains or losses recognised in profit or loss account.

Impairment of financial assets

The Group assesses the expected credit losses associated with financial assets classified as measured at amortised cost at each balance sheet date. Expected credit losses ("ECL's") are measured based on the maximum contractual period over which the Group is exposed to credit risk. The measurement of ECL's is a function of the probability of default, loss event default and exposure at default. The ECL is estimated as the difference between the asset's carrying amount and the present value of the future cash flows the Group expects to receive discounted at the financial asset's original effective interest rate. The carrying amount of the asset is adjusted, with the amount of the impairment gain or loss recognised in the income statement.

ECL's are recognised in two stages. For credit exposures for which there has not been a significant increase in credit risk since initial recognition, ECL's are provided for credit losses that result from default events that are possible within the next 12-months ("a 12-month ECL"). For those credit exposures for which there has been a significant increase in credit risk since initial recognition, a loss allowance is required for credit losses expected over the remaining life of the exposure, irrespective of the timing of the default ("a lifetime ECL"). For trade receivables, the Group applies a simplified approach in calculating ECL's.

For all other financial instruments, the Group recognises lifetime ECL when there has been a significant increase in credit risk since initial recognition. However, if the credit risk on the financial instrument has not increased significantly since initial recognition, the Group measures the loss allowance for that financial instrument at an amount equal to 12-month ECL.

The Group recognises an impairment gain or loss for all financial instruments with a corresponding adjustment to their carrying amount through a loss allowance account, except for investments in debts instruments that are measured at FVTOCI, for which the loss allowance is recognised in other comprehensive income and accumulated in the investment revaluation reserve, and does not reduce the carrying amount of the financial asset in the statement of financial position.

Derecognition of financial assets

The Group derecognises a financial asset only when the contractual rights to the cash flows from the asset expire, or when it transfers the financial asset and substantially all the risks and rewards of ownership of the asset to another entity. If the Group neither transfers nor retains substantially all the risks and rewards of ownership and continues to control the transferred asset, the Group recognises its retained interest in the asset and an associated liability for amounts it may have to pay. If the Group retains substantially all the risks and rewards of ownership of a transferred financial asset, the Group continues to recognise the financial asset and recognises a collateralised borrowing for the proceeds received.

On derecognition of a financial asset measured at amortised cost, the difference between the asset's carrying amount and the sum of the consideration received and receivable is recognised in profit or loss.

Financial liabilities and equity

Equity instruments

An equity instrument is any contract that evidences a residual interest in the assets of an entity after deducting all its liabilities. Equity instruments issued by the Group are recognised at the proceeds received, net of direct issue costs.

Financial liabilities

All financial liabilities are measured subsequently at amortised cost using the effective interest method or at FVTPL.

Financial liabilities at FVTPL

Financial liabilities are classified as at FVTPL when the financial liability is:

· contingent consideration of an acquirer in a business combination;

· it is designated as at FVTPL.

A financial liability is classified as held for trading if:

· it has been acquired principally for repurchasing it in the near term; or

· it is a derivative, except for a derivative that is a financial guarantee contract or a designated and effective hedging instrument.

A financial liability or contingent consideration of an acquirer in a business combination may be designated as at FVTPL upon initial recognition if:

· such designation eliminates or significantly reduces a measurement or recognition inconsistency that would otherwise arise; or

· the financial liability forms part of a group of financial assets or financial liabilities or both, which is managed and its performance is evaluated on a fair value basis; or

· it forms part of a contract containing one or more embedded derivatives, and IFRS 9 permits the entire combined contract to be designated as at FVTPL.

Financial liabilities at FVTPL are measured at fair value, with any gains or losses arising on changes in fair value recognised in profit or loss to the extent that they are not part of a designated hedging relationship.

However, for financial liabilities that are designated as at FVTPL, the amount of change in the fair value of the financial liability that is attributable to changes in the credit risk of that liability is recognised in other comprehensive income, unless the recognition of the effects of changes in the liability's credit risk in other comprehensive income would create or enlarge an accounting mismatch in profit or loss. The remaining amount of change in the fair value of liability is recognised in profit or loss. Changes in fair value attributable to a financial liability's credit risk that are recognised in other comprehensive income are not subsequently reclassified to profit or loss; instead, they are transferred to retained earnings upon derecognition of the financial liability.

Financial liabilities measured subsequently at amortised cost

Financial liabilities that are not:

· contingent consideration of an acquirer in a business combination;

· designated as at FVTPL, are measured subsequently at amortised cost using the effective interest method.

The effective interest method is a method of calculating the amortised cost of a financial liability and of allocating interest expense over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash payments (including all fees and points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the financial liability, or (where appropriate) a shorter period, to the amortised cost of a financial liability.

Derecognition of financial liabilities

The Group derecognises financial liabilities when, and only when, the Group's obligations are discharged, cancelled or have expired. The difference between the carrying amount of the financial liability derecognised and the consideration paid and payable is recognised in profit or loss.

(f) Property, plant and equipment

(i) Recognition and measurement

Items of property, plant and equipment are measured at cost, which includes capitalised borrowing costs, less accumulated depreciation and any accumulated impairment losses. Cost includes expenditure that is directly attributable to the acquisition of the asset. When parts of an item of property, plant and equipment have different useful lives, they are accounted for as separate items (major components) of property, plant and equipment. An item of property, plant and equipment is derecognised upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. The gain or loss arising on the disposal or retirement of an asset is determined as the difference between the sales proceeds and the carrying amount of the asset and is recognised in profit or loss.

(ii) Subsequent expenditure

Subsequent expenditure is capitalised only if it is probable that the future economic benefits associated with the expenditure will flow to the Group.

(iii) Depreciation

Items of property, plant and equipment are depreciated from the date they are available for use or, in respect of self-constructed assets, from the date that the asset is completed and ready for use.

Depreciation is calculated to write off the cost of items of property, plant and equipment less their estimated residual values using the straight-line basis over their estimated useful lives. Depreciation is generally recognised in profit or loss, unless the amount is included in the carrying amount of another asset. Leased assets are depreciated over the shorter of the lease term and their useful lives unless it is reasonably certain that the Group will obtain ownership by the end of the lease term.

The estimated useful lives of property, plant and equipment for the current and comparative years are as follows:

• Motor vehicles	- 5 years
• Furniture and fittings	- 5 years
• Leasehold improvement	- 2 years
• Computers, Communication & Household Equipment	- 4 years
• Plant Machinery, Storage Tank & Others	- 4 years
• Oil and gas assets	- Unit of production method based on proved developed reserves

Depreciation methods, useful lives and residual values are reviewed at each reporting date and adjusted if appropriate.

(g) Exploration and Evaluation (E&E) expenditures

(i) Licence acquisition costs: Licence acquisition costs are capitalised as intangible E&E assets. These costs are reviewed on a continual basis by management to confirm that activity is planned and that the asset is not impaired. If no future activity is planned, the remaining balance of the licence and property acquisition costs are written off. Capitalised licence acquisition costs are measured at cost less accumulated amortisation and impairment losses. Costs incurred prior to having obtained the legal rights to explore an area are expensed directly as they are incurred.

(ii) Exploration expenditure: All exploration and appraisal costs are initially capitalised in well, field or specific exploration cost centres as appropriate pending future exploration work programmes and pending determination. All expenditure incurred during the various exploration and appraisal phase is capitalised until the determination process has been completed or until such point as commercial reserves have been established. Payments to acquire technical services and studies, seismic acquisition, exploratory drilling and testing, abandonment costs, directly attributable administrative expenses are all capitalised as exploration and evaluation assets. Capitalised exploration expenditure is measured at cost less impairment losses.

Treatment of E & E assets at conclusion of exploratory and appraisal activities

Exploration and evaluation assets are carried forward until the existence, or otherwise, of commercial reserves has been determined. If commercial reserves have been discovered, the related E&E assets are assessed for impairment on a cost pool basis as set out below and any impairment loss is recognised in the income statement. The carrying value, after any impairment loss, of the relevant E&E assets is then reclassified as development and production assets within property, plant and equipment or intangible assets. If, however, commercial reserves have not been found, the capitalised costs are charged to expense after the conclusion of the exploratory and appraisal activities. Exploration and evaluation costs are carried as assets and are not depreciated prior to the conclusion of exploratory and appraisal activities.

An E&E asset is assessed for impairment when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Such circumstances include the point at which a determination is made as to whether or not commercial reserves exist. Where the E&E asset concerned falls within the scope of an established full cost pool, the E&E asset is tested for impairment together with any other E&E assets and all development and production assets associated with that cost pool, as a single cash generating unit.

The aggregate carrying value is compared against the expected recoverable amount of the pool, generally by reference to the present value of the future net cash flows expected to be derived from production of commercial reserves. Where the E&E asset to be tested falls outside the scope of any established cost pool, there will generally be no commercial reserves and the E&E asset concerned will be written off in full.

(h) Development expenditure

Once the technical feasibility and commercial viability of extracting oil and gas resources are demonstrable, expenditure related to the development of oil and gas resources which are not tangible in nature are classified as intangible development expenditure. Capitalised development expenditure is measured at cost less accumulated amortisation and impairment losses. Amortisation of development assets attributable to the participating interest is recognised in profit or loss using the unit-of-production method based on proved developed reserves.

(i) Leases

(a) The Group as lessee

The Group assesses whether a contract is or contains a lease, at inception of the contract. The Group recognises a right-of-use asset and a corresponding lease liability with respect to all lease arrangements in which it is the lessee, except for short-term leases (defined as leases with a lease term of 12 months or less) and leases of low value assets (such as tablets and personal computers, small items of office furniture and telephones). For these leases, the Group recognises the lease payments as an operating expense on a straight-line basis over the term of the lease unless another systematic basis is more representative of the time pattern in which economic benefits from the leased assets are consumed.

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted by using the rate implicit in the lease. If this rate cannot be readily determined, the Group uses its incremental borrowing rate.

Lease payments included in the measurement of the lease liability comprise:

· Fixed lease payments (including in-substance fixed payments), less any lease incentives receivable;

· Variable lease payments that depend on an index or rate, initially measured using the index or rate at the commencement date;

· The amount expected to be payable by the lessee under residual value guarantees;

· The exercise price of purchase options, if the lessee is reasonably certain to exercise the options; and

· Payments of penalties for terminating the lease, if the lease term reflects the exercise of an option to terminate the lease.

The lease liability is subsequently measured by increasing the carrying amount to reflect interest on the lease liability (using the effective interest method) and by reducing the carrying amount to reflect the lease payments made.

The Group remeasures the lease liability (and makes a corresponding adjustment to the related right-of-use asset) whenever:

· The lease term has changed or there is a significant event or change in circumstances resulting in a change in the assessment of exercise of a purchase option, in which case the lease liability is remeasured by discounting the revised lease payments using a revised discount rate.

· The lease payments change due to changes in an index or rate or a change in expected payment under a guaranteed residual value, in which cases the lease liability is remeasured by discounting the revised lease payments using an unchanged discount rate (unless the lease payments change is due to a change in a floating interest rate, in which case a revised discount rate is used).

· A lease contract is modified and the lease modification is not accounted for as a separate lease, in which case the lease liability is remeasured based on the lease term of the modified lease by discounting the revised lease payments using a revised discount rate at the effective date of the modification.

The Group did not make any such adjustments during the periods presented.

The right-of-use assets comprise the initial measurement of the corresponding lease liability, lease payments made at or before the commencement day, less any lease incentives received and any initial direct costs. They are subsequently measured at cost less accumulated depreciation and impairment losses.

Whenever the Group incurs an obligation for costs to dismantle and remove a leased asset, restore the site on which it is located or restore the underlying asset to the condition required by the terms and conditions of the lease, a provision is recognised and measured under IAS 37. To the extent that the costs relate to a right-of-use asset, the costs are included in the related right-of-use asset, unless those costs are incurred to produce inventories.

Right-of-use assets are depreciated over the shorter period of lease term and useful life of the underlying asset. If a lease transfers ownership of the underlying asset or the cost of the right-of-use asset reflects that the Group expects to exercise a purchase option, the related right-of-use asset is depreciated over the useful life of the underlying asset. The depreciation starts at the commencement date of the lease.

(j) Inventories

Inventories comprise of crude oil stock at period end and consumable materials.

Inventories are valued at the lower of cost and net realisable value. Cost of consumable materials is determined using the weighted average method and includes expenditures incurred in acquiring the stocks, and other costs incurred in bringing them to their existing location and condition.

Net realisable value is the estimated selling price in the ordinary course of business, less the estimated costs of completion and selling expenses. Inventory values are adjusted for obsolete, slow-moving or defective items where appropriate.

(k) Intangible assets

An intangible asset is an identifiable non-monetary asset without physical substance. The Group expends resources or incurs liabilities on the acquisition, development, maintenance or enhancement of intangible resources such as scientific or technical knowledge, design and implementation of new processes on systems, licences, signature bonus, intellectual property, market knowledge and trademarks.

The Group recognises an intangible asset if, and only if;

i. economic benefits that are attributable to the asset will flow to the entity; and

ii.  the costs of the asset can be measured reliably.

The Group assesses the probability of future economic benefits using reasonable and supportable assumptions that represent management's best estimate of the set of economic conditions that will exist over the useful life of the asset. Intangible assets are measured initially at cost.

Amortisation is calculated to write off the cost of the intangible asset less its estimated residual value using the straight-line basis over the estimated useful lives or using the units of production basis from the date that they are available for use. The estimated useful life and methods of amortisation of intangible assets for current and comparative years are as follows:

Type of asset	Basis
Mineral rights acquisition costs (signature bonus)	Amortised over the licence period.
Accounting software	Amortised over a useful life of three years.
Geological and geophysical software	Amortised over a useful life of five years.

(l) Employee benefits

(i) Short-term employee benefits

Short-term employee benefits are expensed as the related service is provided. A liability is recognised for the amount expected to be paid if the Group has a present legal or constructive obligation to pay this amount because of past service provided by the employee and the obligation can be estimated reliably.

(ii) Share-based payment transactions

The grant-date fair value of equity-settled share-based payment awards granted to employees and others providing similar services is recognised as an employee expense and other general and administrative expense respectively, with a corresponding increase in equity, over the vesting period that the employees become unconditionally entitled to the awards. The amount recognised as an expense is adjusted to reflect the number of awards for which the related service and non-market performance conditions are expected to be met, such that the amount ultimately recognised is based on the number of awards that meet the related service and non-market performance conditions at the vesting date. For share-based-payment awards with non-vesting conditions, the grant-date fair value of the share-based payment is measured to reflect such conditions and there is no true-up for differences between expected and actual outcomes.

(iii) Post-employment benefits

Defined contribution plan

A defined contribution plan is a post-employment benefit plan (pension fund) under which the Group pays fixed contributions into a separate entity. The Group has no legal or constructive obligations to pay further contributions if the fund does not hold sufficient assets to pay all employees the benefits relating to the employee service in the current and prior periods.

In line with the provisions of the Pension Reform Act 2014, a subsidiary domiciled in Nigeria has instituted a defined contribution pension scheme for its permanent staff. Staff contributions to the scheme are funded through payroll deductions while the subsidiary's contribution is recognised in profit or loss as employee benefit expense in the periods during which services are rendered by employees. Employees contribute 8% each of their gross salary to the fund monthly. The subsidiary's contribution is 10% of each employee's gross salary.

(m) Provisions

A provision is recognised if, as a result of a past event, the Group has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. The unwinding of the discount is recognised as finance cost.

The Group's Asset Retirement Obligation ("ARO") primarily represents the estimated present value of the amount the Group will incur to plug, abandon and remediate its areas of operation at the end of their productive lives, in accordance with applicable legislations. The Group determines the ARO on its oil and gas properties by calculating the present value of estimated cash flows related to the liability when the related facilities are installed or acquired.

Contingent liabilities

A contingent liability is a possible obligation that arises from past events and whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Group, or a present obligation that arises from past events but is not recognised because it is not probable that an outflow of resources embodying economic benefits will be required to settle the obligation; or the amount of the obligation cannot be measured with sufficient reliability.

Contingent liabilities are only disclosed and not recognised as liabilities in the statement of financial position. If the likelihood of an outflow of resources is remote, the possible obligation is neither a provision nor a contingent liability and no disclosure is made.

(n) Finance income and finance costs

Finance income comprises, where applicable,   interest income on funds, dividend income, gains on the disposal of financial assets, fair value gains on financial assets at fair value through profit or loss, gains on the remeasurement to fair value of any pre-existing interest in an acquiree in a business combination, gains on hedging instruments that are recognised in profit or loss and reclassifications of net gains previously recognised in other comprehensive income. Interest income is recognised as it accrues in profit or loss, using the effective interest method. Dividend income is recognised in profit or loss on the date that the Group's right to receive payment is established.

Finance costs comprise, where applicable, interest expense on borrowings, unwinding of the discount on provisions and deferred consideration,  dividends on preference shares classified as liabilities, fair value losses on financial assets at fair value through profit or loss and contingent consideration, impairment losses recognised on financial assets (other than trade receivables), losses on hedging instruments that are recognised in profit or loss and reclassifications of net losses previously recognised in other comprehensive income.

Borrowing costs that are not directly attributable to the acquisition, construction or production of a qualifying asset are recognised in profit or loss using the effective interest method.

Foreign currency gains and losses are reported on a net basis as either finance income or finance cost depending on whether foreign currency movements are in a net gain or net loss position.

(o) Earnings per share

The Group presents basic and diluted earnings per share ("EPS") data for its ordinary shares. Basic EPS is calculated by dividing the profit or loss attributable to ordinary shareholders of the Company by the weighted average number of ordinary shares outstanding during the year. Diluted earnings per share is determined by adjusting the profit or loss attributable to ordinary shareholders and the weighted average number of ordinary shares outstanding for the effects of all dilutive potential ordinary shares which comprise share options granted to employees. Potential ordinary shares are treated as dilutive when, and only when, their conversion to ordinary shares would decrease earnings per share or increase loss per share from continuing operations.

(p) Segment reporting

An operating segment is a component of the Group that engages in business activities from which it may earn revenues and incurs expenses, including revenues and expenses that relate to transactions with any of the Group's other components. The Group defines geographical areas as operating segments in accordance with IFRS 8- Operating Segments.

(q) Income tax

Income tax expense comprises current and deferred tax. It is recognised in profit or loss except to the extent that it relates to a business combination, or items recognised directly in equity or other comprehensive income.

(i) Current tax

Current tax comprises the expected tax payable or receivable on the taxable income or loss for the year and any adjustment to tax payable or receivable in respect of previous years. The amount of current tax payable or receivable is the best estimate of the tax amount expected to be paid or received that reflects uncertainty related to income taxes, if any. It is measured using tax rates enacted or substantively enacted at the reporting date. Current tax also includes any tax arising from dividends.

(ii) Deferred tax

Deferred tax is recognised in respect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amount used for taxation purposes.

Deferred tax is not recognised for:

- temporary differences on the initial recognition of assets or liabilities in a transaction that is not a business combination and that affects neither accounting nor taxable profit or loss;

- temporary differences related to investments in subsidiaries, associates and joint arrangements to the extent that the Group is able to control the timing of the reversal of the temporal differences and it is probable that they will not reverse in the foreseeable future; and

- taxable temporary differences arising on the initial recognition of goodwill.

Deferred tax assets are recognised for unused tax losses, unused tax credits and deductible temporary differences to the extent that it is probable that future taxable profit will be available against which they can be used. Future taxable profits are determined based on the reversal of relevant taxable temporary differences. If the amount of taxable temporary difference is insufficient to recognise a deferred tax asset in full, then future taxable profits, adjusted for reversals of existing temporary differences, are considered, based on the business plans for individual subsidiaries in the Group. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realised; such reductions are reversed when the probability of future taxable profits improves.

Unrecognised deferred tax assets are reassessed at each reporting date and recognised to the extent that it has become probable that future profits will be available against which they can be used.

Deferred tax is measured at the tax rates that are expected to be applied to temporary difference when they reverse, using tax rates enacted or substantively enacted at the reporting date.

The measurement of deferred tax reflects the tax consequences that would follow from the way the Group expects, at the reporting date, to recover or settle the carrying amount of its assets and liabilities.

Deferred tax assets and liabilities are offset when there is a legally enforceable right to set off current tax assets against current tax liabilities and when they relate to income taxes levied by the same taxation authority and the Group intends to settle its current tax assets and liabilities on a net basis.  

4 Measurement of fair values

Several of the Group's accounting policies and disclosures require the measurement of fair values, for both financial and non-financial assets and liabilities.

The Group has an established control framework with respect to the measurement of fair values. This includes a valuation expert that has responsibility for overseeing all significant fair value measurements, including Level 3 fair values, and reports directly to the Chief Financial Officer.

When measuring the fair value of an asset or a liability, the Group uses observable market data as far as possible. Fair values are categorised into different levels in a fair value hierarchy based on the inputs used in the valuation techniques as follows:

· Level 1: quoted prices (unadjusted) in active markets for identical assets or liabilities.

· Level 2: inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices).

· Level 3: inputs for the asset or liability that are not based on observable market data (unobservable inputs).

If the inputs used to measure the fair value of an asset or a liability might be categorised in different levels of the fair value hierarchy, then the fair value measurement is categorised in its entirety in the same level of the fair value hierarchy as the lowest level input that is significant to the entire measurement.

The Group recognises transfers between levels of the fair value hierarchy at the end of the reporting period during which the change has occurred. Further information about the assumptions made in measuring fair values is included in the following notes:

Note 30- share-based payment arrangements

Note 34 - financial risk management and financial instruments

5 Adoption of new and revised International Financial Reporting Standards

5.1 Accounting standards and interpretations issued that became effective during the year 2019

Impact of initial application of IFRS 16 Leases

In the current year, IFRS 16 (as issued by the IASB in January 2016) became effective for annual periods that begin on or after 1 January 2019. IFRS 16 introduces new or amended requirements with respect to lease accounting. It introduces significant changes to lessee accounting by removing the distinction between operating and finance lease and requiring the recognition of a right-of-use asset and a lease liability at commencement for all leases, except for short-term leases and leases of low value assets. In contrast to lessee accounting, the requirements for lessor accounting have remained largely unchanged.

The Group leases are largely short-term lease and the Group has elected to adopt the exception for short term leases. The impacts of the adoption of IFRS 16 on the Group's consolidated financial statements is lease expense charge in operating expense (note 11). There were no impact to the Group on transition.

In the current year, the Group has applied a number of amendments to IFRS Standards and interpretations issued by the IASB that are effective for an annual period that begins on or after 1 January 2019. Their adoption has not had any material impact on the disclosures or on the amounts reported in these financial statements. These amendments include:

· IFRIC Interpretation 23 Uncertainty over Income Tax Treatments

· Amendments to IFRS 9 Prepayment Features with Negative Compensation

· Amendments to IAS 28 Long-term Interests in Associates and Joint Ventures

· Amendments to IAS 19 Amendment, Curtailment or Settlement

Annual IFRS Improvements to IFRS Standards 2015 -2017 Cycle Amendments to IFRS 3 Business Combinations, IFRS 11 Joint Arrangements, IAS 12 Income Taxes and IAS 23 Borrowing Costs

5.2 Accounting standards and interpretations issued but not yet effective

The following revisions to accounting standards and pronouncements that are applicable to the Group were issued but are not yet effective. Where IFRSs and International Financial Reporting Interpretations Committee ("IFRIC") interpretations listed below permits early adoption, the Group has elected not to apply them in the preparation of these consolidated financial statements. The Group plans to adopt the standard when it becomes effective.

The full impact of these IFRS's and IFRIC interpretations is currently being assessed by the Group, but none of these pronouncements are expected to result in any material adjustments to the consolidated financial statements.

Pronouncement	Nature of change				Effective date
IFRS 17 Insurance Contracts	IFRS 17 establishes the principles for the recognition, measurement, presentation and disclosure of insurance contracts and supersedes IFRS 4 Insurance Contracts.				1 January 2021 (likely to be extended to 1 January 2022)
Definition of Material - Amendments to IAS 1 and IAS 8	The IASB has made amendments to IAS 1 Presentation of Financial Statements and IAS 8 Accounting Policies, Changes in Accounting Estimates and Errors which use a consistent definition of materiality throughout International Financial Reporting Standards and the Conceptual Framework for Financial Reporting, clarify when information is material and incorporate some of the guidance in IAS 1 about immaterial information.				1 January 2020
Definition of a Business - Amendments to IFRS 3	The amended definition of a business requires an acquisition to include an input and a substantive process that together significantly contribute to the ability to create outputs.			1 January 2020
Revised Conceptual Framework for Financial Reporting		Together with the revised Conceptual Framework, which became effective upon publication on 29 March 2018, the IASB has also issued Amendments to References to the Conceptual Framework in IFRS Standards. The document contains amendments to IFRS 2, IFRS 3, IFRS 6, IFRS 14, IAS 1, IAS 8, IAS 34, IAS 37, IAS 38, IFRIC 12, IFRIC 19, IFRIC 20, IFRIC 22, and SIC-32.	1 January 2020
Sale or contribution of assets between an investor and its associate or joint venture - Amendments to IFRS 10 and IAS 28		The IASB has made limited scope amendments to IFRS 10 Consolidated financial statements and IAS 28 Investments in associates and joint ventures. The amendments clarify the accounting treatment for sales or contribution of assets between an investor and its associates or joint ventures.	The effective date has not been set by IASB. **

6 Operating segments

The Group has a single class of business which is exploration, development and production of crude oil and natural gas. For management purposes, the Group is organised into geographical locations and has one reportable segment under IFRS 8 Operating Segment which is Nigeria. Other geographic locations include USA, Cayman Islands.

The Chief Executive Officer is considered the Chief Operating Decision Maker (CODM) and monitors the operating results of these geographical locations for the purpose of making decisions about resource allocation and performance assessment. Segment performance is evaluated based on total profit or loss.

The accounting policies used by the Group in reporting segments internally are the same as those described in the significant accounting policies in Note 3.

The following is an analysis of the Group's revenue and results by reportable segment in 2019. Profit/(Loss) for the years represents total profit or loss for the year after taxation. This is the measure reported to the Group's CODM for the purpose of resource allocation and assessment of segment performance.

	Nigeria 2019 US$'000		Other 2019 US$'000		Consolidated 2019 US$'000
Revenue	42,027		-		42,027
Loss for the year	(4,559)		(7,474)		(12,033)
	Nigeria 2018 US$'000		Other 2018 US$'000		Consolidated 2018 US$'000
Revenue	48,687		-		48,687
Profit/(Loss) for the year	2,870		(10,653)		(7,783)

Other segment information

		Nigeria 2019 US$'000		Other 2019 US$'000		Consolidated 2019 US$'000
Interest expense		3,877		-		3,877
Interest income		238		-		238
Depreciation and amortisation		8,917		-		8,917
Income tax expense		7,118		-		7,118
		Nigeria 2018 US$'000		Other 2018 US$'000		Consolidated 2018 US$'000
Interest expense		4,569		-		4,569
Interest income		7,151		-		7,151
Depreciation and amortisation		9,875		-		9,875
Income tax expense		10,077		-		10,077

Other segment information represents information included in the measure of segment profit or loss reviewed by the Group's CODM.

Geographical information

The Group's revenue from external customer and information about non-current assets excluding financial instruments, deferred tax assets and other financial assets by geographical locations are detailed below:

     Revenue      Non-current assets

	2019 US$'000	2018 US$'000	2019 US$'000	2018 US$'000
Nigeria	42,027	48,687	192,546	174,880
USA	-	-	-	5
Cayman Islands	-	-	-	2
	42,027	48,687	192,546	174,887

Information about major customer

The Group has a single customer which contributes 100 percent of the Group's revenue in 2019 and 2018. The Group's revenue from this customer is disclosed in note 8.

7 Capital Management

The Group's policy is to maintain a strong capital base to maintain investor, creditor and market confidence and to sustain future development of the business.

The Group monitors capital using a ratio of adjusted net debt to adjusted equity. For this purpose, adjusted net debt is defined as total liabilities less cash and bank balances.

The Group's net debt to equity ratio at the end of the reporting year was as follows:

	2019 US$'000	2018 US$'000
Total liabilities	42,861	41,040
Less: cash and bank balances	(2,733)	(10,423)
Net debt	40,128	30,617
Equity	174,344	185,305
Net debt to equity ratio	0.23	0.17

There were no changes in the Group's approach to capital management during the year. The Group is not subject to externally imposed capital requirements.

8 Revenue

	2019 US$'000	2018 US$'000
Crude proceeds (a)	42,027	48,687

(a)  Crude proceeds of US$42.0 million represents the Group's share of crude oil sales from Otakikpo operation during the year, which is recognised as revenue ("equity crude"), (31 December 2018: US$48.7 million). The Group's equity crude was 677,788 barrels (31 December 2018: 739,106 barrels) out of which the Group lifted 634,407 barrels (31 December 2018: 696,716 barrels). The balance of 43,381 barrels (31 December 2018: 42,390 barrels) representing the Group's share of overriding royalty crude was lifted on its behalf by its joint operating partner GEIL based on an agreed lifting arrangement. In addition, the Group lifted 32,745 barrels in cost recovery crude made up of outstanding pre-paid development costs (16,260 barrels; US$0.93 million) and GEIL carried cost (16,485 barrels; US$0.94 million) during the year (31 December 2018: 507,176 barrels).

		2019		2018
		Barrels	US$'000	Barrels	US$'000
Equity crude		677,788	42,027	739,106	48,687
Cost recovery crude		32,745	1,875	507,176	34,055
GEIL cash call crude		-	-	100,243	6,587
		710,533	43,902	1,346,525	89,329

(b)  The Group has a single customer Shell Western Supply and Trading Limited whom it executed a crude off take agreement with.

9 Costs of sales

	2019 US$'000	2018 US$'000
Depletion	6,212	7,893
Crude handling, evacuation and production operation costs	6,011	5,756
Royalty expenses	3,146	4,919
Closing stock adjustments	(1,236)	(549)
Other expenses	-	99
	14,133	18,118

10 Operating expenses

	2019 US$'000	2018 US$'000
Field personnel costs	3,474		3,631
Field facility management costs	200		378
Community and security expenses	2,345		2,081
Gas flaring	331		187
Other operating costs	1,384	1,665
	7,734	7,942

11 General and administrative expenses

	2019 US$'000	2018 US$'000
Personnel expenses (a)	8,382	8,033
Depreciation and amortization (Notes 15 and 17)	2,705	1,982
Rent and facility management expenses (b)	1,650	1,514
NDDC levy	363	(2,692)
Travel expenses	1,020	1,460
IT and telecommunication expenses	866	1,217
Audit	356	349
Non audit services	-	52
Legal and consultancy expenses*	4,068	5,238
Other expenses	2,026	1,980
	21,436	19,133

(a) Personnel expenses

	2019 US$'000	2018 US$'000
Wages and salaries	6,859	6,488
Defined contribution pension expense	451	371
Equity settled share-based payment	1,072	1,174
	8,382	8,033

*Legal and consultancy expenses in 2018 has been represented. The cost were included in other expenses in 2018 and has now been further analysed and represented.

(b) Leases

The Group leases office and residential facilities under short term cancellable leases.

(c) Key management personnel and Director compensation

In addition to their salaries, the Group also provides non-cash benefits to key management personnel, in the form of share-based payments.

(i) Key management personnel and Director compensation comprised the following:

	2019 US$'000	2018 US$'000
Short-term benefits	1,890	2,092
Share-based payment	442	475
	2,332	2,567

(ii) Key management personnel and Director compensation comprised the following:

	2019 US$'000	2018 US$'000
Salaries	1,367	1,452
Fees	523	640
	1,890	2,092

Details of Directors' remuneration (including the fair value of share-based payments) earned by each Director of the Company during the year have been disclosed below.

		Basic Salary or Fees
US Dollars			Cash	Shares		General Benefits		Vacation Pay	Total Emoluments 2019		Total Emoluments 2018
			$000	$000		$000		$000	$000		$000
Executive
Lekan Akinyanmi (CEO)			805	303		141			1,249		1,260
Lisa Mitchell (CFO)			193	74		33		20	320		595
Greg Eckersley (Ag CFO)			144	-		25		6	175
Non-Executive
Samuel Adegboyega			123	13		-			136		154
Aisha Muhammed-Oyebode			87	13		-			100		114
Greg Eckersley			50	12		-			62		114
John van der Welle			88	12		-			100		114
Hezekiah Adesola Oyinlola			87	13		-			100		114
Thomas Schmitt			88	2		-			90		102
			1,665	442		199		26	2,332		2,567

12 Finance income and costs

	2019 US$'000	2018 US$'000
Finance income
Joint operating partner carry interest income	-	6,984
Other interest income (a)	113	167
Net foreign exchange gain (b)	125	-
	238	7,151
Finance costs
Finance expenses (c)	3,877	4,569
Net foreign exchange loss (b)	-	2,495
	3,877	7,064

(a)  Other interest income

Other interest income represents interest earned on short term deposits and call accounts transactions with the Group's bankers and interest on Director's loan.

(b) Net foreign exchange loss/gain

Net foreign exchange loss/gain represents exchange differences resulting from the conversion of US$ amounts to Nigerian Naira amounts, to meet obligations settled in Nigerian Naira and revaluation of Nigerian Naira balances to US$ at reporting periods.

(c)  Finance expenses-

Finance costs consist largely of interest costs on third party loans during the year.

13 Taxes

(a)  Petroleum profit tax

The Group with its principal assets and operations in Nigeria is subject to the Petroleum Profit Tax Act of Nigeria ("PPTA"). The Group's Petroleum Profit Tax charge for the period is summarised below:

	2019 US$'000	2018 US$'000
Balance at 1 January	2,889	218
Charge for the year	1,995	2,493
Tertiary education tax	392	396
Payment for the year	(4,644)	(218)
Balance at 31 December	632	2,889

(b) Company income tax

Interest on recovered carried cost and technical fees earned on Otakikpo operations of the Group is subject to Company Income Tax Act of Nigeria ("CITA"). The Group's Company Income Tax charge for the year is summarised below:

	2019 US$'000	2018 US$'000
Balance at 1 January	2,235	1,694
Charge for the year	14	2,095
Tertiary education tax	1	140
Payment for the year	(1,756)	(1,694)
Balance at 31 December	494	2,235

(c) Deferred tax assets

The Group has an estimated deferred tax asset of US$114.0 million (2018: US$95.7 million), out of which the Group has recognised deferred tax assets of US$13.6 million (2018: US$18.3 million); derived from the activities of its subsidiary LEKOIL Oil and Gas Investments Limited.  The Directors have assessed the future profitability of its operation in Otakikpo marginal field and have a reasonable expectation that the Group will make enough taxable profit from LEKOIL Oil and Gas Investments Limited in the near future to utilise the deferred tax assets. There is no expiration period to utilize the deferred tax assets. The balance of US$100.45 million (2018: US$77.5 million) of unrecognised deferred tax assets relates to unutilised capital allowances and tax losses from other subsidiaries in which the Directors are not certain when there will be available taxable profit from the subsidiaries to utilise the deferred tax assets.

		2019 US$'000	2018 US$'000
Recognised deferred tax assets		13,580	18,296
Unrecognised deferred tax assets		100,440	77,452
		114,020	95,748

Deferred tax at 31 December relates to the following:

	Consolidated statement of financial position				Consolidated statement of profit or loss and other comprehensive income
	2019		2018		2019		2018
	US$'000		US$'000		US$'000		US$'000
Deferred tax liability
Accumulated unrealised net exchange gain carried forward	(3,962)		(3,867)		95		279
	(3,962)		(3,867)
Deferred tax assets
Property, plant and equipment	6,084		11,295		5,211		5,345
Unutilised capital allowances	11,062		10,824		(238)		(683)
Provision for assets retirement obligation	396		44		(352)		12
	17,542		22,163
Deferred tax expense					4,716		4,953
Deferred tax assets (net)	13,580		18,296

(d) Total income tax expense recognised in the year.

	2019 US$'000	2018 US$'000
Petroleum profit tax	1,995	2,493
Company income tax	14	2,095
Tertiary education tax	393	536
Deferred tax expense (note 13c)	4,716	4,953
	7,118	10,077

(e) Current tax liabilities

	2019 US$'000	2018 US$'000
Balance at 1 January	5,124	1,912
Charge for the year
-  Petroleum profit tax	1,995	2,493
-  Company income tax	14	2,095
-  Tertiary education tax	393	536
Payment during the year	(6,400)	(1,912)
Balance at 31 December	1,126	5,124

(f) Reconciliation of tax expenses

The effect of tax reconciliation has been computed based on the operating results of Lekoil Oil and Gas Investment Limited as the recognised tax expense in the consolidated financial statements originated from this entity's operations. This is because it is the only entity in the Group that has started production and lifting of crude oil.

	2019 U S$'000	2018 U S$'000
Profit before tax from continuing operation*	10,582	18,164
Income tax expense calculated at 65.75% (2018: 65.75%)	6,958	11,943
Effect of expenses that are not deductible in determining taxable profit - PPT	6,041	5,969
Effect of income not taxable in determining taxable profit	(128)	(4,872)
Tax effect of capital allowance utilised in the year	(10,876)	(10,547)
Effect of Tertiary education tax on taxable profit	393	536
Effect of Companies income tax on other income	14	2,095
Change in deferred tax assets	4,716	4,953
	7,118	10,077
Income tax expense	7,118	10,077
Difference	-	-

At the effective income tax rate of 67% (2018: 55%)

* Profit before tax from continuing operation as stated above relates to Lekoil Oil and Gas Investment Limited which is the only revenue generating entity in the Group.

14 Loss per share

(a)  The calculation of basic loss per share has been based on the following loss attributable to ordinary shareholders and weighted-average number of ordinary shares outstanding.

(i)  Loss attributable to ordinary shareholders (basic)	2019 US$'000	2018 US$'000
Loss for the year attributable to owners of the Company	11,578	7,924

(ii)  Weighted-average number of ordinary shares (basic)	2019	2018
Issued ordinary shares	536,529,983	536,529,983
Weighted-average number of ordinary shares at 31 December	536,529,983	536,529,983

(b) The calculation of diluted loss per share has been based on the following loss attributable to ordinary shareholders and weighted-average number of ordinary shares outstanding after adjustment for the effects of all dilutive potential ordinary shares. Basic and diluted loss per share are equal as all options are anti- dilutive.

(i)  Loss attributable to ordinary shareholders (diluted)	2019 US$'000	2018 US$'000
Loss for the year attributable to owners of the Company	11,578	7,924
(ii)  Weighted-average number of ordinary shares (diluted)	2019	2018
Issued ordinary shares	536,529,983	536,529,983
Weighted-average number of ordinary shares at 31 December	536,529,983	536,529,983

(c) Basic/diluted loss per share is calculated by dividing the loss for the year attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the year.

	2019 US$'000	2018 US$'000
Loss for the year attributable to ordinary shareholders (US$'000)	11,578	7,924
Weighted average number of ordinary shares ('000)	536,530	536,530
Basic/diluted loss per ordinary share (US$)	(0.02)	(0.02)

15 Property, Plant and Equipment

(a)  The movement on this account was as follows:

	Oil and Gas Assets US$'000	Motor Vehicles US$'000	Furniture & Fittings US$'000	Computers, Communication & Household Equipment US$'000	Plant, Machinery, Storage Tank & Others US$'000	Leasehold Improvement US$'000	Total US$'000
Balance at 1 January 2018	40,059	296	417	764	148	1,199	42,883
Additions	10,195	-	16	49	135	-	10,395*
Changes to provision for Asset Retirement Obligation (note 25)	1,683	-	-	-	-	-	1,683
Balance at 31 December 2018	51,937	296	433	813	283	1,199	54,961
Balance at 1 January 2019	51,937	296	433	813	283	1,199	54,961
Additions	3,132	196	3	3	28	-	3,362*
Changes to provision for Asset Retirement Obligation	(77)	-	-	-	-	-	(77)
Balance at 31 December 2019	54,992	492	436	816	311	1,199	58,246
Accumulated depreciation and impairment losse s:
Balance at 1 January 2018	6,327	203	249	519	48	944	8,290
Charge for the year	7,893	42	81	156	51	12	8,235
Balance at 31 December 2018	14,220	245	330	675	99	956	16,525
Balance at 1 January 2019	14,220	245	330	675	99	956	16,525
Charge for the year	6,212	50	60	89	58	10	6,479
Balance at 31 December 2019	20,432	295	390	764	157	966	23,004
Carrying amounts:
At 31 December 2018	37,717	51	103	138	184	243	38,436
At 31 December 2019	34,559	197	46	53	154	233	35,242

*The additions of US$3.4 million during the year consist largely of capital expenditure on production facilities in the Otakikpo marginal field. The Group's assets have not been pledged as security for loans.

During the year ended 31 December 2019, the Group performed an impairment review or test of its producing oil and gas asset (i.e. the Otakikpo marginal field) based on impairment trigger arising from significant change in average crude oil price in 2019 compared to 2018 (The average crude oil price in 2019 is US$60 while US$70 in 2018). The test results showed a recoverable amount of US$44.3 million hence no impairment loss was recognised for the year.

In assessing whether an impairment is required, the carrying value of the asset or cash generating unit (CGU) is compared with its recoverable amount. The recoverable amount is the higher of the asset's/CGU's fair value less costs of disposal (FVLCD) and value in use (VIU). Given the nature of the Group's activities, information on the fair value of the asset is usually difficult to obtain unless negotiations with potential purchasers or similar transactions are taking place. Consequently, unless indicated otherwise, the recoverable amount used in assessing the impairment of the Group's asset is VIU. The Group generally estimates VIU using a discounted cash flow model.

The future cash flows were discounted to their present values using a pre-tax discount rate of 15%. This discount rate is derived from the Group's post tax weighted average cost of capital (WACC), with appropriate adjustments made to reflect the risks specific to the CGU and to determine the pre-tax rate. The forecast commodity prices used in the model is the average crude oil forecast pre-Covid-19 obtained from the World Bank, IMF, EIA and the Canada Energy Board (CEB).

The forecast production is based on the production profile of the Group's proved developed reserves per the reservoir estimate in the Competent Person's Report (CPR) completed during the year.

Subsequent to year-end, the Group re-assessed the impairment of its oil and gas asset due to the impact of COVID-19 on prices of crude oil. The impairment test showed recoverable amount of US$31.1 million. The likely impairment loss of US$4.8 million has not been recognised in 2019 financial year-end because COVID-19 is a non-adjusting event.  

16 Exploration and Evaluation (E&E) assets

E&E assets represents the Group's oil mineral rights acquisition and exploration costs.

(a)  The movement on the E&E assets account was as follows:

	2019 US$'000	2018 US$'000
Balance at 1 January	131,822	130,773
Additions during the year (b)	1,850	1,886
E&E adjustments (c)	(1,840)	-
Derecognition of E&E expenditure of LEKOIL Exploration and Production (Pty) Limited	-	(554)
Other impairments	-	(283)
Balance at 31 December	131,832	131,822

(b) The additions during the year consists largely of US$1.9 million E&E expenditure in OPL 310 including the Groups share of Licence extension fees. Total expenditure incurred on OPL 310 from inception of the farm-in agreement to 31 December 2019 amounts to US$115.5 million.

(c)  The Group revised its accrual in the current year due to reconciliation with vendors thus resulting in the reversal of accrued E&E expenditure of US$1.8 million in the current year.

(d)  LEKOIL and the Operator of the OPL 310 block, Optimum, announced on 6 September 2019 that pursuant to a letter dated 4 September 2019, the Federal Government of Nigeria and the Ministry of Petroleum Resources approved the extension of OPL 310's ("the Block") exploration Licence for three (3) years, subject to the payment of an extension fee of US$7.5m within 90 days effective from 2 August 2019. The extension fee was paid in October 2019. The Group's share of the extension is 17.14% (US$1.3 million) being is participating interest.

(e) OPL 310 was assessed for impairment by the Directors and it was concluded no impairment charge was necessary. This was based upon management's assessment of the asset's value in use, its expectation that the Group will execute the planned work program during the Licence period and develop and bring the asset to commercial production.

17 Intangible Assets

The movement on the intangible assets account was as follows:

	Mineral Rights Acquisition Costs* US$'000	Geological and Geophysical Software US$'000	Accounting Software US$'000	Total US$'000
Costs
Balance at 1 January 2018	7,000	1,787	104	8,891
Balance at 1 January 2019	7,000	1,787	104	8,891
Additions during the year	400	-	278	678
Balance at 31 December 2019	7,400	1,787	382	9,569
Accumulated amortization
Balance at 1 January 2018	1,318	1,237	67	2,622
Charge for the year	1,227	409	4	1,640
Balance at 1 January 2019	2,545	1,646	71	4,262
Charge for the year	2,256	141	41	2,438
Balance at 31 December 2019	4,801	1,787	112	6,700
Carrying amounts At 31 December 2018	4,455	141	33	4,629
At 31 December 2019	2,599	-	270	2,869

*Mineral rights acquisition costs represent the signature bonus for the Otakikpo marginal field amounting to US$7.0 million. A further $0.4 million being the Group share of renewal of Otakikpo Marginal Field Licence was paid in September 2019.

18 Inventories

Inventories consist of the Group's share of crude stock of US$2.8 million as at 31 December 2019 (2018: US$1.6 million).

19 Trade receivables

Trade receivables comprise:	2019	2018
	US$'000	US$'000
Sales proceeds receivable	-	8,814

20 Other receivables

Other receivables comprise:	2019	2018
	US$'000	US$'000
Cash call receivable from joint operating partner- GEIL (a)	2,367	5,684
Director's loan (b)	1,778	1,708
Employee loans and advances	2	4
Other receivables	136	95
	4,283	7,491

Non-current	-	1,708
Current	4,283	5,783
	4,283	7,491

(a)  The cash call due receivable from Otakikpo joint operating partner (GEIL), represents GEIL's share of cash calls paid by the Group on their behalf.

(b) The Director's loan represents the balance due on an unsecured loan of US$1,500,000 granted to a Director on 9 December 2014. The loan had a three-year term and bore interest at a rate of four per cent per annum. In September 2017, the loan was extended for another 3 years to 9 December 2020 under the same terms and conditions.

Following the adoption of IFRS 9 in 2018, the Group has recognised a total ECL provisions of US$0.05 million on the director's loan balance.

21 Other assets

Other assets comprise:	2019	2018
	US$'000	US$'000
Non-current
Optimum funded obligation (a)	20,137	-
OPL 310 Third party funded obligation (a)	2,466	-
	22,603	-
Current
Restricted cash (b)	1,090	3,166
Pre-paid rent	128	309
Pre-paid insurance	317	321
Others	42	68
	1,577	3,864

(a)  In August 2019, the Group executed a legally binding Cost Recovery and Sharing Agreement with Optimum Petroleum Development Limited ("Optimum") to progress appraisal and development programme activities at the Ogo discovery. Prior to the agreement, there was dispute as to the legitimate ownership of the 22.86 per cent stake in OPL 310. 

The Group had in November 2015, executed a sale and purchase agreement with the Administrators of Afren Nigeria Holdings Limited and Afren Plc relating to the entire issued share capital of Afren Investment Oil & Gas (Nigeria) Limited as a prelude to acquiring Afren 22.86 per cent stake on the block.  Following from lack of progress to establish its rights to the 22.86 per cent stake, the Group instituted a case against the Minister of Petroleum Resources and Optimum at the Federal High Court. As a result, development on the block was delayed, leading up to the expiration of the Licence in February 2019.

Consequent upon the expiration of the Licence, the Ministry of Petroleum Resources, through its letter in May 2019, mandated the parties to resolve their disagreement and withdraw the litigation in the Federal High Court or risk losing the extension of the Licence. Thereafter, the Group withdrew the ligation in May 2019, and finally reached an agreement with Optimum in August 2019.

Highlights of the Cost Recovery and Sharing Agreement are summarised below:

1.  A payment structure for previously outstanding G&A arrears payable by LEKOIL to Optimum in the amount of US$3,035,000 was agreed.

2.  The parties agreed that the Group will pay Optimum US$5.0 million for an Operator's fee in regard to the Group's 17.14 per cent participating interest upon receipt of the extension. US$1.0 million of the sum was paid in October 2019.

3.  The Agreement also makes provision for the Group to pay Optimum certain production prepayments from the proceeds of a continuous sale of crude oil produced from Ogo, such amounts being subject to 2P reserves or aggressive production milestones being achieved. The payments, once due, include a US$10m per year payment for five years following completion of a successful well (being a well capable of producing 5,000 BBL/d of Crude Oil).

4.  Further, the Group also agreed to pay (a) 42.85 per cent of US$10.0 milion payable to the Nigerian Government on conversion of OPL 310 to an Oil Mining Lease ("OML") and (b) 42.85 per cent of US$10.0 million to the Nigerian Government on reaching First Oil. The balance of the two US$10.0 million payments will be made by the potential Funding Partner.

5.  Upon receipt of the extension, the Group will also pay the Ministry of Petroleum Resources the fee to be prescribed by the Minister of Petroleum Resources in respect of the extension. The extension fee of US$7.5 million was paid by the Group in October 2019.

In addition, the Group will, subject to securing funding, cover 42.85 per cent of the capital expenditures and operating expenses of the Block to First Oil, being its 17.14 per cent pro rata of an aggregate 40 per cent participating interest held by it and the potential Funding Partner.  The potential Funding Partner will cover the remaining 57.15 per cent of the capital expenditures. 

All payments set out above made to or on behalf of Optimum are cost recoverable to the Group with a 50% uplift plus an additional compounding of 5 per cent per annum in respect of cost of capital to the Group. Whilst the Group hopes to have secured a Funding Partner in short order and therefore progressing appraisal and development activities at pace, the Group will be required to fund payments 1 and 2 above within approximately 6 months period from the execution of the agreement and the Group will retain it right to cost oil whatever the outcome on securing a Funding Partner. The Group expects to fund these payments from a combination of existing cash resources, cash from future production and drawdown on available debt facilities.

The Agreement also provides the order of priority for cost recovery by the Group and Optimum.

(b) Restricted cash represents cash funding of the debt service reserve accounts for the FBN Capital Notes and restricted cash on BG MT Nox & Busy Snail.

22 Pre-paid development costs

Pre-paid development costs comprise:	2019 US$'000	2018 US$'000
Balance at 1 January	931	42,463
Adjustment	-	(10,615)
Addition during the year	-	2,839
Recoveries during the year	(931)	(34,055)
Interest for the year	-	299
Balance at 31 December	-	931

(a)  The outstanding pre-paid development costs balance of US$0.93 million was recovered during year. The total recoveries from pre-paid development costs from inception was US$68.69 million.  

23 Cash and bank balances

	2019 US$'000	2018 US$'000
Bank balances	2,733	10,423

24 Trade and other payables

	2019 US$'000	2018 US$'000
Accounts payable	6,939	4,137
Accrued expenses	10,638	5,110
Other statutory deductions	2,443	3,601
Non-Government Royalties Payable	522	649
Other payables	21	126
	20,563	13,623

25 Provisions for asset retirement obligation

The movement in the provision for asset retirement obligation account was as follows:	2019 US$'000	2018 US$'000
Balance at 1 January	1,808	107
Unwinding of discount	534	18
Effect of changes to decommissioning estimates	(77)	1,683
Balance at 31 December	2,265	1,808

The Group has recognised a provision for Asset Retirement Obligation ("ARO") which represents the estimated present value of the amount the Group will incur to plug, abandon and remediate the Otakikpo operation at the end of its productive life, in accordance with applicable legislation. The provision has been estimated at a US inflation rate of 2% and discounted to present value at 8.24%. The provision recognised represents 40% of the net present value of the estimated total future cost as the Company's partner, GEIL is obligated to bear 60% of the cost.

A corresponding amount equivalent to the provision is recognised as part of the cost of the related property, plant and equipment. The amount recognised is the estimated cost of decommissioning, discounted to its net present value, and is reassessed each year in accordance with local conditions and requirements, reflecting management's best estimates.

The unwinding of the discount on the decommissioning is included as a finance cost. Changes in the estimated timing of decommissioning, or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision and a corresponding adjustment to property, plant and equipment.

Management estimates that the future decommissioning event will occur in 2026.

In the current year, the Group revised its estimate due to change in the economic life of the reserve type used as the basis for the determination of the decommissioning obligation from 2025 to 2026 as a result of the updated competent persons report (CPR) concluded in June 2019. The impact of this change in estimate has been effected in the table above.

26 Deferred income

The movement in deferred income was as follows:

	2019 US$'000	2018 US$'000
Balance at 1 January	-	6,685
Additions during the year	-	299
Charge to finance income	-	(6,984)
Balance at 31 December	-	-

27 Loans and borrowings

(a)  US$10 million FBNC Dollar Facility

The Company entered into a two-tranche facility for a US$10.0 million notes issuance agreement and a 2 billion Naira Facility with FBN Capital in June 2016. Interest on the US$10.0 million notes issuance agreement was charged at 3-month LIBOR plus 11.25% per annum. The Facility had maturity date of 30 June 2019.

In August 2018, the interest rate on US$10.0 million notes issuance facility was revised to 3-month LIBOR plus 10% per annum and the maturity extended to June 30, 2021 with principal repayment moratoriums for two quarters and equal quarterly principal repayments thereafter.

(b)   US$8.55 million FBNM Dollar Facility

In June 2016, the Group drew down on the N2 billion Naira Facility. The Naira Facility was upsized by 2.5 billion Naira in September 2016.

In June 2018, the FBNC Naira Facility plus the outstanding on the Sterling bank Facility was re-denominated into a new US$8.55 million Facility.

The US$8.55 million FBNM Dollar Facility has an interest rate of 3-month LIBOR plus 10% per annum and will mature in June 30, 2021 with a principal repayment moratorium for two quarters and equal quarterly principal repayments thereafter.

The documentation for the partial refinancing and re-denomination was concluded in March 2019.

(c)  USS$11.5 million FBNM Facility

In October 2019, the Group signed an agreement for a new US$11.5 million Debt Facility with FBNQuest Merchant Bank ("FBNQuest").  The Facility has a maturity of four years and is repayable quarterly with a margin of LIBOR + 10%. The proceed from the Facility was used to pay outstanding principal and interest due to Shell Western Supply and Trading Limited Advance Payment Facility and for the payment of the Licence/Lease extension fees on OPL 310 of US$7.5 million

(d) US$15 Million Shell Western Supply and Trading Limited Advance Payment Facility

The Group fully repaid the outstanding principal and interest on the US$15.0 million Advance Payment Facility with Shell Western Supply and Trading Limited (a member of the Royal Dutch Shell plc group of companies) in December 2019. The Facility was settled from proceeds of the new US$11.5 million FBNQuest Debt Facility.

The following is the outstanding balance of interest-bearing loans and borrowings as at the year-end:

		Interest rate p.a.	2019 US$'000	2018 US$'000
US$10 million FBNC Dollar Facility		10% + LIBOR	2,957	4,831
US$8.55 million FBNM Dollar Facility		10% + LIBOR	5,236	8,191
US$15 million Shell Facility		10% + LIBOR	-	7,463
US$11.5 million FBNM Facility		10% + LIBOR	11,005	-
Total			19,198	20,485
Analysis of borrowing Current Non-current			7,149 12,049	11,439 9,046
			19,198	20,485

The movement in the loan account was as follows:

	2019 US$'000	2018 US$'000
Balance at 1 January	20,485	29,509
Draw-down during the year	11,500	7,000
Effective interest during the year	2,929	4,699
Principal repayment during the year	(12,614)	(17,558)
Interest paid during the year	(3,230)	(3,307)
Fees paid during the year	(307)	-
Revaluation adjustments	435	142
Balance at 31 December	19,198	20,485

(e) Changes in liabilities arising from financing activities

	Cash changes					Non-cash changes
	1 January 2019	Draw-down during the year	Principal repayment	Interest and fees paid	Effective interest		Revaluation adjustments	Other changes (ii)	31 December 2019
	US$'000	US$'000	US$'000	US$'000	US$'000		US$'000	US$'000	US$'000
Loans and borrowings	20,485	11,500	(12,614)	(3,537)	2,929		435	-	19,198
Total liabilities from financing activities	20,485	11,500	(12,614)	(3,537)	2,929		435	-	19,198

28 Capital and reserves

(a) Share capital

	Ordinary shares 2019 US$'000	2018 US$'000
Authorised	50	50
Issued, called up and fully paid	27	27
Total issued and called up share capital	27	27

	Number of shares 2019	Number of shares 2018
Authorised - par value US$0.00005	1,000,000,000	1,000,000,000
Issued, called up and fully paid - par value US$0.00005	536,529,983	536,529,983

(b) Share premium

Share premium represents the excess of amount received over the nominal value of the total issued share capital as at the reporting date.

	2019 US$'000	2018 US$'000
Share premium	264,004	264,004

29 Non-controlling interest

	% of ownership	2019 US$'000	2018 US$'000
LEKOIL Nigeria Limited	10	4,058	3,603
LEKOIL Exploration and Production (Pty) Limited	20	346	346
		4,404	3,949

(a) This shows the net assets of the non-controlling interest analysed to the relevant companies.

(b)  The following table summarises the information relating to each of the Group's subsidiaries, before any intra-group eliminations:

31 December 2019	LEKOIL Nigeria Limited Group	LEKOIL Exploration and Production (Pty) Limited	Intra -group eliminations	Total
NCI Percentage	10%	20%
	US$'000	U$'000	US$'000	US$'000
Non-current assets	207,675	-	-	-
Current assets	7,892	152	-	-
Non-current liabilities	(298,042)	(1,521)	-	-
Current liabilities	(61,137)	(361)	-	-
Net liabilities	(143,612)	(1,730)	-	-
Carrying amount of NCI	(14,361)	(346)	10,303	(4,404)
Revenue	42,027	-	-	-
Profit	6,301	-	-	-
Net finance cost	(33,917)	-	-	-
Income tax expense	(7,118)	-	-	-
Total comprehensive  loss	(34,734)	-
Loss allocated to NCI	(3,473)	-	3,018	(455)
OCI allocated to NCI	-	-
Cash flows from operating activities	39,859	-	-	-
Cash flows from investment activities	(25,924)	-	-	-
Cash flows from financing activities	(14,831)	-	-	-
Net decrease in cash and bank balances	(896)	-	-	-

31 December 2018	LEKOIL Nigeria Limited Group	LEKOIL Exploration and Production (Pty) Limited	Intra -group eliminations	Total
NCI Percentage	10%	20%
	US$'000	U$'000	US$'000	US$'000
Non-current assets	193,061	-	-	-
Current assets	55,862	152	-	-
Non-current liabilities	(331,118)	(1,521)	-	-
Current liabilities	(28,704)	(361)	-	-
Net liabilities	(110,900)	(1,730)	-	-
Carrying amount of NCI	(11,090)	(346)	7,487	(3,949)
Revenue	48,687	-	-	-
Profit/ (loss)	12,875	(652)	-	-
Net finance cost	(30,965)	(51)	-	-
Income tax expense	(10,077)	-	-	-
Total comprehensive loss	(28,167)	(703)
Loss allocated to NCI	(2,817)	(141)	3,099	141
OCI allocated to NCI	-	-
Cash flows from operating activities	(33,526)	566	-	-
Cash flows from investment activities	17,253	(439)	-	-
Cash flows from financing activities	12,952	(51)	-	-
Net (decrease)/increase in cash and bank balances	(3,321)	76	-	-

30 Share-based payment arrangements

At 31 December 2019, the Group had the following share-based payment arrangements:

Long Term Incentive Plan scheme (equity-settled)

The long-term incentive plan ("LTIP") was approved on 19 November 2014 and amended on 21 December 2015. No new awards were made under the LTIP scheme in 2019.

The existing options have the following performance conditions.

(i)  No shares may be acquired, and the option will lapse in full if annual compound Total Shareholder Return ("TSR") is less than 10%

(ii)  30% of the shares subject to the option may be acquired by exercise if annual compound TSR is 10%

(iii)  100% of the shares subject to the option may be acquired by exercise if annual compound TSR is 20% or more

(iv)  The number of shares subject to the option which may be acquired on exercise will be determined on a straight-line basis between 30% and 100% if annual compound TSR is between 10% and 20%

The number and weighted average exercise prices of share options are as follows:

	Weighted average exercise price US$	Number of options	Weighted average exercise price US$	Number of options
	2019		2018
Outstanding at 1 January	0.53	34,666,750	0.53	27,421,750
Granted during the year	-	-	0.13	7,630,000
Forfeited during the year	0.19	(3,445,000)	0.19	(385,000)
Outstanding at 31 December	0.33	31,221,750	0.30	34,666,750

The options outstanding at 31 December 2019 had exercise prices in the range of US$0.16 to US$0.4 and a weighted average contractual life of 6.12 years.

Inputs for measurement of grant date fair values

The fair value of each stock option granted was estimated on the date of grant using the Black-Scholes option-pricing model with the following inputs:

Fair value of share options and assumptions
	2019	2018
Weighted average fair value at grant date for options issued during the year	-	US$0.13
Share price at grant date - Stock options issued on 3 August 2018	-	US$0.26
Exercise price - Stock options issued on 3 August 2018	-	US$0.26
Option life (Expected Life in Years) of options issued during the year	-	6 year
Weighted average expected volatility - Stock options issued during the year	-	55%
Weighted average Risk-free Interest rate for options issued during the year	-	1.11%
Expected dividends	-	na

Volatility was estimated with reference to empirical data for proxy companies with listed equity.

Share option scheme (equity-settled)

The Group established a share option scheme available to Directors, key management personnel, employees and consultants providing employment-type services, which provides the opportunity to purchase shares in the Group. In accordance with the scheme, holders of vested options are entitled to purchase shares at prices of the shares established at the date of grant, during a period expiring on the tenth anniversary of the effective date i.e. grant date. The grant dates for awards were 3 December 2010, 1 June 2011, 1 November 2011, 4 June 2012, 19 February 2013, 7 April 2013, 17 May 2013 and 26 March 2014 based upon a shared understanding of the terms of the awards at that time. This share option scheme has been replaced by the LTIP scheme described above.  As such, no new options were granted in 2019 under this scheme.

The number and weighted average exercise prices of share options are as follows:

	Weighted average exercise price US$	Number of options	Weighted average exercise price US$	Number of options
	2019		2018
Outstanding at 1 January	0.46	16,555,000	0.46	16,555,000
Granted during the year	-	-	-	-
Forfeited during the year	-	-	-	-
Exercised during the year	-	-	-	-
Outstanding at 31 December	0.46	16,555,000	0.46	16,555,000
Exercisable at 31 December	0.46	16,555,000	0.46	16,555,000

The options outstanding at 31 December 2019 had exercise prices in the range of US$0.4 to US$0.46 and a weighted average contractual life of 2.14 years (2018: 3.18 years).

Non-Executive Director Share Plan (equity-settled)

The Board established the Non-Executive Director share plan on 21 December 2015.

These stock options are not subject to any performance criteria and vest three years from the grant date, subject to successful completion of a three-year service period starting on the grant date. The options can be exercised over a seven-year period beginning on the expiry of the service period.

No awards were made under the Non-Executive Director Share Plan in 2019. 

The number and weighted average exercise prices of share options are as follows:

	Weighted average exercise price US$	Number of options	Weighted average exercise price US$	Number of options
	2019		2018
Outstanding at 1 January	0.24	2,100,000	0.35	1,500,000
Granted during the year	-	-	0.13	600,000
Outstanding at 31 December	0.24	2,100,000	0.24	2,100,000

The options outstanding at 31 December 2019 had a weighted average exercise price of 0.16 to 0.4 and a weighted average contractual life of 7.27 years.

Inputs for measurement of grant date fair values

The fair value of each stock option granted was estimated on the date of grant using the Black-Scholes Option Pricing Model with the following inputs:

	2019	2018
Weighted average fair value at grant date	-	US$0.13
Share price at grant date	-	US$0.26
Exercise price	-	US$0.26
Option life (Expected Life in Years)	-	6.0
Expected volatility - Stock options issued	-	55%
Risk-free Interest rate	-	1.11%
Expected dividends	-	na

Employee benefit expenses

	2019 US$'000	2018 US$'000
Non-Executive Director Share Plan (equity-settled)	64	72
Long Term Incentive Plan scheme (equity-settled)	1,008	1,102
Total expense recognised as employee costs	1,072	1,174

31 Related Party Transactions

The Group had transactions during the period with the following related parties:

(a)  Transactions with key management personnel

Key management personnel are those persons having authority and responsibility for planning, directing and controlling the activities of the Group, directly or indirectly. These are the Directors of the Group.

(i)  Loans to key management personnel

An unsecured loan of US$1,500,000 was granted to a Director on 9 December 2014. The loan had a three-year term and bears interest at a rate of four per cent per annum. Repayment was due at the end of the term. In September 2017, the loan was extended for another 3 years up to 9 December 2020 under the same terms and conditions.

At 31 December 2019, the balance outstanding was US$1,778,373 net of ECL provision (2018: US$1,707,947) and is included in 'Other receivables'. Interest income from the loan during the year amounted to US$70,000 (2018: US$ 68,000)

(ii)  Key management personnel transactions

Transactions with key management and related parties are summarised below:

· There is an outstanding balance of  US$0.03 million (2018: US$.83 million) with respect to well completion services rendered by SOWSCO Wells Services Nigeria Limited, a company controlled by a Director.

(iii)  Key management personnel compensation

Details of key management personnel compensation during the year have been disclosed in note 11(c).

(iv)  Key management personnel and Director transactions

Directors of the Company control 7.77% (2018: 8.27%) of the voting shares of the Company.

(b)  LEKOIL Limited, has a Management & Technical Services Agreement with LEKOIL Management Corporation ("LMC") under the terms of which LMC was appointed to provide management, corporate support and technical services. The remuneration to LMC includes reimbursement for charges and operating costs incurred by LMC.

32 Group entities

(a)  Significant subsidiaries

Country of incorporation		Ownership interest
		2019	2018
LEKOIL Nigeria Limited (See (a)(i))	Nigeria	40%	40%
LEKOIL Exploration and Production (Pty) Limited	Namibia	80%	80%
LEKOIL Management Corporation	USA	100%	100%
LEKOIL 310 Limited	Cayman Islands	100%	100%
LEKOIL Management Services	Cayman Islands	100%	100%

(i)  Although the Company holds less than a 50% ownership interest in LEKOIL Nigeria Limited, it is contractually entitled to 90% economic benefits and net assets based on the terms of agreements under which the entity was established. Consequently, the Company consolidates LEKOIL Nigeria Limited.

LEKOIL Nigeria Limited has ten wholly owned subsidiaries, namely: Mayfair Assets and Trust Limited, LEKOIL Oil & Gas Investments Limited, LEKOIL Exploration and Production Nigeria Limited, LEKOIL Energy Nigeria Limited, Princeton Assets and Trust Limited, Lekgas Nigeria Limited, Lekpower Limited, LEKOIL Supply and Trading Limited, LEKOIL Oil and Gas Integrated Limited, and LEKOIL 276 Limited (previously LEKOIL 24 Limited). The results of these subsidiaries have been included in the consolidated financial results of LEKOIL Nigeria Limited.

33 Financial Commitments and Contingencies

(a)  On 5 December 2014, the Green Energy International Limited/LEKOIL Oil and Gas Investments Limited joint operation signed a Memorandum of Understanding ("MoU") with its host community, Ikuru with respect to the Otakikpo marginal field area. The key items of the MoU include the following:

‒ The joint operation will allocate 3% of its revenue from the Liquefied Petroleum Gas (LPG) produced from the field to the Ikuru Community in each financial year;

‒ The joint operation will allocate the sum of US$0.53 million (NGN 90 million) annually for sustainable community development activities.

(b)  In May 2015, the Company provided a corporate guarantee in favour of FBN Capital for the full sum of the loan notes issued by LEKOIL Oil and Gas Investment Limited, a subsidiary of the Company.

(c)  In June 2018, the Company issued a corporate guarantee for the re-denomination of existing term loan facility of NGN2.3 billion availed to LEKOIL Oil and Gas Investments Limited plus the refinancing of Sterling bank facility to an US$8.5 million term loan facility for funding Otakikpo operations.

(d)  Based on Cost Recovery and Sharing Agreement signed in August 2019, the Group has the following financial commitments on OPL 310 as at year end.

1.  The Group is bound to pay (a) 42.85 per cent of US$10.0 million payable to the Nigerian Government on conversion of OPL 310 to an OML and (b) 42.85 per cent of US$10.0 million to the Nigerian Government on reaching First Oil. The balance of the two US$10.0 million payments will be made by the potential Funding Partner.

2.  The Group is bound to pay Optimum certain production prepayments from the proceeds of a continuous sale of crude oil produced from Ogo, such amounts being subject to 2P reserves or aggressive production milestones being achieved. The payments, once due, include a US$10.0 million per year payment for five years following completion of a successful well (being a well capable of producing 5,000 BBL/d of Crude Oil).

In addition, the Group will, subject to securing funding, cover 42.85 per cent of the capital expenditures and operating expenses of the Block to First Oil, being its 17.14 per cent pro rata of an aggregate 40 per cent participating interest held by it and the potential Funding Partner.  The potential Funding Partner will cover the remaining 57.15 per cent of the capital expenditures.

(e)  Litigation and claims

Litigations and claims involving the Group are summarised below:

i.)  Lekoil 310 Limited, Afren Investment Oil & Gas (Nigeria) Limited Vs. Hon. Minister of Petroleum Resources and Optimum Petroluem Development Co. Ltd, Suit No. FHC/L/482/2018.

Lekoil 310 Ltd (1st Plaintiff) a subsidiary of Lekoil Limited, Cayman by Share Purchase Agreement dated November 30, 2015 acquired the entire issued share capital of Afren Investment Oil & Gas (Nigeria) Ltd ("AIOGNL") (2nd Plaintiff) through the Administrators of its parent Company (Afren Plc). AIOGNL is a holder of 22.86% participating interest in OPL 310 - an oil block located at Dahomey basin adjacent to the Lagos shoreline. Lekoil 310 instituted an action against the Hon. Minister of Petroleum Resources (1st Defendant) seeking for the following:

§ a Declaration that the sale of the shares of AIOGNL was properly conducted and concluded, save for approval of ministerial consent;

§ An Order of Mandamus compelling the Hon. Minister of Petroleum Resources to give the Company consent;

The Judge ruled that ministerial consent is required for the acquisition of Afren's 22.86% interest in OPL 310 and that the Share Purchase Agreement signed by parties for the acquisition is inchoate and invalid without obtaining Optimum's consent to the acquisition of the 22.86% interest. The Judge further ruled against the Plaintiffs prayer that consent should be deemed granted based on the Federal Government Executive Order on ease of doing business in Nigeria noting that the Order cannot have retroactive effect as the Plaintiff's application for consent was made before the Order was signed in 2017.

The Plaintiff's Appeal before the Court of Appeal withdrawn by the Appellant at request of the 1st Defendant as a pre-condition to the extension of the OPL 310 Licence which expired in February 2019. The Hon. Minister of Petroleum Resources on May 20, 2019 granted the extension of the OPL 310 License for a period of three (3) years commencing from August 2, 2019.

ii.)  Guy-Us Safety and Environmental Engineering Ltd Vs. Afren Investment Oil & Gas Nig Ltd and Ors, Suit No. LD/ADR/1517/2018

Guy-Us Safety and Environmental Engineering Ltd (the "Claimant") is claiming against Afren Investment Oil & Gas Nigeria Limited ("AIOGNL") (Defendant) the sum of US$64,540 (N23, 398, 260) and interest, being outstanding sum relating to the contract for a two season baseline seabed survey (wet and dry) for OPL 310 offshore development Nigeria (the "Contract") performed between 2014 - 2015 before the acquisition of AIOGNL by Lekoil 310 Limited (the "Acquisition"). In addition, the Claimant also claims for:

§ AN Order that the Defendants shall pay to the Claimant forthwith the said sum of US$6,896 (N2,500,000) being attorney's fees; and

§ AN Order for the sum of US$13,792 (N5 Million) being general damages

The suit came up at the Lagos State High Court on November 14, 2019 for the hearing of the Motion to re-enlist the suit filed by the Claimant. The matter came up for hearing on February 24, 2020 before Hon. Justice Pedro of Lagos State High Court and was subsequently adjourned to May 26, 2020 to enable the Defendant file its Preliminary Objection. However, the matter could not hold on May 26, 2020 as a result of the lockdown. Management has not made accruals for this claim or adjusted for this claim as at year end based on the advice of its legal advisers regarding the Group's chance of obtaining a favourable judgment on the case.

iii.)  Ayi Emokpae (Trading under the name and style "Smart Contracting Solutions Services) Vs. Lekoil Nigeria Limited, Suit No. LD/ADR/2053/2018.

Lekoil Nigeria Limited (The Defendant) was in the process of contracting Smart Contracting Solutions (the "Claimant") to organise training for contracting and contract management for its staff but could not conclude. The Claimant demanded for compensation in the sum of US$11,701 (N4,242,187.50) to cover commitment made for the preparation of the training. The Defendant claimed that parties were still in negotiation, and no final contract had been awarded.

The Defendant paid and took delivery of the training materials. The Claimant being dissatisfied with the development proceeded against the Defendant at the Lagos State High Court, Lagos praying the Court for the award of a total sum of US$17,933 (N6,501,447) in damages and costs.

The matter suit has been settled pursuant to a Settlement Agreement dated May 14, 2019 executed by Parties which was adopted by the Court on June 18, 2019 as its judgement. The judgement outcome was settled in 2019 and forms part of the operating expenses in 2019.

iv.)  Mr. Sotonye Boyle Vs. Lekoil Nigeria Limited, Suit No. NICN/PHC/1372018.

The Claimant was employed by the Defendant (Lekoil Nigeria Limited) as an Offtake Supervisor. Upon termination of his employment by the Defendant, the Claimant instituted an action against the Defendant at the National Industrial Court of Nigeria, Port Harcourt Judicial Division seeking the following reliefs: 

§ An Order awarding damages of US$137,916 (N50,000,000) only against the Defendant for wrongful termination of employment

§ An Order awarding damages of US$1,379 (N500,000) only against the Defendant being compensation for unfair labour practice;

§ An Order of mandatory injunction compelling the Defendant to pay the Claimant his terminal benefits upon the wrongful termination of his employment as a permanent staff of the Defendant.

The matter came up on March 4, 2020 for the commencement of trial and further adjourned to April 28 and 29, 2020 for continuation of Cross Examination and Defence. The Court could not sit on the fixed dates of April 28 and 29, 2020 due to the COVID-19 lockdown. Management has not made accruals for this claim or adjusted for this claim as at year end based on the advice of its legal advisers regarding the Group's chance of obtaining a favourable judgment on the case.

v.)  Members of Ngo Asuk Family royal lineage of Asukama town, in Andoni LG of Rivers State Vs. Mr. Nathan Sampson Asuk, Mr. Iyeoron Brown Nteogwuile, Green Energy International Ltd, Lekoil Oil and Gas Investments Ltd and Registered Trustees of Host Communities of Green Energy-Lekoil Development Trust Fund, Suit No. PHC/1299/2018

The Claimants instituted the suit against the 1st and 2nd Defendants and joined the 3rd, 4th and 5th Defendants at the Rivers State High Court, Port Harcourt. The Claimants in the Writ of Summons claim the following reliefs:

§ An Order directing the 1st and 2nd Defendants to remit and grant to the Claimants all benefits, entitlements and money meant for Ngor Asuk Family (Royal Lineage) in Asukama Community including but not limited to US$4,137 (N1,500,000) and 70 (seventy) bags of rice received from the 3rd and 4th Defendants;

§ An Order for the payment of US$16,550 (N6,000,000) to the Claimants by the 1st and 2nd Defendants as compensation.

The Otakikpo JV Parties are not necessary parties to the suit. However, the Joint Operation will engage counsel to monitor proceedings thus Management has not made accruals for the claims in respect of the suit.

vi.)  Chief Hector Awaji (The Okan Ama of Agbafor - Alias Court) Community for Himself and on behalf of the Elders and People of the Community) Vs. SINOPEC Chanjian Engineering Services Ltd and Green Energy International Ltd, Suit No. PHC/3149/2018.

Chief Hector Awaji, (The Okan Ama of Agbafor) instituted a suit in 2018 at the High Court of Rivers State against, SINOPEC Chanjian Engineering Services Ltd and Green Energy International Ltd (Operator of Otakikpo JV) claiming US$55,166 (N20,000,000) as special and general damages for illegal and unlawful trespass by conducting seismic acquisition operations at Agbafor Community without prior consent of the Community. The Otakikpo JV has engaged External Counsel to represent the Joint Operation in the suit. Management has not made accruals for the claims because it is not a party to the suit though its joint operating partner (Green Energy International Limited) is a co-defendant.

vii.)  Members of Ereforokuma Arong Royal family of Ngo Town in Andoni Local Government Area of rivers State of Nigeria Vs. Green Energy International Limited, Lekoil Oil and Gas Investments Limited, Suit No. PHC/1972/2019.

The Claimants instituted an action against the Defendants at the High Court of Rivers State, Port Harcourt seeking for the following declarations:

§ The sum of US$13,792 (N5,000,000) only being general exemplary/aggravated damages for the unlawful trespass of the Defendants on the Claimant's land in dispute.

§ 10% Interest rate per annum on judgement sum from date of judgement till judgement debt is fully liquidated.

Otakikpo Joint Operation has engaged External Counsel to represent the Joint Operation in the suit. Management has not made accruals for the claims in respect of this suit based on the advice of its legal advisers regarding the joint operation including the Group to obtain favourable court judgment.

viii.)  Members of Ekede Community of Andoni Local Government Area, Rivers State Vs. members of Ikuru Town Community in Andoni Local Government Area, Rivers State. Suit No. PHC/4125/2019.

The Claimants instituted an action against the Defendants at the High Court of Rivers State, Port Harcourt alleging trespass and seeking:

§ A Declaration that the Claimants are the lawful owners of all that land in dispute known as and called Ekede Community land on which oil wells 2 and 3 of the Green Energy International Limited and Lekoil Oil and Gas Investments Limited joint venture are cited.

§ An Order of perpetual injunction restraining the Defendants from further trespass of any kind and from dealing with the land and asserting title thereto and the sum of US$13,792 (N5,000,000) as damages for trespass

Action is primarily against members of Ikuru Town Community. The Otakikpo JV are not Parties to the suit hence the reason Management has not adjusted for the claims in respect of this suit as at year end .

ix.)  Other than the matters disclosed above, there are no litigations or claims involving the Group as at 31 December 2019.

34 Financial risk management and financial instruments

Overview

The Group has exposure to the following risks from its use of financial instruments:

· credit risk

· liquidity risk

· market risk

This note presents information about the Group's exposure to each of the above risks, the Group's objectives, policies and processes for measuring and managing risk, and the Group's management of capital. Further quantitative disclosures are included throughout these financial statements.

Risk management framework

The Board of Directors has overall responsibility for the establishment and oversight of the Group's risk management framework.

The Group's risk management policies are established to identify and analyse risks faced by the Group, to set appropriate risk limits and controls, and to monitor risks and adherence to limits. Risk management policies and systems are reviewed regularly to reflect changes in market conditions and the Group's activities. The Group, through its training and management standards and procedures, aims to develop a disciplined and constructive control environment in which all employees understand their roles and obligations.

(a)  Credit risk

Credit risk is the risk of financial loss to the Group if a customer or counterparty to a financial instrument fails to meet its contractual obligations and arises principally from the Group's receivables from joint operating partners, employees and related parties.

Exposure to credit risk

The carrying amount of financial assets represents the maximum credit exposure. The maximum exposure to credit risk at the reporting date was:

In US Dollars

	Notes	2019 US$'000	2018 US$'000
Cash and bank balances	23	2,733	10,423
Trade receivables	19	-	8,814
Other receivables	20	4,283	7,491

In respect of the Group's trade sales, the Group manages credit risk through dealing with, whenever possible, international energy companies or those with a track record of creditworthiness. The Group closely monitors the risks and maintains a close dialogue with those counterparties considered to be highest risk in this regard. The Group trades only with recognised, creditworthy third parties, and as such collateral is not requested nor is it the Group's policy to securitise its trade receivables. There are no trade receivables as at year end.

In respect of other receivables, they consist largely of receivables from joint operating partners and Directors loans. Management has assessed that the receivable from GEIL is not impaired as the Group has agreed a repayment plan with GEIL whereby the Group pays less amount for its share of cash call obligation until the amount is fully received. Following the adoption of IFRS 9 in 2018, the Group has recognised an ECL provision for the full sum of the receivable due from Afren Investment Oil & Gas (Nigeria) Limited.

For Director's loan, the Group recognised the sum of US$0.05 million as ECL provision of as at 31 December 2019, while the outstanding receivable balance at year end is US$1.83 million. Management has assurances from the Director that the balance on the Director's loan will be paid in full when it falls due at maturity.

The Group recovered all outstanding balance of pre-paid development costs during the year.

Cash and bank balances

The cash and bank balances of US$2.7 million (2018: US$10.4 million) are held with reputable financial institutions with very high credit ratings. The treasury manager monitors the financial position of the financial institutions on a periodic basis.

(b) Liquidity risk

Non-derivative financial liabilities

The following tables detail the remaining contractual maturity for non-derivative financial liabilities. The tables have been drawn up based on the undiscounted cash flows of financial liabilities based on the earliest date on which the Group can be required to pay.

	Weighted average effective interest rate	Less than 1-month US$'000	1-3 months US$'000	3 months to 1-year US$'000	1-5 years US$'000	5+ years US$'000	Total US$'000
31 December 2019
Non- interest bearing	n/a	10,992	-	9,571	-	-	20,563
Variable interest rate instrument Principal  repayments	15.76%	-	1,700	5,444	12,139	-	19,283
Interest repayments		-	593	1,456	1,743	-	3,792
		10,992	2,293	16,471	13,882	-	43,638
31 December 2018
Non- interest bearing	n/a	13,623	-	-	-	-	13,623
Variable interest rate instrument Principal  repayments Interest repayments	13.75%	- -	2,855 780	8,565 1,404	9,628 938	- -	21,048 3,122
		13,623	3,635	9,969	10,566	-	37,793

(c)  Market risk

Market risk is the risk that changes in market prices, such as foreign exchange rates, interest rates and equity prices will affect the Group's income or the value of its holdings of financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable parameters, while optimising the return.

The Group manages market risks by monitoring market developments, forecasting and scenarios planning; and discussing issues regularly, and deploying mitigating actions where necessary. The Group's cash flow model anticipates different possible scenarios and proffers the action plans for each scenario including match inflows to outflows.

Currency risk

The Group is exposed to currency risk on bank balances, employee receivables and trade and other payables denominated in Nigerian Naira.

The summary of quantitative data about the Group's exposure to currency risks are as follows:

	Carrying amounts
	2019 US$'000	2018 US$'000
Trade and other receivables	2	32
Cash and bank balances	128	667
Trade and other payables	(103)	(822)
Net exposure	27	(123)

Sensitivity analysis

A 20 percent strengthening of the US Dollar against the following currencies at 31 December would have increased / (decreased) equity and loss by the amounts shown below. This analysis assumes that all other variables, in particular interest rates, remain constant.

		Foreign exchange rate risk
		20%		(-20%)
	Carrying Amount	Profit or loss	Other Movements in Equity	Profit or loss	Other Movements in Equity
	US$'000	US$'000	US$'000	US$'000	US$'000
31 December 2019
Financial Assets:
Naira
Cash and bank balances	128	27	-	(27)	-
Trade and other receivables	2	-	-	-	-
Impact on financial assets	-	27	-	(27)	-
Financial Liabilities:
Naira
Accounts payable	(103)	(21)	-	21	-
Impact on financial liabilities	-	(21)	-	21	-
Total increase (decrease)	-	6	-	(6)	-

		Foreign exchange rate risk
		20%		(-20%)
	Carrying Amount	Profit or loss	Other Movements in Equity	Profit or loss	Other Movements in Equity
	US$'000	US$'000	US$'000	US$'000	US$'000
31 December 2018
Financial Assets:
Naira
Cash and bank balances	667	133	-	(133)	-
Trade and other receivables	32	6	-	(6)	-
Impact on financial assets	-	139	-	(139)	-
Financial Liabilities:
Naira
Loans and borrowings	(8,190)	(1,638)	-	1,638	-
Accounts payable	(822)	(164)	-	164	-
Impact on financial liabilities	-	(1,802)	-	1,802	-
Total increase (decrease)	-	(1,663)	-	1,663	-

The amounts shown represent the impact of foreign currency risk on the Group's consolidated profit or loss. The foreign exchange rate movements have been calculated on a symmetric basis. This method assumes that an increase or decrease in foreign exchange movement would result in the same amount and further assumes the currency is used as a stable denominator.

(d) Fair values

Fair values vs carrying amounts

Set out below is a comparison by class of the carrying amounts and fair value of the Group's financial instruments, other than those whose carrying amounts are a reasonable approximation of fair value.

			Carrying amount				Fair value
	Note		2019	2018			Level 2 2019	Level 2   2018
			US$'000	US$'000			US$'000	US$'000
Financial liabilities measured at amortised costs
Loans and borrowings		27	19,198	20,485			19,198	20,485
			19,198	20,485			19,198	20,485

Management assessed that the fair values of cash and short-term deposits, trade receivables, other receivables, trade payables and other current liabilities approximate their carrying amounts largely due to the short-term maturities of these instruments.

The fair value of loans and borrowings classified as level 2 above was calculated using the discounted cash flow method. 3-month Libor rate plus 10% was used for discounting future cash flows. However, the carrying amount and the fair value of loans and borrowings are the same because the rate of interest on loans and borrowings is not different from the market rate.

35 Events after the Reporting Date

a)  On 2 January 2020, the Group announced that it had secured funding for OPL 310 work program through a binding agreement with Qatar Investment Authority ("QIA") . The agreement was facilitated by Seawave Invest Limited ("Seawave").

Following from the above, on 12 January 2020, the Group's advisers were approached by representatives of QIA questioning the validity of the loan agreement earlier announced. 

On 13 January 2020, the Group announced that based on all information available to it, the loan agreement announced on 2 January 2020 by the Company, purportedly with the QIA was entered into by the Company with individuals who constructed a complex facade in order to masquerade as representatives of QIA (the "Counterparties"). The Group confirmed that its financial exposure associated with the Facility Agreement was limited to approximately US$600,000 (being the amounts paid in good faith as initial arrangement fees to Seawave (US$450,000) in 2019 and accrued associated legal fees (US$150,000)). There were no monies paid by Lekoil to the Counterparties.

The Company has contacted relevant authorities across a number of jurisdictions, with regards to the transaction which was an attempt to defraud LEKOIL. The Group set up an investigation Committee composed of its independent Non-Executive Directors, to investigate the origination and execution of the Facility Agreement, what steps can be taken to retrieve any monies already paid in association with the Transaction and the Company's wider corporate governance practices.

b)  On 6 January 2020, the Group announced changes in its board of Directors with the appointment of The Rt. Hon. Mark Simmonds and Mr. Anthony Hawkins as Non-Executive Directors. Mr. Greg Eckersley, who served as the Group's interim Chief Financial Officer since May 2019, and John van der Welle a Non-Executive Director, stepped down from the Board.

Also, on changes in its board of Directors, the Group announced on 21 April 2020 that Hezekiah Adesola Oyinlola, Non-Executive Director and Thomas Schmitt, Non-Executive Director resigned from the board.

c)  In January 2020, the Group announced that, it has reached an agreement with Optimum, the Operator of the OPL 310 License, on deferring the Company's financial and operational obligations due in February 2020 pursuant to the Cost Recovery and Sharing Agreement executed between the Group and Optimum in August 2019. US$2.0 million out of the obligation was paid in March 2020.

Consequently, the Group announced the payments of US$1.0 million and US$2.0 million to Optimum in July 2020 and September 2020 respectively. The remaining obligations due on the Cost Recovery and Sharing Agreement will be paid on or before 30 November 2020.

d)  In May 2020 and following significant decrease in oil price as a result of the corona-virus pandemic, the Group assessed impairment using the current depressed oil price outlook. The impairment charge was calculated by comparing the future discounted post-tax cash flows expected to be derived from production of commercial reserves (the value-in-use) against the carrying value of the asset. The impairment test showed recoverable amount of US$31.1 million and impairment charge of US$4.8 million.

The impairment charge has, however, not been adjusted in 2019 reporting year and is disclosed as non-adjusting event after the reporting date.

The major impact of the pandemic to the Group is primarily the depressed crude sales receipts. The Group has however, implemented measures to mitigate the impact, including the implementation of costs cutting measures to significantly reduce its operating costs, initiation of debt refinance discussion with lenders, and creditors payments deferment. Impairment charges are anticipated in subsequent financial reporting period.

e)  The Group subsequent to year-end, executed a loan restructure agreement with FBNQuest Merchant Bank Limited to restructure its existing loan facilities with the Bank with effective from 21 July 2020. The loan restructure agreement has the following terms:

· The consolidation of the Group's existing loan facilities as at year-end with FBNQuest Merchant Bank Limited into a restructured facility amount of US$15.88 million;

· Interest rate - 90 day LIBOR plus a margin of 10%;

· Tenor - March 2024; and

· The loan covenants remained the same as the existing loan facilities as at year-end.

f)  There were no other subsequent events that could have had material effect on the state of affairs of the Group as at 31 December 2019 and on the profit or loss for the year ended on that date, which have not been considered in the preparation of these financial statements.

-ends-

 

END

 

 

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