Eland Oil & Gas Regulatory News (ELA)

20 March 2019

Eland Oil & Gas Plc ("Eland" or the "Company")

Final Results for the Year ended 31 December 2018

Eland Oil & Gas PLC (AIM: ELA), an oil and gas production and development company operating in West Africa with an initial focus on Nigeria, is pleased to announce full year results for the year ending 31 December 2018.

George Maxwell, CEO of Eland, commented:

"2018 was a ground-breaking year for Eland. Record oil production, revenues and profits, and confirmation of a 20-year extension to the OML 40 licence allows us to continue our investment in this world-class asset.

As well as our continuing investment in the Opuama oil field, in 2018 we accelerated the development of the Gbetiokun and Ubima oil fields, both of which are expected to contribute to a material increase in production and cash flow in 2019.

This progress would not be possible without the ongoing hard work and dedication of our staff, our partners, and the support of NPDC."

2018 Highlights

· Average production in 2018 was 8,000 barrels of oil per day ('bopd') net to Elcrest, more than doubling the 2017 average production of 3,934 bopd.*

· 2018 exit production rate of 13,240 bopd net to Elcrest (29,425 bopd gross), a record exit production rate for OML 40 and Eland. Peak record production of 13,986 bopd net to Elcrest (31,081 bopd gross).

· Formal renewal of the 20-year OML 40 licence, allowing the Joint Venture to continue its significant investment into the OML 40 work programme.

· Ubima field tested at rates of up to 2,200** bopd net to Eland (2,500 bopd gross), with commercial production commencing in H1 2019.

· The first phase of Gbetiokun development commenced in H2 2018 with the recompletion of the Gbetiokun-1 well and the drilling of the Gbetiokun-3 infill well.

· The most active development period in the Company's history, running two rigs and drilling continuously throughout 2018 with seven wells drilled, re-entered or completed on the Opuama, Gbetiokun and Ubima fields.

· Lease Automatic Custody Transfer ('LACT') unit commissioned in 2018, reducing hydrocarbon allocation losses from the crude oil delivered from OML 40.

· Total Recordable Injury Frequency Rate of 0.2

· One million man-hours with no Lost Time Injury

Financial

· Record 2018 revenues net to Eland of $169.2 million.

· Maiden annual profit before tax $77.6 million.

· Transformation in cash generation with EBITDA at $104.0 million equating to $40 per barrel.***

· Successfully refinanced its existing reserve-based lending facility ('RBL') with a new $75m facility which has the potential to increase to $200m (subject to production growth and reserves). In March 2019 the facility increased to $125m through further syndication, based on a redetermined borrowing base of $134m.

· Year-end cash position of $43.1m and net debt position of $4.3m.

· Post year end NPDC reimbursed the Company $19.3m for drilling costs on Opuama-8 and Opuama-9.

Post-period end activities

· Testing of the Gbetiokun wells is ongoing and whilst the testing program is not yet completed some encouraging preliminary outcomes are available.

· The Gbetiokun-1 Short String, completed on the E2000 reservoir, successfully flowed at stable rates up to 4,000 bopd gross (1,800 bopd net to Elcrest) on a 32/64" choke. This performance is fully in line with the pre-completion predictions.

· Similarly, the Gbetiokun-3 Long String, completed on the E4000 reservoir, successfully flowed at stable rates up to 3,000 bopd gross (1,350 bopd net to Elcrest) on a 36/64" choke. Again, this performance is fully in line with the pre-completion predictions.

· Testing continues on the Gbetiokun-1 Long String and the Gbetiokun-3 Short String. The Gbetiokun-1 Long String, completed on the E6000 reservoir, whilst demonstrating good rate potential in line with expectations, was complicated by mechanical issues related to poor cementing of the original casing prior to Elcrest's entry into the OML40 licence. Testing of the Gbetiokun-3 Short String was delayed as no satisfactory pressure integrity test could be obtained on the completion. Determination of appropriate remedial activities is underway and it is anticipated that these strings should be available for testing during Q2 2019 and based on current results they are anticipated to perform in line with previous expectations.

· The combination of Gbetiokun-1 Short String and Gbetiokun-3 Long String will be monetised once the Early Production Facility (EPF) is installed in April and it is expected that the initial rates will be higher than the recent test rates as they will be flowed with a less restrictive choke.

· Drilling of the next phase of Gbetiokun development wells is scheduled immediately after the OES rig returns from its current maintenance/upgrade program which will quickly provide further production potential for the EPF facility which will have a nominal capacity of 25,000 bopd gross.

Outlook

· 2019 production is expected to average in the range of 14,000 to 17,000 bopd net to Eland (post 15% budgeted downtime)

· Ongoing production from Opuama field to be augmented by Gbetiokun and Ubima start-ups

· 2019 active development work programme targeting four new wells across Opuama -12 and -13 and Gbetiokun -4 and -5

· Amobe exploration prospect, the Company's first near-field exploration well, expected to spud in H2 2019, targeting best case gross resources of 78 mmbbls, with a 42% probability of success****

· 2019 capex guidance of $80-90 million net to Eland

· The Company has advised of its Capital Return and Dividend Policy

*Elcrest Exploration & Production Nigeria Ltd has a 45% interest in OML 40. Eland has a 45% equity shareholding in Elcrest. OML 40 net position reflects Elcrest ownership.

**88% economic interest until payback reached

*** Earnings before interest, taxes, depreciation and amortisation

****Netherland, Sewell & Associates Inc CPR report 31 December 2018

For further definitions, glossary of technical terms, and detailed accounts, please see our full audited 2018 Annual Report & Accounts which are available shortly on the Company website: www.elandoilandgas.com.

This announcement contains inside information as defined in Article 7 of the Market Abuse Regulation No. 596/2014 and is disclosed in accordance with the Company's obligations under Article 17 of those Regulations.

For further information:

Eland Oil & Gas PLC (+44 (0)1224 737300)

www.elandoilandgas.com

George Maxwell, CEO

Ronald Bain, CFO

Finlay Thomson, IR

Peel Hunt LLP, Nominated Adviser & Joint Broker (+44 (0)20 7418 8900)

Richard Crichton / David McKeown

Stifel Nicolaus Europe Limited, Joint Broker (+44 (0)20 7710 7600)

Callum Stewart / Nicholas Rhodes / Ashton Clanfield

Camarco (+44 (0) 203 757 4980)

Billy Clegg / Georgia Edmonds / Tom Huddart

Notes to Editors

Eland Oil & Gas is an AIM-listed independent oil and gas company focused on production and development in West Africa, particularly the highly prolific Niger Delta region of Nigeria.

Through its joint venture company Elcrest, Eland's core asset is a 45% interest in OML 40 which is in the Northwest Niger Delta approximately 75 km northwest of Warri and has an area of 498 km². 

In addition, the Company has a 40% interest in the Ubima Field, onshore Niger Delta, in the northern part of Rivers State.

The OML 40 licence holds gross 2P reserves of 82.2 million barrels, gross 2C contingent resources of 50.7 million barrels and a best estimate of 252.1 million barrels of gross un-risked prospective resources*

The Ubima field holds gross 2P reserves of 9.3 million barrels of oil and gross 2C resource estimates of 4.2 million barrels *

Net production figures relate to Elcrest Exploration and Production Nigeria Ltd ("Elcrest"), Eland's joint venture company. Production rates, when oil is exported via Forcados, are as measured at the Opuama PD meter, are subject to reconciliation and will differ from sales volumes.

*Netherland, Sewell & Associates Inc CPR report 31 December 2018

Cautionary statement regarding forward-looking statements

This Results Statement may contain forward-looking statements which are made in good faith and are based on current expectations or beliefs, as well as assumptions about future events. You can sometimes, but not always, identify these statements by the use of a date in the future or such words as 'will', 'anticipate', 'estimate', 'expect', 'project', 'forecast', 'intend', 'plan', 'should', 'may', 'assume' and other similar words. By their nature, forward-looking statements are inherently predictive and speculative and involve risk and uncertainty because they relate to events, and depend on circumstances that will occur in the future. You should not place undue reliance on these forward-looking statements, which are not a guarantee of future performance and are subject to factors that could cause actual results to differ materially from those expressed or implied by these statements. The Company undertakes no obligation to update any forward-looking statements contained in this Results Statement, whether as a result of new information, future events or otherwise.

Chairman's Statement

I am pleased to tell you that your company has had an exceptional year. Our primary asset OML 40 has reached record levels of production and further production increases are anticipated in 2019 as the company continues a multi-field development programme.

The receipt of a 20-year licence extension for OML 40 in 2018 is a milestone which gives the necessary confidence to continue the investment to fully capitalise on this exceptional asset. The year also saw the declaration of a maiden profit, with the company on a sound financial footing for the future.

2018 was a volatile year for oil prices. Having started the year at around $65 per barrel, Brent rose throughout the next nine months to peak at $85 per barrel, before a sharp retreat down to $50 per barrel by the year end. With Eland's production increasing steadily throughout the year, cash flow benefited from the higher oil prices. With the current oil price at $60+ your company continues to generate substantial cash flow.

The Nigerian oil industry also enjoyed a second consecutive year of production growth. Relatively stable market conditions and low levels of production interruption also benefited the country's levels of production.

Throughout 2018 Eland continued to demonstrate the outstanding nature of its asset base with further material increases in production from the Opuama oil field in OML 40.

Additionally, 2018 saw material progress with two additional development assets, the Gbetiokun oil field in OML 40 and the Ubima oil field both of which are scheduled to come on stream in the first half of 2019. Finally, the company will participate in its first exploration well, with the spudding of the Amobe prospect on OML 40 expected in the second half of 2019. This is a near-field exploration well on a well-defined structure which, if successful, can utilise the Opuama facilities - only 6.5 kilometres away - to provide an opportunity for early monetisation.

The year also saw excellent financial progress, with the Group's first net profit, a direct result of the materially higher oil production rates from Opuama. Your company is well positioned to continue its programme of adding value in 2019.

During the year there was one addition to the Board. Nicholas Gay joined as non-executive director in June, bringing a wealth of industry and financial experience. As a professional accountant Nicholas has now assumed the role of Chairman of the Audit Committee.

Your company is rigorous in its application of corporate governance and during 2018 adopted the QCA corporate governance guidelines. During 2019 the necessary changes will be made to ensure compliance. This has already been commenced with the above change to the Audit Committee and I look forward to advising further.

In conclusion, 2018 was a watershed year for the Company, with record production from the Opuama field, and the commencement of operations on the Gbetiokun and Ubima fields. Material progress has been made with the financial strength of the Group, which will allow us to continue to develop our excellent asset base. The Company has expanded its technical and managerial team and is well positioned to both develop its current asset base and evaluate opportunities that add further value. I look forward to advising you of another year of progress in 2019.

Russell Harvey

Chairman

Chief Executive Officer's Statement

2018 was the most successful year in Eland's short history. Throughout 2018 the Company sustained the drilling campaign on OML 40 which began in 2017 and contracted a second rig for the Ubima-1 well completion.

The success of our drilling campaign has been at the forefront of our significant increase in OML 40 production which we have seen rise to record levels of over 13,500 bopd net (over 30,000 gross). This investment in drilling, combined with the successful execution of the programme and recovering oil prices, delivered record revenues and the Company's maiden post-tax profit in excess of $100 million.

The performance of the Company in 2018 shows the huge opportunity that we have within our asset base as we continue executing our strategy of near-term production and monetisation opportunities. We now have both the human and financial resource in place to continue and accelerate the strategy within our asset base, allowing us to look forward with extreme confidence into 2019 and beyond.

The renewal of the OML 40 licence in October 2018 for a 20-year period (through to 2038) was the most significant event of the year. The licence was due to expire in July 2019, and although this date was still some time off, the Company embarked upon a renewal process in conjunction with our partners in engaging the Ministry on the renewal. This was key for our continued investment and our financing activities, which would have become more restricted had this not been achieved. Successful renewal has allowed for continued investment and the scheduling of our first exploration interest in the 2019 work programme.

The overall growth of the Company during 2018 has been significant, however measured. Growth in production has been doubled since 2017, our financial performance delivered our best year since inception and we enjoyed a significant increase in market capitalisation, raising the Company value by over $100 million in the period.

Drilling and Production Operations

During the year we have drilled or completed five wells within our OML 40 programme and spudded a sixth. The continuous campaign from 2017 delivered Opuama-8, -9, -10 and -11 within the Opuama field and Gbetiokun-1 within the Gbetiokun field, all within OML 40. The drilling continued with Gbetiokun-3 in the Gbetiokun field which was delivered in early 2019. The combined production increase from the Opuama wells in 2018 saw our net exit production rate more than double from 5,625 bopd at the end of 2017 to 13,240 bopd at the end of 2018. This programme did have some complexities with Opuama-9 being a challenging well due to equipment problems, however this well was successfully completed and still returned a payback within 90 days.

The fact that some of our wells within the Opuama campaign had paybacks within 30 days highlights the attractiveness of the investment in the Opuama development. During 2018 we recorded a significant safety milestone with over one million man hours worked without any loss time injuries ("LTI"). This is a significant milestone and a testament to the importance of our safe working environment, standards and operating procedures within the Company.

The equipment issues encountered during Opuama-9 led to a unique level of problem solving, utilising a support barge to provide both power and pumping capacity to allow the programme to continue in both a safe and efficient manner. This solution worked well and was applied to the remainder of the Opuama and Gbetiokun wells until the rig was stood down in March of this year for repair.

This solution is typical of the innovative approach we apply to our ongoing projects to ensure an effective delivery. Our drilling campaign within OML 40 will continue following the rig refurbishment in 2019 and 2020 to further increase OML 40 production levels.

The production activity during 2018 also saw significant improvement in our production processing and handling. The installation of our new Lease Automated Custody Transfer (LACT) unit at Otumara was a significant milestone. This is now fully operational and serves as the main fiscalisation point for OML 40 production. The LACT unit measures both volumetrics and base sediment and water ('BS&W') within the crude and removes considerable uncertainty on delivered volumes into the Forcados terminal. The Company also increased the water handling capacity at the flow station. By reducing the amount of produced water transported through the main export line, this reduces the Opex cost per barrel through lower transportation fees. Further flow station enhancements included the installation of a new pump to handle increased volumes, as well as continued refurbishment and re-certification of the facility.

The overall export capacity of the main export line was increased through the use of a new 16" pipeline (capacity in excess of 120,000 bopd). This replaced the old 12" line ensuring that export capacity will not be an issue as we continue to invest in drilling activities and enhance OML 40 production.

The initial activity on the Gbetiokun field commenced in October 2018. This started with the dredging activity followed by the re-entry of Gbetiokun-1 in late October. The well was successfully completed as a dual producing well in December and is being tested in conjunction with the Gbetiokun-3 well. The activity on the Gbetiokun field continued with dredging for flow line and production facilities in 2018 with the intention of installing an early production facility (EPF), work which is very well developed, to allow first oil from Gbetiokun in the first half of 2019. This again highlights the typical development activities with a focus on early production and monetisation, with this first oil being forecast within six months of initial field activity. The experience gained during 2017 of our shipping and barging system which provides our alternative evacuation system, should our primary route through Forcados be interrupted, continues to pay dividends as we will be utilising both the knowledge and the investment to ship the Gbetiokun crude to the main export line at the loading and injection point we developed in 2017. Completing the delivery of the Gbetiokun crude to Forcados for sale through the same line as the Opuama crude.

We also invested heavily in the Ubima field. We contracted a drilling rig and successfully re-entered the well. The clean out activities also presented some significant technical challenges which were managed well by our technical group, bringing the well to a safe and successful completion with two production strings. The results of the shallower reservoir indicated a more viscous crude and further studies are required in order to plan for a full development of these sands. However, a higher quality crude was intersected in the deeper reservoirs and the well was successfully tested at over 2,200 bopd net (2,500 bopd gross). The plans are ongoing to achieve an extended production test commencing in Q2 2019, expected to last around six months to fully evaluate the deeper reservoirs' potential and monetise this position. Further studies will continue during 2019 on the development of the shallow reservoir.

Organisational Development

 During our 2018 Capital Markets Day I spoke openly about our need to increase our Geoscience group in the UK and our Operations Group in Nigeria. This was essential to maintain and exceed the level of performance and delivery we achieved in 2017. During 2018 we have prepared a full organisational development plan and then sourced and employed key personnel to assist in accelerating our development opportunities. This programme is now essentially complete and we reorganised to allow focus on each key area of development to allow these to run concurrently. This structure provides the platform for our development, appraisal, exploration and new business activities to move forward at an accelerated pace in the future.

Financing Activities

A key contributor to our enhanced financing facility was the OML 40 licence renewal. The increasing production and success of our drilling campaign created the opportunity for the Company to restructure the existing debt facility. This was completed during Q4 of 2018 with a five-year facility initially based at $75 million which will cover all of the near-term financing needs of the Company and can be expanded to $200 million to meet future needs as our investing activities continue to grow.

2019 - Continuing Growth

This year has started well, with continuing production from Opuama, the completion of the Gbetiokun-3 well in Gbetiokun and oil prices remaining relatively stable. 2019 will carry a number of key milestones for the Company. We will deliver first oil from Gbetiokun and continue to drill at least a further two wells in the field. The early production system will be operational with a capacity of 25,000 bopd. This accelerated development is a key feature of our planned 2019 strategy.

Infill drilling within Opuama will continue and currently we have scheduled two further wells (Opuama-12 and Opuama-13) to enhance Opuama production and offset field decline which is to be expected. The successful execution of these wells will result in continuing record production from OML 40 and, for the first time, full diversification from single field production. The information we gained from the Opuama drilling programme is being incorporated into our understanding of the overall Opuama structure. This will be re-mapped in Q1 2019 and then re-appraised for additional drilling and workover opportunities.

We also plan our first exploration well on OML 40 with a well planned for the Amobe prospect which lies around 6.5 km north of Opuama. We are very positive on the prospects of this well and the benefits it can deliver. The potential on a success case basis outcome of this well is significant for the Company and may result in a change to our current work programme and investing activities.

In Q1 2019 we published our 2018 Competent Person's Report (CPR). In this issue we combined both OML 40 and Ubima within a single report for ease of reference and consistency of review by Netherland Sewell & Associates (NSAI), our competent person.

We are also working closely with our partners NPDC and Elcrest on a project to further reprocess the existing 3D seismic. This information is critical to provide greater clarity on the future opportunities beyond Opuama and Gbetiokun such as Amobe, Abiala and Polobo. The OML 40 licence covers 498 square kilometres, a significant proportion of which remains lightly explored.

The extended well test of Ubima-1 will provide monetisation and return on investment on this field and will also highlight the extent of the opportunity available for development of the deeper reservoirs while we continue our evaluation of the development opportunities of the shallow reservoirs.

A full-year drilling programme is planned in 2019, resulting in a continuous drilling campaign for almost three years as we extend into 2020. At times in 2018 we had two rigs operating and we worked that scenario very well. It is likely, on a success case basis, that we will again operate a multi-rig programme in 2019.

The organisation is structured, and the Company financed, for continued growth with numerous investing opportunities. Our existing asset base remains relatively under exploited and this provides a degree of optionality as we continue our review.

We look forward to continuing our performance-focused, near-term development and monetisation strategy, delivering shareholder value growth through performance and additional shareholder return through our Capital Return and Dividend Policy.

George Maxwell

Chief Executive Officer

Chief Financial Officer's Statement

Best financial performance ever with record revenues of $169.2 million and posting a maiden profit.

Completion of the refinancing

· Reprofiled existing reserve-based lending ("RBL") facility in April 2018 with principal repayments pushed back to March 2019. Then in November 2018 refinanced the RBL facility with a new lender group and increased the facility from $35 million to $75 million while extending the facility life from 2019 to 2023.

o 2023. - Provided funds to secure a 20-year renewal of the OML 40 licence.

o Enabled the execution of the planned drilling programme.

o Provided working capital headroom to fund NPDC share of drilling costs prior to reimbursement.

Financial risk management

· Commenced a commodity hedging programme in 2018 to protect the committed capital programme.

· Agreed mechanism with NPDC to fund its share of OML 40. This resulted in US$19.3 million of receipts in January 2019.

· Active management across the business repaired the working capital deficit in the period, creating opportunity for investment while repaying legacy working capital balances.

Investment in future growth opportunities

· Increase in EBITDA has provided the funding platform to step up an investment in human resource capital to deliver the next phase of Company growth.

· Operating cash flows from Opuama have been reinvested in the Gbetiokun and Ubima fields in 2018 providing further sources of cash flow generation in 2019 as these fields are brought into production.

· Funding has been secured to drill the Company's first exploration well, Amobe in 2019.

· Strong Balance sheet and liquidity buffer with headroom to increase gearing.

OVERVIEW

· 2018 was the most successful year in the Company's history demonstrated by the following achievements:

· Record revenues $169.2 million (2017: $68.9 million)

· Record production with four new wells brought on stream in the period providing a full year average 8,000 bbls/day (2017: 3,934 bbls/day)

· Posted a maiden pre-tax profit at $77.6 million (2017: $15.6 million loss)

· Transformation in cash generation with EBITDA at $104.0 million (2017: $2.7 million) or $40/bbl

· Operating costs under $10/bbl (2017: $24/bbl)

· Step change in investment with net capital expenditure of $85.1 million (2017: $21.1 million)

· Booked an income tax credit of $70.5 million recognising the increasing certainty of the utilisation of historic trading tax losses

CASH FLOW AND LIQUIDITY

The EBITDA and additional funding from the increased loan facility in the year was largely reinvested in capital investments.

Capital expenditure (net)

* Includes 20-year licence renewal fee $6.3m.

The Opuama field investment totalled $42.8 million resulting in four new wells, Opuama -8, -9, -10 and 11 brought on stream in 2018 with excellent paybacks from each well averaging around 90 days. The benefits from the investments in Gbetiokun of $22.2 million and Ubima of $16.2 million will be derived in 2019 with first production on both fields targeted 1H 2019 which will further increase production with the added benefit of diversifying the cash flow generation from one to three fields.

Working Capital

Other uses of the cash were predominantly to fund our government partner's share of OML 40 drilling capital ahead of later reimbursement. The cash inflow from NPDC of $19.3 million received in January 2019 has therefore not been reflected in the $43.9 million working capital movement opposite.

RBL refinancing

The Group's RBL was refinanced in November 2018 with an increase in committed facility size from $35 million to $75 million and a new lead bank, Stanbic, supporting the facility. At 31 December 2018 $25 million of the committed facility was undrawn, with $75 million undrawn at the date of this report following the facility increase to $125 million completed in March 2019. Proceeds of the refinancing were used to repay and cancel pre-existing indebtedness. The refinancing has enabled the company to extend the facility life from 2019 to 2023.

For accounting purposes, the refinancing was deemed an extinguishment of the existing loan and creation of a new loan. As part of the extinguishment of the existing loan, the remaining balance of unamortised fees of $1.0 million were expensed in 2018. Interest on the new loan is LIBOR + 7.5% to the extent the total amount outstanding is lower than 50% of the higher of total commitments and the borrowing base amount, and LIBOR plus 8% in all other cases.

INCOME STATEMENT

Production and realised prices

As a result of the record production levels revenue more than doubled to $169.2 million (2017: $68.9 million) in the year. Liftings rose strongly to 2,382,209bbls (2017: 1,351,000bbls) with an average realised price of $71.01/bbl (2017: $50.98/bbl), the realised price reflecting the increase in commodity prices compared to the prior year. Furthermore, Elcrest produced 234,750 bbls in excess of liftings in the year which resulted in a credit to the income statement for underlifted barrels of $15.8 million. Revenue generated based on bbls produced was therefore $185 million in 2018.

Cost of Sales

Cost of sales rose in the year from $77.3 million to $82.2 million. The main components are noted in the table below:

*Includes shipping transportation costs in H1 2017

Direct OML 40 operating expenses including tariff were held at similar levels to the prior year of around $10/bbl once Forcados was reopened. Royalty charges rose in line with increased volumes and higher oil prices in the year with the DDA charge being volume driven.

The under/overlift simply reflects the timing of liftings with the unsold bbls at year end being included in revenue in the following period.

General and administrative expenses

 Net G&A costs of $7.8 million (2017: $4.5 million) increased year on year reflecting the upscaling of operations and human resource requirements necessary to deliver the business growth. Excluding the impact of the non-cash share options net G&A rose to $6.1 million (2017: $3.7 million).

Finance gains and charges

Net finance costs fell to $1.1 million (2017: $2.8 million) although this was largely influenced by the recording of a $3.9 million gain on the mark-to-market adjustment on the open put options at 2018 year-end. Finance interest and fees totalled $5.6 million including $1.1 million for extinguishment of the existing $35 million loan facility with a further $0.2 million on realised hedging costs. Other net finance income was $0.7 million.

Profit after tax

Profit after tax was $148.0 million ($2017: $8.8 million loss) resulting in a basic profit per share for the owners of the Company of $0.28 (2017: $0.06).

BALANCE SHEET

Working capital

The working capital deficit created following the prolonged Forcados closure was repaired in the period with net assets rising strongly to $20.1 million by 2018 year-end compared to a deficit of $29.4 million in the corresponding period in 2017.

Capital Structure

In November 2018 the Company announced a share buyback programme to purchase £3 million of its own shares. By year end the Company had purchased 957,000 shares equating to $1.4 million (£1.0 million) and the Company largely expects to complete the share buyback programme by the end of Q1 2019.

TAXATION

Elcrest will exit Pioneer Tax status following the end of the five-year period on 30 April 2019 which provided relief from Petroleum Profits Tax in Nigeria. Following the end of the Pioneer Tax period, Elcrest will enter new entrant status for five years. As Elcrest continued to build up tax losses and capital allowances whilst in the Pioneer Tax period it does not anticipate any Petroleum Profits cash taxes will be payable in the near term. With the increasing certainty of Elcrest generating future taxable profits to utilise the tax losses the Group has recognised a deferred tax credit of $70.5 million in the period taking the total deferred tax asset balance to $83.6 million.

FINANCIAL RISK MANAGEMENT

Commodity prices

Considering the planned capital investment programme the Group adopted a commodity hedging policy in the year to protect the capex programme in the event of low oil prices.

In May 2018 the Group purchased put options for the second half of 2018 for 840,000 bbls with a $65/bbl floor. The net cost of these options was $0.2million in the year with the $1.1 million of fees largely offset by $0.9 million income received when the oil prices dropped below the $65 floor in November and December 2018. At 31 December the Group held open put options for the first half of 2019 for 930,000bbls, setting a floor of $55/bbl with no ceiling to a rise in oil prices. A mark-tomarket non-cash gain was recorded on these options of $3.9 million at year end as the oil price dropped towards the end of the year.

Invoice Factoring

In order to accelerate cash flows a factoring arrangement was put in place in 2018 whereby lifting proceeds were received in the month of lifting rather than the standard contract terms of the following month. This aided the working capital during periods of intensive investment with an associated financing cost of $0.2million incurred in the year.

GOING CONCERN

The financial statements continue to be presented on a going concern basis as detailed further on page 70 of the Annual Report.

OUTLOOK AND DIVIDEND POLICY

The Group is gearing for growth and is looking to build on the success of 2018 by further growing production and cash flows in 2019 and preparing to drill the Company's first exploration well transforming it into a full cycle E&P company. As a measure of the growing confidence and sustainability of the future cash flow generation the Company announced in February 2019 that it would pay a maiden ordinary dividend in 2019.

As the share buyback programme nears completion, the Board will consider whether to extend the buyback programme further.

In March 2019 the Group announced a further increase in the debt facility from $75 million to $125 million with the $50 million increase underwritten by the Group's lead lender bank, Stanbic ITBC Limited. At the date of this report $75 million of the facility remains undrawn.

Ron Bain

Chief Financial Officer

Consolidated Statement of Comprehensive Income for the year ended 31 December 2018

The Company has elected to take the exemption under section 408 of the Companies Act 2006 from presenting the parent Company statement of comprehensive income.

The notes form part of these financial statements

Consolidated Balance Sheet as at 31 December 2018

The financial statements of Eland Oil & Gas PLC, registered number SC 364753, contained on pages 78 to 112 were approved by the Board of Directors on 19 March 2019 and signed on its behalf by:

George Maxwell Ron Bain

Chief Executive Officer Chief Financial Officer

Consolidated Statement of Changes in Equity for the year ended 31 December 2018

Consolidated Cash Flow Statement for the year ended 31 December 2018

Notes to the Financial Statements for the year ended 31 December 2018

Section 1 - Basis of preparation

This section contains the Group's going concern statement and significant accounting policies that relate to the financial statements as a whole. Significant accounting policies specific to one note are included with the note itself. Accounting policies have been consistently applied to all years presented, unless otherwise stated.

This section also includes details on new EU endorsed accounting standards, amendments and interpretations and their expected impact on the performance of the Group including the impact of IFRS 9, IFRS 15 and IFRS 16.

1.1 Significant accounting policies

A) Basis of preparation

Eland Oil & Gas PLC (the 'Company', together with its subsidiaries and controlled entities, the 'Group') is a public limited Company, which is listed on the AIM market of the London Stock Exchange and incorporated and domiciled in Scotland. The address of the registered office is given on the back cover. The nature of the Company's operations and its principal activities are set out in the Strategic Report. The Company and the Group's financial statements cover the year to 31 December 2018.

The consolidated financial statements have been prepared under the historical cost convention, except for the revaluation of certain financial assets and liabilities (under IFRS) to fair value, including derivative instruments. The principal accounting policies adopted are contained within the individual account notes.

As permitted by section 408 of the Act, the Company has elected not to present its statement of comprehensive income for the year. Eland Oil & Gas PLC reported a profit for the year ended 31 December 2018 of $5,538,000 (2017: $7,793,000).

B) Accounting standards

The financial statements of Eland Oil & Gas PLC have been prepared in accordance with International Financial Reporting Standards (IFRS) and IFRS Interpretations Committee (IFRS IC) interpretations as adopted by the European Union and as applied in accordance with the provisions of the Companies Act 2006 as applicable to companies reporting under IFRS.

New and amended standards adopted by the Group

The Group has applied the following standards for the first time for their annual reporting period commencing 1 January 2018:

IFRS 9 Financial Instruments

IFRS 9 Financial Instruments is the replacement of IAS 39 Financial Instruments: Recognition and Measurement. The Group has applied IFRS 9 retrospectively, with the initial application date of 1 January 2018. There has been no restatement to the comparative balances for the period beginning 1 January 2017 as there are no requirements under the standard to restate comparatives. The new standard covers three distinct areas: the classification and measurement of financial assets and liabilities; the impairment of financial assets; and hedge accounting.

Classification and measurement of financial assets and liabilities

Under the new Standard, financial assets are classified as either at amortised cost or fair value through other comprehensive income (FVOCI); or fair value through profit and loss (FVPL) on the basis of both the entity's business model for managing the financial assets and the contractual cash flow characteristics of the financial asset. When an entity changes its business model, it reclassifies all its affected financial assets.

All of the Group's financial assets as at 1 January 2018 (trade and other receivables and cash and bank balances) satisfied the conditions for classification at amortised cost under IFRS 9.

Under the new Standard, financial liabilities are classified as at amortised cost, with some exceptions. Financial liabilities are not reclassified at any point. The Group's financial liabilities are classified at amortised cost, with the exception of derivatives that are measure at fair value.

As the impact of IFRS 9 in relation to the classification and measurement of financial assets and liabilities was immaterial on the transition date, no retrospective adjustments have been posted on adoption of this Standard.

Impairment of financial assets

IFRS 9 establishes a new model for recognition and measurement of impairments in loans and receivables that are measured at amortised cost or FVOCI - the so-called "expected credit losses" model. Expected losses are recognised and measured according to one of three approaches - a general approach, a simplified approach and the so-called "credit adjusted approach":

• The simplified approach applies for qualifying trade receivables, IFRS 15 contract assets and lease receivables.

• The credit adjusted approach applies for assets that are credit impaired at initial recognition.

• The general approach applies to all other loans and receivables not covered by another approach.

A review of Eland's earlier credit losses has revealed that annual credit losses are not material to its Consolidated Financial Statements, therefore no retrospective adjustments have been posted on adoption of IFRS 9.

Hedge accounting

The third major change that IFRS 9 introduces relates to hedging - IFRS 9 allows more exposures to be hedged and establishes new criteria for hedge accounting that are somewhat less complex and more aligned with the way that entities manage their risks than under IAS 39. The Group does not apply hedge accounting, therefore this change did not have any impact to the Group's accounting policies.

IFRS 15 revenue from contracts with customers

IFRS 15 Revenue from Contracts with Customers replaces IAS 18 with effect from accounting periods commencing 1 January 2018.

The new standard requires that revenue is recognised by performance obligation, as or when each performance obligation is satisfied, and that variable elements of pricing are recognised, to the extent that it is not highly probable they will be reversed.

The Group has evaluated its customer contract with Shell Western Supply and Trading Limited ('Shell Western') to identify the performance obligations, the timing of the revenue recognition and the treatment of variable elements of pricing.

The Group has elected to apply the 'modified retrospective' approach to transition permitted by IFRS 15 under which comparative financial information is not restated. The standard did not have a material effect on the Group's financial statements as at 1 January 2018 and so no transition adjustment has been made.

In addition the following standards have been adopted, none of which have a material impact on the Group's annual results:

• IFRS 2 (amendments) - Classification and measurement of share based payment transactions.

• Annual improvements to IFRS 2014-2016 cycle; IFRS1 First time adoption of IFRS, IFRS 12 Disclosure of interests in other entities and IAS 28 Investments in Associates and Joint Ventures.

• IAS 40 (amendments) - Transfer to Investment Property.

• Interpretation 22 - Foreign currency Transactions and Advance Consideration.

No new Standards or Interpretations were early adopted by the Group or Company during the year.

New standards and interpretations not yet adopted

Certain new accounting standards and interpretations have been published that are not mandatory for 31 December 2018 reporting periods and have not been early adopted by the Group. The Group's assessment of the impact of these new standards and interpretations are set out below.

IFRS 16 'Leases'

IFRS 16 was issued in January 2016. It will result in almost all leases being recognised on the balance sheet by lessees, since the distinction between operating and finance leases is removed. Under the new standard, an asset (that is, the right to use the leased item) and a financial liability to pay rentals are recognised. The only exceptions are short-term and low-value leases.

As at 31 December 2018, the Group holds a small number of operating leases that are expensed over the lease term. The adoption of IFRS 16 would not have a material impact on the net debt, gross assets, profit from operations and finance costs of the Group in the current period. However,

in the future should the Group contract equipment on longer-term contracts to develop its existing licences there may be a material impact.

The Group will apply the standard from its mandatory adoption date of 1 January 2019. The Group intends to apply the simplified transition approach and will not restate comparative amounts for the year prior to first adoption. Right-of-use assets for property leases will be measured on transition as if the new rules had always been applied. All other right-of-use assets will be measured at the amount of the lease liability on adoption (adjusted for any prepaid or accrued lease expenses).

C) Basis of consolidation

The Group's consolidated financial statements incorporate the financial statements of the Company and entities controlled by the Company made up to 31 December each year. Control exists when an investor has power over the investee, exposure or rights to variable returns from its involvement with the investee and the ability to use power over the investee to affect the amount of returns. All Group companies apply the Group's accounting policies and prepare financial statements to 31 December.

Consolidation of Elcrest - critical accounting judgement

The Group owns 45% of the shares of Elcrest Exploration and Production (Nigeria) Limited. It has been consolidated because it is controlled by the Company. The Company has power to affect the amount of returns for the following reasons:

• the Company is entitled to appoint a number of Directors to the Board such that it can control decision making.

• in the event of disagreement amongst the Board of Directors, decisions are reached by shareholder vote and the Company has the ability, through the combined effect of a Shareholders Agreement, Loan Agreement and Share Charge, to direct the votes of the 55% shareholding that it does not own.

Non-controlling interests in the net assets of the consolidated subsidiaries are identified separately from the Group's equity therein.

Non-controlling interests consist of the amount of those interests at the date of the original business combination and the non-controlling interest's share of changes in equity since the date of combination.

D) Joint arrangements

The Group applies IFRS 11 to all joint arrangements. Under IFRS 11, investments in joint arrangements are classified as either joint operations or joint ventures, depending on the contractual rights and obligations of each investor. The Company has assessed the nature of its joint arrangements and determined them to be joint arrangements.

The Company recognises its share in its accounting records as follows:

a) Its share of the mineral properties which is shown within property, plant and equipment.

b) Any liabilities that it has incurred.

c) Its share of any liabilities incurred jointly with other ventures, including the decommissioning liability of production and field facilities.

d) Any income from its sale or use of its share of the output.

e) Any expenses that is has incurred, together with its share of any expenses incurred by the joint operation.

These have been incorporated in the financial statements under the appropriate headings.

E) Foreign currencies

Functional and presentation currency

Items included in the financial statements of each of the Group's entities are measured using the currency of the primary economic environment in which the entity operates ('the functional currency'). All companies contained within the consolidated financial statements are US dollars functional currency. The consolidated financial statements are presented in US dollars, which is Eland Oil & Gas PLC' s both functional and presentation currency.

Transactions and balances

Foreign currency transactions are translated into the functional currency using the exchange rates at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions, and from the translation of monetary assets and liabilities denominated in foreign currencies at year-end exchange rates, are generally recognised in the statement of comprehensive income.

The Group's income, and the majority of its costs, are denominated in US dollars. The remainder of the costs are denominated in other currencies, predominantly sterling and Nigerian naira. The Group also has foreign currency denominated liabilities. Exposures to exchange rate fluctuations therefore arise. The Directors currently believe that foreign currency risk is at an acceptable level.

The Group has adopted the use of the parallel exchange rate in Nigeria, which more closely reflects the rate at which the Group converts US dollars to Nigerian naira. Further details of the resulting exchange impact are provided in Note 2.2.

Exchange differences are recognised in the statement of comprehensive income in the period in which they arise.

Group companies

The Group maintains the financial statements of the parent and subsidiary undertakings in their functional currency. Where applicable, the Group translates subsidiary financial statement into the presentation currency, US dollars, using the closing rate method for assets and liabilities which are translated at the rate of exchange prevailing at the balance sheet and rates at the date of transactions for income statement accounts. Eland takes exchange differences arising on the translation of net assets of Group companies whose functional currency is non-US dollars directly to reserves.

Rates of exchange to US$1 were as follows:

F) Critical accounting estimates and judgements

The preparation of the financial statements requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the year. These estimates and judgments are based on management's best knowledge of the amount, event or actions and actual results ultimately may differ from those estimates. The estimates and assumption that could result in a material adjustments to the carrying amounts of assets and liabilities are summarised below. Further details of the critical accounting judgements and estimates involved can be found in the account notes.

Critical accounting estimates Critical accounting judgement

Recoverability of NPDC receivable (Note 4.7) Consolidation of Elcrest (Note 1.1(c)) NPDC accrued balance and disputed costs (Note 4.6, 4.9) E&E impairment Indicators (Note 3.1) Recoverability of deferred tax asset (Note 5.2)

G) Brexit

The Group's activities in the UK comprise executive management, corporate financing, technical and other finance and commercial support services to the Nigerian operations. Eland derives all of its income from crude oil, a globally-traded commodity which is priced in US dollars. In addition, there is minimal supply chain or goods exported from either the UK or other EU countries into Nigeria.

Brexit may result in a change in the financial reporting standards applicable to the Group's consolidated financial statements which currently reports under IFRS for the EU. However, the Group does not envisage that this would result in a material variance from what is currently reported. The Group is not exposed to any material financial risk arising from Brexit. It is not exposed to additional market risk, liquidity risk or credit risk from its UK subsidiary.

It is the view of management that, given the Group's single country focus on Nigeria, the Group's business, assets and operations will not be materially affected by Brexit. Eland also derives most of its income from crude oil, a globally-traded commodity which is priced in US dollars. Management has therefore assessed and concludes that there are no material uncertainties arising from Brexit that would significantly impact the Group.

1.2 Going concern

In assessing its conclusion on going concern, the Group has prepared cash, funding and liquidity forecasts through this year and next, and has appropriate plans and levers in place including access to further debt drawdown, capex scheduling and hedging to ensure it has access to funding when required and that it is compliant with its covenants.

The ramp up in production during 2018 and resulting increase in profitability and cash flows has enabled the Group to repair its working capital deficit while at the same time undertaking an intensive drilling programme. Although risks and uncertainties remain as documented on pages 38 to 47, management has sufficient mitigating actions available to them.

Having regard to the matters above, and after making reasonable enquiries and taking account of uncertainties and reasonably possible changes in operating performance, the Directors have a reasonable expectation that the Group has adequate resources to continue operations for a period of at least 12 months from the date of approval of the financial statements. For that reason, they continue to adopt the going concern basis in the preparation of the accounts.

Section 2 - Results for the year

This section includes the results and performance of the Group, including details of revenue generated during the year through oil sales and related cost of sales.

This section also includes details of employee benefits paid in the year, finance income and costs and the earnings per share calculation.

2.1 Revenue and segmental analysis

Revenue

Accounting policy

IFRS 15 Revenue from Contracts with Customers replaces IAS 18 with effect from accounting periods commencing 1 January 2018.

The new standard requires that revenue is recognised by performance obligation, as or when each performance obligation is satisfied, and that variable elements of pricing are recognised, to the extent that is it not highly probable they will be reversed.

The Group has evaluated its customer contract with Shell Western to identify the performance obligations, the timing of the revenue recognition and the treatment of variable elements of pricing. Sales revenue represents the sales value of the Group's oil liftings in the year. Oil revenue is recognised when title of the crude has passed to the buyer by means of the bill of lading document. Typically, payment for the sale of the oil is received by the end of the month following the month in which the sale is recognised. Revenue is measured at the fair value of the consideration received or receivable, and represents amounts receivable for oil and gas products in the normal course of business, net of discounts, customs duties and sales taxes.

For 2018, crude from the OML40 asset was exported via pipeline to the Forcados oil terminal with the revenue being derived from an offtake contract with Shell Western.

No significant judgements have been made in determining the timing of satisfaction of performance obligations and the transaction price and the amounts allocated to performance obligations.

2.1 Revenue and segmental analysis continued

Segmental Analysis

The Directors believe that the Group has only one reportable operating and geographic segment, which is the exploration and production of oil and gas reserves in Nigeria. All operations are classified as continuing. The Board monitors the operating results of its operating segment for the purpose of making decisions and performance assessment. Segmental performance is evaluated based on operating profit or loss and is reviewed consistently with operating profit and loss in the consolidated financial statements.

During 2018, all of the revenue of the Group was derived from a single external customer, Shell Western. During 2017, $43,273,000 of the revenue of the Group was derived from Shell Western and the remaining from Vitol SA.

2.2 Profit/(loss) before tax

The profit/(loss) before tax for the year is stated after charging/(crediting):

1 Includes costs of $1,091,000 (2017: $805,000) relating to non-executive directors' fees/employee benefits and other temporary employment costs not included in Note 2.3(a) below.

Adjusted EBITDA

Accounting policy

Adjusted EBITDA is a non-IFRS measure that represents net income before additional specific items that are considered to impact the comparability of the Group's performance in each period or with other businesses. The Group defines Adjusted EBITDA as the operating result for the year excluding depreciation, amortization, foreign exchange and the share-based payment charge. The items excluded are non-cash in the year.

The Group believes that adjusted EBITDA is an important indicator of the operational strength and the performance of the business, and provides a meaningful performance indicator of underlying operating cash generation.

2.3 Employee benefits: Staff costs, share-based payments and Director's emoluments

Accounting policy

Pension costs

Payments to a defined contribution retirement benefit scheme are charged as an expense as they fall due. The Group had no defined benefit schemes in place during the years presented

The Group operates a defined contribution pension scheme, and has no obligation to pay amounts other than the contributions. Obligations are recognised as staff costs and are expensed to the consolidated statement of comprehensive income in the periods during which services are rendered by employees. Contributions owed to the scheme at 31 December 2018 amounted to $72,000 (2017: $21,000).

The above share-based payment charge represent a non-cash charge principally from the granting of share awards over the past two years with an effective date of July 2017 and July 2018.

Further details are provided in the Remuneration Report and in Note 2.3b.

(b) Share-based payments

Accounting policy

Equity settled share-based payments are measured at the fair value of the equity instruments at the grant date. The fair value excludes the effect of non-market-based vesting conditions. Details regarding the determination of the fair value of equity settled share-based transactions are set out below.

The fair value determined at the grant date of the equity settled share-based payments is expensed on a straight-line basis over the vesting period, based on the Group's estimate of equity instruments that will eventually vest.

At each balance sheet date, the Group revises its estimate of the number of the equity instruments expected to vest as a result of the effect of non-market-based vesting conditions. The impact of the revision of the original estimates, if any, is recognised in the statement of comprehensive income such that the cumulative expense reflects the revised estimate, with a corresponding adjustment to equity reserves.

Equity settled share option scheme

The Company operates an employee share option plan. Details of share options granted in the years up to 31 December 2018 are noted below.

• On 3 December 2012 all Directors and key personnel of the Group were granted share options comprising of 2,669,763 Founder options exercisable at £1.00 each, 8,210,000 share options exercisable at £1.00 each and 368,500 share options exercisable at £1.13 each. As at 31 December 2018 2,269,301 Founder options and 157,500 share options both of which are (exercisable at £1.00) remain outstanding.

• During 2014, 65,000 share options at £1.25 each and 1,250,000 share options were granted to employees at £1.16 each. The options will be exercisable in full if the average closing price per share over any continuous thirty day period, ignoring any days which are non-dealing days for AIM, occurring wholly during the period of ten years from the date of grant, is equal to or greater than one hundred and fifty percent (150%) of the grant price. On 8 January 2016 the Company offered employees (including Directors) the chance to waive the 150% hurdle rate performance condition associated with their holding. If the employee accepted the offer, they would relinquish their rights to 25% of their options. After relinquishment 52,500 of these share options remain outstanding as at 31 December 2018.

• On 5 January 2016 share options were granted to certain employees of the Group comprising of 1,830,000 options exercisable at £0.285 each. There were no performance conditions associated with the options. As at 31 December 2018 1,630,000 of these share options remain outstanding.

• On 7 November 2017 share options were granted to certain employees of the Group comprising 9,080,500 options exercisable at £0.10 each, with an effective date of 17 July 2017. Some employees were also offered to forfeit their existing options into the new scheme on a 1:1 basis. This was deemed to be a modification to the original equity instruments and as their vesting period was already complete the charge associated with this modification has been recognised immediately. This amounted to $461,000 and is included in the consolidated statement of comprehensive income. As at 31 December 2018 9,060,250 of these share options remain outstanding

• On 25 May 2018 share options were granted to certain employees of the Group comprising 2,100,000 options exercisable at £0.10 each. As at 31 December 2018 2,090,000 of these share options remain outstanding.

• During 2018 personnel left the Company and as a result 30,250 share options lapsed.

There were three performance conditions attached to the 2017 and 2018 options:

With respect to the 2017 LTIP:

· The total shareholder return condition applies to 60% of the number of shares subject to the option. This tranche is only exercisable, on a straight line basis, if the adjusted share price exceeds 50p. Whereby 50p results in 0% being exercisable up to 200p+ when 100% is exercisable.

· 15% of the number of shares subject to the option are tied to the oil price condition. This tranche will only be exercisable if the weighted average share price (expressed in pence) for the 20 dealing days from the publishing date of the 31 December 2019 financial statements is greater than the average Brent Crude oil price for the same period expressed in dollars per barrel.

· The production growth condition will apply to 25% of the shares subject to the option. This tranche will only be exercisable, on a straight line basis, if the average sales volume (being the average sales volume over a period of 90 days from 17 July 2017 to the last of the 20 dealing days following publishing of the 31 December 2017 financial statements) is greater than 25,000 barrels per day. Whereby 25,000 barrels per day results in 0% being exercisable and 40,000 barrels results in 100% being exercisable.

With respect to the 2018 LTIP:

· The total shareholder return condition applies to 60% of the number of shares subject to the option. This tranche is only exercisable, on a straight line basis, if the adjusted share price exceeds 80p (compounding by 5% annually). Whereby 80p (compounding by 5% annually) results in 0% being exercisable up to 160p+ when 100% is exercisable.

· 15% of the number of shares subject to the option are tied to the reserves condition. This tranche will be fully exercisable if the reserves increase from the grant date to the vesting date is 20% or greater. Where the increase is between 10% and 20%, the options will exercise on a straight line basis. Where the increase is 10% or lower, 0% of the tranche will vest.

· The production growth condition will apply to 25% of the shares subject to the option. This tranche will only be exercisable, on a straight line basis, if the average sales volume (being the average sales volume over a period of 90 days from 25 May 2018 to the last of the 20 dealing days following publishing of the 31 December 2018 financial statements) is greater than 30,000 barrels per day. Whereby 30,000 barrels per day results in 0% being exercisable and 45,000 barrels results in 100% being exercisable.

In addition to the above, holder of the options must remain in employment at the end of the three-year vesting period.

Details of the share options outstanding during the year are as follows:

The options outstanding at 31 December 2018 had a weighted average exercise price of £0.25 (2017: £0.29), and a weighted average remaining contractual life of seven years and nine months (2017: eight years and six months). The aggregate of the estimated fair values of the options granted in 2018 was $1,362,000 (2017: $2,162,000). In prior years the Black Scholes model has been used to fair value the options, however, both the 2017 and 2018 Long Term Incentive Plans have been valued using the Monte Carlo simulation as this enables the barrier price to be factored in to the calculation. The inputs into the Monte Carlo model during 2018 were as follows:

Expected volatility was determined by calculating the historical volatility of the Company's share price from the date of admission to AIM to the date the share options were issued. The expected life used in the model has been adjusted, based on management's best estimate, for the effects of non-transferability, exercise restrictions, and behavioural considerations.

The Group recognised total expenses of $1,715,000 (2017: $820,000) related to equity settled share-based payment transactions in 2018.

C) Directors' emoluments and remuneration of key management personnel

Remuneration of key management personnel

The remuneration of the Directors, who are the key management personnel of the Group, is set out below in aggregate for each of the categories specified in IAS 24, Related Party Disclosures.

Further details about the remuneration of individual directors is provided in the Directors' Remuneration Report on pages 66 and 67.

2.4 Finance income and costs

Accounting policy

Commodity price hedging

See Financial Instruments accounting policy, Note 4.7 g) Derivatives.

Finance income

Investment income is recognised on an accruals basis within finance income in the statement of comprehensive income. Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalisation.

Finance costs

Borrowing costs are recognised in the statement of comprehensive income in the period in which they are incurred. Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale.

Finance income

Finance costs

The fair value gain on derivative principally represents the mark-to-market adjustment on the open put options at the end of the year.

2.5 Earnings per share

Earnings per share ('EPS') is the amount of post-tax profit attributable to each share. Diluted EPS takes into account the dilutive effect of share option plans being exercised.

From continuing operations

The calculation of the basic and diluted earnings per share is based on the following data:

* Excludes 957,000 of treasury shares held at year-end.

All activities relate to continuing operations.

For diluted earnings per share, the weighted average number of ordinary shares in issue is adjusted to assume conversion of all dilutive potential ordinary shares. The Company only has one class of ordinary share which have the potential to be dilutive, being the share options issued to employees and Directors (see Note 2.3b for details).

At the end of 2018, the share options issued in January 2016, July 2017 and July 2018 totalling 11,282,000 are considered dilutive. The impact on the EPS between basic and diluted EPS is noted above.

Section 3 - Assets and investments: Oil and gas assets and decommissioning provisions

This section focuses on the assets in the balance sheet which form the core of Eland's business. This section quantifies the financial impact of exploration, appraisal and development activities for the year.

3.1 Intangible oil and gas assets

Accounting policy

Oil and gas assets - exploration and evaluation assets

During the geological and geophysical exploration phase, expenditures are charged against income as incurred. Once the legal right to explore has been acquired, expenditures directly associated with exploration and evaluation are capitalised as intangible assets and are reviewed at each reporting date to confirm that there is no indication of impairment and that drilling is still underway or is planned.

If no future exploration or development activity is planned in the licence area, the exploration licence and leasehold property acquisition costs are written off. Pre-licensing expenditures on oil and gas assets are recognised as an expense within the consolidated statement of comprehensive income when incurred.

Impairment of exploration and evaluation assets

Exploration and evaluation ('E&E') costs are not amortised prior to conclusion of appraisal activities. Once active exploration is completed the asset is assessed for impairment. If commercial reserves are discovered then the carrying value of the E&E asset is reclassified as a development and production ('D&P') asset, following development sanction, but only after the carrying value is assessed for impairment and where appropriate its carrying value adjusted. If commercial reserves are not discovered the E&E asset is written off to the consolidated statement of comprehensive income.

Critical accounting judgement

Exploration and evaluation assets

The accounting for exploration and evaluation ('E&E') assets requires management to make certain judgements and assumptions, including whether exploratory wells have discovered economically recoverable quantities of reserves. Designations are sometimes revised as new information becomes available. If an exploratory well encounters hydrocarbons, but further appraisal activity is required in order to conclude whether the hydrocarbons are economically recoverable, the well costs remain capitalised as long as sufficient progress is being made in assessing the economic and operating viability of the well. Criteria used in making this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected additional development activities, commercial evaluation and regulatory matters. The concept of 'sufficient progress' is an area of judgement, and it is possible to have exploratory costs remain capitalised for several years while additional drilling is performed or the Group seeks government, regulatory or partner approval of development plans.

Impairment indicators

The Group monitors internal and external indicators of impairment relating to E&E assets. The following are examples of the types of indicators used:

• The entity's right to explore in an area has expired or will expire in the near future without renewal;

• No further exploration or evaluation is planned or budgeted;

• The decision to discontinue exploration and evaluation in an area because of the absence of commercial reserves; or

• Sufficient data exists to indicate that the book value will not be fully recovered from future development and production.

The assessment of impairment indicators requires the exercise of judgement. If an impairment indicator exists, then the recoverable amounts of the cash-generating units and/or individual assets are determined based on the higher of value-in-use and fair values less costs of disposal calculations. These require the use of estimates and assumptions, such as future oil and natural gas prices, life of field, discount rates, operating costs, future capital requirements, decommissioning costs, exploration potential, reserves and operating performance. These estimates and assumptions are subject to risk and uncertainty. Therefore, there is a possibility that changes in circumstances will impact these projections, which may impact the recoverable amount of assets and/or Cash Generating Units (CGUs).

The Group's oil & gas exploration and evaluation assets at 31 December 2018 relate to the Group's interest in the Ubima marginal field in Nigeria.

In August 2014, the Group's subsidiary Wester Ord Oil & Gas (Nigeria) Limited ('Wester Ord') acquired a 40% participating interest in the Ubima field from All Grace Energy Limited ('All Grace'). Wester Ord paid a signature bonus of $7,000,000 at completion. A production bonus of $3,000,000 may become payable in the future. Further details are disclosed in Note 4.9.

Wester Ord has agreed to fund 100% of the initial work programme and will be entitled to 88% of production cash flow until the partner costs have been recovered. The above exploration and evaluation balance therefore include 100% of the initial work programme expenditure, together with interest charged to All Grace of $1,307,000 (2017: $580,000) as detailed in Note 2.4.

The other intangible asset relates to the approval fee paid on grant of Pioneer tax status during 2014 (Note 5.1). The cost has been amortised on a straight-line basis over the minimum expected tax relief period of three years. There is no amortisation charge included in operating costs within the year (2017: $500,000) as the cost was fully amortised in the previous year

3.1 Intangible oil and gas assets

The Group monitors both internal and external indicators of impairment, at least on an annual basis. The types of indicators are noted above within the critical accounting judgements. As the Group continues to have a right to explore and intends further investment, has drilled an appraisal well which it plans to develop commercially no impairment indicator has been triggered. Following the results of the extended well test, scheduled for the first half of 2019, a decision will be made whether to drill a further well and thereafter pursue a Field Development Plan ('FDP'). An impairment review would be undertaken at that time in line with the Group's E&E accounting policy.

3.2 Property, plant and equipment

Accounting policy

Oil and gas assets - development and production assets

Once a project is technically feasible and commercially viable, which in practice is when the asset has been approved for development by the appropriate regulatory authorities, the carrying value of the associated exploration licence and property acquisition costs and the related cost of exploration wells are transferred to development oil and gas properties after the impairment test. Development and production assets are accumulated generally on a field-by-field basis and represent the full cost of developing the commercial reserves discovered and bringing them into production. The cost of development and production assets also includes the cost of acquisitions and purchase of such assets, directly attributable overheads, finance costs capitalised, and the cost of recognising provisions for future restoration and decommissioning.

Depreciation of producing assets

The net book values of producing assets are depreciated on a field-by-field basis using the unit-of-production method by reference to the ratio of production in the year aggregating individual fields within the licence, compared to the related proved and probable commercial reserves of the licence, taking into account future development expenditures necessary to bring those reserves into production. Producing assets are

generally grouped with other assets that are dedicated to serving the same reserves for depreciation purposes, but are depreciated separately from producing assets that serve other reserves.

Impairment of development and production assets

An impairment test is performed whenever events and circumstances arising during the development or production phase indicate that the carrying value of a development or production asset may exceed its recoverable amount.

The carrying value is compared against the expected recoverable amount of the asset, generally by reference to the fair value less costs of disposal expected to be derived from production of commercial reserves. The Cash Generating Unit (CGU) applied for impairment test purposes is generally the licence, where typically a number of field interests will be grouped as a single cash generating unit if they share common infrastructure.

Commercial reserves are proved and probable oil and gas reserves, which are defined as the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially viable. There should be at least a 50% statistical probability that the actual quantity of recoverable reserves will be equal or more than the amount estimated as proved and probable reserves.

Any impairment identified is charged to the consolidated statement of comprehensive income as additional depreciation. Where conditions giving rise to impairment subsequently reverse, the effect of the impairment charge is also reversed as a credit to the consolidated statement of comprehensive income, net of any depreciation that would have been charged since the impairment.

Other property, plant and equipment

All classes of other property, plant and equipment are stated at cost less accumulated depreciation and any recognised impairment loss.

Depreciation is recognised so as to write off the cost or valuation of assets less their residual values over their useful lives, using the straight-line method, on the following bases:

Fixtures and equipment 10 - 30% per annum

Motor vehicles 30% per annum

Acquisitions, asset purchases and disposals

Acquisitions of oil and gas properties are accounted for as a business combination when the assets acquired and liabilities assumed constitute a business. There have been no such acquisitions to date.

Transactions involving the purchase of an individual interest, or a Group of interests, that do not constitute a business, are treated as asset purchases irrespective of whether the specific transactions involve the transfer of the interests directly or the transfer of an incorporated entity. Accordingly, no goodwill and no deferred tax gross up arises, and the consideration is allocated to the assets and liabilities purchased based on relative fair values.

Proceeds on disposal are applied to the carrying amount of the specific intangible asset or development and production assets disposed of and any surplus or deficit is recorded as a gain or loss on disposal in the consolidated statement of comprehensive income.

Accounting judgement

Impairment indicators

The Group monitors internal and external indicators of impairment relating to property, plant and equipment. The following are examples of the types of indicators used:

• A significant and unexpected decline in the asset's capital market value or likely future revenue;

• A significant change in the asset's reserves assessment;

• Significant tax or regulatory changes;

• Significant changes to licence expiry terms;

• Significant changes in the technological, market, economic or legal environments for the asset; or

• Evidence is available to indicate obsolescence or physical damage of an asset, or that it is underperforming expectations.

The assessment of impairment indicators requires the exercise of judgement. If an impairment indicator exists, then the recoverable amounts of the cash-generating units and/or individual assets are determined based on the higher of value-in-use and fair values less costs of disposal calculations. These require the use of estimates and assumptions, such as future oil and natural gas prices, life of field, discount rates, operating costs, future capital requirements, decommissioning costs, exploration potential, reserves and operating performance. These estimates and assumptions are subject to risk and uncertainty. Therefore, there is a possibility that changes in circumstances will impact these projections, which may impact the recoverable amount of assets and/or Cash Generating Units (CGUs).

Accounting estimate

Carrying value of oil and gas assets

The carrying value of oil and gas assets is subject to judgement over their recoverable value. The calculation of recoverable value requires estimates of future cash flows within complex value-in-use or fair value less costs to dispose models. Key assumptions and estimates in the cash flow models relate to commodity prices, commercial reserves and the related cost and production profiles, discount rates that are adjusted to reflect risk specific to individual assets.

Management assesses the Group's oil and gas assets for indicators of impairment at least annually with reference to indicators as defined in IAS 36. During 2018 management assessed the following indicators; oil price environment, reserve revisions, tax or regulatory changes, local market conditions, licence expiry terms, and Group market capitalisation movement. In addition, management reviewed the economic outputs from the December 2018 NSAI reserves compared to its carrying value which showed significant headroom exists to cover the carrying value. Following this assessment, management concluded that no material adverse impact had occurred across any key indicator. As such, and in line with its policy, management did not complete a impairment review in the year comparing carrying value to future cashflows as described in the impairment of development and production assets policy above.

The Directors do not believe that any reasonably possible change in key assumptions on which the recoverable amount is based would cause the carrying amount to exceed its recoverable amount

Section 3 - Assets and investments: Oil and gas assets and decommissioning provisions continued

3.2 Property, plant and equipment

The note below discloses the carrying value of tangible oil and gas assets.

* The 2017 additions number is a credit in the year as a result of finalisation of previously accrued capital costs.

The Group's oil and gas development and production assets at 31 December 2018 and 31 December 2017 relate to the Group's interest in OML 40 in Nigeria.

Management assess the Group's oil and gas assets for indicators of impairment at least annually. Management assessed the indicators as outlined in the Group's accounting policy above at 2018 year-end. Following this assessment management concluded that no material adverse impact had occurred across any key indicator and no impairment review was therefore undertaken.

As no indicators for impairment were triggered and significant headroom between the carrying value and the fair value exist a full impairment review was not undertaken. Nonetheless, a reasonably possible change in key assumptions, deemed to be a +/- 10% movement in either oil price, reserves, discount rate would not result in an impairment charge.

3.3 Decommissioning provision

Accounting policy

A provision for decommissioning the Group's oil and gas assets is recognised in full when the related facilities are installed or acquired. Provisions are measured at the present value of management's best estimates of the expenditure required to settle the present obligation at the end of the reporting period. The extent to which a provision is required depends on the legal requirements for decommissioning, the costs and timing of work and the discount rate to be applied. A corresponding adjustment to property, plant and equipment of an amount equivalent to the provision is also recognised. This is subsequently depreciated as part of the asset and included in depletion expense in the consolidated statement of comprehensive income. Changes in the estimated timing of decommissioning or decommissioning cost estimates are accounted for prospectively by recording an adjustment to the provision, and a corresponding adjustment to property, plant and equipment. The unwinding of discount on the decommissioning provision is classified in the consolidated statement of comprehensive income as finance costs.

Accounting estimate - Estimation of cost and timing of decommissioning cost

Key inputs to the reported decommissioning provision is the cost, timing and discount rate to apply to the cash flows.

• The costs of decommissioning are reviewed internally on an annual basis and by an independent specialist at least every three years. A review of all decommissioning cost estimates was undertaken by an independent specialist in 2017 and the updated cost estimate provided by the specialist, along with an internal update for 2018 activity, has been applied in recording the 2018 provision. Provision for environmental clean-up and remediation costs is based on current legal and constructive requirements, technology and price levels.

• Timing of costs is estimated to be incurred between 2031 and 2033, from the latest life of field plans.

• The estimated cash flows have been discounted using a discount rate of 2.75% (2017: 2.75%), which is estimated using a risk free rate adjusted for timing uncertainty. An inflation rate of 2% (2017: 2%) has also been used.

• A 50% risk factor has been applied in the estimation of future decommissioning to reflect the combined effect of the political environment, isolated location and potential future changes in fiscal regime.

Due to the nature of decommissioning costs, the Group believes that there is a risk given the above estimates, but only in the long-term (i.e. not within the next year).

The provision for decommissioning is in respect of the Group's interest in OML 40 and Ubima (oil and gas fields).

A corresponding amount equivalent to the provision is recognised as part of the cost of the related intangible assets and property, plant and equipment for the Ubima and OML 40 licence respectively. 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 2018 decommissioning revision has been increased to reflect the additional decommissioning expenditure arising from the drilling and facilities infrastructure commissioned during 2018. The 2017 revision principally reflects a change in estimate following an independent review of the Group's decommissioning obligations.

The unwinding of the discount on the decommissioning is included in the consolidated statement of comprehensive income as a finance cost (see Note 2.4).

Section 4 - Assets, liabilities and investments: Financial assets, cash and borrowings and working capital

This section includes details of the Group's cash resources and the loans and borrowings drawn in the year.

4.1 Inventories

Accounting policy

Inventories are stated at the lower of cost and net realisable value. Cost comprises direct materials, and where applicable, direct labour costs and those overheads that have been incurred in bringing the inventories to their present location and condition and is determined on a first-in, first-out method. Net realisable value represents the estimated selling price less all estimated costs to be incurred in marketing, selling and distribution.

Spare parts inventory relates to equipment which will be used in the future Ubima drilling campaign. The stock in terminal tanks relates to crude oil held in Eland's storage tanks at the Forcados terminal. The stock is required by Shell Western to operate Forcados pipeline/refinery system efficiently. The stock on storage vessel relates to barrels stored on the FPSO Trinity Spirit resulting from shipping operations in 2017 which were previously considered to have been lifted in the prior year. Elcrest expects to sell these barrels at market value in the first half of 2019.

4.2 Cash and cash equivalents

Accounting policy

For the purpose of presentation in the statement of cash flows, cash and cash equivalents include cash on hand, deposits held at call with financial institutions, other short-term, highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value, and bank overdrafts. Bank overdrafts are shown within borrowings in current liabilities in the balance sheet.

Under the terms of the reserve based lending facility ('RBL'), the Group is required to set aside amounts to cover the servicing of the debt and stamp duty costs for the next six months in restricted cash accounts.

4.2 Cash and cash equivalents

The re-financing of the RBL was completed in November 2018 increasing both the facility size to $75,000,000 (2017: $35,000,000) and amount borrowed to $50,000,000 (2017: $27,000,000). As a result a corresponding increase in restricted cash was required compared to the prior year. After the year end a further $1,074,000 was deposited in restricted accounts taking the total restricted cash to $3,528,000.

See further details in Note 4.3.

Notes to the cashflow statement

4.3 Loans and borrowings

Accounting policy

Borrowings are initially recognised at fair value, net of transaction costs incurred. Borrowings are subsequently measured at amortised cost. Any difference between the proceeds (net of transaction costs) and the redemption amount is recognised in statement of comprehensive income over the period of the borrowings using the effective interest method. Fees paid on the establishment of loan facilities are recognised as transaction costs of the loan to the extent that it is probable that some or all of the facility will be drawn down. In this case, the fee is deferred until the draw down occurs. To the extent there is no evidence that it is probable that some or all of the facility will be drawn down, the fee is capitalised as a prepayment for liquidity services and amortised over the period of the facility to which it relates.

Borrowings are removed from the balance sheet when the obligation specified in the contract is discharged, cancelled or expired. The difference between the carrying amount of a financial liability that has been extinguished or transferred to another party and the consideration paid, including any non-cash assets transferred or liabilities assumed, is recognised in the statement of comprehensive statement income as other income or finance costs.

Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least 12 months after the reporting period.

The maturity of the loan balances due for repayment can be categorised as follows:

In November 2018, the Group refinanced its existing RBL with a new $75,000,000 reserve-based lending facility (the 'RBL') provided by Stanbic IBTC Bank PLC (a member of the Standard Bank Group) and the Mauritius Commercial Bank Ltd. The RBL is secured against the Group's producing assets in OML 40 via the Company's shares in Elcrest, and by way of a debenture which creates a charge over certain assets of the Group, including its bank accounts.

The Group concluded that the amended and restated RBL was a substantial modification of the terms, resulting in the previous loan carrying amount of $25,417,000 being derecognised and a new loan of $47,355,000 being recognised at fair value.

The RBL has a maturity of five years, the repayments of principal are due on a semi-annual basis so that the outstanding balance of the RBL will not exceed the lower of (a) the borrowing base amount and (b) the facility amount. There is a one-year grace period from execution of the RBL before any principal amount is repaid and the interest rate payable under the RBL is LIBOR plus 7.5% to the extent that the total amount outstanding is lower than 50% of the higher of total commitments and the borrowing base amount, and LIBOR plus 8% in all other cases.

The RBL has the potential to increase up to a maximum of $200.000,000 subject to incremental reserves and production. The RBL has an initial borrowing base of $103,000,000. In March 2019, the Company announced an increase in the RBL from $75,000,000 to $125,000,000. At the same time the lenders agreed a borrowing base increase from $103,000,000 to $134,000,000 reflecting the inclusion of additional wells. The available facility is capped at the lower of the facility or borrowing base therefore the debt available for drawdown being $125,000,000, representing $75,000,000 headroom on the $50,000,000 drawn at the date of this report. This provides additional headroom to not only execute the 2019 work programme but also provides additional funding in the event of a successful exploration campaign.

The amount drawn under the RBL is reconciled to the carrying amount of the loan as at the Balance Sheet date as follows:

4.4 Commitments: Non-cancellable operating leases and capital commitments

a) Non-cancellable operating leases

Accounting policy

Leases

Leases are classified as finance leases whenever the terms of the lease transfer substantially all of the risks and rewards of ownership to the lessee. All other leases are classified as operating leases. Rentals payable under operating leases are charged to the statement of comprehensive income on a straight line basis over the term of the lease.

At the balance sheet date, the Group had outstanding commitments for future minimum lease payments under non-cancellable operating leases, which fall due as follows:

Operating lease payments represent rentals payable by the Group for certain of its office properties and staff residences.

b) Capital commitments

Significant capital expenditure contracted for at the end of the reporting period but not recognised as liabilities is as follows:

Accounting policy

Trade receivables

See details of the trade receivables accounting policy in Note 4.7.

Other receivables

These amounts generally arise from transactions outside the usual operating activities of the Group. The Group holds the other receivables with the objective to collect the contractual cash flows and therefore measures them subsequently at amortised cost using the effective interest method.

Overlift/underlift

Lifting or offtake arrangements for oil and gas produced in 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 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 basis.

Critical accounting estimate

See Financial Instruments at 4.7 for the critical accounting estimate regarding the NPDC receivable balance.

The Directors consider that the carrying value of trade and other receivables is approximately equal to their fair value

Impairment and risk exposure

Information about the impairment of trade receivables and the Group's exposure to credit risk, foreign currency risk and interest rate risk can be found in Note 4.7.

4.6 Trade and other payables

Accounting policy

Trade payables

See details of the trade payables within the financial instruments policy in Note 4.7.

Offsetting of financial assets and financial liabilities

See accounting policy at 4.7 Financial Instruments f) Offsetting of financial assets and financial liabilities.

Provisions

Provisions are recognised when the Group has a present obligation as a result of a past event, it is probable that the Group will be required to settle that obligation and a reliable estimate can be made of the amount and timing of the obligation.

The amount recognised as a provision is the best estimate of the consideration required to settle the present obligation at the balance sheet date, taking into account the risks and uncertainties surrounding the obligation. Where a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows.

When some or all of the economic benefits required to settle a provision are expected to be recovered from a third party, a receivable is recognised as an asset if it is virtually certain that reimbursement will be received, and the amount of the receivable can be measured reliably.

Critical accounting estimate - NPDC accrued balance and disputed costs

In line with the Joint Operating Agreement ('JOA'), the Group is responsible for its share of expenditures incurred on OML 40 in respect of its participating interest, on the basis that the operator's estimated expenditures are reasonably incurred based on the approved programme and budget. From time to time, management disputes such expenditures on the basis that they do not meet these criteria, and when this occurs management accrues at the period end for its best estimate of the amounts payable to the operator.

Consequently, the amounts recognised as accruals as at 31 December 2018 reflect management's best estimate of amounts that have been incurred in accordance with the JOA and that will ultimately be paid to settle its obligations in this regard. To the extent additional amounts have been claimed by the operator which are being disputed, management consider any material liability in excess of that accrued to be unlikely. However, where such liability is considered possible the Group will disclose its best estimate within the contingent liability Note 4.9. Where management are of the view the liability is considered remote no such disclosure is made.

Trade payables principally comprise amounts outstanding for trade purchases and ongoing costs.

The Directors consider that the carrying amounts of trade and other payables are approximate to their fair values. All trade and other payables are denominated in sterling, US dollars or Nigerian naira.

Accruals mainly relate to drilling and facility costs still to be invoiced.

The joint venture creditor balance includes a net of amounts which have been billed and agreed upon and estimates of amounts due under the OML 40 Joint Operating Agreement ('JOA') which are either not yet invoiced or agreed with our partner on the licence. The JV creditor balance includes amounts due to NPDC offset by balances receivable from NPDC to Elcrest. A right of offset exists as agreed by both joint venture parties (at Operating Committee, 'OPCOM' meetings) and as a result a net balance is shown above.

Other payables relate principally to amounts due to the Department of Petroleum Resources ('DPR') in respect of royalty payments and factoring receipts outstanding at year-end. 90% of the December 2018 lifting invoice from Shell Western was factored during the month and the factor receipt was received prior to the year end. This amount was repaid following receipt from Shell Western during January 2019. The remaining balance within other payables relates to employment taxes, VAT and withholding tax liabilities.

The shareholder management fee represents the balance due from Elcrest to its indigenous shareholder in Nigeria, for a liability due under a shareholders' agreement signed in March 2011. The outstanding historic balance at 31 December 2017 was fully settled in 2018. Management fees payable under the agreement are $3,000,000 per annum.

The Company has financial risk management policies in place to ensure that all payables to third parties are paid within the credit timeframe. Details of interest charged by suppliers in the prior year as a result of late payment has been disclosed in Note 2.4.

4.7 Financial instruments and financial risk management

Financial Instruments

Accounting policy from 1 January 2018

The Group's accounting policies were changed to comply with IFRS 9. IFRS 9 replaces the provisions of IAS 39 that relate to the recognition, classification and measurement of financial assets and financial liabilities; derecognition of financial instruments; impairment of financial assets and hedge accounting. IFRS 9 also significantly amends other standards dealing with financial instruments such as IFRS 7 Financial Instruments: Disclosures.

a) Classification and measurement

Financial assets

It is the Group's policy to initially recognise financial assets at fair value plus transaction costs, except in the case of financial assets recorded at fair value through profit or loss which are expensed in the statement of comprehensive income.

Classification and subsequent measurement is dependent on the Group's business model for managing the asset and the cashflow characteristics of the asset. On this basis, the Group may classify its financial instruments at amortised cost, fair value through statement of comprehensive income and at fair value through other comprehensive income.

All the Group's financial assets as at 31 December 2018 satisfy the conditions for classification at amortised cost under IFRS 9 except derivative financial instruments which is measured at fair value through profit or loss.

The Group's financial assets include trade receivables, NPDC receivables, other receivables, derivative financial instruments and cash and bank balances. They are included in current assets, except for maturities greater than 12 months after the reporting date. Interest income from these assets is included in finance income using the effective interest rate method. Any gain or loss arising on derecognition is recognised directly in the statement of comprehensive income and presented in finance income/costs.

Financial liabilities

Financial liabilities of the Group are classified and measured at fair value on initial recognition and subsequently at amortised cost net of directly attributable transaction costs, except for derivatives which are classified and subsequently recognised at fair value through the statement of comprehensive income.

Fair value gains or losses for financial liabilities designated at fair value through the statement of comprehensive income are accounted for as a profit or loss except for the amount of change that is attributable to changes in the Group's own credit risk which is presented in other comprehensive income. The remaining amount of change in the fair value of the liability is presented in the statement of comprehensive income. The Group's financial liabilities include trade and other payables and interest-bearing loans and borrowings.

b) Impairment of financial assets

Recognition of impairment provisions under IFRS 9 is based on the expected credit loss (ECL) model. The ECL model is applicable to financial assets classified at amortised cost and contract assets under IFRS 15: Revenue from Contracts with Customers. The measurement of ECL reflects an unbiased and probability-weighted amount that is determined by evaluating a range of possible outcomes, time value of money and reasonable and supportable information that is available without undue cost or effort at the reporting date, about past events, current conditions and forecasts of future economic conditions.

The Group applies the simplified approach or the three-stage general approach to determine impairment of receivables depending on their respective nature. The simplified approach is applied for trade receivables while the general approach is applied to NPDC receivables and cash and bank balances.

The simplified approach requires expected lifetime losses to be recognised from initial recognition of the receivables. This involves determining the expected loss rates using a provision matrix that is based on the Group's historical default rates observed over the expected life of the receivable and adjusted forward-looking estimates. This is then applied to the gross carrying amount of the receivable to arrive at the loss allowance for the period.

The three-stage approach assesses impairment based on changes in credit risk since initial recognition using the past due criterion and other qualitative indicators such as increase in political concerns or other macroeconomic factors and the risk of legal action, sanction or other regulatory penalties that may impair future financial performance. Financial assets classified as stage 1 have their ECL measured as a proportion of their lifetime ECL that results from possible default events that can occur within one year, while assets in stage 2 or 3 have their ECL measured on a lifetime basis.

Under the three-stage approach, the ECL is determined by projecting the probability of default (PD), loss given default (LGD) and exposure at default (EAD) for each ageing bucket and for each individual exposure. The PD is based on default rates determined by external rating agencies for the counterparties. The LGD is determined based on management's estimate of expected cash recoveries after considering the historical pattern of the receivable, and it assesses the portion of the outstanding receivable that is deemed to be irrecoverable at the reporting period. The EAD is the total amount of outstanding receivable at the reporting period.

These three components are multiplied together and adjusted for forward looking information, such as crude oil prices, to arrive at an ECL which is then discounted back to the reporting date and summed. The discount rate used in the ECL calculation is the original effective interest rate or an approximation thereof. Loss allowances for financial assets measured at amortised cost are deducted from the gross carrying amount of the related financial assets and the amount of the loss is recognised in the statement of comprehensive income.

c) Significant increase in credit risk and default definition

The Group assesses the credit risk of its financial assets based on the information obtained during periodic review of publicly available information, industry trends and payment records. Based on the analysis of the information provided, the Group identifies the assets that require close monitoring.

Furthermore, financial assets that have been identified to be more than 30 days past due for trade receivables or 90 days past due for NPDC receivables on contractual payments are assessed to have experienced significant increase in credit risk. These assets are grouped as part of Stage 2 financial assets where the three-stage approach is applied.

In line with the Group's credit risk management practices, a financial asset is defined to be in default when contractual payments have not been received at least 365 days after the contractual payment period. Subsequent to default, the Group carries out active recovery strategies to recover all outstanding payments due on receivables. Where the Group determines that there are no realistic prospects of recovery, the financial asset and any related loss allowance is written off either partially or in full.

d) Derecognition

Financial assets

The Group derecognises a financial asset when the contractual rights to the cash flows from the financial asset expire or when it transfers the financial asset and the transfer qualifies for derecognition. Gains or losses on derecognition of financial assets are recognised as finance income/costs

Financial liabilities

The Group derecognises a financial liability when it is extinguished i.e. when the obligation specified in the contract is discharged or cancelled or expires. When an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability. The difference in the respective carrying amounts is recognised immediately in the statement of comprehensive income.

e) Modification

When the contractual cash flows of a financial instrument are renegotiated or otherwise modified and the renegotiation or modification does not result in the derecognition of that financial instrument, the Group recalculates the gross carrying amount of the financial instrument and recognises a modification gain or loss immediately within finance income/costs-net at the date of the modification. The gross carrying amount of the financial instrument is recalculated as the present value of the renegotiated or modified contractual cash flows that are discounted at the financial instrument's original effective interest rate.

f) Offsetting of financial assets and financial liabilities

Financial assets and liabilities are offset and the net amount is reported in the consolidated balance sheet. Offsetting can be applied when there is a legally enforceable right to offset the recognised amounts, and there is an intention to settle on a net basis or realise the asset and settle the liability simultaneously. The legally enforceable right is not contingent on future events and is enforceable in the normal course of business, and in the event of default, insolvency or bankruptcy of the Company or the counterparty.

g) Derivatives

The Group uses derivative financial instruments such as forward exchange contracts to hedge its foreign exchange, risks as well as put options to hedge against its oil price risk. However, such contracts are not accounted for as designated hedges. Derivatives are initially recognised at fair value on the date a derivative contract is entered into and subsequently remeasured to their fair value at the end of each reporting period. Any gains or losses arising from changes in the fair value of derivatives are recognised within finance income/ costs for the period. An analysis of the fair value of derivatives is provided in note 4.8.

h) Fair value of financial instruments

The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. When available, the Group measures the fair value of an instrument using quoted prices in an active market for that instrument. A market is regarded as active if quoted prices are readily available and represent actual and regularly occurring market transactions on an arm's length basis.

If a market for a financial instrument is not active, the Group establishes fair value using valuation techniques. Valuation techniques include using recent arm's length transactions between knowledgeable, willing parties (if available), reference to the current fair value of other instruments that are substantially the same, and discounted cash flow analysis. The chosen valuation technique makes maximum use of market inputs, relies as little as possible on estimates specific to the Group, incorporates all factors that market participants would consider in setting a price, and is consistent with accepted economic methodologies for pricing financial instruments.

Inputs to valuation techniques reasonably represent market expectations and measure the risk-return factors inherent in the financial instrument. The Group calibrates valuation techniques and tests them for validity using prices from observable current market transactions in the same instrument or based on other available observable market data.

The best evidence of the fair value of a financial instrument at initial recognition is the transaction price - i.e. the fair value of the consideration given or received. However, in some cases, the fair value of a financial instrument on initial recognition may be different to its transaction price. If such fair value is evidenced by comparison with other observable current market transactions in the same instrument (without modification or repackaging) or based on a valuation technique whose variables include only data from observable markets, then the difference is recognised in the statement of comprehensive income on initial recognition of the instrument. In other cases, the difference is not recognised in the statement of comprehensive income immediately but is recognised over the life of the instrument on an appropriate basis or when the instrument is redeemed, transferred or sold, or the fair value becomes observable.

Financial Instruments policy prior to 1 January 2018

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

Trade and other receivables

Trade receivables are initially measured at fair value and subsequently measured at amortised cost. The exception to this is underlift which is valued at market value.

Trade and other payables

Accounts payable are initially measured at fair value and subsequently measured at amortised cost. The exception to this is overlift which is valued at market value.

Impairment of financial assets

The Group assesses at each reporting date whether there is objective evidence that a financial asset or a group of financial assets is impaired. A financial asset or a group of financial assets is deemed to be impaired if there is objective evidence of impairment as a result of one or more events that has occurred since the initial recognition of the asset (an incurred loss event) and that loss event has an impact on the estimated future cash flows of the financial asset or the Group of financial assets that can be reliably estimated. Evidence of impairment may include indications that the debtor or a group of debtors is experiencing significant financial difficulty, default or delinquency in interest or principal payments, the probability that they will enter bankruptcy or other financial reorganisation and observable data indicating that there is a measurable decrease in the estimated future cash flows, such as changes in arrears or economic conditions that correlate with defaults.

Financial liabilities and equity

Debt and equity instruments are classified as either financial liabilities or as equity in accordance with the substance of the contractual arrangement.

Other financial liabilities

Other financial liabilities (including borrowings) are initially measured at fair value, net of transaction costs.

Other financial liabilities (including borrowings) are subsequently measured at amortised cost using the effective interest method, with interest expense recorded on an effective yield basis.

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 through the expected life of the financial liability to the net carrying amount on initial recognition.

Critical accounting estimate - Recoverability of NPDC receivable

The NPDC receivable balance at the end of 2018 represents invoices issued to Elcrest's government partner, NPDC and receivables where Elcrest has paid expenditure on behalf of the OML 40 Joint Venture. As Elcrest has executed an increasing work programme, as de facto Operator, and initially funding the drilling programme the balance between Elcrest and NPDC has grown significantly during 2018 to $46,540,000 (2017: $4,566,000). Subject to applying the IFRS 9 expected credit loss calculation management believe this will be recovered in full.

Management has concluded this assessment on the basis $19,300,000 was paid in January 2019 which followed a cash call reconciliation agreement between Elcrest and NPDC as at 30 June 2018, where payment was subsequently endorsed at OPCOM in November 2018. Further reconciliation meetings are at an advanced stage to agree the balance between Elcrest and NPDC as at 31 December 2018, following which we expect OPCOM endorsement ahead of NPDC remitting payments to Elcrest, thereby following a similar mechanism to the process prior to the January 2019 payment.

The critical accounting estimate in applying IFRS 9 to the NPDC receivable involves the assessment of the Probability of Default. As NPDC is a government body we have applied the credit rating of Nigerian Federal Government bonds as a proxy to reflect the credit worthiness of the NPDC receivable. The Group has subsequently translated the credit rating into a Probability of Default using externally published data.

Key sensitivity:

• A change in Nigerian government credit rating by +/- one notch would increase the expected credit loss by $336,000 in the event of a downward credit rating movement, or $168,000 decrease in expected credit loss in the event of an upward movement in credit rating.

Of the cash balances of $43,094,000 (2017: $36,743,000), $40,578,000 (2017: $34,251,000) was denominated in US dollars, $525,000 (2017: $855,000) was denominated in sterling and $1,992,000 (2017: $1,637,000) was denominated in naira.

Credit risk management

Credit risk arises from cash and cash equivalents and deposits with banks. Cash balances are held with banks with an 'A' rating or better where possible. There is believed to be insignificant credit risk associated with trade, other debtors and prepayments other than as noted on the NPDC receivable balance in the critical accounting estimate section of Note 4.5.

Changes in accounting policies

This note explains the impact of the adoption of IFRS 9: Financial Instruments and IFRS 15 Revenue from Contracts with Customers on the Group's financial statement that have been applied from 1 January 2018, where they are different from those applied in prior periods. The adoption of IFRS 15 Revenue from Contracts with Customers did not have a material impact on the Group's financial statements.

Impairment of financial assets

The Group has three types of financial assets that are subject to IFRS 9's new expected credit loss model. Under IFRS 9, the Group is required to revise its previous impairment methodology under IAS 39 for each of these classes of assets.

• Cash and Cash Equivalents

• Nigerian Petroleum Development Company (NPDC) receivables

• Trade Receivables

While cash and cash equivalents are also subject to the impairment requirements of IFRS 9, the identified impairment loss was insignificant.a) Nigerian Petroleum Development Company (NPDC) receivables $47,099,000 (2017: $4,566,000)

NPDC receivables represent the outstanding invoices due to Elcrest from its JV partner, Nigerian Petroleum Development Company ('NPDC'). The Group applies the IFRS 9 general model for measuring expected credit losses (ECL). This requires a three-stage approach in recognising the expected credit loss for NPDC receivables.

The ECL recognised is a probability-weighted estimate discounted at the effective interest rate of the financial asset. Credit losses are measured as the present value of all cash shortfalls (i.e. the difference between the cash flows due to the Group in accordance with the contract and the cash flows that the Group expects to receive).

During 2018 Elcrest invoiced NPDC for the first time in order to be reimbursed for expenditure incurred on behalf of the OML Joint Venture. As a result, there is limited historical information in which to form an estimate on the probability of receiving the balances contractually due.

Net exposure at default calculation

The net exposure at default is contained within the accounting policies above and can be summarised as PD x LGD x EAD adjusted for future macroeconomic indicators. The probability of default, loss given default and exposure at default and macroeconomic conditions used in calculating the NPDC receivables expected credit loss have been based on the following:

Probability of default (PD)

The credit rating of Federal Government bonds was used as a proxy to reflect the assessment of the probability of default on these receivables. This was supplemented with external data from the credit rating agencies; Standard & Poor's, Moody's and Fitch to arrive at a 12-month PD of 2.5% which is applied to Stage 1 receivables, apart from those received post year end. Stage 2 and Stage 3 receivables apply the lifetime probability of default. We have assumed the 12 month PD is the same as the lifetime PD.

Loss given default (LGD)

The LGD was determined based on management's estimate of expected cash recoveries after considering the historical recovery pattern of these receivables, and it assesses the portion of outstanding receivable that is deemed to be irrecoverable at the reporting period.

Exposure at default (EAD)

This is the amount that best represents the maximum exposure to credit risk at the end of the reporting period.

Macroeconomic indicators

Crude oil prices and the corresponding impact on the wider Nigerian economy and ability for NPDC to pay were identified as the key economic variables impacting the credit risk on these receivables. The Group considers both quantitative and qualitative indicators in classifying the receivables into the relevant stage for impairment calculation:

· Stage 1 includes receivables that are less than 30 days past due for which OPCOM concurrence has been obtained (Performing).

· Stage 2 includes receivables that have been assessed to have experienced a significant increase in credit risk using the days past due criteria (i.e. the outstanding receivables amounts are more than 30 days past due but less than 365 days past due) and other qualitative indicators such as the increase in political risk concerns or other micro-economic factors and the risk of legal action, sanction or other regulatory penalties that may impair future financial performance.

· Stage 3 receivables are receivables that have been assessed as being in default (i.e. receivables that are more than 365 days past due) or there is a clear indication that the imposition of financial or legal penalties and/or sanctions will make the full recovery of indebtedness improbable.

B) Trade receivables - $8,121,000 (2017: $nil)

Crude from the OML40 asset is exported via pipeline to the Forcados oil terminal with the revenue being derived from an offtake contract with Shell Western. The full balance of trade receivables is with Shell Western. The outstanding receivable balance at the 31 December 2018 reflects the crude lifting in the month of December 2018, which was received in January 2019 when contractually due. Although 90% of this balance has been factored and cash received at 2018 year end the Group retains the credit risk and therefore the full receivable balance has been included above.

The Group applies the IFRS 9 simplified model for measuring expected credit losses (ECL) which uses a lifetime expected loss allowance and are measured on the days past due criterion.

Having reviewed past payment performance combined with the credit rating of Shell Western in order to assess the potential for impairment, the Group has concluded this to be insignificant as there has been no history of default or disputes arising on invoiced amounts since inception of the contract in 2012 and as such the credit loss % is assumed to be almost zero.

Market risk

The Group's activities expose them primarily to the financial risks of changes in foreign currency exchange rates. There has been no change to the Group's exposure to market risk or the manner in which these risks are measured and managed.

Foreign currency sensitivity analysis

Although the Group reports in US dollars, elements of its business are conducted in sterling and Nigerian naira. The current exposure to foreign currency risk is manageable due to the predictability of transactions in these currencies. A reasonably possible exchange rate variance based on historical volatility and the impact on the financial statements are presented below.

If the US Dollar had strengthened by 10% against sterling, with all other variables held constant, post tax profit for the year would have been $913,000 lower mainly as a result of differences of translation of sterling denominated expenditure at lower rates of exchange.

If the US Dollar had weakened by 10% against sterling, with all other variables held constant, post tax profit for the year would have been $1,115,000 higher mainly as a result of translating Sterling denominated expenditure at higher rates of exchange.

If the US Dollar had strengthened by 10% against naira, with all other variables held constant, post tax profit for the year would have been $2,556,000 lower mainly as a result of translating naira denominated expenditure at higher rates of exchange.

If the US Dollar had weakened by 10% against naira, with all other variables held constant, post tax profit for the year would have been $3,123,000 higher as a result of translating naira denominated expenditure at lower rates of exchange.

Interest rate risk management

As the Group utilises the RBL it will become exposed to potential adverse movements in the US Dollar LIBOR component of the rate. Based on existing borrowings of $50 million and a reasonably possible interest rate variance at 31 December 2018, a 1.0 percent change in average interest rates over a 12-month period would increase or decrease net income or loss by approximately $500,000.

Foreign currency risk management

The Group's income, borrowings, and the majority of its costs, are denominated in US dollars. The remainder of the costs are denominated in other currencies, predominantly sterling and Nigerian naira. The Group also has foreign currency denominated assets and liabilities. Exposures to exchange rate fluctuations therefore arise. The Directors currently believe that foreign currency risk is at an acceptable level.

Liquidity risk management

Liquidity risk is the risk that the Group will encounter difficulty in meeting its financial obligations as they fall due. Ultimate responsibility for liquidity risk management rests with the Board of Directors. In order to mitigate this risk, management regularly reviews liabilities to ensure these can be met as and when they fall due.

The Group manages liquidity risk by maintaining adequate cash reserves and reserve borrowing facilities and by continuously monitoring forecast and actual cash flows. Details of undrawn facilities that the Group has at its disposal to further reduce liquidity risk are set out in Note 4.3. Additionally, at the end of the reporting period the Group held deposits at call of $40,640,000 (2017: $35,637,000) that are expected to readily generate cash inflows for managing liquidity risk.

Fair value of financial instruments

The Directors consider that the carrying amounts of financial assets and financial liabilities approximate their fair values, unless otherwise stated.

Maturity of financial assets and liabilities

All of the Group's financial assets as at 31 December 2018 are receivable within one year. On this basis, no maturity analysis has been disclosed.

All of the Group's financial liabilities are payable within one year with the exception of the RBL. The following table as at 31 December 2018, for the years 2019 through 2023 and thereafter, shows the maturities of the Group's undiscounted financial liabilities inclusive of any interest and fees associated with the RBL:

Under the terms of the RBL amounts repayable are first to be held in restricted accounts for principal and interest due up to six months prior to the repayment dates.

In comparison the following table as at 31 December 2017, for the years 2018 through 2021 and thereafter, shows the maturities of the Group's undiscounted financial liabilities inclusive of any interest and fees associated with the RBL (all of the Group's financial liabilities were payable within one year with the exception of the RBL):

Financial facilities

Loan facility

The Group has a loan facility with Stanbic IBTC Bank PLC and the Mauritius Commercial Bank Ltd. Details are given in Note 4.3.

4.8 Derivative financial instruments

The accounting policy for crude oil hedges is covered in Note 4.7 g) Derivatives.

The Group uses its derivatives for economic hedging purposes and not as speculative investments. However, where derivatives do not meet the hedge accounting criteria they are accounted for at fair value through profit and loss. They are presented as current assets.

The derivative financial instrument of $4,682,000 (2017: nil) as at 31 December 2018 is as a result of a fair value gain on crude oil hedges. The fair value has been determined using an externally sourced pricing model which generates results from inputs.

Fair value hierarchy

As at the reporting period, the Group had classified the derivative financial instruments into the three levels prescribed under the accounting standards. There were no transfers of financial instruments between fair value hierarchy levels during the year.

Level 1 - Quoted (unadjusted) market prices in active markets for identical assets or liabilities.

Level 2 - Valuation techniques for which the lowest level input that is significant to the fair value measurement is directly or indirectly observable.

Level 3 - Valuation techniques for which the lowest level input that is significant to the fair value measurement is unobservable.

The fair value of the financial instruments is included at the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

4.9 Contingent liabilities

JOA accruals

Under the OML 40 Joint Operating Agreement ('JOA'), the Group is responsible for its share of expenditures incurred on OML 40 in respect of its participating interest, on the basis that the operator's estimated expenditures are reasonably incurred based on the approved work programme and budget. From time to time, management disputes such expenditures on the basis that they do not meet these criteria, and when this occurs management accrues at the period end for its best estimate of the amounts payable to the operator. Consequently, the amounts recognised as accruals as at 31 December 2018 reflect management's best estimate of amounts that have been incurred in accordance with the JOA and that will ultimately be paid to settle its obligations in this regard. However, management recognise there are a range of possible outcomes, which may be higher or lower than the management estimate of accrued expenditure. It is estimated that around $40,700,000 (2017: $6,700,000) of possible expenditure currently remains under dispute.

The movement from the prior year is driven by a number of changes including the construction of a 36km pipeline from the Opuama field to the Custody Transfer Point at Otumara. The construction of the pipeline was clearly in violation of the JOA, nonetheless, OML 40 crude has been transported through the pipeline since August 2018. The Group recognises as a user of the pipeline it should accrue for the transportation of its crude via the new pipeline and has done so since August 2018 accruing $1,825,000 at year-end. It is possible, provided it is commercially advantageous, that Elcrest may elect to make a capital contribution to become a joint owner of the pipeline. If this were to occur a capital contribution would be payable to NPDC (which would impact the property, plant and equipment balance), but correspondingly, future transportation costs would be reduced. Management's best estimate of the maximum that could become payable is included within the $40,700,000 above.

Wester Ord production bonus

The Group's subsidiary Wester Ord Oil & Gas (Nigeria) Limited may become, subject to certain conditions, ultimately liable to pay a production bonus of $3,000,000 to All Grace Energy Limited in respect of the transfer of a 40% interest in the Ubima Field. The payment is contingent on both receiving Nigerian Ministerial Consent to the transfer and attaining production volume of 2,000 barrels gross of crude oil per day on average over a 30-day period. Although an extended well test was approved by the DPR in November 2018 to test the E1000/E2000 reservoirs following the successful Ubima appraisal well, full Field Development Plan ('FDP') has not been requested or approved, therefore management still consider the asset to be in Exploration and Evaluation stage. The production milestone, Nigerian Ministerial Consent and DPR approval are not within the control of the Group and further, it is not uncommon in the oil and gas industry for these contingent events/milestones not to be achieved on any given E&E project. On this basis management has disclosed this amount as a contingent liability, but do not consider payment of the amount to be probable.

Section 5 - Taxation

This section highlights the Group's taxation policies, including both the accounting policy and wider strategy and governance policies. Analysis is provided of the Group's income statement charges and credits and deferred tax movements through the balance sheet.

Accounting policy

The total tax charge or credit represents the sum of current tax and deferred tax.

Current tax

The current tax credit is based on the taxable profit or loss for the year. Taxable profit or loss differs from net profit or loss as reported in the income statement because it excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible.

Deferred tax

Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the balance sheet liability method. Deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised.

The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.

Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled, or the asset is realised based on tax laws and rates that have been enacted or substantively enacted at the balance sheet date. Deferred tax is charged or credited in the statement of comprehensive income, except when it relates to items charged or credited in other comprehensive income, in which case the deferred tax is also dealt with in other comprehensive income.

Critical accounting estimate - Recoverability of deferred tax asset

Assumptions and judgements were used to determine the probability that deferred tax assets recognised in the financial statements will be recovered from taxable income in future years. The calculations involve judgements in two key areas:

• Utilisation of available taxable losses; significant estimates are required in determining future phasing of the capital and operating programme, oil prices, production profile, and the resulting cash flows.

- Management have assumed $60/bbl flat oil price in estimating the utilisation of taxable losses. If oil prices were +/-10% this would have no impact on the deferred tax asset.

- Probable value of losses; the valuation requires judgement regarding whether differences may arise between the value of tax losses submitted in tax computations and ultimately what may be agreed by the taxation authorities in Nigeria.

- The key sensitivity in valuing tax losses is the financing charges between Group companies. Inter-Group financing charges have ranged between 12-18%. Using the interest range, on average a +/-1% adjustment in the interest rate applied on Group financing would have impacted the deferred tax asset by +/-$10,700,000.

The standard rate of tax for the year is 65.75% (2017: 65.75%), being the current applicable rate of Nigerian Petroleum Profits Tax. The total tax credit can be reconciled to the loss per the consolidated statement of comprehensive income as follows:

5.2 Deferred tax asset

The following is the deferred tax asset recognised by the Group and movements thereon during the current and prior reporting years.

Pioneer tax relief

When granted, Pioneer tax relief provides relief from Petroleum Profits taxes. Pioneer status is granted by the Nigerian Investment Promotion Commission ('NIPC') upon approval of applications in line with Section 2 of the Industrial Development (Income Tax Relief) Act ('IDITRA'). Elcrest made an application for Pioneer tax relief with effect from 1 May 2014 for the five-year period, covering both the initial period of three years and extended period of a further two years. Elcrest fully complied and provided NIPC with the necessary information requirements and projections for the 5-year period, as well as, made payment of the fees based on potential tax savings for the five-year period. Consequently, the Company was not required to submit an extension application.

Federal Inland Revenue Service ('FIRS') acknowledged the five-year pioneer period granted to Elcrest in 2014. NIPC can restrict the Pioneer period to a 3-year term if the Pioneer company does not fulfil the conditions stated in Section 10(3) of IDITRA. Given that Elcrest has fully complied with the Pioneer requirements and furthermore, issued a reconfirmation letter in 2017 notifying NIPC of such compliance it therefore continues to benefit from Pioneer status. Elcrest has submitted tax computations to FIRS under the basis Pioneer status continues and will do so until the end of the five-year period, which expires on 30 April 2019.

Net aggregate tax losses arising in the Pioneer period, in addition to losses generated prior to Pioneer, are available for carry forward to offset against taxable profits arising in future periods. There is no time restriction in the utilisation of these losses.

Deferred tax

As at 31 December 2018, the Group has taxable trading losses of $332,750,000 (2017: $327,611,000). Elcrest accounts for the majority of these tax losses totalling $302,047,000 (2017: $307,844,000). Following a significant increase in production and profitability during 2018, the Group reviewed previously unrecognised tax losses and determined that it was now probable that taxable profits will be available against which the tax losses can be utilised. Consequently, a deferred tax asset on the expected usable pool of brought forward tax losses (of $82,363,000) which can be offset against the current and future taxable profits has been recognised at year end.

The Group has also recognised a deferred tax asset of $29,488,000 as at 31 December 2018 (2017: $12,436,000) in relation to the temporary difference that arises between the net book value and the tax written down value of the oil and gas assets. Capital allowances can be deferred during the Pioneer tax relief period and will be available following the tax relief period, whilst the book value of the asset is depreciated following commencement of production.

On expiry of Pioneer tax status and following the full utilisation of available tax losses and $269,405,000 (2017: $207,869,000) of capital allowances, Elcrest is expected to be paying tax at 65.75% for five years and at 85% thereafter. The quantum of losses reported above represent amounts submitted to the Nigerian tax authorities although is subject to agreement.

5.2 Deferred tax asset

State Aid investigation (Contingent liability)

In October 2017 the EU Commission opened a formal State Aid investigation into an exemption within the UK's Controlled Foreign Company ('CFC') regime. The investigation is ongoing, but if the Commission ruled that the provisions do constitute State Aid they may require the UK to recover any such aid from affected parties. Similar to other UK-based international companies, the Group has claimed the benefit of this exemption and could be adversely impacted by the outcome of the investigation.

There is considerable uncertainty regarding a number of related issues; the outcome of the EU investigation, the impact Brexit may have on the enforceability of the ruling, whether the UK government would appeal against the ruling, and finally whether the Group would appeal against the ruling. Currently, in view of the uncertainty as to the final outcome, the Group believes no provision is required in respect of this issue. Additionally, given the various uncertainties at this stage in the investigation, management's view is that any numerical disclosures on the possible impact of this on the Group is unlikely to give users useful information concerning the potential outflow.

Section 6 - Capital structure and other disclosures

This section includes details of Eland's issued share capital and equity reserves.

Other disclosures include details on auditors' remuneration.

Each new voting ordinary share has the same rights and benefits as the existing voting ordinary shares.

Deferred shares do not entitle holders to receive notice of or attend and vote at any general meeting of the Company or to receive a dividend or other distribution or to participate in any return on capital on a winding up or other than the nominal amount paid on such shares following a substantial distribution to the holders of ordinary shares in the Company. As such the deferred shares do not form part of the calculation of earnings per share.

Share premium

No issuance of new ordinary shares was carried out in 2018. Share Premium therefore reflects the differential of the placing price against the share capital price along with associated costs in respect of the issuance of new ordinary shares in the prior year.

Other reserve

This reserve relates to costs incurred on funds raised on AIM in 2012.

Retained earnings

Treasury shares

On 19 November 2018 Eland announced a share buyback programme for a maximum aggregate consideration of up to £3,000,000 (the 'Programme'). As at 31 December 2018 the Company had purchased 957,000 shares for a consideration of $1,372,000 (GBP £1,037,900 representing an average price per share of £1.08). Eland expects to complete the planned Programme by the end of the first quarter in 2019.

Translation Reserve

Prior to 1 January 2013 exchange differences relating to the translation of the net assets of the Company from its functional currency (sterling) into the Group's presentation currency, US dollars, were recognised directly in the translation reserve. From 1 January 2013, the Company's functional currency changed to US dollars. As a result, there is no movement on the reserve in the current year or the prior year.

Non-Controlling Interests

Summarised financial information in respect of each of the Group's subsidiaries that has a material non-controlling interest is set out below.

The summarised financial information below represents amounts before intra-group eliminations.

Elcrest Exploration and Production Nigeria Limited

6.2 Capital management

The objective of the Group's capital management structure is to ensure sufficient liquidity exists within the Group to carry out committed work programme requirements. The Group monitors both short and long-term cash flow requirements of the business in order to assess the requirement for changes to the capital structure to meet that objective and to maintain flexibility.

Eland manages the capital structure and may make adjustments in light of opportunities available or changes to economic conditions. To maintain or adjust the capital structure, Eland may issue new shares for cash, buy back shares, return capital, repay debt, put in place new debt facilities or undertake other such restructuring activities as appropriate. No significant changes were made in the objectives, policies or processes during the year ended 31 December 2018.

The capital structure of the Group includes debt drawn down from the RBL of $50,000,000 as at 31 December 2018 (2017: $27,000,000). Equity attributable to equity holders of the parent comprises issued capital, share premium, reserves and retained earnings as disclosed in Note 6.1.

Under the terms of the borrowing facility, the Group is required to comply with the following financial covenants:

• The ratio of net debt to EBITDAX must not be greater than 3:1;

• The ratio of projected net revenues to the sum of financing costs and principal repayments for the subsequent 12 month period (the projected debt service cover ratio) shall be not less than 1.1:1, and not less than 1.25:1 when opening cash is added to net revenues.

The Group has complied with these covenants throughout the reporting period.

The other assurance services provided in both years relate to non-audit procedures on the interim financial statements performed by PwC.

6.4 Post balance sheet events

Increase to RBL

In March 2019, the Company announced an increase in the Reserve Based Lending ('RBL') facility from $75 to $125 million. At the same time the lenders agreed a borrowing base increase from $103 million to $134 million. See Note 4.3 for further details.

Repayment of trade receivables amounts owed by NPDC

On 14 January 2019 Elcrest's government partner in OML40, NPDC remitted $19.3million to Elcrest thereby fulfilling its commitment to fund its share of drilling expenditure on the first two OML 40 wells invoiced by Elcrest in October 2018. This was the first such recovery from NPDC and represents an important milestone in completing the funding mechanism cycle where Elcrest initially funds the drilling programme prior to NPDC reimbursement for its equity share.

Dividend proposal

In February 2019, the Company announced it plans to pay an ordinary dividend based on the Group's free cash flow generation, whilst ensuring an appropriate balance between investment in its business and operating within its debt and banking facility. It is expected that the maiden dividend will be declared for the year ended 31 December 2019 and will be payable semi-annually, split between the interim and final dividend (1/3:2/3).

Company Balance Sheet as at 31 December 2018

The Company only profit for the year after tax was $5,538,000 (2017: $7,793,000). The notes form part of these financial statements.

The financial statements of Eland Oil & Gas PLC, registered number SC 364753, contained on pages 113 to 120 were approved by the Board of Directors on 19 March 2019 and signed on its behalf by:

George Maxwell Ron Bain