Eland Oil & Gas Regulatory News (ELA)

11 September 2019

Eland Oil & Gas PLC

("Eland" or the "Company" and, together with its subsidiaries, the "Group")

Interim Results for the six months to 30 June 2019

Eland Oil & Gas PLC (AIM: ELA), an oil & gas development and exploration company operating in West Africa with an initial focus on Nigeria, today announces its unaudited financial results for the six-month period to 30 June 2019 (the "Period").

George Maxwell, CEO of Eland, commented:

"The diversification of production from our second oil field, Gbetiokun, represents a significant moment for the Company as we generate material production and operational cash-flow. In the second half, we are excited to drill the high-impact, 78 million barrel, near-field Amobe prospect. The Amobe prospect represents the first pure exploration well in the company's history and the first on OML40 since 1991. We look forward to updating all stakeholders on these developments in the remainder of the year."

H1 2019 HIGHLIGHTS

Sustained operational delivery

·; Net production from OML 40 achieved an average 9,948 bopd (22,106 gross) during the six-month period to 30 June 2019 in comparison to 7,716 bopd in H1 2018 (17,146 gross), an increase of 29%, with Opuama average uptime of 90% for the Period

·; Liftings in Period of 1,599,000 bbls (H1 2018: 976,000bbls) 

·; The first two Gbetiokun development wells were successfully flow tested with cumulative rates up to 5,400 bopd net (12,000 gross). The Gbetiokun Field Development Plan ("FDP"), which was updated following the drilling of the Gbetiokun-3 appraisal/development well has been approved by the Department for Petroleum Resources (DPR)

·; Dredging activities to allow rig access for Eland's first Exploration well on the Amobe prospect continued during H1 2019. The high-impact, near-field prospect is planned to be drilled in the second half of 2019

·; Updated Competent Person's Report ("CPR") for OML 40 in March 2019 increased gross Proved ("1P") reserves by 8% and decreased Proved plus Probably ("2P") reserves by 1%, despite record production of approximately 6.5 million barrels ("mmbbls") of oil (gross) in 2018

·; Performance of the OES Teamwork drilling unit continues to be the key operational issue during 2019. Production capacity growth has been adversely affected by the OES Teamwork drilling unit performance.

·; Following success of the Ubima-1 re-entry operations in 2018, updated CPR for the Ubima Field in March 2019 increased gross 1P reserves over sevenfold to 6.2 mmbbls and increased 2P reserves almost fourfold to 9.3 mmbbls 

·; Medical outreach programme undertaken within OML40 as part of the Group's ongoing environmental, social and governance ("ESG") effort

 Record financial performance

·; Record revenues of $106.0 million (H1 2018: $67.4 million) with an average realised price of $66/bbl (H1 2018: $69/bbl)

·; Operating cash flow before movements in working capital risen to $59.1 million (H1 2018: $50.6 million)

·; Operating profit sustained at $40.0million (H1 2018 $39.1 million) 

·; Net capital investment of $79m includes an accrual for capital expenditure for Elcrest share in a new 36km 16" Export Pipeline between Opuama and Otumara, with a capacity of over 100,000 bbls per day. The investment in the line demonstrates the joint venture's long-term commitment following the 20-year extension to the OML40 licence in 2018.

·; Non diluted Earnings per share ("EPS") rose to $0.12 per share (H1 2018: $0.08)

·; Net debt at period-end $30.9 million (H1 2018 $4.3 million net cash) with $60 million headroom available from Reserve Based Lending ("RBL") Facility

·; RBL borrowing base expanded to $135 million following re-determination

Shareholder returns

·; Maiden interim dividend declared of 1 pence per share representing an approximately $2.6 million return to shareholders. The dividend will be payable on 31 October 2019 to shareholders on the register at the close of business on 18 October 2019

·; Ongoing share buyback programme increased by a further £3.0 million on 20 March 2019 to a maximum of £6.0 million. Since commencing the Programme in November 2018 Eland has purchased 4,363,573 shares at a cost of £5.3 million, representing an average price of approximately 120 pence per share

Post-Period End - continued delivery

·; Successful start-up of Gbetiokun EPF on 31st July, initially with two wells, Gbetiokun-1 and -3, with production rates between 11,000 and 12,000 bopd achieved.

·; Third Gbetiokun development well, Gbetiokun-4, successfully completed the drilling phase in September, with the well significantly exceeding pre-drill expectations. A 60ft core was successfully obtained in the E5000 reservoir. The E5000 and E7000 reservoirs had total net pay thicknesses of approximately 63 feet and 49 feet TVD respectively. The secondary target reservoir, E3000, encountered 48 feet TVD of net pay. See separate announcement for further details

Outlook

·; Performance of the OES Teamwork drilling unit continues to be the key operational issue during 2019. Production capacity growth has been adversely affected by the OES Teamwork drilling unit performance. Resultant delays in our drilling sequence have pushed back on-stream dates for Gbetiokun-4 and -5. The Company has a number of Opuama workover activities in progress to offset the delay in bringing Gbetiokun production on stream.

·; Drilling will continue at Gbetiokun during H2 2019 with Gbetiokun-5 being drilled following completion of Gbetiokun-4. Following completion of Gbetiokun-5 net average production from Gbetiokun is expected to be between 9,000 to 9,900 (20,000 - 22,000 bopd gross). We maintain our production guidance.

·; Outstanding rig upgrade activities are planned to be completed ahead of drilling Gbetiokun-5

·; The high-impact, near-field Amobe prospect is planned to be drilled in H2 2019. Amobe carries Unrisked best estimate Gross Prospective Oil Resources of 78.4 million barrels

·; Completion of the Gbetiokun-4 well is expected at the end of September with production commencing through the recently commissioned EPF immediately thereafter.

·; Excluding the impact of the non-cash accrual for the export pipeline the Company maintains its capex guidance at $80-$90 million.

·; Options for an additional rig are currently being matured

·; Ubima extended well test ("EWT") operations expected to commence in H2 2019. Flow testing for reservoir characterisation will focus on the E1000/E2000

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 / Tom Huddart / Monique Perks

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 OML 40 which is located in the Northwest Niger Delta approximately 75km northwest of Warri and has an area of 498km². In addition, the Company has a 40% interest in the Ubima Field, onshore Niger Delta, in the northern part of Rivers State.

The entire OML 40 licence holds gross 2P reserves of 82.2 million barrels ("mmbbls"), gross 2C contingent resources of 50.7 mmbbls and a best estimate of 252.1 mmbbls of gross unrisked prospective resources (NSAI Competent Person's Report of 31 December 2018). The Ubima field holds gross 2P reserves of 9.3 mmbbls and gross 2C resource estimates of 4.2 mmbbls (NSAI Competent Person's Report of 31 December 2018)

* 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.

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.

The information contained within this announcement is deemed to constitute inside information as stipulated under the Market Abuse Regulations (EU) No. 596/2014. Upon the publication of this announcement, this inside information is now considered to be in the public domain.

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

REVIEW OF H1 ACTIVITIES

Development of the OML 40 licence continues to progress with the Opuama oil field maintaining reliable operations, production has been diversified in 2019 with the ongoing development of the Gbetiokun field and final preparations for the Amobe exploration well later this year which will be the first exploration well on the licence since 1991.

Production

OML 40 production, previously only from Opuama field, saw H1 2019 contributions from the Gbetiokun field, with well testing on Gbetiokun-1 and -3 wells where the produced crude was captured and transported to Opuama for injection into the 16" export line.

Gross production from OML 40 achieved an average 22,106 bopd (9,948 net) during the six-month period to 30 June 2019, compared to 17,146 bopd in H1 2018 (7,716 net): an increase of 29%. With the exception of 18 days of planned maintenance flowstation shutdown in Feb/Mar only 3.75 hrs of down time have been recorded in H1 2019. Overall this represents a 90% uptime compared to 87% for the same period in 2018.

With the OES Teamwork drill rig focussed on the Gbetiokun development, no additional wells have been drilled in the Opuama field since the Opuama-11 which started production in Q4 2018. Whilst additional rig opportunities are being matured, the focus at Opuama during H1 2019 has been on maintaining stable, reliable production and execution of simple interventions that do not require a rig. To that end, the lower D2000 perforations on Opuama-7, which had watered out, were successfully plugged off to improve recovery from remaining D2000 perforations.

The new LACT Unit at Otumara, installed during H1 2018, was successfully commissioned during Q4 2018 and has been fully operational during H1 2019. As a direct consequence, average monthly allocation losses were 7% for H1 2019 compared to 11% for the same period last year.

OML 40: Opuama Reservoir Management

Following the completion of the Opuama-11 well in Q3 2018, OML 40 drilling operations have been focussed on the Gbetiokun development. On Opuama, this has provided an opportunity to fully assess the new well and production data acquired over the last 18 months. The subsurface team, which was significantly expanded during H2 2018, has successfully remodelled the multiple reservoirs at Opuama to support ongoing reservoir management operations and identify additional opportunities and confirms through history matching that the production performance remains within expectation. These new opportunities will be further matured during H2 2019 with an expectation to commence drilling during 2020.

OML 40: Gbetiokun Development

Following the drilling of Opuama-11, the OES Teamwork rig moved to the Gbetiokun field in H2 2018. Initially it re-entered and completed the Gbetiokun discovery well (Gbetiokun-1) followed by the drilling of Gbetiokun-3 which is part of the initial phase of the field development plan. Drilling & completion operations on Gbetiokun-3, which had a number of appraisal objectives including obtaining fluid samples for a number of key reservoir zones, were completed in Q1 2019 after which the drill rig stood down for a period of planned maintenance and upgrade.

The OES Teamwork drilling unit continues to be upgraded as activities were delayed, primarily due to contractor supply chain challenges leading to substantial delays and work carry-over. During the rig shutdown period the Gbetiokun-1 and -3 wells were successfully flow tested with flow rates in line with pre-drill expectations.

Gbetiokun-1 was completed as a dual string producer on the E2000 (short string) and E6000 (long string). The short string flowed 4,000 bopd of oil on a 32/64th choke. When the long string was flow tested it confirmed expectations of limited fluid flow behind casing due to poor cementing during the initial drilling in 1987. As a consequence, whilst the string has good deliverability, it produces some early water on higher choke settings. However, flow testing demonstrated this string will produce 2,800 bopd oil on a 36/64th choke.

Gbetiokun-3 is also completed as a dual string producer; the short string is open to the D9000 whilst the long string is open to the E4000. Following the initial completion operations in Q1 2019 a small pressure leak in the completion meant the short string could not be produced. During Q2 2019, intervention logging successfully located the leak point which was repaired by installing a tubing patch. The short string subsequently flowed dry oil at 3,880 bopd on a 36/64th choke whilst the long string flowed dry oil at 3,000 bopd on a 36/64th choke.

Approximately 300,000 barrels were produced by these two wells during the flow test period. All the oil from the Gbetiokun-1 and -3 flow tests was captured and shipped to the Opuama flowstation to be injected into the OML 40 16" export line.

During H1 2019 the additional information gathered from the Gbetiokun-3 well was incorporated into an updated Field Development Plan (FDP) which was approved by the Department of Petroleum Resources (DPR).

In parallel with the flow testing operations the installation of the Gbetiokun Early Production Facility (EPF) was being finalised. At the end of the period the production facilities were onsite and being hooked up ready for an early Q3 start up. Initial start-up rates in Q3 2019 have been approximately 12,000 bopd gross (5,400 bopd net).

The approved FDP outlines that oil export will initially be by ship to the Benin River Valve Station where the oil will be injected into the OML 40 export pipeline to the Forcados oil terminal. In the medium term, oil export will be by a planned new pipeline to the Adagbassa Manifold, from where the oil will be injected into the Forcados system.  

During H2 2019, two further development wells including Gbetiokun-4 and -5, will be completed allowing production rates to reach between 20-22,000 bopd gross (9,000 - 9,500 net) from the field.

OML 40: Exploration

During H1 2019, Eland has been undertaking planned dredging activities to allow rig access for the drilling of the Amobe exploration prospect. These activities will be completed in H2 2019. The Amobe prospect represents the first pure exploration well in the company's history and the first on OML40 since 1991. The prospect is a large, relatively low-risk opportunity located only 6km from the Opuama Flow-Station allowing for an accelerated development tied back to existing facilities. The Amobe structure is similar to Opuama and on an adjoining fault terrace. NSAI currently carries estimates for the Amobe prospect of 15 -78 -340 million stock tank barrels ("MMstb") on a low/best/high estimate basis with a probability of success of 42%.

OML 40: Medical Outreach Programme

As part of Eland's ongoing environmental, social and governance ("ESG") efforts in-country, the Company initiated a medical outreach programme for Opuama town. This involved over 50 medical staff spending 5 days in Opuama town, treating over 5,000 adults and children. Eland remains committed to the wellbeing of our employees and communities.

CPR

Despite producing approximately 6.5 mmbbls of oil (gross) in 2018, an updated Competent Person's Report ("CPR") for OML 40 in March 2019 increased gross Proved ("1P") reserves by 8% to 42.9 mmbbls. Additionally, the CPR only decreased OML 40 gross 2P reserves by 1% to 82.2 million barrels.

This OML 40 revision was principally as a result of the 2018 drilling campaign on Opuama which confirmed and accessed additional oil reserves in the field.

Ubima

Following the 2018 re-entry of the Ubima-1 well and the flow testing on a number of different reservoir levels the Ubima partnership has obtained permission from the DPR to conduct an Extended Well Test ("EWT") on the target E1000/E2000 reservoir for the proposed development to confirm fluid flow characteristics. This will allow the reservoir model to be fine-tuned and the resulting development design to be optimised. During H1 2019 works to install the facilities to undertake this EWT, including the ability to store, transport and inject the produced hydrocarbons, have been undertaken.

A CPR published in March 2019 by NSAI increased gross 1P reserves over sevenfold to 6.2 mmbbls and increased 2P reserves almost fourfold to 9.3 million barrels. Those reserves sit principally in the E1000 and E2000 reservoirs which will be the focus of the H2 2019 EWT.

Financial Review

The financial performance was underpinned by a continued increase in production combined with a stable operating environment and excellent infrastructure uptime of over 90% between the OML40 workstation and the export terminal at Forcados. The liftings net to Elcrest of 1,598,000 bbls in the Period (H1 2018: 976,000bbls) generated revenue of $106.0 million (H1 2018: $67.4 million). The commodity environment remained stable with the average realised price of over $66/bbl achieved in the Period, a marginal reduction from the $69/bbl in H1 2018.

Excluding the impact of non-cash items, underlift and depreciation, operating expenses were $42.8 million in the Period (1H 2018: $32.7 million). The increase resulted from the addition of Gbetiokun pre-production operating costs during the extended well test.

H1 2019 net Capex at $79m includes an accrual for capital expenditure for Elcrest share in a new 36km 16" Export Pipeline between Opuama and Otuamara. Outside of the accrual for the Pipeline capital expenditure is as per guidance.

The new 16" Pipeline has capacity of over 100,000 bbls per day and replaces the aged and smaller previous 12" line. The investment in the line demonstrates the joint venture's long-term commitment following the 20-year extension to the OML40 licence in 2018. With the switch to this line in H2 2018 and the inclusion of the LACT at Otuamara we have seen a reduction in losses recorded between the Flowstation and the LACT which for H1 2019 amounted to less than 3%.

Exploration and Evaluation spend totalled $13.7 million; including $9.1 million on OML 40 principally in relation to access and clearing required to enable rig access to the Amobe drilling location planned for the second half of 2019. A further $4.6 million was invested in Ubima with facilities now in place to commence first production in the second half of 2019.

Development and Production expenses totalled $65.6 million; this included the pipeline accrual as mentioned above. Further development drilling expenditure was incurred with the completion of the Gbetiokun-1 and Gbetiokun-3 wells in the Period. Together with the Early Production Facility ("EPF") and other facilities infrastructure enabled first production to be achieved at Gbetiokun in the Period.

Administrative expenses fell to $1.8 million (H1 2018: $3.6 million). The reduction reflects an increased allocation of costs to capital and operational support projects.

Net finance costs rose to $7.8 million (H1 2018: $2.6 million). Excluding the non-cash mark-to-market hedging adjustment recorded in the Period net finance costs were $4.0 million (this adjustment reversed a non-cash gain recorded in 2018). The higher finance costs compared to the prior year reflected higher loan balances in the Period compared to the corresponding period in 2018.

Taxation was a credit of $0.5 million primarily reflecting the timing difference between the depreciation charges and the usage of capital allowances partially offset by current taxes and the utilisation of tax losses following Elcrest exiting Pioneer status with effect from 1 May 2019.

Balance Sheet

The group maintained a working capital surplus of $0.3 million at Period end despite the record capital investment, compared to a deficit of $17.1 million in the corresponding period in 2018. Working capital includes a net receivable balance of $24.4 million with NPDC with the reduction in the balance comprising the capital contribution for the 36km pipeline together with a cash call receipt of $19.3 million received in the Period. This was partially offset by the receivables due on the ongoing Gbetiokun drilling and facility capital programme.

Eland has continued with the share buyback programme announced in November 2018. During the Period it purchased shares equating to $4.0 million (£3.1 million). As at the reporting date, the group had completed £4.2 million ($5.4 million) of its £6 million buyback programme.

Cash flow

Operating cash flow in the Period before movements in working capital was $59.1 million (H1 2018: $50.6 million), equating to a cash flow margin of approximately $37/bbl on every barrel sold in the Period.

The cash flow generated was principally used for investment activities totalling $47.5 million (2018: $18.5 million) as detailed above. The difference between the accrued capital expenditure of $79.3 million quoted above and the cash investment is largely due to the fact the pipeline expenditure originally incurred by our partner, NPDC, has been accrued with no cash outlay.

In addition, settlement of working capital balances totalled $30.1 million in the Period (H1 2018 $38.1 million).

A hedging programme was executed for 645,000 bbls with a blended strike price of $53/bbl in H2 2019.

The group entered a 5-year Reserve Based Lending Facility ("RBL") secured against the Group's producing assets in November 2018. The facility has an initial borrowing base of $125 million from existing OML40 producing wells and includes an accordion to allow for expansion of the facility up to $200 million. $15 million was drawn against this facility in the reporting Period taking total borrowings to $65 million, and therefore $60 million headroom available at Period end.

Outlook

In the second half of 2019, the Company looks forward to continuing our near-term development and monetisation strategy through continued delivery from Opuama and Gbetiokun supplemented by the exploration of the Amobe prospect. The Company intends to deliver shareholder value growth through operational performance, our exciting near field expoloration and our capital returns and dividend policy.

CONDENSED CONSOLIDATED INTERIM STATEMENT OF COMPREHENSIVE INCOME

There were no items of comprehensive income in the current or prior period/year, other than the profit for the period/year. The notes on pages 11 to 29 form part of these financial statements.

CONDENSED CONSOLIDATED INTERIM BALANCE SHEET

The notes on pages 13 to 31 form part of these financial statements. 

CONDENSED CONSOLIDATED INTERIM STATEMENT OF CHANGES IN EQUITY

The notes on pages 13 to 31 form part of these financial statements.

CONDENSED CONSOLIDATED INTERIM CASH FLOW STATEMENT

The notes on pages 13 to 31 form part of these financial statements.

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

1. BASIS OF PREPARATION

General information

Eland Oil & Gas PLC is a limited liability company incorporated in Scotland and listed on the AIM Market of the London Stock Exchange. The address of the registered office is 28 Albyn Place, Aberdeen, AB10 1YL, United Kingdom. The principal activities of the Company are oil and gas exploration and development, with a focus on West African opportunities for acquisition and development.

The condensed consolidated interim financial statements for the six months ended 30 June 2019 were authorised for issue in accordance with a resolution of the Board of Directors on 9 September 2019.

The information for the 6 months ended 30 June 2019 contained within the condensed consolidated interim financial statements does not constitute statutory accounts within the meaning of section 435 of the Companies Act 2006 but has been derived from those accounts. Statutory accounts for the year ended 31 December 2018 were approved by the Board of Directors on 19 March 2019 and delivered to the Registrar of Companies. The report did not contain any statement under section 498(2) or 498(3) of the Companies Act 2006.

The financial information contained in this report is unaudited.

Basis of preparation

The condensed consolidated interim financial statements for the six months ended 30 June 2019 have been prepared in accordance with IAS 34, "Interim financial reporting", as adopted by the European Union ("EU") and the AIM rules for Companies, on a going concern basis. The condensed consolidated interim set of financial statements included in this half-yearly financial report have been prepared in accordance with the accounting policies the Group intends to use in preparing its next annual financial statements and should be read in conjunction with the annual financial statements for the year ended 31 December 2018.

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 capex scheduling and hedging to ensure it has access to funding when required (including funding for items as per note 17 under a worst case scenario) and that it is compliant with its covenants.

Increased production from the continuing work programme, coupled with a relatively stable oil price, has seen operational cash flows increase significantly. Although risks and uncertainties remain as documented within the 2018 Annual Report on pages 39 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 the foreseeable future. For that reason, they continue to adopt the going concern basis in the preparation of the accounts.

1. BASIS OF PREPARATION (CONTINUED)

Accounting policies

The accounting policies applied in these condensed consolidated interim financial statements are consistent with those of the previous financial year and corresponding interim reporting period, except for the adoption of IFRS 16 Leases.

New and amended standards adopted by the group

A number of new or amended standards became applicable for the current reporting period, and the group had to change its accounting policies as a result of adopting IFRS 16 Leases. The impact of the adoption of the leasing standard and the new accounting policies are disclosed below and in Note 16. The other standards did not have any impact on the group's accounting policies and did not require retrospective adjustments.

IFRS 16 'Leases'

IFRS 16 Leases was issued in January 2016 and became effective for reporting periods beginning on or after 1 January 2019. It replaces the provisions of IAS 17 Leases and IFRIC 4 Determining whether an arrangement contains a lease.

The group has adopted IFRS 16 retrospectively from 1 January 2019 but has not restated comparatives for the 2018 reporting period, as permitted under the specific transitional provisions in the standard. The reclassifications and the adjustments arising from the new leasing rules are therefore recognised in the opening balance sheet on 1 January 2019.

The adoption of IFRS 16 has resulted in the recognition of "right to use" assets and corresponding financial liabilities for those leases that had been classified as an operating lease under IAS 17. The only exceptions are those leases deemed short-term and low value.

The impact of the adoption of this standard and the related new account policy are disclosed in note 16.

2. REVENUE

 An analysis of the group's revenue is as follows:

For both 2019 and 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 Supply and Trading Limited.

2. REVENUE (continued)

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. Please refer to the 2018 Annual Report for further details.

3. OPERATING EXPENSES

The analysis of operating expenses is as follows:

4. ADMINISTRATIVE EXPENSES

The analysis of administrative expenses is as follows:

5. FINANCE INCOME AND COSTS

6. PROFIT BEFORE TAX

7. TAXATION

The current tax charge relates to the impact of a change in UK tax rules with effect from 1 January 2019, whereby finance income profits accruing to a Controlled Foreign Company ("CFC") subsidiary which are attributable to UK Significant People Functions ("SPFs") no longer qualify for the Chapter 9 finance company exemption, and therefore may be subject to a UK CFC charge. A full SPF analysis has yet to be performed, although a preliminary estimate of the impact has been recorded in the Period.

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

As at 30 June 2019, the Group has taxable trading losses of $321,877,000 (31 December 2018: $332,750,000). Elcrest accounts for the majority of these tax losses totalling $287,961,000 (31 December 2018: $302,047,000). 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 tax losses can be utilised. Consequently, a deferred tax asset of $45,838,000 (31 December 2018 $54,154,000) has been recognised in respect of these losses.

7. TAXATION (continued)

The Group has also recognised a deferred tax asset of $39,898,000 as at 30 June 2019 (31 December 2018: $29,488,000) 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 were deferred during the Pioneer tax relief period and are now available for utilisation following the end of the tax relief period, whilst the book value of the asset has been depreciated following commencement of production.

The Group exited Pioneer status in May 2019. Following full utilisation of the available tax losses mentioned above of $287,961,000 and capital allowance of $335,755,000 (31 December 2018: $269,405,000) Elcrest will be liable to tax at 65.75% for five years and at 85% thereafter. There is no time limit to the utilisation of these losses although the quantum of the losses are subject to agreement with the Nigerian tax authorities. The June 2019 tax losses reflect the submitted year-end 2018 computations and an estimate for taxable losses and capital allowances incurred in the Period.

8. EARNINGS PER SHARE

From continuing operations

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

8. EARNINGS PER SHARE (continued)

9. INTANGIBLE OIL AND GAS ASSETS

The Group's oil and gas exploration and evaluation assets at 30 June 2019 relate to the Group's exploration interests in the OML40 licence, principally Amobe, together with the Ubima field in Nigeria.

The other intangible asset related to the approval fee paid on grant of Pioneer tax status in 2014. The cost of the pioneer tax has been fully amortised since the period ended June 2017. Following the exit from Pioneer status in 2019, the asset was derecognised. 

10. PROPERTY, PLANT AND EQUIPMENT

The Group's oil and gas production and development assets as at 30 June 2019 relate to the Group's interests in the OML40 licence in Nigeria.

The additions above include an accrual for capital expenditure for Elcrest share in a new 36km 16" Export Pipeline between Opuama and Otuamara. The cost of this pipeline, which was met by our partner (NPDC) is subject to reconciliation in accordance with the Joint Operating Agreement and the cost accrued by Eland is based on an independent third-party engineering estimate of the total cost for the 36 kilometre line.

11. INVENTORIES

Spare parts inventory relates to long-lead equipment which will be used in the future Ubima and OML40 drilling campaigns.

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 second half of 2019.

11. TRADE AND OTHER RECEIVABLES

The Directors consider that the carrying value of trade and other receivables is approximately equal to their fair value. It is recognised the receivable balance has risen in the Period, particularly other receivables and advance payments and the receivable due from NPDC. These balances are considered fully recoverable.

Other receivables consist of advance payments on contracts and accrued income.

Underlift represents the barrels of oil unsold as at the Period end.

An Expected Credit Loss of $1,437,000 (2018: $559,000) has been recognised in respect of the NPDC receivable.

12. TRADE AND OTHER PAYABLES

The joint venture creditor includes amounts accrued in relation to the 36km pipeline.

13. DECOMMISSIONING PROVISIONS

The provision for decommissioning is in respect of the Group's interest in OML 40 and Ubima. The provision represents the present value of amounts that are expected to be incurred in 2033 and 2031 for OML40 and Ubima respectively, discounted to the present value using a 2.75% discount rate (2018: 2.75%) and an inflation rate of 2% (2018: 2%).

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 unwinding of the discount on the decommissioning is included in the consolidated statement of comprehensive income as a finance cost (see note 5).

Changes in the estimated timing of decommissioning or decommissioning estimates are dealt with prospectively by recording an adjustment to the provision and a corresponding adjustment to property, plant and equipment.

14. DECOMMISSIONING PROVISIONS (continued)

The most recent evaluation by an external specialist of the expected decommissioning costs for the OML40 licence was undertaken in December 2017. To date there has been no specialist evaluation of expected decommissioning costs for the Ubima licence, but estimates have been updated in line with the OML40 development activities. Management believes the estimates continues to form a reasonable basis for the expected future costs of decommissioning, which are now expected to be incurred in 2033. The effect in future periods is impractical to calculate, as the provision in future periods may be affected by the drilling of future wells, and changes to inflation or discounting assumptions.

15. BANK LOAN

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 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 RBL Facility has a maturity of five years from November 2018 and includes an accordion to allow for the expansion of the facility up to a total amount of $200 million. The initial $50 million of the accordion was exercised in June 2019 with the syndicate comprising Stanbic IBTC Bank PLC, The Mauritius Commercial Bank Limited and The Standard Bank of South Africa Limited. 

15. BANK LOAN (continued)

There is a one-year grace period from execution of the RBL Facility before any principal amount is repaid and the interest rate payable under the RBL Facility 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 grace period expires in November 2019 however no repayment is due until December 2020.

The amount available under the RBL is subject to a cap determined by the lower of the borrowing base amount and the committed facility amount. Repayments of the principal are due on a semi-annual basis so that the outstanding balance of the RBL is not in excess of this cap. The borrowing base amount is calculated on OML 40 production and is re-determined every six months in accordance with the terms of the RBL.

As at 30 June 2019 the borrowing base stood at $134 million (31 December 2018: $103 million), although the amount available under the RBL is capped at the facility amount of $125,000,000 (31 December 2018: $75,000,000).

The RBL facility includes certain financial covenants on which the group is required to submit compliance documents showing that it has met these requirements at all times throughout the term of the loan.

The carrying amount of the loan is classified as below on the balance sheet:

At June 2019 the full carrying amount of the loan was classified as a non-current liability as the first repayment of the RBL is expected in December 2020.

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

16. LEASES

The Group's leased assets include buildings and equipment. The terms and conditions of each lease are negotiated on an individual basis. Certain leases contain options to extend. As at 30 June 2019, the lease terms are between 1 and 5 years.

Until 31 December 2018, the company applied IAS 17 Leases. While working under the principles of IAS 17, leases were classified as finance leases whenever the terms of the lease transferred substantially all of the risks and rewards of ownership to the lessee. All other leases were classified as operating leases. Rentals payable under operating leases were charged to the statement of comprehensive income on a straight-line basis over the term of the lease.

From 1 January 2019, IAS 17 was replaced by IFRS 16 Leases. On adoption of IFRS 16, the Group recognised lease liabilities in relation to leases which had previously been classified as operating leases under the principles of IAS 17. These liabilities were measured at the present value of the remaining lease payments, discounted using the Group's discount rate of 2.75%. The discount rate is estimated using a risk-free rate adjusted for timing uncertainty. The associated right-of-use assets were measured at the amount equal to the lease liability, adjusted by the amount of any prepaid or accrued lease payments relating to that lease recognised in the balance sheet as at 31 December 2018.

The Group applies the short-term lease recognition to those leases with a lease term of 12 months or less from commencement date. The Group also applies the low value exemption to the lease of assets with a lease amount of $5,000 or less when new. Lease payments on short-term leases and low-value items are recognised as an expense in the period to which they relate.

Right-of-use assets

At the commencement of a lease, the Group recognises a right-of-use asset. The right-of-use asset is measured at cost, less accumulated depreciation and impairment, and adjusted for any remeasurement of the corresponding lease liability.

The cost of right-to-use assets includes the amount of lease liabilities recognised, any lease payments that are made at or prior to commencement of the lease and any initial direct costs that are incurred less any incentives.

The right-of-use asset is depreciated over the shorter of lease term or the estimated useful life on a straight-line basis.

16. LEASES (continued)

Lease Liabilities

On the commencement of a lease, the present value of lease payments to be made over the term are recognised as the lease liability, including the exercise price of an option to purchase or penalties for early termination of a lease should the likelihood of either of these scenarios be reasonably certain. Any variable lease payments that do not depend on an index or a rate are recognised as an expense in the period to which they relate.

Where the interest rate implicit in the lease is not readily determinable, the Group applies a discount rate.

After the commencement of a lease, the lease liability is reduced by payments made and increased to reflect the accretion of interest. The carrying amount of the liability will be remeasured should there be a change in circumstances or changes to the terms and conditions of the lease agreement.

16. LEASES (continued)

A reconciliation of the group's operating lease payments as at 31 December 2018 and the lease liabilities as at 1 January 2019 and 30 June 2019 is shown below:

Impact of adoption

IFRS 16 replaces the provisions of IAS 17 Leases and IFRIC 4 Determining whether an arrangement contains a lease. The Group has elected to apply the new standard using the modified retrospective approach. Under this approach, there has been no restatement for the 2018 comparatives which are presented as previously reported under IAS 17.

The lease liabilities for leases classified as operating leases under IAS 17 were measured at the present value of the remaining lease payments using the group's incremental borrowing rate.

Practical expedients applied

The group elected to apply the following practical expedients upon application of IFRS 16:

·; The group relied on its previous assessment of existing lease contracts;

·; Leases with a remaining lease term of one year with no extension commitments as at 1 January 2019 were treated as short-term leases;

·; The group excluded initial direct costs in determining the cost of right-of-use assets;

·; The same discount rate was applied for a portfolio of leases with reasonably similar characteristics.

·; The group has also elected not to reassess whether a contract is, or contains a lease at the date of initial application. Instead, for contracts entered into before the transition date the group relied on its assessment made applying IAS 17 and Interpretation 4 Determining whether an arrangement contains a lease.

16. LEASES (continued)

Impact on balance sheet

The following table summarises the impact of transition to IFRS 16 on the balance sheet as at 1 January 2019 for each affected individual line item. Where line items were not affected by the changes, they have not been included and therefore the totals and sub-totals shown cannot be recalculated from the numbers provided.

There was no impact of adoption of IFRS 16 on retained earnings as at 1 January 2019.

Impact on the statement of profit or loss

16. LEASES (continued)

Impact on the statement of cash flows

17. 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. As reported in the 2018 Annual Report a contingent liability was disclosed following the completion and utilisation of the 36km pipeline from the Opuama field to the Custody Transfer Point at Otumara. While the construction of the pipeline by NPDC was clearly in violation of the provisions of the JOA, nonetheless, OML 40 crude has been transported via the pipeline since August 2018. Following the completion of an independent cost estimate in early 2019 management has concluded that it would be in the best interests of Elcrest and the OML 40 JOA if the pipeline was a jointly owned asset in accordance with each party' OML 40 equity interest. Elcrest has therefore capitalised the cost of the pipeline in the Period at approximately the cost estimate previously disclosed within contingent liabilities. As a consequence, Elcrest no longer has a contingent liability for the cost of the pipeline and has reversed the tariff cost of $1,825,000 which had been accrued in 2018.

There were no other material movements in the JOA contingent liabilities from that disclosed in the 2018 Annual Report.

State Aid investigation

The Group continues to monitor developments in relation to the European Commission's State Aid investigation into the UK's Controlled Foreign Company (CFC) tax regime. On 25 April 2019, the European Commission released its decision in relation to the group company finance exemption in the UK's CFC rules finding that the exemption constitutes unlawful state aid if the exempted profits arise in connection with UK activity. In common with other UK-based international companies whose arrangements are in line with current UK CFC legislation Eland may be affected by the ultimate outcome of this investigation. The UK government and other UK-based international companies, including Eland, have separately appealed to the General Court of the European Union against the decision.

17. CONTINGENT LIABILITIES (continued)

We are assessing the potential impact of the Commission's decision on the tax treatment of the Group's financing arrangements. Based on that assessment, and the current level of uncertainty, we consider that no provision is required at 30 June 2019.

Under a worst-case scenario in which the UK government, a test case, and Eland all lose their appeal to the General Court this could be a material tax liability for the Group. Notwithstanding the on-going court proceedings, HMRC may request payment for the alleged state aid within the next 12 months.

18. SHARE CAPITAL

No new shares were issued during 2018 or 2019.

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.

19. SHARE PREMIUM

20. RECONCILIATION OF PROFIT FOR THE PERIOD/YEAR TO OPERATING CASH FLOW

21. DIVIDENDS

The Board approved an interim dividend of 1 pence per share (31 December: nil), aggregate of $2.7 million, which is payable on 31 October 2019 to shareholders on the register at the close of business on 18 October 2019. The dividend was approved by the Board after the balance sheet date and has therefore not been reflected as a liability in the interim financial statements.