Interim Results for the six months to 30 June 2018

20 September 2018

Eland Oil & Gas PLC

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

Interim Results for the six months to 30 June 2018

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 2018 (the "Period").

George Maxwell, CEO of Eland, commented:

"The first half of 2018 has been the most important operational and financial period in Eland's history. With two successful infill wells completed on the Opuama field, average gross production increased threefold to over 17,000 barrels of oil per day and has since hit highest levels to date of nearly 30,000 bopd since period end, and will continue to increase further in the near-term.

The operational successes in the period translated into a transformational financial performance with the Company reporting its maiden profit following record Group revenues. The strong operational cash flow in the Period also allowed for a positive turnaround in the Company's working capital position through a period of considerable capital investment. The significant increase in the re-financed debt opportunity is testament to the improvement in the Company's performance.

We continue with the Ubima appraisal while also targeting first oil on Gbetiokun this year, further significantly increasing the Company's production base. The outlook for the remainder of this year is extremely exciting as we drive towards further record production and financial performance in 2018."

H1 2018 HIGHLIGHTS

Strong operational delivery

· Success with Opuama-8 and Opuama-9 in H1-2018 led to record high gross production from OML 40 of 25,000 barrels of oil per day ("bopd") (Elcrest net 11,250 bopd*).

· Gross production from OML 40 achieved an average 17,146 bopd (7,716 net) during the six-month period to 30 June 2018 in comparison to 5,275 bopd in H1 2017 (2,374 net), an increase of 225%.

· Successful installation of a Lease Automatic Custody Transfer ("LACT") unit at Otumara providing accurate measurements of crude oil delivery from OML 40.

· The Ubima-1 appraisal operations, an asset diversification by Eland outside of OML 40, commenced in H1 with re-entry of the well commencing post period end. Appraisal continues.

· An updated Competent Person's Report ("CPR") for OML 40 in April 2018 increased gross Proved ("1P") reserves by 20% to 39.5 million barrels ("mmbbls") and increased gross Proved plus Probable ("2P") reserves slightly to 83.4 million barrels.

Record financial performance

· Revenue of $67.4 million (1H 2017: $0.8 million) with an average realised price of $69/bbl (1H 2017: $37/bbl).

· Including the effect of the movement in crude inventories in the Period the value of production was $87.9 million (1H 2017 $20.2 million).

· First reported profit in the Group's history with $44.7 million post-tax profit in the Period (H1 2017: $22.4 million loss).

· Strong operating cash flows in Period of $50.6 million (H1 2017: $17.5 million deficit).

· Net current liabilities stood at $17.1 million at Period end (1H 2017: $35.7 million) although excluding the impact of the short term-bank loan net current assets were $8.2 million (1H 2017: $31.3 million net current liabilities).

· Direct OML 40 operating costs of $8/bbl (excluding royalties).

· Liftings in Period of 976,000 bbls (H1 2017: 23,000bbls) generating revenue of $67.4 million (H1 2017: $0.8 million).

· Cash of $29.8 million at 30 June 2018 (H1 2017: $22.3 million).

Post-Period End - continued delivery

· At an advanced stage in securing an initial debt facility of $100 million, with an accordion feature to grow to $200 million based on incremental reserves and production.

· Facility expected to close with $75 million commitment and $25 million due to be syndicated in the near term

· Opuama-10 production testing in progress with production of 6,898 bopd (3,104 net) achieved during testing operations. It is expected following completion of testing stabilised initial production from Opuama-10 will be in excess of 5,500 bopd (2,321 net).

· Aggregate Opuama field production is expected to average above 29,000 bopd (13,050 net) once Opuama-10 testing operations complete.

· Opuama-11 has been drilled to a total true vertical depth of 7,914 feet and the final casing string has been run and cemented. It is expected that initial gross production from Opuama-11 will be between 4,000 and 6,000 bopd (1,800 to 2,700 net) further adding to Opuama field production.

· Following the completion of drilling at Opuama-11 and the receipt of regulatory approvals, the OES Teamwork rig will be moved to the Gbetiokun field, where it will re-enter Gbetiokun-1 followed by drilling of Gbetiokun-3 as part of the initial phase of the field development plan.

· OML 40 twenty-year licence renewal process approved and agreed by all stakeholders. The licence renewal fee has been paid and we await final consent of the Honourable Minister of Petroleum Resources.

· Ubima well testing operations in progress with the F7000 reservoir tested at flow rates of up to 2,500 bopd. At present the D1000 reservoir is being tested with the potential to test the E1000/E2000 to be evaluated.

· Post period end we have received $50.5 million in cash receipts from our July and August liftings totalling 679,000 bbls. A further 350,000 bbls have been lifted in September which will provide an additional $26.6 million cash when funds are received in October.

· Current cash balance of $32.3 million.

Outlook

· Busy H2 drilling programme following the completion of Opuama-11 to include the re-entry of Gbetiokun-1 and drilling of Gbetiokun-3.

· Ubima appraisal is currently underway and on success a significant amount of contingent resources to be converted into recoverable reserves. Four wells are currently planned to develop the main reservoirs.

· H1 2018 has delivered exceptional growth notwithstanding the challenges of the extended drilling programme on Opuama-9. However, the full benefit of production from Opuama-9, coupled with Opuama-10 and 11 will be realised in H2 2018 resulting in further significant increase to both revenue and cashflow.

For further information:

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

www.elandoilandgas.com

George Maxwell, CEO

Ronald Bain, CFO

Finlay Thomson, IR

Canaccord Genuity Limited (+44 (0)20 7523 8000)

Henry Fitzgerald O'Connor / James Asensio

Panmure Gordon (UK) Limited (+44 (0)20 7886 2500)

Adam James / Atholl Tweedie

Tom Salvesen

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 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 83.4 million barrels ("mmbbls"), gross 2C contingent resources of 40.4 mmbbls and a best estimate of 254.5 mmbbls of gross unrisked prospective resources (NSAI Competent Person's Report of 31 December 2017. The Ubima field holds gross 2P reserves of 2.4 mmbbls and gross 2C resource estimates of 31.1 mmbbls (AGR TRACS Competent Person's Report of 19 April 2016).

* 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

Highest ever group production

Development of the world class Opuama oil field continued apace in H1-2018, with two additional infill wells coming onstream and boosting OML 40 production to a record 25,000 bopd gross (11,250 net) by late June.

Production

Gross production from OML 40 achieved an average 17,146 bopd (7,716 net) during the six-month period to 30 June 2018, compared to 5,275 bopd in H1 2017 (2,374 net): an increase of 225%. Average production on operational days was 19,785 bopd (8,903 net), compared to 9,184 bopd in H1 2017 (4,133 net): an increase of 115%.

The restart of the Opuama-1 well following the restart of pipeline export in May 2017 and the successful completion of three infill wells accounted for the production increase in H1 2018. These infill wells were the sidetrack of the Opuama-7 well which started production in November 2017 and the two new wells, Opuama-8 and Opuama-9, which started production in January 2018 and June 2018 respectively. In addition, the decline in Opuama-3 production was less than expected.

As previously announced, the Company had planned to recomplete the Opuama-7 sidetrack well due to the well experiencing increased water-cut. The Company has since decided to postpone this remedial activity in order to maximise the recovery of reserves from the existing drainage point. The well is currently producing from the lower D2000 reservoir in an optimum position, not accessible anywhere else in the field.

Average uptime across the Period was 87%: an average of 90% in Q1 was followed by an average of 83% in Q2, with limited interruptions to production throughout Q2 causing the lower average uptime in this period. On advice from Shell Petroleum Development Company ("SPDC") the Opuama Flow-station was shut down on the 28th of April due to a leak on the Trans-Escravos Pipeline ("TEP") near the Otumara Flow-station; production resumed on the 7th of May on completion of the repairs. Following this a reported leak on the TEP on the 14th of May resulted in a shutdown of the flow-station until the 20th of May when repairs were completed and the flow-station resumed production. Uptime post H1 2018 has reduced in July and August (55% average uptime) due to non-planned maintenance and timing issues switching production into the new 16" export line.

LACT

The installation of the LACT Unit at Otumara was successfully completed without any safety incidents in H1 2018, following approvals from the relevant third parties (SPDC) and the Nigerian Oil & Gas regulator (DPR). Testing of the LACT Unit is in progress and final commissioning is expected to be completed in Q3 2018. The LACT Unit is essential in providing accurate flow measurements as well as flowline pressure monitoring for the crude produced from the OML-40 assets and was anticipated to reduce loss allocations from around 11% in the Period to below 5% downstream of the custody transfer point. However, this benefit of reduced loss allocation is now expected from Q4 2018 due to the commissioning delays.

OML 40: Opuama infill drilling

The Opuama-8 well was successfully completed in January, with initial gross production of 6,200 bopd gross increasing total gross production from Opuama field to over 22,000 bopd. The well encountered oil in six reservoirs, which included the shallow "C" reservoirs, and was the first time oil had been discovered in this location. The well is currently producing from the D3500 and D4000 reservoirs whilst the D5000 will be produced at a later date.

Following completion of Opuama-8, drilling operations on Opuama-9 commenced in March. The well took longer than expected due to some mechanical issues with the OES Teamwork rig although these were ultimately rectified, and the rig has performed very well since. The well successfully intersected the D1000 and D2000 reservoirs with a total of 63 feet of net pay. Opuama-9 subsequently came onstream in late June at around 7,000 bopd, ahead of expectations, boosting total field production to 25,000 bopd gross (11,250 net). Opuama-8 and 9 represented excellent combined flow rates.

Since the period end, Opuama-10 was successfully brought on stream in late August, further increasing production from the Opuama field. Opuama-10 encountered six oil-bearing reservoirs with 307 feet net pay, with the well completed on two of these reservoirs, namely the D1000 and D5000. During the testing of Opuama-10 aggregate gross production of 6,898 bopd was recorded from the well.

Following a review by the OML 40 Joint Venture between Elcrest and the Nigerian Petroleum Development Company Ltd ("NPDC"), a decision was made to accelerate the drilling of the Opuama-11 well with the target of developing incremental reserves from the intermediate zones not targeted by Opuama-10. The OES Teamwork Rig has drilled Opuama-11 to total true vertical depth of 7914 feet and the final casing string has been run and cemented. The three target zones, D3500, D4000 and D2000 reservoirs, which recorded net pay of 185 feet of apparent vertical thickness, will be perforated and a long-term production test carried out. It is expected that initial gross production from Opuama-11 will be between 4,000 and 6,000 bopd (1,800 to 2,700 net).

OML 40: Gbetiokun

Following the drilling of Opuama-11 and the completion of regulatory approvals, the OES Teamwork rig will be moved to the Gbetiokun field, where it will re-enter and drill Gbetiokun-1 followed by Gbetiokun-3 as part of the initial phase of the field development plan. Dredging operations have now been completed enabling rig access to commence Gbetiokun phase 1 on re-entry to Gbetiokun-1.

Netherland Sewell & Associates ("NSAI") forecasts that the Gbetiokun field will ultimately produce 2P reserves of 38 mmbbls, with initial gross production rates of 8,000 bopd (3,600 bopd net) anticipated from Gbetiokun-1. The Gbetiokun-1 well is located near the Benin river: oil export would initially be by ship to the Benin River Valve Station where the oil would be injected into the OML 40 export pipeline to the Forcados oil terminal. In the medium term, oil export would be by a new pipeline to the Adagbassa Manifold, from where the oil would be injected into the Forcados system.  

OML 40: Exploration

Eland continues to prepare for the drilling of the Amobe exploration prospect in OML 40 in H2-2019, the first pure exploration well in the company's history. The well is a large, relatively low-risk prospect located only 6km from the Opuama Flow-Station allowing for an accelerated development tied back to existing facilities. It is similar to Opuama structurally 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%. Current estimates for the cost of the well are c$22 million.

Licence renewal

OML 40 twenty-year licence renewal process approved and agreed by all stakeholders and all fees have been paid. The licence renewal is still subject to final consent of the Honourable Minister of Petroleum Resources.

CPR

An updated Competent Person's Report ("CPR") for OML 40 in April 2018 increased gross OML 40 Proved ("1P") reserves by 20% to 39.5 mmbbls (13.5 mmbbls net entitlement to Eland after royalties, an increase of 14%). The CPR also increased OML 40 2P reserves slightly to 83.4 mmbbls (26.3 mmbbls net entitlement to Eland after royalties, an increase of 17%).

Opuama 2P Reserves declined by 12 MMstb, from 57.4 MMstb to 45.4 MMstb (a reduction of 8.7 MMstb allowing for production of 3.9 MMstb between June 2015 and December 2017). The revised figures were a result of a new 3D dataset and different method of depth conversion for the D1000, D2000, D5000 and E2000 reservoirs, as well as transfer of 3.3 MMstb in the D3500 and D4000 reservoirs from Contingent Resources (June 2015 CPR) to Reserves.

Since the June 2015 CPR, Gbetiokun 2P Reserves increased by 12 MMstb, from 25.8 MMstb to 38 MMstb, with the main changes being inclusion of oil in the D8900, E1000 and E6500 as Reserves, and significant increases in Reserves of the E2000, E5000 and E6000 reservoirs compared to the previous CPR.

Ubima

The Company, together with its partner All Grace Energy Limited, is currently appraising Ubima field, and re-entered the Ubima-1 well with the Deutag T-57 land rig in late July 2018. Ubima-1 is the first well to be worked on in the licence by the Company and its partner and it is expected that upon successful appraisal the Ubima partnership will convert a significant amount of contingent resources into recoverable reserves. Ubima-1 represents Eland's diversification of production outside OML 40 and opens a new operational leg in Rivers State, Nigeria, with ultimately different export routes than those from the OML 40 licence.

A CPR published in April 2016 by AGR TRACS ascribes gross 2P reserves of 2.4 million barrels of oil to the Ubima-1 well. On a full field development basis, the CPR carries gross contingent resources of 20.6 million barrels (1C), 31.1 million barrels (2C) and 66.0 million barrels (3C).

Since period end, the Ubima-1 well was re-entered with testing operations expected to complete in Q4 2018. However, to date we have recorded 2,500 bopd from the F7000 reservoir.

CSR

As part of the Group's ongoing commitment to its Corporate Social Responsibility(CSR) the Group continues to provide much needed services and offers employment to contractors and host community staff wherever possible. In the current Period in preparation for drilling at Ubima the Group offered employment in areas such as security, surveillance and rig support to local employees and local contractors provided infrastructure in building water supply facilities and general logistic support. On the OML 40 licence, Elcrest in partnership with NPDC, continues to offer local employment to support the ongoing drilling operations.

In total we have awarded in the order of $1.8 million of our drilling expenditure to community contractors and personnel.

Financial Review

The record financial performance was underpinned by a significant production ramp-up combined with a stable operating environment with excellent infrastructure uptime from OML 40 through to its export route to the Forcados terminal. The liftings net to Elcrest of 976,000 bbls in the Period (1H 2017: 23,000bbls) generated revenues of $67.4 million (1H 2017: $0.8 million). The Group benefitted from the improving commodity environment with average realised price achieved in the Period of $69/bbl (1H 2017: $37/bbl).

In addition, the Group was in an underlift position at 30 June 2018 where 183,000 bbls were produced but not yet sold which will provide further revenues of approximately $14.5 million when these barrels are sold. Post period end all underlifted barrels have since been sold therefore unwinding the build-up of underlift in 1H 2018.

Excluding the impact of non-cash items; underlift and depreciation, operating expenses reduced to $32.7 million in the Period (1H 2017: $36.4 million) reflecting the return to Forcados and significantly reduced transportation costs compared to shipping in 1H 2017. This was largely offset by an increase in royalties driven by the higher production and improved commodity price. Direct OML 40 operating costs per bbl were $8/bbl demonstrating the low operating cost for the field.

The Group continued its OML 40 Opuama drilling campaign in the Period with Opuama capital expenditure amounting to $35.3 million ($16.3 million net to Elcrest). This primarily consisted of the costs to complete Opuama-8 which was brought into production in January 2018 and the Opuama-9 well brought into production in June 2018. Further capital spend was incurred on Gbetiokun amounting to $3.4 million gross ($2.0 million net) as the Group prepares access for drilling in the second half of 2018. In addition, Ubima preparatory costs of $1.8 million were incurred in the Period representing the civil works necessary for the appraisal well which commenced in July 2018. In total the Group invested $20.8 million of capital additions in the Period with $18.5million of this being cash expenditure in the Period.

Administrative expenses rose to $3.6 million (1H 2017: $1.7 million), although excluding the impact of UK foreign exchange losses and new venture expenditure, remaining administrative expenses total $3.1 million (1H2017: $1.8 million). The increase reflects the necessary and planned organisational growth to support a rapidly growing business and includes a $0.3m increase in the non-cash share option charge. Despite the increase in headline administrative costs, the costs per bbl continued to fall to $2.87 in the Period (1H 2017 $4.45/bbl).

Finance expenditure rose to $2.6 million (1H 2017: $1.8 million) reflecting higher loan balances in the Period compared to the corresponding period in 2017. Hedging expenses in the Period were $0.6 million although there was a reduction in other interest compared to 1H 2017 where non-recurring interest charges were incurred.

Taxation showed a credit of $1.1 million reflecting the timing difference between the depreciation charges and the usage of capital allowances. As Elcrest continues to benefit from Pioneer tax status no tax charge will be payable on the profits generated in the Period, however capital allowances will still be available for capital expenditure incurred in the Period following the end of Pioneer, and as a result a taxation credit is recorded in the Income Statement.

Balance Sheet

The working capital position continues to improve although it has taken time to unwind given the significant financial strain on the Group arising from the prolonged Forcados shutdown from February 2016 until May 2017. Net current liabilities stood at $17.1 million at Period end (1H 2017: $35.7 million) although excluding the impact of the short term-bank loan net current assets were $8.2 million.

Working capital includes a net receivable balance of $21.5 million with NPDC with the build-up in 2018 mainly due to the drilling programme in the Period. Settlement of cash calls will be subject to well close out reports and reconciliation at future OPCOM. In July 2018 Elcrest invoiced NPDC for $9.8 million of operating costs paid by Elcrest over the last year on behalf of the JV that were included within receivables at 30 June 2018.

As part of the settlement of legacy working capital balances amounts due to Elcrest's indigenous shareholder of $13.5 million at year-end were fully repaid in the Period.

Cash flow

Operating cash flow in the Period before movements in working capital was $50.6 million (1H 2017: $17.5 million deficit) representing a transformational change in the Group's cash flow generation. This equates to a cash flow margin of over $40/bbl on every barrel sold in the period after deduction of all operating costs including royalties payable. The cash flow generated was used for investment activities totalling $18.5 million (1H 2017: $2.1 million) as detailed above. In addition, settlement of working capital balances totalled $38.1 million in the Period (1H 2017 $12.6 million).

During the Period a hedging programme was executed for 720,000 bbls setting a floor of $65/bbl on the sale of these bbls in the second half of 2018.

Refinancing 

A new 5-year US$100 million Reserve Based Lending Facility ("RBL") secured against the Group's producing assets in OML40 is in advanced documentation stage. The facility is expected to be set at an initial facility amount of US$100 million, with an accordion feature to grow to US$200 million based on incremental reserves and production. The facility has an initial borrowing base in excess of US$100 million from existing Opuama proven producing wells, with further upside from future inclusion of Opuama-9 and 10 probable reserves and Opuama-11 post production at the next borrowing base review, as well as inclusion of new fields.

The facility will be available to roll the existing US$27 million debt outstanding and provide low cost strategic capital for growth to support the development of the Gbetiokun field and general corporate purposes. The facility will close with initial Commitments of US$75 million from two lead arranging banks (credit approved). The Company is looking to syndicate a further $25 million to a third lead bank in the near-term.

Governance

The Board has continued to adopt the Quoted Companies Alliance (QCA) corporate governance code. The Chairman's Statement will shortly be published on the website detailing the Group's compliance with the QCA's ten principles aligned with revised AIM rule 26.

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 12 to 25 form part of these financial statements.

CONDENSED CONSOLIDATED INTERIM BALANCE SHEET

The notes on pages 12 to 25 form part of these financial statements.

CONDENSED CONSOLIDATED INTERIM STATEMENT OF CHANGES IN EQUITY

The notes on pages 12 to 25 form part of these financial statements.

CONDENSED CONSOLIDATED INTERIM CASH FLOW STATEMENT

The notes on pages 12 to 25 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 1FW, 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 2018 were authorised for issue in accordance with a resolution of the Board of Directors on 19 September 2018.

The information for the 6 months ended 30 June 2018 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 2017 were approved by the Board of Directors on 17 April 2018 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 2018 have been prepared in accordance with IAS 34, "Interim financial reporting", as adopted by the European Union ("EU"), 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 2017.

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 and that it is compliant with its covenants.

The return to Forcados combined with the increased production achieved from the 2017 and 2018 capital investment has seen profitability and cash flows ramp up significantly. Although risks and uncertainties remain as documented within the 2017 Annual Report on pages 36 to 43, management has sufficient mitigating action 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 annual financial statements for the year ended 31 December 2017, as described in the 2017 Annual Report.

In the current year the following new Standards have been adopted. The Group has considered the impact of these standards and concluded the adoption has not impacted the interim results, and we do not anticipate either having a material impact on the Group's future results.

Initial adoption of IFRS 9 Financial Instruments

IFRS 9 Financial Instruments replaces IAS 39 with effect from accounting periods commencing 1 January 2018.

The new standard covers three distinct areas: the classification and measurement of financial assets and liabilities; the impairment of financial assets; and hedge accounting.

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 Group has performed an assessment to understand the requirements of IFRS 9 and how these differ from IAS 39 and has concluded there is no significant impact on the condensed consolidated financial statements from the date of adoption. There were no differences between previous carrying amounts and consequently no adjustment has been made to opening retained earnings.

Initial adoption of 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 in line with the fixed elements of pricing throughout the duration of the contract.

The Group has evaluated its customer contract with Shell 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.

The following standard has been published and will be mandatory on or after 1 January 2019. The Group has not early adopted this Standard.

IFRS 16 'Leases'

IFRS 16 Leases replaces IAS 17 with effect from accounting periods commencing 1 January 2019. The main impact for the Group is that IFRS 16 introduces a single lessee accounting model and requires the recognition of assets and liabilities for all leases, unless the lease term is 12 months or less or the underlying asset is of low value.

As at 30 June 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

1. BASIS OF PREPARATION (CONTINUED)

on the timing of recognition of assets and liabilities when contracts are committed, rather than spread over the life of the contract. We do not anticipate a material impact on the income statement arising from the adoption of this standard.

The Group is likely to adopt the modified retrospective option from 1 January 2019. The project to assess the impact and to meet the requirements of IFRS 16 is well advanced.

2. REVENUE

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

Revenue in both years derives from an offtake contract with its partner, Shell Western Supply and Trading Limited. From January to May 2017, crude from the OML40 asset was shipped to FPSO and sold to Vitol SA whilst the Forcados oil terminal was shut down.

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 2017 Annual Report for further details.

3. OPERATING EXPENSES

The analysis of operating expenses is as follows:

Tariff and transportation costs include shipping operations to export crude during the period January to May 2017 when the company's principal export route Forcados was unavailable. Since the re-opening of the Forcados terminal in May 2017 no further shipping costs have been incurred and the tariff and transportation costs relate to the pipeline transportation to Forcados.

4. ADMINISTRATIVE EXPENSES

The analysis of administrative expenses is as follows:

5. FINANCE INCOME AND COSTS

6. PROFIT/(LOSS) BEFORE TAX

7. TAXATION

The current tax credit relates to a R&D tax credit receipt under the scheme available to SME companies.

The Group has recognised a deferred tax asset of $20.6 million as at 30 June 2018 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 has been depreciated following commencement of production in July 2014.

As at 30 June 2018, the Group has taxable losses of $325,519,000 (31 December 2017: $327,611,000) for which no deferred tax asset has been recognised as there is not sufficient certainty at this time regarding the utilisation of these losses. In particular, Elcrest accounts for the majority of these tax losses totalling $293,577,000 (31 December 2017: $307,844,000). On expiry of Pioneer tax status, and following the full utilisation of available tax losses, and in addition capital allowances of $223,290,000 (31 December 2017: $207,869,000) Elcrest is expected to be paying 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 2018 tax losses reflect submitted year-end 2017 computations and an estimate for taxable losses and capital allowances incurred in the current period.

8. EARNINGS PER SHARE

From continuing operations

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

9. INTANGIBLE OIL AND GAS ASSETS

The Group's oil and gas exploration and evaluation assets at 30 June 2018 relate to the Group's interest in the Ubima marginal field in Nigeria.

The other intangible asset relates 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.

10. PROPERTY, PLANT AND EQUIPMENT

The Group's oil and gas production and development assets as at 30 June 2018 entirely relate to the Group's interest in OML40 in Nigeria.

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, notably Other receivables and the balance due to our JV partner has become a JV debtor balance. These balances are considered fully recoverable.

Other receivables consists of costs incurred on behalf of the OML40 JV, advance payments on contracts and accrued income.

Underlift represents the barrels of oil unsold as at the period end. As at 31 December 2017, this was an overlift included in trade and other payables (note 12).The JV debtor balance includes the net amount receivable from the JV partner. As at 31 December 2017, this was included in the trade and other payables (note 12).

12. TRADE AND OTHER PAYABLES

Trade and other 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 US Dollars, Nigerian Naira or Sterling.

Accruals include accruals relating to the ongoing capex programme and G&A accruals.

The joint venture creditor balance includes accruals for estimated amounts due under the OML 40 Joint Operating Agreement ("JOA") which are either not yet invoiced or agreed with our partner on the licence. Additionally, it also includes amounts which have been billed and agreed upon.

Other payables relate principally to amounts due to the DPR in respect of Royalty payments outstanding at period-end. 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 the period to 30 June 2018. Management fees payable under the agreement are $3 million 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.

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 2031 and 2034 for OML40 and Ubima respectively, discounted to the present value using a 2.75% discount rate (2017: 2.75%) and an inflation rate of 2% (2017: 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.

During 2017, an independent specialist evaluated the decommissioning costs for the OML40 licence and the study led to the adjustment of the amounts previously provided for. Management believes the estimates continue to form a reasonable basis for the expected future costs of decommissioning, which are now expected to be incurred in 2031. 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.

14. BANK LOAN

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

The reserves based lending facility with Standard Chartered Bank (SCB), which Westport (the Group's finance vehicle) entered into on 31 December 2014 (the "RBL") is available to the Group to fund, amongst other things, capital expenditure obligations in respect of Elcrest's participating interest in OML 40 and for the Group's working capital purposes up to $5 million.

The RBL has a maturity of four and a half years from 31 December 2014, this will mature on 30 June 2019. The facility was amended in December 2017 which saw the available amount increase to $27 million, with two new lenders - The Mauritius Commercial Bank Ltd and Mercuria Energy Trading SA - joining the syndicate alongside SCB, with equal participation by each of the three lenders. Interest is payable on amounts outstanding on a quarterly basis at a rate equivalent to USD LIBOR plus a margin of 9% from 21 December 2017 (previously 7.75%).

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. 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 2018 the borrowing base stood at $70,100,000 (31 December 2017: $37,900,000), although the amount available under the RBL is capped at the facility amount of $35,000,000 (2017: $35,000,000), of which $27 million is committed as at 30 June 2018.

The RBL is secured over the Company's shares in Elcrest, and by way of a debenture which creates a charge over certain asset of the Group, including its bank accounts.

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. These submissions are subject to agreement by the lender on the treatment of certain items.

14. BANK LOAN (CONTINUED)

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

At June 2018 the full carrying amount of the loan has been classified as a current liability as the final repayment date of the RBL is June 2019.

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

15. SHARE CAPITAL

SHARE CAPITAL (CONTINUED)

No new shares were issued during 2018.

During 2017, a total of 27,548,000 new ordinary shares were issued pursuant to the Share Placing announced on 14 June 2017. The company raised approximately $19.5 million (gross) through the placing at 55 pence per share. Of the net proceeds of $18,551,000 received $3,537,000 has been recorded in share capital, $15,917,000 in share premium with expenses of $903,000 also included in share premium.

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

In addition to the placing mentioned above, on 14 June 2017 as a shareholder, Helios Natural Resources ("Helios") requested the conversion of 6,296,815 respectively of £0.10 non-voting shares into voting shares. Following completion of this conversion all non-voting ordinary shares have now been converted into voting 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. 

16. SHARE PREMIUM

A total of Nil shares were issued in 2018. In June 2017, 27,548,000 new ordinary shares were issued, consisting of 27,548,000 voting and Nil non-voting shares.

In 2017 the difference between the placing price of 55 pence per share and the share capital of 10 pence per share was recorded in share premium at a rate of GBP: USD 1:1.28. Further, share premium expenses for broker and professional fees totalling $903,000 (2016: $647,000) were recorded against the share premium account. 

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

18. DIVIDENDS

No interim dividend is proposed and no dividend has been paid in the period to 30 June 2018 (Full Year 2017: $nil).