Seplat Energy Regulatory News (SEPL)

Seplat Petroleum Development Company Plc

Half-yearly Results

For the six months ended 30 June 2018(Expressed in Naira and US Dollars)

Seplat Petroleum Development Company Plc

Consolidated financial results for the period ended 30 June 2018

Lagos and London, 30 July 2018: Seplat Petroleum Development Company Plc ("Seplat" or the "Company"), a leading Nigerian indigenous oil and gas company listed on both the Nigerian Stock Exchange and London Stock Exchange, today announces its consolidated half-yearly financial results for the period ended 30 June 2018 and provides an operational update. Information contained within this release is un-audited and is subject to further review. Details of the Webcast and conference call are set out on page 7 of this release.

Commenting on the results Austin Avuru, Seplat's Chief Executive Officer, said:

"The results today continue to demonstrate our ability to generate cashflow and profitability from our assets and we are on track to deliver our 2018 production guidance in both oil and gas, with gas now contributing a significant portion to the bottom line. Post refinancing in Q1 this year, we have continued to strengthen the balance sheet with a quarter on quarter reduction in net debt to low levels at the end of H1 2018. The second half of this year will see us accelerate field development activities across the existing portfolio as we start to drill the first wells on our OML 53 asset. Due to slower than expected progress we have revised the timeline for delivery of the Amukpe to Escravos pipeline and FID at the ANOH gas condensate project to later in the year. The fundamentals of the underlying business remain very strong as we continue to focus on delivering on our promises."

Half-yearly results highlights

Strong underlying profitability

· Gross profit margin of 51% for H1 2018 (up from 41% in H1 2017) driven by higher production, firmer oil prices and lower unit production opex which stood at US$4.50/boe (down from US$5.85/boe in H1 2017)

· H1 2018 profit before tax stood at US$121 million (H1 2017 loss before tax US$26 million); Profit after tax (but before deferred tax) of US$105 million; net profit for the period of US$49 million.

Robust balance sheet and cash flow generation to support growth

· Cash at bank at 30 June 2018 US$510 million; gross debt US$550 million and net debt US$40 million with US$100 million un- drawn headroom on the four year revolving credit facility

· Net cash flow from operations in H1 2018 stood at US$245 million against capex of US$21 million; FY 2018 capex guidance of US$100 million reiterated as field development activities step up in H2 2018

Working interest production within guidance range

· Overall working interest production in H1 across all blocks stood at 25,286 bopd and 155 MMscfd, or 51,099 boepd

· Production uptime stood at 76% in the first half and reconciliation losses around 8%

· FY 2018 guidance reiterated at 24,000 to 29,000 bopd and 148 to 158 MMscfd (or 48,000 to 55,000 boepd)

Increasing revenue contribution from the gas business

· Gas revenues of US$85 million in H1 2018 (25% of total revenues in the period and up 57% year-on-year)

· Continued to supply commissioning gas to the Azura IPP. Upon commissioning, expected in Q3, deliveries will move to the contracted level of 116 MMscfd gross on take-or-pay terms

· Actively engaged with counterparties to finalise new GSA's - plan to take gross production towards 400 MMscfd

· Proceeding towards FID at the ANOH gas and condensate development at OML 53. Expect FID in Q4 2018

License renewal for OMLs 4, 38 and 41

· Confirmation of approval was received from the Department of Petroleum Resources (DPR) for renewal of licenses on OML's 4, 38 and 41 for a period of 20 years. The license renewal is still subject to final consent of the Honourable Minister of Petroleum Resources

Update on alternate export routes

· Two jetties at the Warri refinery provide a back-up option that can allow for sustained exports of 30,000 bopd gross if required in the future

· Completion of the 160,000 bopd Amukpe to Escravos pipeline is progressing slower than anticipated. Consequently, Seplat has adjusted its own expectation of completion to Q4 2018

Financial overview

(1) Profit after tax has been adjusted for US$56 million of non cash deferred tax

OPERATIONS REVIEW

Production for the first six months ended 30 June 2018

(1) Liquid production volumes as measured at the LACT unit for OMLs 4, 38 and 41 and OPL 283 flow station. Volumes stated are subject to reconciliation and will differ from sales volumes within the period.

Average working interest production during H1 2018 was 51,099 boepd (compared to 26,383 boepd in H1 2017) and comprised 25,286 bopd liquids and 155 MMscfd gas. Production uptime in the period was 76% while reconciliation losses were around 8%.

In H1 2018, Seplat lifted and a monetised an equivalent of 221 kbbls of oil from OML55, which resulted in a receipt of US$14.7 million. The carrying value of the investment in the balance sheet was consequently reduced to US$202 million.

Looking ahead, the Company maintains working interest production guidance (before reconciliation losses) for FY 2018 of 24,000 to 29,000 bopd and 148 to 158 MMscfd, which equates to 48,000 to 55,000 boepd. This guidance range is predicated on there being no further prolonged force majeure event.

Alternative oil export routes

The Company's policy of creating multiple export routes for all of its assets has resulted in it actively pursuing alternative crude oil evacuation options for production at OMLs 4, 38 and 41 and potential strategies to further grow and diversify production in order to reduce any over-reliance on one particular third party operated export system. In line with this objective, the Company had previously installed a pipeline linking OMLs 4, 38 and 41 to the Warri refinery where, in 2017, it successfully completed repairs and upgrades on two jetties that will enable sustained exports of 30,000 bopd (gross) if required in the future.

Longer term, the Amukpe to Escravos 160,000 bopd capacity pipeline is set to provide a third export option for liquids production at OMLs 4, 38 and 41. The pipeline owners, NAPIMS (a 100% subsidiary of NNPC), Pan Ocean Corporation Limited (Pan Ocean) and the pipeline contractor FENOG are responsible for completion of the pipeline. The pipeline operator, Pan Ocean, is advancing negotiations with the operator of the Escravos terminal, Chevron, in relation to necessary Crude Handling Agreements. Completion work has been slower than anticipated and, based on information provided by the pipeline operator and contractor, Seplat has consequently adjusted its own expectation of pipeline completion to Q4 2018.

It is Seplat's ultimate intention to utilise all three independent export options to ensure there is adequate redundancy in evacuation routes, reducing downtime which has adversely affected the business over a number of years, significantly de-risking the distribution of production to market.

Continued strong performance of the gas business

Seplat's gas business continues to make an increasing revenue contribution and in H1 2018 generated US$85.3 million revenue at an average gas price of US$3.04/Mscf, within which Q2 2018 was another record quarter which saw gas revenues hit a new high of US$45.8 million. Having commenced the deliveries of commissioning gas to the 459MW Azura-Edo IPP in December 2017, when the first turbine was synchronised to the national grid, the Company anticipates the commissioning phase to be completed in Q3 2018 after which deliveries will move to the contracted level of 116 MMscfd gross under take-or-pay and credit enhanced terms.

The ANOH gas development at OML 53 (and adjacent OML 21 with which the upstream project is unitised) is expected to underpin the next phase of growth for the gas business and Seplat's involvement positions it at the heart of one of the largest greenfield gas and condensate developments onshore in the Niger Delta to date. The Company is working with its partners to finalise a framework within which to progress the upstream and midstream elements of the project to FID. The FID originally planned for H1 2018 is delayed as a result of the need to ensure the internodal aspects of the project between the upstream and the midstream are sufficiently de-risked. Based on the latest estimates, we have revised the FID target date to Q4 2018.

License renewal for OMLs 4, 38 and 41

Confirmation of approval was received from the Department of Petroleum Resources (DPR) for renewal of licenses on OML4, 38, 41 for a period of 20 years. The license renewal is subject to the payment of a renewal fee, a continued commitment to gas monetization and final consent of the Honourable Minister of Petroleum Resources.

Work programme

In H2 2018 the Company is set to redeploy rigs into the field and undertake certain facilities upgrade and optimisation projects. At OMLs 4, 38 and 41 the Company plans to drill one new gas production well that will also incorporate an exploration and appraisal tail to test potential in deeper zones. In addition to this one workover of an existing gas production well will be undertaken. The Company will also install NAG booster compression, a second condensate train at the Oben gas processing plant and make upgrades to the Sapele gas plant.

At OML 53 the Company plans to re-enter, complete, and bring onstream two oil production wells at the Ohaji South oil field and work over one oil production well at the Jisike oil field. The Company continues to high grade the large inventory of production drilling opportunities within the existing portfolio with a view to scaling up the forward work programme to efficiently capture the highest cash return production opportunities.

FINANCE REVIEW

Revenue

Gross revenue for H1 2018 was US$342.7 million, an increase of 160% compared to the same period in 2017 (H1 2017: US$131.8 million). Crude revenue was US$257.3 million for the first six months, a 131% increase from the same period in 2017 (H1 2017: US$111.2 million). Gas revenue for the period was US$85.3 million, a 57% increase from the same period in 2017 (H1 2017: US$54.4 million).

During the first six months the Group realised an average oil price of US$69.1/bbl (H1 2017: US$45.0/bbl) and an average gas price of US$3.04/Mscf (H1 2017: US$2.97/Mscf). Working interest sales volume for the period stood at 8.4 MMboe up from 4.8 MMboe during the same period in 2017. Total gas volumes sold were 28.0 Bscf (H1 2017: 18.3 Bscf), while total liquid (crude and condensate) volumes lifted during the first six months were 3.7 MMbbls (H1 2017: 1.7 MMbbls).

Gross profit

Gross profit for the first six months was US$174.3 million, an increase of 222% compared to the same period in 2017 (H1 2017: US$53.6 million). The movement is primarily driven by the higher level of oil production owing to increased uptime in the period, higher oil price realisations, increased gas sales and lower unit production opex which stood at US$4.50/boe (H1 2017: US$5.85/boe).

Operating profit

Operating profit for the first six months was US$158.4 million (H1 2017: US$7.2 million) and includes US$27.7 million recognised in relation to a crude oil underlift position while G&A costs were stable year-on-year at US$38.5 million (having seen a 27% reduction in H1 2017 to US$36.3 million through cost reduction initiatives).

Profit for the period

Profit before tax for the period was US$121.3 million (H1 2017: US$26.5 million loss before tax) after adjusting for net finance charges of US$37.1 million (H1 2017: US$33.7 million). The Group recognised non-cash corporate taxes and non-cash deferred tax of US$72.8 million in the period to record a net profit of US$48.5 million (H1 2017: US$27.6 million net loss).

Cash flows and liquidity

Cash flows from operating activities for the first six months was US$245.4 million, up 131% compared to the same period in 2017 (H1 2017: US$106.2 million). Capital investments in the first six months stood at US$21.2 million (H1 2017: US$11.2 million) and reflects limited development activity. The Group maintains guidance of US$100 million capital investments for the full year as it scales up development activities in the second half. The vast majority of the Group's capital expenditures are discretionary and it has the flexibility to align spend with cash flow on a rolling basis.

Having reached agreement in 2016 with partner BelemaOil on a revised commercial arrangement at OML 55, which provides for a discharge sum of US$330 million to be paid to Seplat over a six-year period through allocation of crude oil volumes, the Group received total proceeds of US$14.7 million in the period under this arrangement from the monetisation of 221 kbbls. Consequently, after adjusting for interest receipts of US$4.4 million, net cash outflow from investing activities for the first six months was US$2.1 million compared to a net cash inflow in H1 2017 of US$11.9 million.

In March the Group successfully refinanced its existing US$300 million revolving credit facility ("RCF") with a new four year US$300 million RCF at LIBOR + 6% (US$200 million drawn at 30 June 2018) and issued a debut US$350 million bond priced at 9.25%, diversifying the long term capital base. Proceeds from the re-financing were used to repay and cancel pre-existing indebtedness and also to cash settle crude oil prepayments undertaken during the extended period of force majeure in 2016 and 2017. The Group also reinstated a dividend of US$0.05/share and in doing so returned US$29.4 million to shareholders.

The Group has continued to receive the proceeds of gas sales from its partner NPDC in lieu of cash calls for ongoing operations. Tolling fees arising from NPDC's share of processed gas from the Oben Gas Expansion Project, which was financed on a sole risk basis by Seplat, are yet to be settled by NPDC and Seplat is currently in discussions with NPDC to finalise terms.

Overall Seplat's aggregate indebtedness at 30 June 2018 stood at US$550 million and cash at bank US$509.9 million to give a net debt position of US$40.1 million with US$100 million undrawn headroom on the RCF facility. The Group is well capitalised and fully funded to execute its organic growth plans and also well positioned to pursue inorganic growth opportunities in line with its price disciplined approach.

Hedging

The Company had in place dated Brent puts covering a volume of 3.6 MMbbls over H1 2018 at a strike price of US$40.0/bbl resulting in a realised hedging loss of US$2.5 million in the period. Over H2 2018 the Company has in place dated Brent puts covering a volume of 3.0 MMbbls at a strike price of US$50.0/bbl. The board and management continue to closely monitor prevailing oil market dynamics, and will consider further measures to provide appropriate levels of cash flow assurance in times of oil price weakness and volatility.

Principal risks and uncertainties

The Board of Directors is responsible for setting the overall risk management strategy of the Company and the determination of what level of risk is acceptable for Seplat to bear. The principal risks and uncertainties facing Seplat at the year-end are detailed in the risk management section of the 2017 Annual Report and Accounts. The board has identified the principal risks for the remainder of 2018 to be:

· Third party infrastructure downtime and the corresponding impact on oil and gas production levels

· Niger Delta stability and geo-political risk

· Oil price volatility

· Successful delivery of the planned work programme

Responsibility Statement

The Directors confirm that to the best of their knowledge:

a) The condensed set of financial statements have been prepared in accordance with lAS 34 'Interim Financial Report';

b) The interim management report includes a fair review of the information required by UK DTR 4.2.7R indication of important events during the first three months and description of principal risks and uncertainties for the remaining nine months of the year and 

c) The interim management report includes a fair review of the information required by UK DTR 4.2.8R disclosure of related parties' transactions and changes therein.

The Directors of Seplat Plc are as listed in the Group's 2017 Annual Report and Accounts. A list of current Directors is included on the company website: www.seplatpetroleum.com.

By order of the Board,

Important notice

The information contained within this announcement is deemed by the Company to constitute inside information as stipulated under the market Abuse Regulation. Upon the publication of this announcement via Regulatory Information Service, this inside information is now considered to be in the public domain.

Certain statements included in these results contain forward-looking information concerning Seplat's strategy, operations, financial performance or condition, outlook, growth opportunities or circumstances in the countries, sectors or markets in which Seplat operates. By their nature, forward-looking statements involve uncertainty because they depend on future circumstances, and relate to events, not all of which are within Seplat's control or can be predicted by Seplat. Although Seplat believes that the expectations and opinions reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations and opinions will prove to have been correct. Actual results and market conditions could differ materially from those set out in the forward-looking statements. No part of these results constitutes, or shall be taken to constitute, an invitation or inducement to invest in Seplat or any other entity, and must not be relied upon in any way in connection with any investment decision. Seplat undertakes no obligation to update any forward-looking statements, whether as a result of new information, future events or otherwise, except to the extent legally required.

Webcast and conference call

At 09:00 am BST (London) / 09:00 am WAT (Lagos), Austin Avuru (CEO), Effiong Okon (Operations Director and Roger Brown (CFO) will host a webcast and conference call to discuss the Company's results.

The webcast can be accessed via the Company's website http://seplatpetroleum.com/ or at the following address:

https://webconnect.webex.com/webconnect/onstage/g.php?MTID=e66192890bc2d50e24c8f3b8337487902 

To listen to the audio commentary only, participants can use the following telephone number:

Telephone Number (UK toll free and international access): +44 (0) 1452 569 393

Conference title: Seplat Petroleum Development Company - Interim Results

Conference ID: 8998566

If you are listening to the audio commentary and viewing the webcast, you may notice a slight delay to the rate the slides change on the webcast. If this is affecting you, please download the pdf slide pack from the Company's website http://seplatpetroleum.com/

Enquiries:

Notes to editors

Seplat Petroleum Development Company Plc is a leading indigenous Nigerian oil and gas exploration and production company with a strategic focus on Nigeria, listed on the Main Market of the London Stock Exchange ("LSE") (LSE:SEPL) and Nigerian Stock Exchange ("NSE") (NSE:SEPLAT).

Seplat is pursuing a Nigeria focused growth strategy and is well-positioned to participate in future divestment programmes by the international oil companies, farm-in opportunities and future licensing rounds. For further information please refer to the Company website, http://seplatpetroleum.com/

Report on review of interim condensed consolidated financial statements to the shareholders of Seplat Petroleum Development Company Plc

Introduction

We have reviewed the accompanying interim condensed consolidated financial statements of Seplat Petroleum Development Company Plc and its subsidiaries (the "Group"), which comprise the interim condensed consolidated statement of financial position as at 30 June 2018, statement of profit or loss and other comprehensive income, statement of changes in equity and statement of cash flows for the half year then ended, and explanatory notes. The Company's directors are responsible for the preparation and fair presentation of these interim condensed consolidated financial statements in accordance with IAS 34 Interim Financial Reporting and in the manner required by the Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria 2004 and the Financial Reporting Council of Nigeria Act, No. 6, 2011. Our responsibility is to express a conclusion on these interim condensed consolidated financial statements based on our review.

Scope of Review

We conducted our review in accordance with International Standard on Review Engagements 2410, Review of Interim Financial Information Performed by the Independent Auditor of the Entity. A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the accompanying interim condensed consolidated financial statements are not prepared, in all material respects, in accordance with IAS 34.

Bernard Carrena, FCA

FRC/2013/ICAN/00000000670

For Ernst & Young

Lagos, Nigeria

30 July 2018

Interim condensed consolidated statement of profit or loss and other comprehensive income

for the half year ended 30 June 2018

The above interim condensed consolidated statement of profit or loss and other comprehensive income should be read in conjunction with the accompanying notes.

Interim condensed consolidated statementof financial position

As at 30 June 2018

The above interim condensed consolidated statement of financial position should be read in conjunction with the accompanying notes.

Interim condensed consolidated statement offinancial position continued

As at 30 June 2018

The Group financial statements of Seplat Petroleum Development Company Plc and its subsidiaries for the half year ended 30 June 2018 were authorised for issue in accordance with a resolution of the Directors on 30 July 2018 and were signed on its behalf by

Interim condensed consolidated statementof changes in equity continued

for the half year ended 30 June 2018

The above interim condensed consolidated statement of changes in equity should be read in conjunction with the accompanying notes.

Interim condensed consolidated statement of cash flow

for the half year ended 30 June 2017

The above interim condensed consolidated statement of cashflows should be read in conjunction with the accompanying notes.

Notes to the interim condensed consolidatedfinancial statements

1. Corporate structure and business

Seplat Petroleum Development Company Plc ("Seplat" or the "Company"), the parent of the Group, was incorporated

on 17 June 2009 as a private limited liability company and re-registered as a public company on 3 October 2014, under

the Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria 2004. The Company commenced

operations on 1 August 2010. The Company is principally engaged in oil and gas exploration and production.

The Company's registered address is: 25a Lugard Avenue, Ikoyi, Lagos, Nigeria.

The Company acquired, pursuant to an agreement for assignment dated 31 January 2010 between the Company, SPDC,

TOTAL and AGIP, a 45% participating interest in the following producing assets:

OML 4, OML 38 and OML 41 are located in Nigeria. The total purchase price for these assets was ₦ 104 billion paid at the completion of the acquisition on 31 July 2010 and a contingent payment of ₦ 10 billion payable 30 days after the second anniversary, 31 July 2012, if the average price per barrel of Brent Crude oil over the period from acquisition up to 31 July 2012 exceeds ₦ 24,476 per barrel. ₦110 billion was allocated to the producing assets including ₦ 5.7 billion as the fair value of the contingent consideration as calculated on acquisition date. The contingent consideration of ₦ 10 billion was paid on 22 October 2012.

In 2013, Newton Energy Limited ("Newton Energy"), an entity previously beneficially owned by the same shareholders

as Seplat, became a subsidiary of the Company. On 1 June 2013, Newton Energy acquired from Pillar Oil Limited ("Pillar

Oil") a 40 percent Participant interest in producing assets: the Umuseti/Igbuku marginal field area located within OPL

283 (the "Umuseti/Igbuku Fields").

On 12 December 2014, Seplat Gas Company Limited ("Seplat Gas") was incorporated as a private limited liability company to engage in oil and gas exploration and production.

In 2015, the Group purchased a 40% participating interest in OML 53, onshore north eastern Niger Delta, from Chevron Nigeria Ltd for ₦ 79 billion.

In 2017, the Group incorporated a new subsidiary, ANOH Gas Processing Company Limited. The principal activities of the Company is the processing of gas from OML 53.

The Company together with its six wholly owned subsidiaries namely, Newton Energy, which was incorporated on 1June 2013, Seplat Petroleum Development Company UK Limited ("Seplat UK"), which was incorporated on 21 August 2014, Seplat East Onshore Limited ("Seplat East"), which was incorporated on 12 December 2014, Seplat East Swamp Company Limited ("Seplat Swamp"), which was incorporated on 12 December 2014, Seplat Gas Company Limited ("Seplat GAS"), which was incorporated on 12 December 2014 and ANOH Gas Processing Company Limited which was incorporated on 18 January 2017 are collectively referred to as the Group.

Notes to the interim condensed consolidatedfinancial statements continued

2. Significant changes in the current reporting period

The following significant changes occurred during the reporting period ended 30 June 2018:

· The offering of ₦107 billion in aggregate principal amount of 9.25% senior notes due April 2023 in March 2018. The notes have been issued by the Group and guaranteed by some of its subsidiaries. The proceeds of the notes are being used to refinance existing indebtedness and for general corporate purposes.

· The refinancing of an existing ₦91.8 billion revolving credit facility due in December 2018 with a new four year ₦91.8 billion revolving facility due June 2022 in March 2018. The facility has an initial interest rate of the 6% +Libor with interest payable semi-annually and principal repayable annually. ₦61.2 billion was drawn down in March 2018. The proceeds from the notes are being used to repay existing indebtedness.

· The issue of 25,000,000 additional shares in furtherance of the Group's Long Term Incentive Plan in February 2018. The additional issued shares are held by Stanbic IBTC Trustees Limited as Custodian. The Group's share capital as at the reporting date consists of 588,444,561 ordinary shares of N0.50k each, all with voting rights.

3. Summary of significant accounting policies

3.1 Introduction to summary of significant accounting policies

The accounting policies adopted are consistent with those of the previous financial year end corresponding interim reporting period, except for the adoption of new and amended standards which are set out below.

3.2 Basis of preparation

i) Compliance with IFRS

The interim condensed consolidated financial statements of the Group for the half year reporting period ended 30 June 2018 have been prepared in accordance with accounting standard IAS 34 Interim financial reporting.

ii) Historical cost convention

The financial information has been prepared under the going concern assumption and historical cost convention, except for contingent consideration and financial instruments measured at fair value on initial recognition. The financial statements are presented in Nigerian Naira and United States Dollars, and all values are rounded to the nearest million (₦'million) and thousand (US$'000) respectively, except when otherwise indicated.

iii) Going concern

Nothing has come to the attention of the directors to indicate that the Group will not remain a going concern for at least twelve months from the date of these interim condensed consolidated financial statements.

iv) 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 and make retrospective adjustments as a result of adopting the following standards.

· IFRS 9 Financial instruments,

· IFRS 15 Revenue from contracts with customers, and

· Amendments to IFRS 15 Revenue from contracts with customers.

The impact of the adoption of these standards and the new accounting policies are disclosed in note 3.3 below. The

other standards did not have any impact on the Group's accounting policies and did not require retrospective

adjustments.

Notes to the interim condensed consolidatedfinancial statements continued

v) New standards, amendments and interpretations not yet adopted

The following standards are issued but not yet effective and may have a significant impact on the Group's consolidated financial statements.

a. IFRS 16 Leases

b. Amendments to IAS 19 Employee benefits

These amendments were issued in February 2018. The amendments issued require an entity to use updated assumptions to determine current service cost and net interest for the remainder of the period after a plan amendment, curtailment or settlement. They also require an entity to recognise in profit or loss as part of past service cost or a gain or loss on settlement, any reduction in a surplus, even if that surplus was not previously recognised because of the impact of the asset ceiling.

These amendments are mandatory for annual periods beginning on or after 1 January 2019. The Group does not intend to adopt the amendment before its effective date.

c. IFRIC 23- Uncertainty over income tax treatment

These amendments were issued in June 2017. IAS 12 Income taxes specifies requirements for current and deferred tax assets and liabilities. An entity applies the requirements in IAS 12 based on applicable tax laws. It may be unclear how tax law applies to a particular transaction or circumstance. The acceptability of a particular tax treatment under tax law may not be known until the relevant taxation authority or a court takes a decision in the future. Consequently, a dispute or examination of a particular tax treatment by the taxation authority may affect an entity's accounting for a current or deferred tax asset or liability.

This Interpretation clarifies how to apply the recognition and measurement requirements in IAS 12 when there is uncertainty over income tax treatments. In such a circumstance, an entity shall recognise and measure its current or deferred tax asset or liability applying the requirements in IAS 12 based on taxable profit (tax loss), tax bases, unused tax losses, unused tax credits and tax rates determined applying this Interpretation.

These amendments are mandatory for annual periods beginning on or after 1 January 2019. The Group does not intend to adopt the amendment before its effective date.

d. Conceptual framework for financial reporting

These amendments were issued in March 2018. Included in the revised conceptual framework are revised definitions of an asset and a liability as well as new guidance on measurement and derecognition, presentation and disclosure. The amendments focused on areas not yet covered and areas that had shortcomings.

These amendments are mandatory for annual periods beginning on or after 1 January 2020. The Group does not intend to adopt the amendment before its effective date. 

Notes to the interim condensed consolidatedfinancial statements continued

e. Amendments to IAS 23 Borrowing costs

These amendments were issued in December 2017. The amendments clarify that if any specific borrowing remains outstanding after the related asset is ready for its intended use or sale, that borrowing becomes part of the funds that an entity borrows generally when calculating the capitalisation rate on general borrowings.

These amendments are mandatory for annual periods beginning on or after 1 January 2019. The Group does not intend to adopt the amendment before its effective date.

3.3 Changes in accounting policies

This note explains the impact of the adoption of IFRS 9: Financial Instruments and IFRS 15: Revenue from Contracts with Customers (including the amendments to IFRS 15) on the Group's financial statements and discloses the related accounting policies that have been applied from 1 January 2018.

3.3.1 Impact on the financial statements

Except as described below, the accounting policies applied in these interim financial statements are the same as those applied in the Group's consolidated financial statements for the year ended 31 December 2017.

As explained in note 3.3.2 below, IFRS 9: Financial instruments was adopted without restating comparative information. The adjustments arising from the new impairment rules are therefore not reflected in the statement of financial position as at 31 December 2017, but are recognised in the opening statement of financial position on 1 January 2018.

The Group has adopted IFRS 15: Revenue from Contracts with Customers using the simplified method, with the effect of applying this standard recognised at the date of initial application (1 January 2018). Accordingly, the information presented for 2017 financial year has not been restated but is presented, as previously reported, under IAS 18 and related interpretations. 

The following tables summarise the impact, net of tax, of transition to IFRS 9 and IFRS 15 for each individual line item for the reporting period ended 1 January 2018 and 30 June 2018. Line items that were not affected by the changes have not been included. As a result, the sub-totals and totals disclosed cannot be recalculated from the numbers provided. There was no impact on the statement of cash flows as a result of adopting the new standards.

Notes to the interim condensed consolidatedfinancial statements continued

Notes to the interim condensed consolidatedfinancial statements continued

3.3.2 IFRS 9 Financial Instruments - Impact of adoption

The new financial instruments standard, IFRS 9 replaces the provisions of IAS 39. The new standard presents a new model for classification and measurement of assets and liabilities, a new impairment model which replaces the incurred credit loss approach with an expected credit loss approach, and new hedging requirements.

The adoption of IFRS 9: Financial Instruments from 1 January 2018 resulted in changes in accounting policies and adjustments to the amounts recognised in the financial statements. The new accounting policies are set out in note below. In accordance with the transitional provisions in IFRS 9, comparative figures have not been restated.

3.3.2.1 Classification and measurement

a) Financial assets

On 1 January 2018 (the date of initial application of IFRS 9), the Group's management assessed the classification of its financial assets which is driven by the cash flow characteristics of the instrument and the business model in which the asset is held.

The Group's financial assets includes cash and cash equivalents, trade and other receivables and contract assets. The Group's business model is to hold these financial assets to collect contractual cash flows and to earn contractual interest. For cash and cash equivalents, interest is based on prevailing market rates of the respective bank accounts in which the cash and cash equivalents are domiciled. Interest on trade and other receivables is earned on defaulted payments in accordance with the joint operating agreement (JOA). The contractual cash flows arising from these assets represent solely payments of principal and interest (SPPI).

Cash and cash equivalents, trade and other receivables and contract assets that have previously been classified as loans and receivables (L and R) are now classified at amortised cost.

Since there was no change in the measurement basis except for nomenclature change, opening retained earnings was not impacted (no differences between the previous carrying amount and the revised carrying amount of these assets at 1 January 2018).

b) Financial liabilities

Following the adoption of IFRS 9, the Group no longer has a choice to either recognise gain or loss from the refinancing of a borrowing on day 1 or defer any gain or loss over the remaining life of the borrowing by adjusting the effective interest rate, on the basis that the terms and conditions of the facility remained largely unchanged. Day one gain or loss must now be recognised at once. No retrospective adjustments have been made in relation to this change as at 1 January 2018.

Notes to the interim condensed consolidatedfinancial statements continued

On the date of initial application of, 1 January 2018, the financial instruments of the Group were classified as follows:

*Other receivables exclude NGMC VAT receivables, cash advance and advance payments.

** Trade and other payables excludes accruals, provisions, bonus, VAT, Withholding tax, deferred revenue and royalties.

3.3.2.2 Impairment of financial assets

The total impact on the Group's retained earnings as at 1 January 2018 and on profit for the period as at 30 June 2018is as follows:

Notes to the interim condensed consolidatedfinancial statements continued

The Group has six types of financial assets that are subject to IFRS 9's new expected credit loss model. The Group was

required to revise its impairment methodology under IFRS 9 for each of these classes of assets. The impact of the change in impairment methodology on the Group's retained earnings is disclosed in the table in note 3.3.2 above.

§ Nigerian Petroleum Development Company (NPDC) receivables

§ National Petroleum Investment Management Services (NAPIMS)

§ Trade receivables

§ Contract assets

§ Other receivables and;

§ Cash and cash equivalents

a) Nigerian Petroleum Development Company (NPDC) receivables

The Group applies the IFRS 9 general model to measuring expected credit losses (ECL) which uses a three-stage approach in recognising the expected loss allowance for NPDC receivables. NPDC receivables represent the outstanding cash calls due to Seplat from its JV partner, Nigerian Petroleum Development Company

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

The ECL was calculated based on actual credit loss experience from 2014, which is the date the Group initially became a party to the contract. The following analysis provides further detail about the calculation of ECLs related to these assets. The Group considers the model and the assumptions used in calculating these ECLs as key sources of estimation uncertainty.

Loss rate was calculated as the portion of the receivables that have been deemed uncollectible during a particuar period, as a percentage of the outstanding receivables over the same reporting period. The expected loss rate at the end of the reporting period was 7.6%.

The outstanding net NPDC receivables at the end of the reporting period has been netted off against the gas receipts payable to NPDC.

1 January 2018

*Exposure of default

30 June 2018

The Group considers both quantitative and qualitative indicators in classifying its receivables into the relevant stages for impairment calculation.

*Stage 1 includes receivables that are less than 30 days past due (Performing).

*Stage 2 includes receivables that have been assessed to have experienced a significant increase in credit risk using the days past due criteria (i.e the outstanding receivables amount are more than 30 days past due but less than 90 days past due) and other qualitative indicators such as the increase in political risk concerns or other micro-economic factors and the risk of legal action, sanction or other regulatory penalties that may impair future financial performance.

*Stage 3 receivables are receivables that have been assessed as being in default( i.e receivables that are more than 90 days past due) or there is a clear indication that the imposition of financial or legal penalties and/or sanctions will make the full recovery of indebtedness highly improbable.

Notes to the interim condensed consolidatedfinancial statements continued

The reconciliation of loss allowances for Nigerian Petroleum Development Company (NPDC) receivables as at 1 January 2018 and 30 June 2018 is as follows:

Probability of default (PD)

The credit rating of Federal Government bonds was used to reflect the assessment of the probability of default on these receivables. This was supplemented with external data from credit bureau scoring information from Standard & Poor's (S&P) to arrive at a 12-month PD of 3.9%. Lifetime PD (stage 2) was assumed to be the 12-month PD as the maximum contractual period over which the Group is exposed to credit risk is less than 12 months. The PD for Stage 3 receivables was 100% as these amounts were deemed to be in default using the days past due criteria. (See note 3.3.3 for definition of default).

Loss given default (LGD)

The 12-month LGD was calculated as the present value of the percentage loss on the outstanding receivables adjusted with forward looking macroeconomic indicators. The 12-month LGD assumptions are a reasonable proxy of lifetime LGD.

Exposure at default (EAD)

This is the amount that best represents the maximum exposure to credit risk at the end of the reporting period without taking account of any collateral.

Macroeconomic indicators

The real historical gross domestic product (GDP) growth rate in Nigeria and crude oil price were identified as the key economic variables impacting the credit risk on these receivables. Forecasts of these economic variables ( the "base economic scenario") provide the best estimate view of the economy in the last ten (10) years. In addition to the base economic scenario, two additional scenarios (optimistic and downturn) were used along with scenario weightings.

The probability weight attached to each of the scenarios was determined using the GDP growth rates. The historical GDP growth rates were evaluated at 75% confidence interval. Based on this confidence interval, 75% of historical GDP growth rate observation falls within the acceptable bounds, 8% of the observation relates to period of boom while 17% of the observation relate to periods of recession/downturn.

b) National Petroleum Investment Management Services (NAPIMS) receivables

The Group applies the IFRS 9 general model to measuring expected credit losses (ECL) which uses a three-stage approach in recognising the expected loss allowance for NAPIMS receivables. NAPIMS receivables represent the outstanding cash calls due to Seplat from its JV partner, National Petroleum Investment Management Services

The ECL was calculated based on actual credit loss experience from 2016, which is the date the Group initially became a party to the contract. The following analysis provides further detail about the calculation of ECLs related to these assets. The Group considers the model and the assumptions used in calculating these ECLs as key sources of estimation uncertainty. The explanation of inputs, assumptions and estimation techniques used are consistent with those for NPDC receivables.

Loss rate was calculated as the portion of the receivables that have been deemed uncollectible during a particuar period, as a percentage of the outstanding receivables over the same reporting period. The expected loss rates at the end of the reporting period for NAPIMS receivables in Stage 1 and Stage 3 were 1.85% and 47.8% respectively.

Notes to the interim condensed consolidatedfinancial statements continued

1 January 2018

30 June 2018

The Group considers both quantitative and qualitative indicators in classifying its receivables into the relevant stages for impairment calculation.

*Stage 1 includes receivables that are less than 30 days past due (Performing).

*Stage 2 includes receivables that have been assessed to have experienced a significant increase in credit risk using the days past due criteria (i.e the outstanding receivables amount are more than 30 days past due but less than 90 days past due) and other qualitative indicators such as the increase in political risk concerns or other micro-economic factors and the risk of legal action, sanction or other regulatory penalties that may impair future financial performance.

 *Stage 3 receivables are receivables that have been assessed as being in default( i.e receivables that are more than 90 days past due) or there is a clear indication that the imposition of financial or legal penalties and/or sanctions will make the full recovery of indebtedness highly improbable.

The reconciliation of loss allowances for National Petroleum Investment Management Services receivables as at 1 January 2018 and 30 June 2018 is as follows:

c) Trade receivables and contract assets

The Group applies the IFRS 9 simplified approach to measuring expected credit losses which uses a lifetime expected loss allowance for all trade receivables and contract assets.

To measure the expected credit losses, trade receivables and contract assets have been grouped based on shared credit risk characteristics and the days past due criterion. Contract assets relate to unbilled receivables for the delivery of gas supplies in which NGMC has taken delivery of but has not been invoiced as at the end of the reporting period. These assets have substantially the same risk characteristics as the trade receivables for the same types of contracts. The Group has therefore concluded that the expected loss rates for trade receivables are a reasonable approximation of the loss rates for the contract assets.

Trade receivables and contract assets include amounts receivable from Mercuria Energy Group, Shell Western Supply, Pillar Limited and Nigerian Gas Marketing Company (NGMC).

For Mecuria Energy Group and Shell Western Supply, impairment was assessed to be immaterial as there has been no history of default (i.e. the Group receives the outstanding amount within the standard payment period of 30 days) and there has been no dispute arising on the invoiced amount from both parties.

Notes to the interim condensed consolidatedfinancial statements continued

The Group also assessed for impairment on receivable balances from Pillar Limited and Nigerian Gas Marketing Company (NGMC) using outstanding payments to model the expected loss rates. Based on this assessment, the identified impairment loss as at 1 January 2018 and 30 June 2018 was immaterial as there has been no history of default or dispute on the receivables. The impairment allowance on these assets was nil under the incurred loss model of IAS 39.

d) Other receivables

The Group applies the IFRS 9 simplified approach to measuring expected credit losses which uses a lifetime expected loss allowance for all financial assets that are classified within other receivables.

Other receivables relate to staff receivables and an amount receivable from SPDC for an investment no longer being pursued. Impairment allowance on both receivable amounts were assessed to be immaterial.

For staff receivables, this was on the basis that there has been no history of default on these assets as repayments are deducted directly from the staff's monthly salary. In addition, the outstanding balance as at the 30 June 2018 and

31 December 2017 was deemed to be immaterial ₦718,865 (2017: ₦4.5 million). The impairment was nil under the incurred loss model of IAS 39.

The amount of loss allowance for the receivables arising from the settlement of the investment in OML 25 as a result of applying the simplified approach was immaterial as the receivables are assessed to be fully recoverable and less than 30 days past due as at the reporting date. The impairment was nil under the incurred loss model of IAS 39.

e) Cash and cash equivalents

While cash and cash equivalents are also subject to the impairment requirements of IFRS 9, the identified impairment loss was immaterial.

3.3.2.3 Hedge accounting

As at the reporting periods ended 31 December 2017 and 30 June 2018, the Group had no derivative assets or liabilities. However, the Group entered agreements to sell put options for crude oil in Brent at a strike price of ₦12,236 per barrel to NedBank Limited for 600,000 barrels within a period of 6 months from 1 January 2018 to 30 June 2018.

It also entered into agreements to sell put options for crude oil in Brent at a strike price of ₦15,295 per barrel to Natixis for 500,000 barrels within a period of 6 months from 1 July 2018 to 31 December 2018.

The purpose of these is to hedge its cash flows against oil price risk. The contracts provide for a no loss position for Seplat, in that Seplat makes a gain if the price of oil falls below the strike price; and if the price of oil is above the strike price, there is no loss i.e. no payment is made by Seplat except for the mutually agreed monthly premium which is paid in arrears and is settled net of any gain on settlement date.

These contracts however, are not designated as hedging instruments, and as such hedge accounting is not being applied. In the event where the Group takes the option of designating its derivative as hedging instruments, the Group would need to make a formal designation and documentation of the hedging relationship and the Group's risk management objective and strategy for undertaking the hedge.

3.3.3 IFRS 9: Financial Instruments - Accounting policies applied from 1 January 2018 

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

a) Classification and measurement

§ Financial assets

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

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

Notes to the interim condensed consolidatedfinancial statements continued

All the Group's financial assets as at 30 June 2018 satisfy the conditions for classification at amortised cost under IFRS 9.

The Group's financial assets include trade receivables, NPDC receivables, NAPIMS receivables, contract assets, other receivables and cash and cash equivalents.

§ Financial liabilities

Financial liabilities of the Group are classified and subsequently recognised at amortised cost net of directly attributable transaction costs, except for derivatives which are classified and subsequently recognised at fair value through profit or loss.

Fair value gains or losses for financial liabilities designated at fair value through profit or loss are accounted for in profit or loss except for the amount of change that is attributable to changes in the Group's own credit risk

which is presented in other comprehensive income. The remaining amount of change in the fair value of the liability is presented in profit or loss. The Group's financial liabilities include trade and other payables and interest bearing loans and borrowings.

b) Impairment of financial assets

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

The Group applies the simplified approach or the three-stage general approach to determine impairment of receivables depending on their respective nature. The simplified approach is applied for trade receivables and contract assets while the three-stage approach is applied to NPDC receivables, NAPIMS receivables and other receivables.

The simplified approach requires expected lifetime losses to be recognised from initial recognition of the receivables. This involves determining the expected loss rates which is then applied to the gross carrying amount of the receivable to arrive at the loss allowance for the period.

The three-stage approach assesses impairment based on changes in credit risk since initial recognition using the past due criterion. Financial assets classified as stage 1 have their ECL measured as a proportion of their lifetime ECL that results from possible default events that can occur within one year, while assets in stage 2 or 3 have their ECL measured on a lifetime basis.

Under the three-stage approach, the ECL is determined by projecting the probability of default (PD), loss given LGD and EAD for each ageing bucket and for each individual exposure. The PD is based on default rates determined by external rating agencies for the counterparties. The LGD assesses the portion of the outstanding receivable that is deemed to be irrecoverable at the reporting period. These three components are multiplied together and adjusted using macro-economic indicators. This effectively calculates an ECL which is then discounted back to the reporting date and summed. The discount rate used in the ECL calculation is the original effective interest rate or an approximation thereof.

Loss allowances for financial assets measured at amortised cost are deducted from the gross carrying amount of the related financial assets and the amount of the loss is recognised in profit or loss.

c) Derecognition

§ Financial assets

The Group derecognises a financial asset when the contractual rights to the cash flows from the financial asset expire or when it transfers the financial asset and the transfer qualifies for derecognition.

The Group's financial assets include trade receivables, NPDC receivables, NAPIMS receivables, contract assets, other receivables and cash and cash equivalents.

§ Financial liabilities

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

Notes to the interim condensed consolidatedfinancial statements continued

d) Significant increase in credit risk and default definition

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

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

In line with the Group's credit risk management practices, a financial asset is defined to be in default when contractual payments have not been received at least 90 days after the contractual payment period. Subsequent to default, the Group carries out active recovery strategies to recover all outstanding payments due on receivables. Where the Group determines that there are no realistic prospects of recovery, the financial asset and any related loss allowance is written off either partially or in full.

3.3.4 IFRS 15 Revenue from Contracts with Customers - Impact of adoption 

The Group has adopted IFRS 15 Revenue from Contracts with Customers from 1 January 2018 which resulted in changes in accounting policies and adjustments to the amounts recognised in the financial statements. In accordance with the transition provisions in IFRS 15, the Group has applied the modified retrospective approach and has not restated comparatives for the 2017 financial year. There was no impact on the Group's retained earnings at the date of initial application (i.e. 1 January 2018).

The analysis below shows the impact on the statement of financial position and statement of other comprehensive income for the period ended 30 June 2018.

3.3.4.1. Presentation of contract assets

a) Trade and other receivables

The Group introduced the presentation of contract assets in the balance sheet to reflect the guidance of IFRS 15. Contract assets recognised in relation to unbilled revenue from Nigerian Gas Marketing Company (NGMC) were previously presented as part of trade and other receivables.

3.3.4.2. Reclassifications

The following reclassification adjustments were made in the current reporting period to recognise the impact of the initial application of IFRS 15.

Notes to the interim condensed consolidatedfinancial statements continued

a) Reclassification of underlifts to other income

In some instances, Joint ventures (JV) partners lift the share of production of other partners. Under IAS 18, over lifts and underlifts were recognised net in revenue using entitlement accounting. They are settled at a later period through future liftings and not in cash (non-monetary settlements). This is referred to as the entitlement method. IFRS 15 excludes transactions arising from arrangements where the parties are participating in an activity together and share the risks and benefits of that activity as the counterparty is not a customer. To reflect the change in policy, the Group has reclassified underlifts to other income.

b) Reclassification of demurrage from costs of sales

Seplat pays demurrage to Mercuria for delays caused by incomplete cargoes delivered at the port. These are referred to as price adjustments and Seplat is billed subsequently by Mercuria. Under IFRS 15, these are considerations payable to customers and should be recognised net of revenue. Revenue has therefore been recognised net of demurrage costs. In the current period, there was a refund of demurrage which has been added to revenue. In prior reporting periods, demurrage costs were included as part of operations and maintenance costs.

3.3.4.3. Financing component

The Group does not have any contracts where the period between the transfer of the promised goods or services to the customer and payment by the customer exceeds one year. As a result, the Group does not adjust any of the transaction prices for the time value of money.

3.3.5 IFRS 15 Revenue from Contracts with Customers - Accounting policies

The Group has adopted IFRS 15 as issued in May 2014 which has resulted in changes in the accounting policy of the Group. IFRS 15 replaces IAS 18 which covers revenue arising from the sale of goods and the rendering of services, IAS 11 which covers construction contracts, and related interpretations. In accordance with the transitional provisions in IFRS 15, comparative figures have not been restated as the Group has applied the modified retrospective approach in adopting this standard.

IFRS 15 introduces a five-step model for recognising revenue to depict transfer of goods or services. The model distinguishes between promises to a customer that are satisfied at a point in time and those that are satisfied over time.

a) Revenue recognition

It is the Group's policy to recognise revenue from a contract when it has been approved by both parties, rights have been clearly identified, payment terms have been defined, the contract has commercial substance, and collectability has been ascertained as probable. Collectability of customer's payments is ascertained based on the customer's historical records, guarantees provided, the customer's industry and advance payments made if any.

Revenue is recognised when control of goods sold has been transferred. Control of an asset refers to the ability to direct the use of and obtain substantially all of the remaining benefits (potential cash inflows or savings in cash outflows) associated with the asset. For crude oil, this occurs when the crude products are lifted by the customer (buyer) Free on Board at the Group's loading facility. . Revenue from the sale of oil is recognised at a point in time when performance obligation is satisfied. For gas, revenue is recognised when the product passes through the custody transfer point to the customer. Revenue from the sale of gas is recognised over time using the practical expedient of the right to invoice.

The surplus or deficit of the product sold during the period over the Group's ownership share of production is termed as an overlift or underlift. With regard to underlifts, if the over-lifter does not meet the definition of a customer or the settlement of the transaction is non-monetary, a receivable and other income is recognised. Conversely, when an overlift occurs, cost of sale is debited and a corresponding liability is accrued. Overlifts and underlifts are initially measured at the market price of oil at the date of lifting, consistent with the measurement of the sale and purchase. Subsequently, they are remeasured at the current market value. The change arising from this remeasurement is included in the profit or loss as other income or cost of sales.

Notes to the interim condensed consolidatedfinancial statements continued

§ Definition of a customer

A customer is a party that has contracted with the Group to obtain crude oil or gas products in exchange for a consideration, rather than to share in the risks and benefits that result from sale. The Group has entered into collaborative arrangements with its Joint venture partners to share in the production of oil. Collaborative arrangements with its Joint venture partners to share in the production of oil are accounted for differently from arrangements with customers as collaborators share in the risks and benefits of the transaction, and therefore, do not meet the definition of customers. Revenue arising from these arrangements are recognised separately in other income.

§ Identification of performance obligation

At inception, the Group assesses the goods or services promised in the contract with a customer to identify as a performance obligation, each promise to transfer to the customer either a distinct good or series of distinct goods. The number of identified performance obligations in a contract will depend on the number of promises made to the customer. The delivery of barrels of crude oil or units of gas are usually the only performance obligation included in oil and gas contract with no additional contractual promises. Additional performance obligations may arise from future contracts with the Group and its customers.

The identification of performance obligations is a crucial part in determining the amount of consideration recognised as revenue. This is due to the fact that revenue is only recognised at the point where the performance obligation is fulfilled, Management has therefore developed adequate measures to ensure that all contractual promises are appropriately considered and accounted for accordingly.

§ Contract enforceability and termination clauses

The Group may enter into contracts that do not create enforceable rights and obligation to parties in the contract. Such instances may include where the counterparty has not met all conditions necessary to kick start the contract or where a non-contractual promise exists between both parties to the agreement. In these instances, the agreement is not yet a valid contract and therefore no revenue can be recognised. The agreement between Seplat and PanOcean is not a valid contract. Therefore, it may not be appropriate to reclassify the outstanding balance from deferred revenue to contract liability. The outstanding balance has been included as part of accruals and other payables.

No amount has been recognized in revenue in relation to the transaction''

It is the Group's policy to assess that the defined criteria for establishing contracts that entail enforceable rights and obligations are met. The criteria provides that the contract has been approved by both parties, rights have been clearly identified, payment terms have been defined, the contract has commercial substance, and collectability has been ascertained as probable.

The Group may enter into contracts that do not meet the revenue recognition criteria. In such cases, the consideration received will only be recognised as revenue when the contract is terminated.

The Group may also have the unilateral rights to terminate an unperformed contract without compensating the other party. This could occur where the Group has not yet transferred any promised goods or services to the customer and the Group has not yet received, and is not yet entitled to receive, any consideration in exchange for promised goods or services.

b) Transaction price

Transaction price is the amount that an entity allocates to the performance obligations identified in the contract. It represents the amount of revenue recognised as those performance obligations are satisfied. Complexities may arise where a contract includes variable consideration, significant financing component or consideration payable to a customer.

Variable consideration not within the Group's control is estimated at the point of revenue recognition and reassessed periodically. The estimated amount is included in the transaction price to the extent that it is highly probable that a significant reversal of the amount of cumulative revenue recognised will not occur when the uncertainty associated with the variable consideration is subsequently resolved. As a practical expedient, where the Group has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the Group's performance completed to date, the Group may recognise revenue in the amount to which it has a right to invoice.

Significant financing component (SFC) assessment is carried out (using a discount rate that reflects the amount charged in a separate financing transaction with the customer and also considering the Group's incremental borrowing rate) on contracts that have a repayment period of more than 12 months. As a practical expedient, the Group does not adjust the promised amount of consideration for the effects of a significant financing component if it expects, at contract inception, that the period between when it transfers a promised good or service to a customer and when the customer pays for that good or service will be one year or less.

Notes to the interim condensed consolidatedfinancial statements continued

Instances when SFC assessment may be carried out include where the Group receives advance payment for agreed volumes of crude oil or receivables take or pay deficiency payment on gas sales. Take or pay gas sales contract ideally provides that the customer must sometimes pay for gas even when not delivered to the customer.

The customer, in future contract years, takes delivery of the product without further payment. The portion of advance payments that represents significant financing component will be recognised as interest revenue.

Consideration payable to a customer is accounted for as a reduction of the transaction price and, therefore, of revenue unless the payment to the customer is in exchange for a distinct good or service that the customer transfers to the Group. Examples include barging costs incurred, demurrage and freight costs. These do not represent a distinct service transferred and is therefore recognised as a direct deduction from revenue.

c) Breakage

The Group enters into take or pay contracts for sale of gas where the buyer may not ultimately exercise all of their rights to the gas. The take or pay quantity not taken is paid for by buyer called take or pay deficiency payment. The Group assesses if there is a reasonable assurance that it will be entitled to a breakage amount. Where it establishes that a reasonable assurance exists, it recognises the expected breakage amount as revenue in proportion to the pattern of rights exercised by the customer. However, where the Group is not reasonably assured of a breakage amount, it would only recognise the expected breakage amount as revenue when the likelihood of the customer exercising its remaining rights becomes remote.

d) Contract modification and contract combination

Contract modifications relates to a change in the price and/or scope of an approved contract. Where there is a contract modification, the Group assesses if the modification will create a new contract or change the existing enforceable rights and obligations of the parties to the original contract.

Contract modifications are treated as new contracts when the performance obligations are separately identifiable and transaction price reflects the standalone selling price of the crude oil or the gas to be sold. Revenue is adjusted prospectively when the crude oil or gas transferred is separately identifiable and the price does not reflect the standalone selling price. Conversely, if there are remaining performance obligations which are not separately identifiable, revenue will be recognised on a cumulative catch-up basis when crude oil or gas is transferred.

The Group enters into new contracts with its customers only on the expiry of the old contract. In the new contracts, prices and scope may be based on terms in the old contract. In gas contracts, prices change over the course of time. Even though gas prices change over time, the changes are based on agreed terms in the initial contract i.e. price change due to consumer price index. The change in price is therefore not a contract modifications. Any other change expected to arise from the modification of a contract is implemented in the new contracts.

The Group combines contracts entered into at near the same time (less than 12 months) as one contract if they are entered into with the same or related party customer, the performance obligations are the same for the contracts and the price of one contract depends on the other contract.

e) Portfolio expedients

As a practical expedient, the Group may apply the requirements of IFRS 15 to a portfolio of contracts (or performance obligations) with similar characteristics if it expects that the effect on the financial statements would not be materially different from applying IFRS to individual contracts within that portfolio.

f) Contract assets and liabilities

The Group recognises contract assets for unbilled revenue from crude oil and gas sales. A contract liability is consideration received for which performance obligation has not been met.

g) Disaggregation of revenue from contract with customers

The Group derives revenue from two types of products, oil and gas. The Group has determined that the disaggregation of revenue based on the criteria of type of products meets the revenue disaggregation disclosure requirement of IFRS 15 as it depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors. See further details in note 6

3.4 Basis of consolidation

The consolidated financial statements comprise the financial statements of the Company and its subsidiaries as at 30 June 2018. This basis of consolidation is the same adopted for the last audited financial statements as at 31 December 2017. 

Notes to the interim condensed consolidatedfinancial statements continued

3.5 Functional and presentation currency

Items included in the financial statements of the Company and the subsidiaries are measured using the currency of the primary economic environment in which the subsidiaries operate ('the functional currency'), which is the US dollar except for the UK subsidiary which is the Great Britain Pound. The interim condensed consolidated financial statements are presented in the Nigerian Naira and the US Dollars.

The Group has chosen to show both presentation currencies and this is allowable by the regulator.

i) Transactions and balances

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

Foreign exchange gains and losses that relate to borrowings are presented in the statement of profit or loss, within finance costs. All other foreign exchange gains and losses are presented in the statement of profit or loss on a net basis within other income or other expenses.

Non-monetary items that are measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value was determined. Translation differences on assets and liabilities carried at fair value are reported as part of the fair value gain or loss or other comprehensive income depending on where fair value gain or loss is reported.

ii) Group companies

The results and financial position of foreign operations that have a functional currency different from the presentation currency are translated into the presentation currency as follows:

§ assets and liabilities for each statement of financial position presented are translated at the closing rate at the reporting date.

§ income and expenses for each statement of profit or loss and statement of comprehensive income are translated at average exchange rates (unless this is not - a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the respective exchange rates that existed on the dates of the transactions), and

§ all resulting exchange differences are recognised in other comprehensive income.

On disposal of a foreign operation, the component of other comprehensive income relating to that particular foreign operation is recognised in profit or loss.

4. Significant accounting judgements, estimates and assumptions

4.1 Judgements

Management's judgements at the end of the half year are consistent with those disclosed in the recent 2017 Annual financial statements. The following are some of the judgements which have the most significant effect on the amounts recognised in this consolidated financial statements.

i) OMLs 4, 38 and 41

OMLs 4, 38, 41 are grouped together as a cash generating unit for the purpose of impairment testing. These three OMLs are grouped together because they each cannot independently generate cash flows. They currently operate as a single block sharing resources for the purpose of generating cash flows. Crude oil and gas sold to third parties from these OMLs are invoiced together.

Notes to the interim condensed consolidatedfinancial statements continued

ii) New tax regime

Effective 1 January 2013, the Company was granted the inter tax status incentive by the Nigerian Investment Promotion Commission for an initial three-year period and a further two-year period on approval. For the period the incentive applies, the Company is exempted from paying petroleum profits tax on crude oil profits (which was taxed at 65.75% but increased to 85% in 2017), corporate income tax on natural gas profits (currently taxed at 30%) and education tax of 2%. The Company has completed its first three years of the pioneer tax status and now required to pay the full petroleum profits tax on crude oil profits, corporate income tax on natural gas profits and education tax of 2%.

Newton Energy and Seplat East Onshore Limited (OML 53) were also granted pioneer tax status on the same basis as the company. Tax incentives do not apply to Seplat East Swamp Company Limited (OML 55), as it had no activities at the time the incentives were granted to Seplat and Newton Energy.

Deferred tax assets have been recognised during the half year period. Deferred tax liabilities are not recognised in the half year period as the Group was not liable to make future income taxes payment in respect of taxable temporary differences.

iii) Unrecognised deferred tax asset

Deferred income tax assets are recognised for tax losses carried forward to the extent that the realisation of the related tax benefit through future taxable profits is probable. See further details in note 15.

iv) Defined benefit plan

The Group has placed reliance on the actuarial valuations carried at the year end reporting period as it does not expect material differences in the assumptions used for that period and the current period assumptions. All assumptions are reviewed annually.

v) Revenue recognition

§ Definition of contracts

The Group has entered into a non-contractual promise with PanOcean where it allows Panocean to pass crude oil through its pipelines from a field just above Seplat's to the terminal for loading. Management has determined that the non-existence of an enforceable contract with Panocean means that it may not be viewed as a valid contract with a customer. As a result, income from this activity is recognised as other income.

§ Performance obligations

The judgments applied in determining what constitutes a performance obligation will impact when control is likely to pass and therefore when revenue is recognised i.e. over time or at a point in time. The Group has determined that only one performance obligation exists in oil contracts which is the delivery of crude oil to specified ports. Revenue is therefore recognised at a point in time.

For gas contracts, the performance obligation is satisfied through the delivery of a series of distinct goods. Revenue is recognised over time in this situation as NGMC simultaneously receives and consumes the benefits provided by the Group's performance. The Group has elected to apply the 'right to invoice' practical expedient in determining revenue from its gas contracts. The right to invoice is a measure of progress that allows the Group to recognise revenue based on amounts invoiced to the customer. Judgement has been applied in evaluating that the Group's right to consideration corresponds directly with the value transferred to the customer and is therefore eligible to apply this practical expedient.

§ Significant financing component

The Group has entered into an advance payment contract with Mercuria for future crude oil to be delivered. The Group has considered whether the contract contains a financing component and whether that financing component is significant to the contract, including both of the following;

(a) The difference ,if any, between the amount of promised consideration and cash selling price and;

(b) The combined effect of both the following:

- The expected length of time between when the Group transers the crude to Mecuria and when payment for the crude is recieved and;

- The prevailing interest rate in the relevant market.

The advance period is greater than 12 months. In addition, the interest expense accrued on the advance is based on a comparable market rate. Interest expense has therefore been included as part of finance cost.

Notes to the interim condensed consolidatedfinancial statements continued

§ Transactions with Joint Venture (JV) partners

The treatment of underlift and overlift transactions is judgmental and requires a consideration of all the facts and circumstances including the purpose of the arrangement and transaction. The transaction between the Group and its JV partners involves sharing in the production of crude oil, and for which the settlement of the transaction is non-monetary. The JV partners have been assessed to be partners not customer. Therefore, shortfalls or excesses below or above the Group's share of production are recognised in other income and cost of sales respectively.

§ Barging costs

The Group refunds to Mercuria barging costs incurred on crude oil barrels delivered. The Group does not enjoy a separate service as it would have had to pay another party for the delivery of crude oil. The barging costs is therefore determined to be a consideration payable to customer as there is no distinct goods or service being enjoyed by Group. Since no distinct good or service is transferred, barging costs is accounted for as a direct deduction from revenue i.e. revenue is recognised net of barging

vi) Segment reporting

Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision maker.

The Board of directors has appointed a steering committee which assesses the financial performance and position of the Group, and makes strategic decisions. The steering committee, which has been identified as being the chief operating decision maker, consists of the chief financial officer, the general manager (Finance), the general manager (Gas) and the financial reporting manager. See further details in note 6.

4.2 Estimates and assumptions

The key assumptions concerning the future and the other key source of estimation uncertainty that have a significant risk of causing a material adjustment to the carrying amount of assets and liabilities are disclosed in the most recent 2017 annual financial statements.

The following are some of the estimates and assumptions made.

i) Defined benefit plans

The cost of the defined benefit retirement plan and the present value of the retirement obligation are determined using actuarial valuations. An actuarial valuation involves making various assumptions that may differ from actual developments in the future. These include the determination of the discount rate, future salary increases, mortality rates and changes in inflation rates.

Due to the complexities involved in the valuation and its long-term nature, a defined benefit obligation is highly sensitive to changes in these assumptions. The parameter most subject to change is the discount rate. In determining the appropriate discount rate, management considers market yield on federal government bonds in currencies consistent with the currencies of the post-employment benefit obligation and extrapolated as needed along the yield curve to correspond with the expected term of the defined benefit obligation.

The rates of mortality assumed for employees are the rates published in 67/70 ultimate tables, published jointly by the Institute and Faculty of Actuaries in the UK.

ii) Contingent consideration

During the reporting period, the Group continued to recognise the contingent consideration of ₦5.7 billion for OML 53 at the fair value of ₦5.6 billion (2017: ₦4.2 billion). It is contingent on oil price rising above US$90 (₦ 27,535) per barrel over a one year period and expirirng on 31st January 2020.

iii) Income taxes

The Group is subject to income taxes by the Nigerian tax authority, which does not require significant judgement in terms of provision for income taxes, but a certain level of judgement is required for recognition of deferred tax assets. Management is required to assess the ability of the Group to generate future taxable economic earnings that will be used to recover all deferred tax assets. Assumptions about the generation of future taxable profits depend on management's estimates of future cash flows. The estimates are based on the future cash flow from operations taking into consideration the oil and gas prices, volumes produced, operational and capital expenditure.

Notes to the interim condensed consolidatedfinancial statements continued

iv) Impairment of financial assets

The loss allowances for financial assets are based on assumptions about risk of default, expected loss rates and maximum contractual period. The Group uses judgement in making these assumptions and selecting the inputs to the impairment calculation, based on the Group's past history, existing market conditions as well as forward looking estimates at the end of each reporting period. Details of the key assumptions and inputs used are disclosed note 3.3.3.

5. Financial risk management

5.1 Financial risk factors

The Group's activities expose it to a variety of financial risks such as market risk (including foreign exchange risk, interest rate risk and commodity price risk), credit risk and liquidity risk. The Group's risk management programme focuses on the unpredictability of financial markets and seeks to minimise potential adverse effects on the Group's financial performance.

Risk management is carried out by the treasury department under policies approved by the Board of Directors. The Board provides written principles for overall risk management, as well as written policies covering specific areas, such as foreign exchange risk, interest rate risk, credit risk and investment of excess liquidity.

5.1.1 Liquidity risk

Liquidity risk is the risk that the Group will not be able to meet its financial obligations as they fall due.

The Group manages liquidity risk by ensuring that sufficient funds are available to meet its commitments as theyfall due.

The Group uses both long-term and short-term cash flow projections to monitor funding requirements for activities and to ensure there are sufficient cash resources to meet operational needs. Cash flow projections take into consideration the Group's debt financing plans and covenant compliance.

Surplus cash held is transferred to the treasury department which invests in interest bearing current accounts, time deposits and money market deposits.

The following table details the Group's remaining contractual maturity for its non-derivative financial liabilities with agreed maturity periods. The table has been drawn based on the undiscounted cash flows of the financial liabilities based on the earliest date on which the Group can be required to pay.

Notes to the interim condensed consolidated financial statements continued

*Nomura and The Mauritius Commercial Bank replace JP Morgan and Bank of America.

** Trade and other payables (excludes non-financial liabilities such as provisions, accruals, taxes, pension and other

non-contractual payables).

Notes to the interim condensed consolidatedfinancial statements continued

5.1.2 Credit risk

Credit risk refers to the risk of a counterparty defaulting on its contractual obligations resulting in financial loss to the Group. Credit risk arises from cash and cash equivalents, favourable derivative financial instruments, deposits with banks and financial institutions as well as credit exposures to customers and Joint venture partners, i.e. NPDC receivables and NGMC receivables.

Risk management

The Group is exposed to credit risk from its sale of crude oil to Mecuria. The off-take agreement with Mercuria runs until 31 July 2021 with a 30 day payment term. The Group is exposed to further credit risk from outstanding cash calls from Nigerian Petroleum Development Company (NPDC) and National Petroleum Investment Management Services (NAPIMS).