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SEPLAT PetDevCom Plc (SEPL)

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Monday 30 July, 2018

SEPLAT PetDevCom Plc

Consolidated Half-Yearly Financial Results

RNS Number : 0847W
SEPLAT Petroleum Development Co PLC
30 July 2018
 

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

 

US$ million

 

billion

 

H1 2018

H1 2017

% change

H1 2018

H1 2017

Revenue

343

132

160%

105

40

Gross Profit

174

54

222%

53

16

Operating Profit

158

7

n/a

48

2

Profit/(loss) for the Period

(before deferred tax)(1)

105

(28)

(475)%

32

(8)

Operating cash flow

245

106

131%

75

32

Working interest production (boepd)

51,099

26,383

94%

 

 

Average realised oil price (US$/bbl)

69.1

45.0

54 %

21,131

13,764

Average realised gas price (US$/Mscf)

3.04

2.97

2%

930

908

(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

 

Gross

 

Working Interest

 

 

Liquids(1)

Gas

Oil equivalent

 

Liquids(1)

Gas

Oil equivalent

 

Seplat %

bopd

MMscfd

boepd

 

bopd

MMscfd

boepd

 

 

 

 

 

 

 

 

 

OMLs 4, 38 & 41

45.0%

52,082

344

109,445

 

23,437

155

49,250

OPL 283

40.0%

2,163

-

2,163

 

865

-

865

OML 53

40.0%

2,461

-

2,461

 

984

-

984

Total

 

56,706

344

114,069

 

25,286

155

51,099

(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,

 

 

 

 

 

A. B. C. Orjiako

A. O. Avuru

R.T. Brown 

FRC/2013/IODN/00000003161

FRC/2013/IODN/00000003100

FRC/2014/ANAN/00000017939

Chairman

Chief Executive Officer

Chief Financial Officer

30 July 2018

30 July 2018

30 July 2018

 

 

 

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:

Seplat Petroleum Development Company Plc

 

Roger Brown, CFO

+44 203 725 6500

Andrew Dymond, Head of Investor Relations

 

Ayeesha Aliyu, Investor Relations

+234 1 277 0400

Chioma Nwachuku, GM - External Affairs and Communications

 

 

FTI Consulting

Ben Brewerton / Sara Powell

[email protected]

+44 203 727 1000

Citigroup Global Markets Limited

Tom Reid / Luke Spells

 

+44 207 986 4000

Investec Bank plc

Chris Sim / Jonathan Wolf

 

+44 207 597 4000

 

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/

 

 

Ernst & Young

10th Floor, UBA House

57, Marina

Lagos, Nigeria

 

Tel: +234 (01) 844 996 2/3

Fax: +234 (01) 463 0481

Email: [email protected]

www.ey.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

 

 

Half year ended

30 June 2018

Half year ended

30 June 2017

3 months ended
30 June 2018

3 months ended

30 June 2017

 

 

Unaudited

Unaudited

Unaudited

Unaudited

 

Note

'million

'million

'million

'million

Revenue from contracts with customers

7

 104,794

 40,317

 49,558

 25,843

Cost of sales

8

 (51,487)

 (23,914)

 (24,654)

 (15,290)

Gross profit

 

 53,307

 16,403

 24,904

 10,553

Other income

9

 8,483

 -  

 5,855

 -  

General and administrative expenses

10

 (11,769)

 (11,108)

 (6,850)

 (5,979)

Reversal of/(impairment) losses on financial assets - net

11

 529

 -  

 (140)

 -  

Gain/(loss) on foreign exchange - net

12

 8

 (264)

 (564)

 (793)

Fair value loss - net

13

 (2,127)

 (2,817)

 (397)

 (1,155)

Operating profit

 

 48,431

 2,214

 22,808

 2,626

Finance income

14

 1,330

 270

 893

 206

Finance costs                

14

 (12,668)

 (10,574)

 (4,595)

 (5,317)

Profit/(loss) before taxation

 

 37,093

 (8,090)

 19,106

 (2,485)

Taxation

15

 (22,249)

 (342)

 (10,549)

 (92)

Profit/(loss) for the period

 

 14,844

 (8,432)

 8,557

 (2,577)

 

 

 

 

 

 

Other comprehensive (loss)/income:

 

 

 

 

 

Items that may be reclassified to profit or loss:

 

 

 

 

 

Foreign currency translation difference

 

 153

 1,049

 (74)

 (1,403)

 

 

 

 

 

 

Total comprehensive income/(loss) for the period

 

14,997

 (7,383)

8,483

 (3,980)

 

 

 

 

 

 

Earnings/(loss) per share ()

16

25.59

 (14.97)

  14.75

 (4.57)

Diluted earnings/(loss) per share()

16

25.42

 (14.83)

14.65

 (4.53)

 

 

 

 

 

 

 

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 statement
of financial position

As at 30 June 2018

 

 

As at 30 June 2018

As at 31 Dec 2017 

 

 

Unaudited

Audited

 

Note

'million

'million

Assets

 

 

 

Non-current assets

 

 

 

Oil and gas properties

 

 381,376

 393,377

Other property, plant and equipment

 

 690

 1,553

Other asset

 

 61,880

 66,368

Deferred tax

15

 51,305

 68,417

Tax paid in advance

 

 9,670

 9,670

Prepayments

 

 85

 287

Total non-current assets                          

 

 505,006

 539,672

Current assets

 

 

 

Inventories

 

 30,699

 30,683

Trade and other receivables

18

 59,655

 94,904

Contract assets

19

 4,238

 -  

Prepayments

 

 469

 595

Cash & cash equivalents

20

 155,981

 133,699

Total current assets

 

 251,042

 259,881

Total assets

 

756,048

799,553

Equity and liabilities

 

 

 

Equity

 

 

 

Issued share capital

21a

 296

 283

Share premium

 

 82,080

 82,080

Treasury shares

 

(10)

-

Share based payment reserve

21b

 5,938

 4,332

Capital contribution

 

 5,932

 5,932

Retained earnings

 

 170,216

 166,149

Foreign currency translation reserve

 

 201,023

 200,870

Total shareholders' equity

 

 465,475

 459,646

Non-current liabilities

 

 

 

Interest bearing loans & borrowings

17

 153,368

 93,170

Contingent consideration

6.4

 5,619

 4,251

Provision for decommissioning obligation

 

 32,937

 32,510

Defined benefit plan                 

 

 2,383

 1,994

Total non-current liabilities

 

 194,307

 131,925

Current liabilities

 

 

 

Interest bearing loans and borrowings

17

 13,265

 81,159

Trade and other payables

22

 76,615

 125,559

Current tax liabilities

 

 6,386

 1,264

Total current liabilities

 

 96,266

 207,982

Total liabilities

 

290,573

 339,907

Total shareholders' equity and liabilities

 

756,048

799,553

 

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

Interim condensed consolidated statement of
financial 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

 

 

 

A. B. C. Orjiako

A. O. Avuru

R.T. Brown 

FRC/2013/IODN/00000003161

FRC/2013/IODN/00000003100

FRC/2014/ANAN/00000017939

Chairman

Chief Executive Officer

Chief Financial Officer

30 July 2018

 

30 July 2018

 

30 July 2018

 

 

 

Interim condensed consolidated statement
of changes in equity continued

for the half year ended 30 June 2018

For the half year ended 30 June 2017

 

 

 

 

 

 

 

 

Issued share

capital

Share premium

Treasury shares

Share based

payment reserve

Capital contribution

Retained earnings

Foreign currency translation reserve

Total

equity 

 

 

million

million

million

million

million

million

million

million

 

At 1 January 2017

283

82,080

-

2,597

5,932

   85,052

   200,429

   376,373

 

Loss for the period

 - 

 - 

 - 

 - 

 - 

(8,432)

 - 

(8,432)

 

Other comprehensive income

 - 

 -  

 -  

 -  

 -  

-

1,049

1,049

 

Total comprehensive (loss)/ income for the period

 -  

 -  

 -  

 -  

 -  

(8,432)

 1,049

(7,383)

 

Transactions with owners in their capacity as owners:

 

 

 -  

 -  

 -  

 -  

 -  

 -  

 

Share based payments

 -  

 -  

-

818

 -  

 -  

 -  

818

 

Total

 -  

 -  

-  

818  

 -  

 -  

 -  

818

 

At 30 June 2017 (unaudited)

 283

 82,080

 -

 3,415

 5,932

76,620

 201,478

369,808

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the half year ended 30 June 2018

 

 

 

Issued share

capital

Share premium

Treasury shares

Share based

payment reserve

Capital contribution

Retained earnings

Foreign currency translation reserve

Total

equity   

 

 

million

million

million

million

million

million

million

million

 

At 1 January 2018

 283

 82,080

-

4,332

5,932

166,149

200,870

459,646

 

Impact of change in accounting policy:

 

 

 

 

 

 

 

 

 

Adjustment on initial application of IFRS 9  (Note 3.3)

-

-

-

-

-

(1,779)

-

(1,779)

 

Adjustment on initial application of IFRS 15 (Note 3.3)

-

-

-

-

-

-

-

-

 

Adjusted balance at 1 January 2018

283

82,080

-

4,332

5,932

164,370

200,870

457,867

 

Profit for the period

-

-

-

-

-

 14,844

 -  

 14,844

 

Other comprehensive income

-

-

-

-

-

-

153

153

 

Total comprehensive income for the period

-

-

-

-

-

 14,844

 153

 14,997

 

Transactions with owners in their capacity as owners:

 

 

 

 

 

 

 

 

 

Dividends paid

-

-

-

-

-

(8,998)

-

(8,998)

 

Share based payments

-

-

-

1,609

-

-

-

1,609

 

Issue of shares

13

-

(13)

-

-

-

-

-

 

Vested shares

-

-

3

(3)

-

-

-

-

 

Total

13

-

(10)

1,606

-

(8,998)

-

(7,389)

 

At 30 June 2018 (unaudited)

 296

 82,080

(10)

5,938

5,932

170,216

201,023

465,475

 

 

 

 

 

 

 

 

 

 

 

                           

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

 

 

Half year ended
30 June 2018

Half year ended
 30 June 2017

 

 

'million

'million

 

Note

Unaudited

Unaudited

Cash flows from operating activities

 

 

 

Cash generated from operations

23

 75,022

32,492

Net cash inflows from operating activities

 

75,022

32,492

Cash flows from investing activities

 

 

 

Investment in oil and gas properties

 

(6,472)

(3,424)

Investment in other property, plant and equipment

 

-

(118)

Proceeds from disposal of other property,
plant and equipment

 

1

-

Receipts from other assets

 

4,488

6,914

Interest received

 

1,330

270

Net cash inflows/(outflows) from investing activities

 

(653)

3,642

Cash flows from financing activities

 

 

 

Repayments of bank financing

 

 (176,758)

(12,693)

Receipts from bank financing

 

 59,803

-

Dividend paid

 

 (8,998)

-

Proceeds from senior notes issued

 

 103,867

-

Repayments on crude oil advance

 

 (23,707)

-

Payments for other financing charges

 

 (465)

-

Interest paid on bank financing

 

 (5,874)

(10,560)

Net cash outflows from financing activities

 

(52,132)

(23,253)

Net increase in cash and cash equivalents

 

22,237

12,881

Cash and cash equivalents at beginning of period

 

133,699

48,684

Effects of exchange rate changes on cash
and cash equivalents

 

45

66

Cash and cash equivalents at end of period

 

155,981

61,631

 

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

 

 

Notes to the interim condensed consolidated
financial 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.

 

 

Subsidiary

Country of incorporation
and place of business

Shareholding
%

Principal activities

Newton Energy Limited

Nigeria

100%

Oil & gas exploration and production

Seplat Petroleum Development UK

United Kingdom

100%

Oil & gas exploration and production

Seplat East Onshore Limited

Nigeria

100%

Oil & gas exploration and production

Seplat East Swamp Company Limited

Nigeria

100%

Oil & gas exploration and production

Seplat Gas Company

Nigeria

100%

Oil & gas exploration and production

ANOH Gas Processing
Company Limited

Nigeria

100%

Gas processing

 

 

Notes to the interim condensed consolidated
financial 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 consolidated
financial 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

 

Title of standard

 

IFRS 16 Leases

Nature of change

 

IFRS 16 was issued in January 2016. It will result in almost all leases being recognised on the balance sheet, as the distinction between operating and finance leases is removed. Under the new standard, an asset (the right to use the leased item) and a financial liability to pay rentals are recognised. The only exceptions are short-term and low-value leases. The accounting for lessors will not significantly change.

Impact

 

Operating leases: The standard will affect primarily the accounting for the Group's operating leases which include leases of buildings, boats, storage facilities, rigs, land and motor vehicles. As at the reporting date, the Group had no non-cancellable operating lease commitments.

 

Short term leases & low value leases: The Group's one-year contracts with no planned extension commitments mostly applicable to leased staff flats will be covered by the exception for short-term leases, while none of the Group's leases will be covered by the exception for low value leases.

 

Service contracts: Some commitments such as contracts for the provision of drilling, cleaning and community services were identified as service contracts as they did not contain an identifiable asset which the Group had a right to control. It therefore did not qualify as leases under IFRS 16.

Date of adoption

 

The standard for leases is mandatory for financial years commencing on or after 1 January 2019. The Group does not intend to adopt the standard before its effective date.

 

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 consolidated
financial 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.

 

 

 

Amounts without impact of IFRS 9 and IFRS 15

Impact of
IFRS 9

Impact of
IFRS 15

As at
1 January 2018

 

Note

'million

'million

'million

'million

Current assets

 

 

 

 

 

Trade and other receivables

18

99,121

(1,779)

 (4,217)

93,125

Contract assets

19

-

-

4,217

4,217

Total assets

 

799,553

(1,779)

-  

797,774

Equity

 

 

 

 

 

Retained earnings

 

166,149

(1,779)

-  

164,370

Total shareholders' equity

 

459,646

(1,779)

-  

457,867

 

 

 

Amounts without impact of IFRS 9 and IFRS 15

Impact of
IFRS 9

Impact of
IFRS 15

As at
30 June 2018

 

Note

'million

'million

'million

'million

ASSETS

 

 

 

 

 

Current assets

 

 

 

 

 

Trade and other receivables

18

65,143

 (1,250)  

 (4,238)

59,655

Contract assets

19

-

-  

4,238

4,238

Total current assets

 

252,292

 (1,250)  

-  

251,042

Total assets

 

757,298

 (1,250)  

-  

756,048

EQUITY AND LIABILITIES

 

 

 

 

 

Equity

 

 

 

 

 

Retained earnings

 

171,466

 (1,250)  

-  

170,216

Total shareholders' equity

 

466,725

 (1,250)  

-  

465,475

Notes to the interim condensed consolidated
financial statements continued

 

 

Amount without impact of IFRS 9 and IFRS 15

Impact of IFRS 9

Impact of IFRS 15

Half year ended
30 June 2018

 

Notes

'million

'million

'million

'million

Revenue from contracts with customers

7

113,313

-

(8,519)

104,794

Cost of sales

8

(51,523)

-

36

 (51,487)

Gross profit

 

61,790

-

(8,483)

  53,307  

Other income

9

-

-

8,483

 8,483

Reversal of impairment losses on financial assets-net

11

-

529

-

529

Profit before taxation

 

36,564

529

-

 37,093

Taxation

 

(22,249)

-

-

 (22,249)

Profit for the period

 

14,315

529

-

 14,844

Other comprehensive income

 

 

 

 

 

Items that may be reclassified to profit or loss:

 

 

 

 

 

Foreign currency translation difference

 

153

-

-

153

Total comprehensive income for the period

 

14,468

529

 

14,997

Earnings per share for profit attributable
to the equity shareholders

 

 

 

 

 

Basic earnings per share ()

 

24.68

0.91

-

25.59

Diluted earnings per share ()

 

24.51

0.91

-

25.42

 

 

 

 

Amount without impact of IFRS 9 and IFRS 15

Impact of IFRS 9

Impact of IFRS 15

3 months ended
30 June 2018

 

Notes

'million

'million

'million

'million

Revenue from contracts with customers

7

55,459

-

(5,901)

 49,558

Cost of sales

8

(24,700)

-

46

 (24,654)

Gross profit

 

30,759

-

(5,855)

 24,904

Other income

9

-

-

5,855

 5,855

Impairment losses on financial assets-net

11

-

(140)

-

(140)

Profit before taxation

 

19,246

(140)             

-

 19,106

Taxation

 

(10,549)

-                   

-   

 (10,549)

Profit for the period

 

8,697

(140)            

-   

 8,557

Other comprehensive income

 

 

 

 

 

Items that may be reclassified to profit or loss:

 

 

 

 

 

Foreign currency translation difference

 

(74)

-                   

-   

(74)

Total comprehensive income for the period

 

8,623

(140)            

-   

8,483

Earnings per share for profit attributable
to the equity shareholders

 

 

 

 

 

Basic earnings per share ()

 

15.00

(0.25)

14.75

Diluted earnings per share ()

 

14.89

(0.24)

14.65

 

 

Notes to the interim condensed consolidated
financial 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 consolidated
financial statements continued

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

 

 

 

            Measurement category

                 Carrying amount

 

Original

            New

Original

New

 

IAS 39

             IFRS 9

million

million

Current financial assets

 

 

 

 

Trade and other receivables:

 

 

 

Trade receivables

L and R

Amortised cost

33,236

33,236

NPDC receivables

L and R

Amortised cost

34,453

34,453

NAPIMS receivables

L and R

Amortised cost

3,824

3,824

Other receivables*

L and R

Amortised cost

7

7

Cash and cash equivalents

L and R

Amortised cost

133,699

133,699

 

 

 

 

Non-current financial liabilities

 

 

 

Interest bearing loans and borrowings

Amortised cost

Amortised cost

93,170

93,170

 

 

 

 

Current financial liabilities

 

 

 

Interest bearing loans and borrowings

Amortised cost

Amortised cost

81,159

81,159

Trade and other payables**

Amortised cost

Amortised cost

38,876

38,876

 

*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 2018
is as follows:

                 

 

Notes

'million

 

Closing retained earnings as at 31 December 2017- IAS 39

 

166,149

 

Increase in provision for Nigerian Petroleum Development Company (NPDC) receivables

(a)

(1,698)

Increase in provision for National Petroleum Investment Management Services (NAPIMS) receivables

(b)

(81)

 

 

 

(1,779)

 

Opening retained earnings 1 January 2018 on adoption of IFRS 9

 

164,370

 

 

 

 

 

 

Notes

'million

 

Profit for the period (without impact of IFRS 9 and IFRS 15)

 

14,315

 

Reversal of impairment loss for  Nigerian Petroleum Development  Company (NPDC) receivables

(a)

570

 

(Increase in provision for  National Petroleum Investment Management Services (NAPIMS) receivables

(b)

(41)

 

Total reversal of impairment loss

 

529

 

Profit for the period (with impact of IFRS 9 and IFRS 15)

 

14,844

 

 

 

Notes to the interim condensed consolidated
financial 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

 

Stage 1

Stage 2

Stage 3

Total

 

12-month ECL

Lifetime ECL

Lifetime ECL

 

 

₦'million

₦'million

₦'million

₦'million

Gross EAD*

-

11,369

23,084

34,453

Loss allowance as at 1 January 2018

-

(32)

(1,666)

(1,698)

Net EAD

-

11,337

21,418

32,755

*Exposure of default

 

30 June 2018

 

Stage 1

Stage 2

Stage 3

Total

 

12-month ECL

Lifetime ECL

Lifetime ECL

 

 

₦'million

₦'million

₦'million

₦'million

Gross EAD*

-

-

14,817

14,817

Loss allowance as at 30 June 2018

-

-

(1,128)

(1,128)

Net EAD

-

-

13,689

13,689

 

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 consolidated
financial 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:

 

 

₦'million

Loss allowance as at 1 January 2018 - calculated under IAS 39

-

Amounts restated through opening retained earnings

1,698

Loss allowance as at 1 January 2018 - calculated under IFRS 9

1,698

Reversal of impairment loss on NPDC receivables

(570)

Loss allowance as at 30 June 2018 - Under IFRS 9

1,128

 

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 consolidated
financial statements continued

1 January 2018

 

Stage 1

Stage 2

Stage 3

Total

 

12-month ECL

Lifetime ECL

Lifetime ECL

 

 

'million

'million

'million

'million

Gross EAD*

1,306

-

2,518

3,824

Loss allowance as at 1 January 2018

(2)

-

(79)

(81)

Net EAD

1,304

-

2,439

3,743

 

30 June 2018

 

Stage 1

Stage 2

Stage 3

Total

 

12-month ECL

Lifetime ECL

Lifetime ECL

 

 

'million

'million

'million

'million

Gross EAD*

1,186

-

209

1,395

Loss allowance as at 30 June 2018

(22)

-

(100)

(122)

Net EAD

1,164

-

109

1,273

 

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:

 

 

'million

Loss allowance as at 1 January 2018 - calculated under IAS 39

-

Amounts restated through opening retained earnings

81

Loss allowance as at 1 January 2018 - calculated under IFRS 9

81

Increase in provision for impairment loss on NPDC receivables

41

Loss allowance as at 30 June 2018 - Under IFRS 9

122

 

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 consolidated
financial 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 consolidated
financial 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 consolidated
financial 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

 

 

 

Amount without impact of IFRS 9
and  IFRS 15

Impact of
IFRS 9

Impact of
IFRS 15

As at
30 June 2018

 

Note

'million

'million

'million

'million

ASSETS

 

 

 

 

 

Current assets

 

 

 

 

 

Trade and other receivables

(a)

65,143

          (1,250)      

      (4,238)

59,655

Contract assets

(a)

-

           -  

        4,238

             4,238

 

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.

 

 

 

As at 30 June 2018

 

 

Unaudited

 

Note

'million

Revenue from contracts with customers (without IFRS 15 impact)

 

113,313

Reclassification of underlifts to other income

(a)

(8,483)

Reclassification of demurrage from cost of sales  

(b)

(36)

Total impact of reclassification on revenue

 

(8,519)

Revenue from contract with customers under IFRS 15

 

104,794

       

 

Notes to the interim condensed consolidated
financial 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 consolidated
financial 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 consolidated
financial 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 consolidated
financial 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 consolidated
financial 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 consolidated
financial 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 consolidated
financial 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.

 

Risk

Exposure arising from

Measurement

Management

Market risk - foreign exchange

Future commercial transactions

Recognised financial assets and liabilities not denominated in
US dollars.

Cash flow forecasting

Sensitivity analysis

Match and settle foreign denominated cash inflows
with foreign denominated
cash outflows.

Market risk - interest rate

Long term borrowings at
variable rate

Sensitivity analysis

Review refinancing opportunities

Market risk - commodity  prices

Future sales transactions

 

Sensitivity analysis

Oil price hedges

Credit risk

Cash and cash equivalents,
trade receivables and derivative financial instruments.

Aging analysis

Credit ratings

Diversification of bank deposits.

Liquidity risk

Borrowings and other liabilities

Rolling cash flow forecasts

Availability of committed credit lines and borrowing facilities

 

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 they
fall 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

 

Effective interest rate

  Less than

     1 year

        1 - 2

years

         2 - 3

years

         3 - 5

years

After
5 years

      Total

 

 

%

'million

'million

'million

'million

'million

'million

30 June 2018

 

 

 

 

 

 

 

Non - derivatives

 

 

 

 

 

 

 

Fixed interest rate borrowings

 

 

 

 

 

 

 

Senior notes

9.25%

10,344

10,069

10,041

127,147

-

157,601

Variable interest rate borrowings
(bank loans):

 

 

 

 

 

 

 

Stanbic Ibtc Bank Plc

6.0% +LIBOR

 1,495

 2,258

 2,103

 2,869

 -  

 8,725

The Standard Bank Of South Africa L

6.0% +LIBOR

 996

 1,505

 1,403

 1,912

 -  

 5,816

Nedbank Limited, London Branch

6.0% +LIBOR

 2,076

 3,136

 2,922

 3,984

 -  

 12,118

Standard Chartered Bank

6.0% +LIBOR

 1,868

 2,823

 2,630

 3,585

 -  

 10,906

Natixis

6.0% +LIBOR

 1,453

 2,195

 2,045

 2,789

 -  

 8,482

FirstRand Bank Limited Acting

6.0% +LIBOR

 1,453

 2,195

 2,045

 2,789

 -  

 8,482

Citibank N.A. London

6.0% +LIBOR

 1,245

 1,882

 1,753

 2,390

 -  

 7,270

The Maritus Commercial Bank Plc

6.0% +LIBOR

 1,245

 1,882

 1,753

 2,390

 -  

 7,270

Nomura International Plc

6.0% +LIBOR

 623

 941

 877

 1,195

 -  

 3,636

Other non-derivatives

 

 

 

 

 

 

 

Trade and other payables**

-

21,536

-

-

-

-

21,536

 

 

44,334

28,886

27,572

151,050

-

251,842

        

 

Effective interest rate

Less than
1 year

1 - 2
year

2 - 3
years

3 - 5
years

After
5 years

Total

 

%

'million

'million

'million

'million

'million

'million

31 December 2017

 

 

 

 

 

 

 

Non - derivatives

 

 

 

 

 

 

 

Variable interest rate borrowings
(bank loans):

 

 

 

 

 

 

 

Allan Gray

8.5% + LIBOR

 1,696

 1,564

 1,124

 538

 -  

 4,922

Zenith Bank Plc

8.5% + LIBOR

 23,243

 21,439

 15,404

 7,371

 -  

 67,457

First Bank of Nigeria Limited

8.5% + LIBOR

 12,830

 11,835

 8,503

 4,069

 -  

 37,237

United Bank for Africa Plc

8.5% + LIBOR

 14,527

 13,400

 9,628

 4,607

 -  

 42,162

Stanbic IBTC Bank Plc

8.5% + LIBOR

 2,177

 2,008

 1,443

 690

 -  

 6,318

The Standard Bank of South Africa Limited

8.5% + LIBOR

 2,177

 2,008

 1,443

 690

 -  

 6,318

Standard Chartered Bank

6.0% + LIBOR

 5,747

 -  

 -  

 -  

 -  

 5,747

Natixis

6.0% + LIBOR

 5,747

 -  

 -  

 -  

 -  

 5,747

Citibank Nigeria Ltd and Citibank NA

6.0% + LIBOR

 4,470

 -  

 -  

 -  

 -  

 4,470

FirstRand Bank Ltd
(Rand Merchant Bank Division)

6.0% + LIBOR

 -  

 -  

 -  

 -  

 -  

 -  

Nomura Bank Plc*

6.0% + LIBOR

 3,831

 -  

 -  

 -  

 -  

 3,831

NedBank Ltd, London Branch

6.0% + LIBOR

 3,831

 -  

 -  

 -  

 -  

 3,831

The Mauritius Commercial Bank Plc*

6.0% + LIBOR

 3,831

 -  

 -  

 -  

 -  

 3,831

Stanbic IBTC Bank Plc

6.0% + LIBOR

 2,874

 -  

 -  

 -  

 -  

 2,874

The Standard Bank of South Africa Ltd

6.0% + LIBOR

 4,152

 -  

 -  

 -  

 -  

 4,152

Other non-derivatives

 

 

 

 

 

 

 

Trade and other payables**

-

38,876

 -  

 -  

 -  

 -  

  38,876

 

 

 130,009

 52,254

 37,545

 17,965

 -  

237,773

*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 consolidated
financial 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).

 

In addition, the Group is exposed to credit risk in relation to its sale of gas to Nigerian Gas Marketing Company (NGMC) Limited, a subsidiary of NNPC, its sole gas customer during the period.

 

The credit risk on cash is limited because the majority of deposits are with banks that have an acceptable credit rating assigned by an international credit agency. The Group's maximum exposure to credit risk due to default of the counterparty is equal to the carrying value of its financial assets.

 

5.2   Fair value measurements

Set out below is a comparison by category of carrying amounts and fair value of all financial instruments:

 

Carrying amount

Fair value

 

As at
30 June 2018

As at
31 Dec 2017

As at
30 June 2018

As at
31 Dec 2017

 

million

million

million

million

Financial assets

 

 

 

 

Trade and other receivables*

35,519

91,613

35,519

91,613

Contract assets

4,238

 -  

4,238

 -  

Cash and cash equivalents

155,981

 133,699

155,981

133,699

 

195,738

225,312

195,738

225,312

Financial liabilities

 

 

 

 

Interest bearing loans and borrowings

166,633

174,329

169,270

174,329

Trade and other payables

21,536

38,876

21,536

38,876

 

188,169

213,205

190,806

213,205

*Trade and other receivables excludes NGMC VAT receivables, cash advance and advance payments.

 

5.2.1       Fair Value Hierarchy

As at the reporting period, the Group had classified its financial instruments into the three levels prescribed under the accounting standards. These are all recurring fair value measurements. There were no transfers of financial instruments between fair value hierarchy levels during this second quarter.

 

The fair values of the Group's interest-bearing loans and borrowings are determined by using discounted cash flow models that use market interest rates as at the end of the period. The interest-bearing loans and borrowings are in level 2.

 

The Valuation process

 

The finance & planning team of the Group performs the valuations of financial and non financial assets required for financial reporting purposes. This team reports directly to the Finance Manager (FM) who reports to the Chief Financial Officer (CFO) and the Audit Committee (AC). Discussions of valuation processes and results are held between the FM and the valuation team at least once every quarter, in line with the Group's quarterly reporting periods.

 

Notes to the interim condensed consolidated
financial statements continued

6.    Segment reporting

Business segments are based on Seplat's internal organisation and management reporting structure. Seplat's business segments are the two core businesses: Oil and Gas. The Oil segment deals with the exploration, development and production of crude oil while the Gas segment deals with the production of gas.

 

For the half year ended 30 June 2018, revenue from the gas segment of the business constituted 25% of the Group's revenue. Management believes that the gas segment of the business will continue to generate higher profits in the foreseeable future. It also decided that more investments will be made toward building the gas arm of the business. This investment will be used in establishing more offices, creating a separate operational management and procuring the required infrastructure for this segment of the business. The new gas business is positioned separately within the Group and reports directly to the ('chief operating decision maker'). As this business segment's revenues and results, and also its cash flows, will be largely independent of other business units within Seplat, it is regarded as a separate segment.

 

The result is two reporting segments, Oil and Gas. There were no intrasegment sales during the reporting periods under consideration. All operating and reportable segments are situated in Nigeria.

 

Where applicable, the comparative figures for 2017 have been restated to match the new structure for the half year ended 30 June 2018.

 

The Group accounting policies are also applied in the segment reports. 

 

 

6.1 Segment profit disclosure

 

Half year
ended

30 June 2018

Half year
ended

30 June 2017

3 months
ended

30 June 2018

3 months
ended

30 June 2017

                       

'million

'million

'million

'million

Oil

 (1,662)

 (18,790)

 (2,109)

 (8,147)

Gas

 16,506

 10,358

 10,666

 5,570

Total profit/(loss) after tax

 14,844

 (8,432)

 8,557

 (2,577)

 

 

 

 

 

 

 

 

          Oil

 

Half year
ended

30 June 2018

Half year
ended

30 June 2017

3 months
ended

30 June 2018

3 months
ended

30 June 2017

                       

'million

'million

'million

'million

Revenue

 

 

 

 

Crude oil sales

 78,695

 23,690

 35,557

 16,884

Operating profit/(loss) before depreciation,
amortisation and impairment

 44,012

 (4,479)

 15,456

 (2,751)

Depreciation, amortisation and impairment

 (16,893)

 (3,665)

 (8,120)

 (193)

Operating profit/(loss)

 27,119

 (8,144)

 7,336

 (2,944)

Finance income

 1,330

 270

 893

 206

Finance expenses

 (12,668)

 (10,574)

 (4,595)

 (5,317)

Profit/(loss) before taxation

 15,781

 (18,448)

 3,634

 (8,055)

Income tax expense

 (17,443)

 (342)

 (5,743)

 (92)

Profit/(loss) for the period

 (1,662)

 (18,790)

 (2,109)

 (8,147)

 

Notes to the interim condensed consolidated
financial statements continued
                                                                                                                                              Gas

 

Half year
ended

30 June 2018

Half year
ended

30 June 2017

3 months
ended

30 June 2018

3 months
ended

30 June 2017

                       

'million

'million

'million

'million

Revenue

 

 

 

 

Gas sales

 26,099

 16,627

 14,001

 8,959

Operating profit before depreciation,
amortisation

and impairment

 23,878

 16,278

 16,810

 11,488

Depreciation, amortisation and impairment

 (2,566)

 (5,920)

 (1,338)

 (5,918)

Operating profit

 21,312

 10,358

 15,472

 5,570

Finance income

 -  

 -  

 -  

 -  

Finance expenses

 -  

 -  

 -  

 -  

Profit/(loss) before taxation

 21,312

 10,358

 15,472

 5,570

Income tax expense

 (4,806)

 -  

 (4,806)

 -  

Profit for the period

 16,506

 10,358

 10,666

 5,570

 

6.1.1  Disaggregation of revenue from contracts with customers

The Group derives revenue from the transfer of commodities at a point in time or over time on the basis of product type. The Group has not disclosed disaggregated revenue and contract asset for the comparative periods, as the effect of IFRS 15 adjustments have been treated prospectively using the simplified transition approach. The simplified approach does not require an adjustment of the comparative periods.

                         

 

Half year ended

30 June 2018

Half year ended

30 June 2018

Half year ended

30 June 2018

3 months ended

30 June 2018

3 months ended

30 June 2018

3 months ended

30 June 2018

 

Oil

Gas

Total

Oil

Gas

Total

 

'million

'million

'million

million

million

million

Revenue from contract with customers

78,695

26,099

 104,794

35,557

14,001

49,558

Timing of revenue recognition

 

 

 

 

 

 

At a point in time

78,695

-

 78,695

35,557

-

35,557

Over time

-

26,099

26,099

-

14,001

14,001

 

78,695

26,099

104,794

35,557

14,001

49,558

 

6.2 Segment assets

Segment assets are measured in the same way as in the financial statements. These assets are allocated based on the operations of the reporting segment and the physical location of the asset.

 

 

Oil

Gas 

Total

Total segment assets        

'million

'million

'million

30 June 2018

645,639

110,409

756,048

31 December 2017

716,657

82,896

799,553

         

 

Notes to the interim condensed consolidated
financial statements continued

6.3 Segment liabilities

Segment liabilities are measured in the same way as in the financial statements. These liabilities are allocated based on the operations of the segment.

 

Oil

Gas 

Total

Total segment liabilities 

'million

'million

'million

30 June 2018

277,223

13,350

290,573

31 December 2017

325,967

13,940

339,907

         

 

6.4 Contingent consideration

Contingent consideration of 5.7 billion for OML 53 relates solely to the oil segment. This is contingent on oil price rising above N 27,535/bbl. over a one year period and expirirng on 31st January 2020. The fair value loss arising during the reporting period  is 1.37 billion.

7.    Revenue from contracts with customers

 

Half year ended

30 June 2018

Half year ended

30 June 2017

3 months ended

30 June 2018

3 months ended

30 June 2017

 

'million

'million

'million

'million

Crude oil sales

 78,695

 34,007

 35,557

 24,793

Gas sales

 26,099

 16,627

 14,001

 8,959

 

 104,794

 50,634

 49,558

 33,752

Overlifts      

 -  

 (10,317)

 -  

 (7,909)

Total

 104,794

 40,317

 49,558

 25,843

 

The major off-taker for crude oil is Mercuria. The major off-taker for gas is the Nigerian Gas Marketing Company.

8.    Cost of sales

 

Half year ended

30 June 2018

Half year ended

30 June 2017

3 months ended

30 June 2018

3 months ended

30 June 2017

 

'million

'million

'million

'million

Crude handling

 8,939

 1,531

 4,372

 1,363

Royalties

 19,059

 5,736

 9,301

 4,223

Depletion, Depreciation and Amortisation

 18,591

 8,861

 8,887

 5,387

Niger Delta Development Commission

 1,077

 729

 558

 379

Barging costs

 -  

 1,995

 -  

 1,340

Other Rig related Expenses

 12

 499

 4

 193

Operations & Maintenance Costs

 3,809

 4,563

 1,532

 2,405

 

 51,487

 23,914

 24,654

 15,290

9.    Other income

                 

Half year ended

30 June 2018

Half year ended

30 June 2017

3 months ended

30 June 2018

3 months ended

30 June 2017

 

'million

'million

'million

'million

Underlift

 8,483

 -  

 5,855

-

 

 8,483

 -  

 5,855

-

 

Shortfalls may exist between the crude oil lifted and sold to customers during the period and the participant's ownership share of production. The shortfall is initially measured at the market price of oil at the date of lifting and recognised as other income. At each reporting period, the shortfall is remeasured at the current market value. The resulting change, as a result of the remeasurement, is also recognised in profit or loss as other income.

Notes to the interim condensed consolidated
financial statements continued

10.  General and administrative expenses

 

Half year ended

30 June 2018

Half year ended

30 June 2017

3 months ended

30 June 2018

3 months ended

30 June 2017

 

'million

'million

'million

'million

Depreciation

 868

 722

 571

 380

Employee benefits

 4,676

 3,296

 2,321

 1,509

Professional and consulting fees

 2,419

 3,449

 1,331

 2,088

Auditor's remuneration

 57

 94

 19

 48

Directors emoluments (executive)

 195

 423

 108

 245

Directors emoluments (non-executive)

 499

 476

 300

 246

Rentals

 301

 224

 180

 151

Flights and other travel costs

 759

 724  

 511

724  

Other general expenses

 1,995

 1,700

 1,509

588

 

 11,769

 11,108

 6,850

 5,979

 

Directors' emoluments have been split between executive and non-executive directors. There were no non-audit services rendered by the Group's auditors during the period.

Other general expenses relate to costs such as office maintenance costs, telecommunication costs, logistics costs and others. Share based payment expenses are included in the employee benefits expense.

11.  Reversal of/(impairment) losses on financial assets - net

 

Half year ended

30 June 2018

Half year ended

30 June 2017

3 months ended

30 June 2018

3 months ended

30 June 2017

 

₦'million

₦'million

₦'million

₦'million

Reversal of/(impairment) loss on NPDC
and NAPIMS receivables

 529

 -  

 (140)

-

 

On initial application of IFRS 9, an impairment loss of 1.78 billion was recognised for NPDC and NAPIMS receivables as at 1 January 2018. The loss allowance was calculated on a total exposure of 38.3 billion. During the reporting period, the outstanding receivable balance reduced to 1.3 billion. The reduction in the receivables balance led to the reversal of previously recognised loss allowance.

12.  Gain/(loss) on foreign exchange - net

 

Half year ended

30 June 2018

Half year ended

30 June 2017

3 months ended

30 June 2018

3 months ended

30 June 2017

 

₦'million

₦'million

₦'million

₦'million

Exchange gain/(loss)

 8

 (264)

 (564)

(793)

This is principally as a result of translation of naira denominated monetary assets and liabilities.

13.  Fair value loss - net

 

Half year ended

30 June 2018

Half year ended

30 June 2017

3 months ended

30 June 2018

3 months ended

30 June 2017

 

'million

'million

'million

'million

Crude oil hedging payments

 (760)

(3,006)

 (380)

(1,478)

Fair value loss on contingent consideration

 (1,367)

(274)

 (17)

(140)

Fair value gain on other assets

 -  

463

 -  

463

Fair value loss

 (2,127)

(2,817)

 (397)

(1,155)

 

Notes to the interim condensed consolidated
financial statements continued

Crude oil hedging payments represents the payments for crude oil price options charged to profit or loss. Fair value loss on contingent consideration arises in relation to remeasurement of contingent consideration on the Group's acquisition of participating interest in OML 53. The contingency criteria are the achievement of certain production milestones.

14.  Finance income/ (costs)

 

Half year ended

30 June 2018

Half year ended

30 June 2017

3 months ended

30 June 2018

3 months ended

30 June 2017

 

'million

'million

'million

'million

Finance income

 

 

 

 

Interest income

 1,330

270

 893

206

Finance costs

 

 

 

 

Interest on bank loan

 11,722

 10,560

 4,372

 5,310

Interest on advance payments for
crude oil sales

530

 -  

 -  

 -  

Unwinding of discount on provision
for decommissioning 

 416

 14

 223

 7

 

 12,668

 10,574

 4,595

 5,317

Finance cost - net

 (11,338)

 (10,304)

 (3,702)

 (5,111)

15.  Taxation

Income tax expense is recognised based on management's estimate of the weighted average effective annual income tax rate expected for the full financial year. The estimated average annual tax rates used for the period to 30 June 2018 were 85% and 65.75% for crude oil activities and 30% for gas activities. As at 31 December 2017, the applicable tax rates were 85%, 65.75% and 30% for gas activities.

 

15a.        Deferred tax assets

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.

 

 

As at
30 June 2018

As at
30 June 2018

As at
31 Dec 2017

As at
31 Dec 2017

 

'million

'million

'million

'million

 

Gross amount

Tax effect

Gross amount

Tax effect

Tax losses

-

-

14,578

12,392

Other cumulative timing differences

60,359

51,305

65,912

56,025

 

60,359

51,305

80,490

68,417

 

15b.  Unrecognised deferred tax assets

The unrecognised deferred tax assets relates to the Group's subsidiaries and will be recognised once the entities return to profitability. There are no expiration dates for the unrecognized deferred tax assets.

 

 

As at
30 June 2018

As at
30 June 2018

As at
31 Dec 2017

As at
31 Dec 2017

 

'million

'million

'million

'million

 

Gross amount

Tax effect

Gross amount

Tax effect

Other deductible temporary differences

 14,009

 7,838

14,988

7,869

Tax losses

 10,390

 7,775

14,579

8,908

 

 24,399

 15,613

29,567

16,777

 

15c.  Unrecognised deferred tax liabilities

There were no temporary differences associated with investments in the Group's subsidiaries for which a deferred tax liability would have been recognised in the periods presented.
 

Notes to the interim condensed consolidated
financial statements continued

16.  Earnings/(loss) per share (EPS/LPS)

Basic

Basic EPS/LPS is calculated on the Group's profit or loss after taxation attributable to the parent entity and on the basis of the weighted average issued and fully paid ordinary shares at the end of the period.

Diluted

Diluted EPS/LPS is calculated by dividing the profit or loss attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year plus the weighted average number of ordinary shares that would be issued on conversion of all the dilutive potential ordinary shares (arising from outstanding share awards in the share based payment scheme) into ordinary shares.

 

Half year ended

30 June 2018

Half year ended

30 June 2017

3 months ended

30 June 2018

3 months ended

30 June 2017

 

'million

'million

'million

'million

 

 

 

 

 

Profit/(loss) for the period

 14,844

 (8,432)

 8,557

(2,577)

 

Share
'000

Share
'000

Share
'000

Share
'000

Weighted average number of ordinary shares in issue

 580,112

 563,445

 580,112

563,445

Share awards

 3,838

 4,943

 3,838

4,943

Weighted average number of ordinary shares adjusted for the effect of dilution

 583,950

 568,388

 583,950

568,388

 

Basic earnings/(loss) per share

 25.59

 (14.97)

 14.75

(4.57)

Diluted earnings/(loss) per share

 25.42

 (14.83)

 14.65

(4.53)

 

'million

'million

'million

'million

Profit/(loss) used in determining basic/diluted earnings/loss per share

 14,844

 (8,432)

 8,557

(2,577)

17.  Interest bearing loans & borrowings

Below is the net debt reconciliation on interest bearing loans and borrowings.

 

Borrowings due
within 1 year

Borrowings due
above 1 year

 Total

 

'million

'million

'million

Balance as at 1 January 2018

 81,159

 93,170

 174,329

Principal repayment

 (81,162)

 (95,596)

 (176,758)

Interest repayment

 (1,400)

 (4,474)

 (5,874)

Interest accrued

 7,015

 -  

 7,015

Effect of loan restructuring

 -  

 4,708

 4,708

Other financing charges

 -  

 (465)

 (465)

Proceeds from loan financing

 7,645

 155,976

 163,621

Exchange differences

 8

 49

 57

Carrying amount as at 30 June 2018

 13,265

 153,368

 166,633

 

Interest bearing loans and borrowings include a revolving loan facility and senior notes. In the reporting period, the Group repaid its 214 billion seven year term loan and its 91.8 billion four year revolving loan facility.

 

In the reporting period, the Group also issued 107 billion senior notes at a contractual interest rate of 9.25% with interest payable on 1 April and 1 October, and principal repayable at maturity. The notes are expected to mature in April 2023. The interest accrued at the reporting date is 2.9 billion using an effective interest rate of 10.4%.

 

Notes to the interim condensed consolidated
financial statements continued

An agreement for another four year revolving loan facility was entered into by the Group to refinance its old four year revolving loan facility with interest payable semi-annually and principal repayable on 31 December of each year. The new revolving loan has an initial contractual interest rate of 6% +Libor (7.7%) and a settlement date of June 2022. The interest rate of the facility is variable. The Group made a draw down of 61.2 billion in March 2018. The interest accrued at the reporting period was 4.1 billion using an effective interest rate of 8.99%. The interest paid was determined using 3-month LIBOR rate + 6% on the last business day of the half-year period. The amortised cost for the senior notes and the borrowings at the reporting period is 106.8 billion and 59.8 billion respectively.

 

The proceeds from the notes issue and new revolving loan facility were used to repay and cancel existing indebtedness, and for general corporate purposes.

18.  Trade and other receivables

 

As at
30 June 2018

As at
31 Dec 2017

 

'million

'million

Trade receivables (note18a)

 30,843

 33,236

Nigerian Petroleum Development  Company (NPDC) receivables (note 18b)

 -  

 34,453

National Petroleum Investment Management Services receivables

 1,271

 3,824

Advances on investment

 -  

20,093

Underlifts

 876

 -

Advances to suppliers

 12,229

 2,404

Other receivables (note 18c)

 14,436

 894

 

 59,655

94,904

 

18a.  Trade receivables:

Included in trade receivables is an amount due from Nigerian Gas Marketing Company (NGMC) and Central Bank of Nigeria (CBN) totaling 15.7 billion (2017: 23 billion) with respect to the sale of gas, for the Group. Also included in trade receivables is an amount of 12.5 billion (2017: 8.39 billion) due from Mecuria for sale of crude.

18b.  NPDC receivables: 

NPDC receivables represent the outstanding cash calls due to Seplat from its JV partner, Nigerian Petroleum Development Company Nil (2017: 34 billion)

18c.  Other receivables

Included in other receivables is a receivable amount from SPDC on an investment that is no longer being pursued. The outstanding receivable amount as at the reporting date is 13.9 billion (2017: nil).

19.                                                              Contract assets

 

As at
30 June 2018

As at
31 Dec 2017

 

'million

'million

Revenue on gas sales

4,238

-

 

A contract asset is an entity's right to consideration in exchange for goods or services that the entity has transferred to a customer. The Group has recognised an asset in relation to a contract with NGMC for the delivery of Gas supplies which NGMC has received but which has not been invoiced as at the end of the reporting period.

 

The terms of payments relating to the contract is between 30- 45 days from the invoice date. However, invoices are raised after delivery between 14-21 days when the receivable amount has been established and the right to the receivables crytallises. The right to the unbilled receivables is recognised as a contract asset.

At the point where the final billing certificate is obtained from NGMC authorising the quantities, this will be reclassified from the contract assets to trade receivables.

 

 

Notes to the interim condensed consolidated
financial statements continued

19.1    Reconciliation of contract assets

The movement in the Group's contract assets is as detailed below:

 

As at
30 June 2018

As at
31 Dec 2017

 

'million

'million

Impact on initial application of IFRS 15

4,217

-

Gas revenue accrued during the period

21

-

 

4,238

-

20.  Cash and cash equivalents

 

As at
30 June 2018

As at
31 Dec 2017

 

'million

'million

Cash on hand

5

3

Restricted cash

-

19,166

Cash at bank

155,976

114,530

 

 155,981

437,212

       Included in cash and cash equivalents is the total amount of  30.59 billion ($108.2 million) arising from NPDC's share of gas proceeds . These amounts will be applied against tolling fees from the gas processing on the expanded Oben Gas Plant solely funded by Seplat and on-going cash calls.

21.  Share capital

21a.  Authorised and issued share capital

 

As at
30 June 2018

As at
31 Dec 2017

 

'million

'million

Authorised ordinary share capital

 

 

 

 

 

1,000,000,000 ordinary shares denominated in Naira of 50 kobo per share

500

500

 

 

 

Issued and fully paid

 

 

 

 

 

588,444,561 (2017: 563,444,561) issued shares denominated in Naira
of 50 kobo per share

296

283

 

21b.  Employee share based payment scheme

 

As at 30 June 2018, the Group had awarded 40,410,644 shares (2017: 33,697,792 shares) to certain employees and senior executives in line with its share based incentive scheme. Included in the share based incentive schemes are two additional schemes (2017 Deferred Bonus Scheme and 2018 LTIP Scheme) awarded during the reporting period. During the half year ended 30 June 2018, 5,534,964 shares were vested (31 December 2017: No shares had vested).

Notes to the interim condensed consolidated
financial statements continued

21c.         Movement in share capital

 

Number
of shares

Issued share capital

Treasury shares

Share based payment reserve

Total

 

Shares

'million

'million

'million

'million

Opening balance as at 1 January 2018

563,444,561

283

-

4,332

4,615

Share based payments

-

-

-

1,609

1,609

Share issue

19,465,036

13

(13)

-

-

Vested shares

5,534,964

-

3

(3)

-

Closing balance as at 30 June 2018

588,444,561

296

(10)

5,938

6,224

 

22.  Trade and other payables

 

As at
30 June 2018

As at
31 Dec 2017

 

'million

'million

Trade payables

 16,440

 19,191

Nigerian Petroleum Development Company (NPDC)

 10,203

-

Accruals and other payables

 35,267

 45,570

Pension payable

 13

 55

NDDC levy

 2,035

 2,564

Deferred revenue

 -  

41,970

Royalties payable

 12,657

 16,209

 

 76,615

125,559

 

Included in accruals and other payables are field-related accruals of 15.2 billion (2017: 17 billion) and other vendor payables of 20.1 billion (2017: 29 billion). Royalties include accruals in respect of gas sales for which payment is outstanding at the end of the year.

NPDC payables relate to cash calls paid in advance in line with the Group's Joint operating agreement (JOA) on OML 4, OML 38 and OML 41. The net amount of 10.2 billion has been reported after adjusting for interests as set out in the JOA and undercash call payments in other currencies.

 

Notes to the interim condensed consolidated
financial statements continued

23.  Computation of cash generated from operations

 

 

Half year ended

30 June 2018

Half year ended

30 June 2017

 

Notes

'million

'million

Profit/(loss) before tax

 

37,093

(8,090)

Adjusted for:

 

 

 

Depletion, depreciation and amortisation

 

 19,459

9,583

Interest on bank loan

14

 11,722

10,560

Interest on advance payments fo crude oil sales

14

 530

 -  

Unwinding of discount on provision for decommissioning

14

 416

14

Interest income

14

 (1,330)

(270)

Fair value loss on contingent consideration

13

 1,367

274

Fair value gain on other asset

13

-

(463)

Unrealised foreign exchange loss

 

-

264

Share based payments expenses

20c

 1,609

818

Defined benefit expenses

 

 389

341

Reversal of impairment loss on NPDC and NAPIMS receivables

11

(529)

-

Loss on disposal of other property, plant and equipment

 

-

25

Changes in working capital (excluding the effects of exchange differences):

 

 

 

Trade and other receivables, including prepayments

 

 34,349

(8,133)

Contract assets

 

 (4,238)

-

Trade and other payables

 

 (25,799)

26,313

Inventories

 

 (16)

1,256

Net cash from operating activities

 

 75,022

32,492

 

24.  Related party relationships and transactions

The Group is controlled by Seplat Petroleum Development Company Plc (the 'parent Company'). The shares in the parent Company are widely held.

24a.       Related party relationships

 

The services provided by the related parties:

 

Abbeycourt Trading Company Limited: The Chairman of Seplat is a director and shareholder. The company provides diesel supplies to Seplat in respect of Seplat's rig operations.

Cardinal Drilling Services Limited (formerly Caroil Drilling Nigeria Limited): Is owned by common shareholders with the parent Company. The company provides drilling rigs and drilling services to Seplat.

Charismond Nigeria Limited: The sister to the CEO works as a General Manager. The company provides administrative services including stationery and other general supplies to the field locations.

Helko Nigeria Limited: The Chairman of Seplat is shareholder and director. The company owns the lease to Seplat's main office at 25A Lugard Avenue, Lagos, Nigeria.

 

Notes to the interim condensed consolidated
financial statements continued

Keco Nigeria Enterprises: The Chief Executive Officer's sister is shareholder and director. The company provides diesel supplies to Seplat in respect of its rig operations.

Montego Upstream Services Limited: The Chairman's nephew is shareholder and director. The company provides drilling and engineering services to Seplat.

Stage leasing (Ndosumili Ventures Limited): is a subsidiary of Platform Petroleum Limited. The company provides transportation services to Seplat.

Nerine Support Services Limited: Is owned by common shareholders with the parent Company. Seplat leases a warehouse from Nerine and the company provides agency and contract workers to Seplat.

Oriental Catering Services Limited: The Chief Executive Officer of Seplat's spouse is shareholder and director. The company provides catering services to Seplat at the staff canteen.

ResourcePro Inter Solutions Limited: The Chief Executive Officer of Seplat's in-law is its UK representative. The company supplies furniture to Seplat.

Shebah Petroleum Development Company Limited (BVI): The Chairman of Seplat is a director and shareholder of SPDCL (BVI). SPDCL (BVI) provided consulting services to Seplat.

The following transactions were carried by Seplat with related parties:

24b.       Related party relationships

 

Half year ended

30 June 2018

Half year ended

30 June 2017

Purchases of goods and services

'million

'million

Shareholders of the parent company

 

 

SPDCL (BVI)

138

172

 

138

172

Entities controlled by key management personnel:

 

 

Contracts > $1million in 2017

 

 

Nerine Support Services Limited

755

826

 

755

826

 

 

 

Contracts < $1million

 

 

Abbey Court trading Company Limited

128

107

Charismond Nigeria Limited

14

10

Cardinal Drilling Services Limited

180

190

Keco Nigeria Enterprises

14

22

STAGE Leasing Limited

233

170

Oriental Catering Services Limited

94

65

ResourcePro Inter Solutions Limited

3

-

 

666

564

Total

1,421

1,562

 

* Nerine charges an average mark-up of 7.5% on agency and contract workers assigned to Seplat. The amounts shown above are gross i.e. it includes salaries and Nerine's mark-up. Total costs for agency and contracts during the half year ended 30 June 2018 is 703 million (2017: 795 million).

 

Notes to the interim condensed consolidated
financial statements continued

24c.       Balances

The following balances were receivable from or payable to related parties as at 30 June 2018:

 

 

As at
30 June 2018

As at
31 Dec 2017

Prepayments / receivables

'million

'million

Entities controlled by key management personnel

 

 

Cardinal Drilling Services Limited

1,682

1,681

 

1,682

1,681

 

 

As at 30 June 2018

As at 31 Dec 2017

Payables

'million

'million

Entities controlled by key management personnel

 

 

Montego Upstream Services Limited

-

115

Nerine Support Services Limited

13

2

Keco Nigeria Enterprises

-

8

Cardinal Drilling Services Limited

-

292

Helko Nigeria Limited

-

-

 

13

417

 

25.  Commitments and contingencies

25a.  Operating lease commitments - Group as lessee

 

The Group leases drilling rigs, buildings, land, boats and storage facilities. The lease terms are between 1 and 5 years. The operating lease commitments of the Group as at 30 June 2018 are:

 

Operating lease commitments

As at
30 June 2018

As at
31 Dec 2017

 

'million

'million

Not later than one year

-

728

Later than one year and not later than five years

-

565

 

-

1,293

25b. Contingent liabilities

 

The Group is involved in a number of legal suits as defendant. The estimated value of the contingent liabilities for the period ended 30 June 2018 is 352 million (2017: 4.7 billion). The contingent liability for the period ended 30 June 2018 is determined based on possible occurrences though unlikely to occur. No provision has been made for this potential liability in these financial statements. Management and the Group's solicitors are of the opinion that the Group will suffer no loss from these claims.

26.  Proposed dividend

The directors paid an interim dividend of ₦8.99bn (2017: Nil) per fully paid ordinary share. The aggregate amount of the dividend was paid out of retained earnings as at 31 March 2018.

 

Notes to the interim condensed consolidated
financial statements continued

27.  Events after the reporting period

There were no significant events other than proposed dividends that would have a material effect on the Group after the reporting period.

28.  Exchange rates used in translating the accounts to Naira

The table below shows the exchange rates used in translating the accounts into Naira.

 

Basis

30 June 2018
₦/$

30 June 2017
₦/$

31 December 2017
₦/$

Fixed assets - opening balances

Historical rate

Historical

Historical

Historical

 

Fixed assets - additions

Average rate

305.81

305.86

305.80

 

Fixed assets - closing balances

Closing rate

305.90

305.85

305.81

 

Current assets

Closing rate

305.90

305.85

305.81

 

Current liabilities

Closing rate

305.90

305.85

305.81

 

Equity

Historical rate

Historical

Historical

Historical

 

Income and Expenses:

Overall Average rate

305.81

305.86

305.81

 

                   

 

 

 

 

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

for the half year ended 30 June 2018

 

 

Half year ended

30 June 2018

Half year
ended

30 June 2017

3 months
ended
30 June 2018

3 months
ended

30 June 2017

 

 

Unaudited

Unaudited

Unaudited

Unaudited

 

Note

$'000

$'000

$'000

$'000

Revenue from contracts with customers

7

 342,676

 131,814

 162,088

 84,515

Cost of sales

8

 (168,364)

 (78,187)

 (80,636)

 (50,003)

Gross profit

 

 174,312

 53,627

 81,452

 34,512

Other income

9

 27,741

 -  

 19,150

 -  

General and administrative expenses

10

 (38,482)

 (36,315)

 (22,404)

 (19,556)

Reversal of/(impairment) losses on financial assets-net

11

 1,730

 -  

 (456)

 -  

Gain/(loss) on foreign exchange-net

12

 23

 (866)

 (1,847)

 (2,596)

Fair value loss - net

13

 (6,954)

 (9,210)

 (1,301)

 (3,777)

Operating profit

 

 158,370

 7,236

 74,594

 8,583

Finance income

14

 4,351

 883

 2,922

 673

Finance costs

14

 (41,424)

 (34,573)

 (15,029)

 (17,392)

Profit/(loss) before taxation

 

 121,297

 (26,454)

 62,487

 (8,136)

Taxation

15

 (72,753)

 (1,119)

 (34,500)

 (300)

Profit/(loss) for the period

 

 48,544

 (27,573)

 27,987

 (8,436)

 

 

 

 

 

 

Other comprehensive income/(loss):

 

 

 

 

 

Items that may be reclassified to profit or loss:

 

 

 

 

 

Foreign currency translation difference

 

-

-

-

-

 

 

 

 

 

 

Total comprehensive income/(loss) for the period

 

 48,544

 (27,573)

  27,987

(8,436)

 

 

 

 

 

 

Earnings/(loss) per share ($)

16

 0.08

(0.05)

 0.05

(0.01)

Diluted earnings/(loss) per share ($)

16

 0.08

(0.05)

 0.05

(0.01)

 

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 statement
of financial position

As at 30 June 2018

 

 

As at
30 June 2018

As at
31 Dec 2017 

 

 

Unaudited

Audited

 

Note

$'000

$'000

Assets

 

 

 

Non-current assets

 

 

 

Oil and gas properties

 

 1,246,736

 1,286,387

Other property, plant and equipment

 

 2,252

 5,078

Other asset

 

 202,287

 217,031

Deferred tax

15

 167,719

 223,731

Tax paid in advance

 

 31,623

 31,623

Prepayments

 

 269

 939

Total non-current assets

 

 1,650,886

 1,764,789

Current assets

 

 

 

Inventories

 

 100,361

 100,336

Trade and other receivables

18

 195,021

 310,345

Contract assets

19

 13,858

 -  

Prepayments

 

 1,532

 1,948

Cash & cash equivalents

20

 509,907

 437,212

Total current assets

 

 820,679

 849,841

Total assets

 

2,471,565

 2,614,630

Equity and liabilities

 

 

 

Equity

 

 

 

Issued share capital

21a

 1,867

 1,826

Share premium

 

 497,457

 497,457

Treasury shares

 

(32)

-

Share based payment reserve

21b

 23,061

 17,809

Capital contribution

 

 40,000

 40,000

Retained earnings

 

 957,411

 944,108

Foreign currency translation reserve

 

 1,897

 1,897

Total shareholders' equity

 

 1,521,661

 1,503,097

Non-current liabilities

 

 

 

Interest bearing loans & borrowings

17

 501,370

 304,677

Contingent consideration

6.4

 18,370

 13,900

Provision for decommissioning obligation

 

 107,673

 106,312

Defined benefit plan                 

 

 7,793

 6,518

Total non-current liabilities

 

 635,206

 431,407

Current liabilities

 

 

 

Interest bearing loans and borrowings

17

 43,363

 265,400

Trade and other payables

22

 250,459

 410,593

Current tax liabilities

 

 20,876

 4,133

Total current liabilities

 

 314,698

 680,126

Total liabilities

 

949,904

 1,111,533

Total shareholders' equity and liabilities

 

2,471,565

2,614,630

 

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

 

Interim condensed consolidated statement
of financial 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              

 

 

 

 

A. B. C. Orjiako

A. O. Avuru

R.T. Brown 

FRC/2013/IODN/00000003161

FRC/2013/IODN/00000003100

FRC/2014/ANAN/00000017939

Chairman

Chief Executive Officer

Chief Financial Officer

30 July 2018

 

 

 

30 July 2018

 

30 July 2018

 

Interim condensed consolidated statement
of changes in equity continued

for the half year ended 30 June 2018

for the half year ended 30 June 2017

 

 

 

 

 

 

Issued share

capital

Share premium

Treasury shares

Share based

payment reserve

Capital contribution

Retained earnings

Foreign currency translation reserve

Total equity

 

 

$'000

$'000

$'000

$'000

$'000

$'000

$'000

$'000

 

At 1 January 2017

1,826

497,457

-

12,135

40,000

678,922

3,675

1,234,015

 

Loss for the period

 -  

 -  

 -  

 -  

 -  

(27,573)

 -  

(27,573)

 

Other comprehensive income

-

-

-

-

-

-

-

-

 

Total comprehensive loss for
the period

 -  

 -  

 -  

 -  

 -  

(27,573)

 -  

(27,573)

 

Transactions with owners in
their capacity as owners:

 

 

 

 

 

 

 

 

 

Share based payments

-

-

-

2,673

-

-

-

2,673

 

Total

-

-

-

2,673

-

 -

-

 2,673

 

At 30 June 2017 (unaudited)

 1,826

 497,457

-

 14,808

 40,000

651,349

 3,675

1,209,115

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

for the half year ended 30 June 2018

 

 

 

Issued share

capital

Share premium

Treasury shares

Share based

payment reserve

Capital contribution

Retained earnings

Foreign currency translation reserve

Total equity

 

 

$'000

$'000

$'000

$'000

$'000

$'000

$'000

$'000

 

At 1 January 2018

1,826

497,457

-

17,809

40,000

944,108

1,897

1,503,097

 

Impact of change in
accounting policy:

 

 

 

 

 

 

 

 

 

Adjustment on initial application of IFRS 9 (Note 3.3)

-

-

-

-

-

(5,816)

-

(5,816)

 

Adjustment on initial application of IFRS 15 (Note 3.3)

-

-

-

-

-

-

-

-

 

Adjusted balance at
1 January 2018

1,826

497,457

-

17,809

40,000

938,292

1,897

1,497,281

 

Profit for the period

-

-

-

-

-

48,544

-

48,544

 

Total comprehensive income
for the period

-

-

-

-

-

48,544

-

48,544

 

Transactions with owners in their capacity as owners:

 

 

 

 

 

 

 

 

 

Dividends paid

-

-

-

-

-

(29,425)

-

(29,425)

 

Share based payments

-

-

-

5,261

-

-

-

5,261

 

Issue of shares

41

-

(41)

-

-

-

-

-

 

Vested shares

-

-

9

(9)

-

-

-

-

 

Total

41

-

(32)

5,252

-

(29,425)

-

 (24,164)

 

At 30 June 2018 (unaudited)

 1,867

 497,457

(32)

23,061

40,000

957,411

1,897

1,521,661

 

                       

 

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 2018

 

 

Half year
ended
30 June 2018

Half year
ended
30 June 2017

 

 

$'000

$'000

 

Note

Unaudited

Unaudited

Cash flows from operating activities

 

 

 

Cash generated from operations

23

 245,355

106,241

Net cash inflows from operating activities

 

 245,355

106,241

Cash flows from investing activities

 

 

 

Investment in oil and gas properties

 

  (21,157)

(11,202)

Investment in other property, plant and equipment

 

-

(386)

Proceeds from disposal of other property, plant and equipment

 

4

-

Receipts from other asset

 

  14,744

22,604

Interest received

 

4,351

883

Net cash inflows/(outflows) from investing activities

 

(2,058)

11,899

Cash flows from financing activities

 

 

 

Repayments of bank financing

 

 (578,000)

 (41,500)

Receipts from bank financing

 

 195,499

-

Dividend paid

 

(29,425)

-

Proceeds from senior notes issued

 

 339,546

-

Repayments on crude oil advance

 

 (77,499)

-

Payments for other financing charges

 

 (1,518)

-

Interest paid on bank financing

 

 (19,205)

(34,526)

Net cash outflows from financing activities

 

(170,602)

(76,026)

Net increase in cash and cash equivalents

 

72,695

42,114

Cash and cash equivalents at beginning of period

 

437,212

159,621

Effects of exchange rate changes on cash and cash equivalents

 

-

(229)

Cash and cash equivalents at end of period

 

509,907

201,506

 

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

 

Notes to the interim condensed consolidated
financial 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 US$340 million paid at the completion of the acquisition on 31 July 2010 and a contingent payment of US$33 million 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 US$80 per barrel. US$358.6 million was allocated to the producing assets including US$18.6 million as the fair value of the contingent consideration as calculated on acquisition date. The contingent consideration of US$33 million 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 US$259.4 million.

 

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.

 

 

Subsidiary

Country of incorporation
and place of business

Shareholding
%

Principal
activities

Newton Energy Limited

Nigeria

100%

Oil & gas exploration and production

Seplat Petroleum Development UK

United Kingdom

100%

Oil & gas exploration and production

Seplat East Onshore Limited

Nigeria

100%

Oil & gas exploration and production

Seplat East Swamp Company Limited

Nigeria

100%

Oil & gas exploration and production

Seplat Gas Company

Nigeria

100%

Oil & gas exploration and production

ANOH Gas Processing Company Limited

Nigeria

100%

Gas processing

 

 

Notes to the interim condensed consolidated
financial 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 US$350 million 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 it's subsidiaries. The proceeds of the notes are being used to refinance existing indebtedness and for general corporate purposes.

·      The refinancing of an existing US$300 million revolving credit facility due in December 2018 with a new four year US$300 million 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. US$200 million 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 consolidated
financial 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

 

Title of standard

 

IFRS 16 Leases

Nature of change

 

IFRS 16 was issued in January 2016. It will result in almost all leases being recognised on the balance sheet, as the distinction between operating and finance leases is removed. Under the new standard, an asset (the right to use the leased item) and a financial liability to pay rentals are recognised. The only exceptions are short-term and low-value leases. The accounting for lessors will not significantly change.

Impact

 

Operating leases: The standard will affect primarily the accounting for the Group's operating leases which include leases of buildings, boats, storage facilities, rigs, land and motor vehicles. As at the reporting date, the Group had no non-cancellable operating lease commitments.

 

Short term leases & low value leases: The Group's one-year contracts with no planned extension commitments mostly applicable to leased staff flats will be covered by the exception for short-term leases, while none of the Group's leases will be covered by the exception for low value leases.

 

Service contracts: Some commitments such as contracts for the provision of drilling, cleaning and community services were identified as service contracts as they did not contain an identifiable asset which the Group had a right to control. It therefore did not qualify as leases under IFRS 16.

Date of adoption

 

The standard for leases is mandatory for financial years commencing on or after 1 January 2019. The Group does not intend to adopt the standard before its effective date.

 

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 consolidated
financial 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.

 

 

 

 

 

 

Amounts without impact of IFRS 9 and IFRS 15

 

Impact of IFRS 9

 

Impact of IFRS 15

 

As at
1 January 2018

 

Note

$'000

$'000

$'000

$'000

ASSETS

 

 

 

 

 

Current assets

 

 

 

 

 

Trade and other receivables

18

324,135

(5,816)

(13,790)

304,529

Contract assets

19

-

-

13,790

13,790

Total assets

 

2,614,630

(5,816)

-

2,608,814

Equity

 

 

 

 

 

Retained earnings

 

944,108

(5,816)

-

938,292

Total shareholders' equity

 

1,503,097

(5,816)

-

1,497,281

 

 

Notes to the interim condensed consolidated
financial statements continued

 

 

Amounts without impact of IFRS 9 and IFRS 15

 

Impact of IFRS 9

 

Impact of IFRS 15

 

As at
30 June 2018

 

Note

$'000

$'000

$'000

$'000

ASSETS

 

 

 

 

 

Current assets

 

 

 

 

 

Trade and other receivables

18

212,965

(4,086)

(13,858)

195,021

Contract assets

19

-

-

13,858

 13,858

Total current assets

 

824,765

(4,086)

-

 820,679

Total assets

 

2,475,625

(4,086)

-

2,471,566

EQUITY AND LIABILITIES

 

 

 

 

 

Equity

 

 

 

 

 

Retained earnings

 

961,497

(4,086)

-

957,411

Total shareholders' equity

 

1,525,747

(4,086)

-

1,521,661

 

 

 

 

 

 

Amount without impact of IFRS 9 and IFRS 15

Impact of IFRS 9

Impact of IFRS 15

Half year ended 30 June 2018

 

Notes

$'000

$'000

$'000

$'000

Revenue from contracts with customers

7

370,534

-

(27,858)

342,676

Cost of sales

8

(168,481)

-

117

(168,364)

Gross profit

 

202,053

-

(27,741)

174,312

Other income

9

-

-

27,741

27,741

Reversal of impairment losses on financial assets-net

11

-

1,730

-

1,730

Profit before taxation

 

119,567

1,730

-

121,297

Taxation

 

(72,753)

-

-

(72,753)

Profit for the period

 

46,814

1,730

-

48,544

Other comprehensive income

 

 

 

 

 

Items that may be reclassified to profit or loss:

 

 

 

 

 

Foreign currency translation difference

 

-

-

-

-

Total comprehensive income for the period

 

46,814

1,730

-

48,544

Earnings per share for profit attributable to the equity shareholders

 

 

 

 

 

Basic earnings per share ($)

 

0.07

0.01

-

0.08

Diluted earnings per share ($')

 

0.07

0.01

-

0.08

 

 

Notes to the interim condensed consolidated
financial statements continued

 

 

Amount without impact of IFRS 9 and IFRS 15

Impact of IFRS 9

Impact of IFRS 15

3 months ended 30 June 2018

 

Notes

$'000

$'000

$'000

$'000

Revenue from contracts with customers

7

181,387

-

(19,299)

 162,088

Cost of sales

8

(80,785)

-

149

 (80,636)

Gross profit

 

100,602

-

(19,150)

 81,452

Other income

9

-

-

19,150

19,150

Impairment losses on financial assets - net

11

-

(456)

-

(456)

Profit before taxation

 

62,943

(456)

-

62,487

Taxation

 

(34,500)

-

-

(34,500)

Profit for the period

 

28,443

(456)

-

27,987

Other comprehensive income

 

 

 

 

 

Items that may be reclassified to profit or loss:

 

 

 

 

 

Foreign currency translation difference

 

-

-

-

-

Total comprehensive income for the period

 

28,443

(456)

 

27,987

Earnings per share for profit attributable
to the equity shareholders

 

 

 

 

 

Basic earnings per share ($)

 

0.06

(0.01)

-

0.05

Diluted earnings per share ($)

 

0.06

(0.01)

-

0.05

 

 

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.

 

 

Notes to the interim condensed consolidated
financial statements continued

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.

 

 

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

 

 

 

Measurement category

                    Carrying amount

 

Original

New

Original

New

 

 

IAS 39

IFRS 9

US$ '000

US$ '000

 

Current financial assets

 

 

 

 

 

Trade and other receivables:

 

 

 

 

Trade receivables

L and R

Amortised cost

108,685

108,685

 

NPDC receivables

L and R

Amortised cost

112,664

112,664

 

NAPIMS receivables

L and R

Amortised cost

12,506

12,506

 

Other receivables*

L and R

Amortised cost

       23

23

 

Cash and cash equivalents

L and R

Amortised cost

437,212

437,212

 

 

 

 

 

 

Non-current financial liabilities

 

 

 

 

Interest bearing loans and borrowings

Amortised cost

Amortised cost

304,677

304,677

 

 

 

 

 

 

Current financial liabilities

 

 

 

 

Interest bearing loans and borrowings

Amortised cost

Amortised cost

265,400

265,400

 

Trade and other payables**

Amortised cost

Amortised cost

127,128

127,128

 

 

*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.

 

 

 

Notes to the interim condensed consolidated
financial statements continued

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 period as at 30 June 2018
is as follows:

                 

 

Notes

$'000

Closing retained earnings as at 31 December 2017- IAS 39

 

944,108

Increase in provision for Nigerian Petroleum Development Company

(NPDC) receivables

(a)

(5,553)

Increase in provision for National Petroleum Investment Management

Services (NAPIMS) receivables

(b)

(263)

 

 

(5,816)

Opening retained earnings 1 January 2018 on adoption of IFRS 9

 

938,292

 

 

 

 

Notes

$'000

Profit for the period (without impact of IFRS 9 and IFRS 15)

 

46,814

Reversal of impairment loss for Nigerian Petroleum Development Company

(NPDC) receivables

(a)

1,865

Increase in impairment for National Petroleum Investment Management

Services (NAPIMS) receivables

(b)

(135)

Total reversal of impairment loss

 

1,730

Profit for the period (with impact of IFRS 9 and IFRS 15)

 

48,544

 

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%.

 

 

Notes to the interim condensed consolidated
financial statements continued

 

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

 

Stage 1

Stage 2

Stage 3

Total

 

12-month ECL

Lifetime ECL

Lifetime ECL

 

 

$'000

$'000

$'000

$'000

Gross EAD*

-

37,179

75,485

112,664

Loss allowance as at 1 January 2018

-

(105)

(5,448)

(5,553)

Net EAD

-

37,074

70,037

107,111

 

 

                                                                                                                                                                      30 June 2018

 

Stage 1

Stage 2

Stage 3

Total

 

12-month ECL

Lifetime ECL

Lifetime ECL

 

 

$'000

$'000

$'000

$'000

Gross EAD*

-

-

48,439

48,439

Loss allowance as at 30 June 2018

-

-

(3,688)

(3,688)

Net EAD

-

-

44,751

44,751

 

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 Nigerian Petroleum Development Company (NPDC) receivables as at 1 January 2018 and 30 June 2018 is as follows:

 

 

$'000

Loss allowance as at 1 January 2018 - calculated under IAS 39

-

Amounts restated through opening retained earnings

5,553

Loss allowance as at 1 January 2018 - calculated under IFRS 9

5,553

Reversal of impairment loss on NPDC receivables

(1,865)

Loss allowance as at 30 June 2018 - Under IFRS 9

3,688

 

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 NPDC 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.

 

Notes to the interim condensed consolidated
financial statements continued

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.

 

                                                                                                                                                                   1 January 2018

 

Stage 1

Stage 2

Stage 3

Total

 

12-month ECL

Lifetime ECL

Lifetime ECL

 

 

$'000

$'000

$'000

$'000

Gross EAD*

4,274

-

8,232

12,506

Loss allowance as at 1 January 2018

(5)

-

(258)

(263)

Net EAD

4,269

-

7,974

12,243

 

                                                                                                                                                                      30 June 2018

 

Stage 1

Stage 2

Stage 3

Total

 

12-month ECL

Lifetime ECL

Lifetime ECL

 

 

$'000

$'000

$'000

$'000

Gross EAD*

3,876

-

682

4,558

Loss allowance as at 30 June 2018

(72)

-

(326)

(398)

Net EAD

3,804

-

356

4,160

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 that make the full recovery of indebtedness highly improbable.

 

Notes to the interim condensed consolidated
financial statements continued

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

 

 

 

$'000

Loss allowance as at 1 January 2018 - calculated under IAS 39

 

-

Amounts restated through opening retained earnings

 

263

Loss allowance as at 1 January 2018 - calculated under IFRS 9

 

263

Increase in provision on impairment loss on NPDC receivables

 

135

Loss allowance as at 30 June 2018 - Under IFRS 9

 

398

 

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.

 

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 $2,350 (2017: $14,598). 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 deemed immaterial as the receaivables were assessed to be fully recoverable and less than 30 days past due as at the reporting date. The impairment was nill 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.

 

Notes to the interim condensed consolidated
financial statements continued

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 $40 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 $50 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 it's financial instruments as amortised cost, fair value through profit or loss and as fair value through other comprehensive income. 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.

 

Notes to the interim condensed consolidated
financial statements continued

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.

 

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 adopted the new rules prospectively 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.

 

Notes to the interim condensed consolidated
financial statements continued

3.3.4.1.   Presentation of contract assets

 

 

 

Amount without impact of IFRS 15 and IFRS 9

 

 

Impact of IFRS 9

Impact of IFRS 15

As at 30 June 2018

 

Note

$'000

 

$'000

$'000

ASSETS

 

 

 

 

 

Current assets

 

 

 

 

 

Trade and other receivables

(a)

212,965

(4,086)

(13,858)

  195,021

Contract assets

(a)

-

-

13,858

 13,858

 

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.

 

 

 

As at 30 June 2018

 

 

Unaudited

 

Note

$'000

Revenue from contracts with customers (without IFRS 15 impact)

 

370,534

Reclassification of underlifts to other income

(a)

(27,741)

Reclassification of demurrage from cost of sales

(b)

(117)

Total impact of reclassification on revenue

 

(27,858)

Revenue from contract with customers under IFRS 15

 

342,676

 

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.

 

 

 

 

Notes to the interim condensed consolidated
financial statements continued

3.3.4.3.   Financing components

             

          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 recognized at the 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 at a 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.

 

§ 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 determing the amount of consideration recognized 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.

 

Notes to the interim condensed consolidated
financial statements continued

§ Contract enforecability 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 recognises 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.

 

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.

Notes to the interim condensed consolidated
financial statements continued

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.

 

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.

 

Notes to the interim condensed consolidated
financial statements continued

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.

 

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 33) 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.

 

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.

 

Notes to the interim condensed consolidated
financial statements continued

iv)      Defined benefit plan

 

The Group has placed reliance on the actuarial valuation 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 contract, the performance is satisfied through the delivery of a series goods. Revenue is recognised overtime 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 contract. The right to invoice is a measure of progress that allows the Group to recognised revenue based on amount invoiced to the customer. Judgement has been applied in evaluating that the Group right to consideration corresponds directly with the value transferred to the customers 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.

 

§ 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 it's 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 costs.

 

Notes to the interim condensed consolidated
financial statements continued

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 $18.5 million for OML 53 at the fair value of$18.4 million (2017: $13.9 million). It is contingent on oil price rising above US$90 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.

 

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.

 

Notes to the interim condensed consolidated
financial statements continued

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.

 

Risk

Exposure arising from

Measurement

Management

Market risk - foreign exchange

Future commercial transactions

Recognised financial assets and liabilities not denominated in
US dollars.

Cash flow forecasting

Sensitivity analysis

Match and settle foreign denominated cash inflows
with foreign denominated
cash outflows.

Market risk - interest rate

Long term borrowings at variable rate

Sensitivity analysis

Review refinancing opportunities

Market risk - commodity  prices

Future sales transactions

Sensitivity analysis

Oil price hedges

Credit risk

Cash and cash equivalents, trade receivables and derivative financial instruments.

Aging analysis

Credit ratings

Diversification of bank deposits.

Liquidity risk

Borrowings and other liabilities

Rolling cash flow forecasts

Availability of committed credit lines and borrowing facilities

 

 

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 they fall 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

 

 

Effective interest rate

  Less than

     1 year

        1 - 2

years

         2 - 3

years

         3 - 5

years

After
5 years

Total

 

 

%

$ '000

$ '000

$ '000

$ '000

$ '000

$ '000

30 June 2018

 

 

 

 

 

 

 

Non - derivatives

 

 

 

 

 

 

 

Fixed interest rate borrowings

 

 

 

 

 

 

 

Senior notes

9.25%

 33,814

 32,915

 32,825

 415,649

-

515,203

Variable interest rate borrowings
(bank loans):

 

 

 

 

 

 

 

Stanbic Ibtc Bank Plc

6.0% +LIBOR

 4,886

 7,382

 6,877

 9,377

 -  

 28,522

The Standard Bank Of South Africa L

6.0% +LIBOR

 3,257

 4,921

 4,585

 6,251

 -  

 19,014

Nedbank Limited, London Branch

6.0% +LIBOR

 6,785

 10,253

 9,551

 13,024

 -  

 39,613

Standard Chartered Bank

6.0% +LIBOR

 6,107

 9,227

 8,597

 11,721

 -  

 35,652

Natixis

6.0% +LIBOR

 4,750

 7,177

 6,686

 9,116

 -  

 27,729

FirstRand Bank Limited Acting

6.0% +LIBOR

 4,750

 7,177

 6,686

 9,116

 -  

 27,729

Citibank N.A. London

6.0% +LIBOR

 4,071

 6,151

 5,731

 7,814

 -  

 23,767

The Maritus Commercial Bank Plc

6.0% +LIBOR

 4,071

 6,151

 5,731

 7,814

 -  

 23,767

Nomura International Plc

6.0% +LIBOR

 2,036

 3,076

 2,866

 3,907

 -  

 11,885

Other non - derivatives

 

 

 

 

 

 

 

Trade and other payables**

-

70,403

-

-

-

-

70,403

 

 

144,930

94,430

90,135

493,789

 

823,284

 

 

Effective interest rate

Less than
1 year

1 - 2
year

2 - 3
years

3 - 5
years

After
5 years

Total

 

%

$ '000

$ '000

$ '000

$ '000

$ '000

$ '000

31 December 2017<