Interim Management Statement & Q3 2018 Results

RNS Number : 5967F
SEPLAT Petroleum Development Co PLC
30 October 2018
 

Seplat Petroleum Development Company Plc

Interim management statement and consolidated interim financial results for the nine months ended 30 September 2018

Lagos and London, 30 October 2018:  Seplat Petroleum Development Company Plc ("Seplat" or the "Company"), a leading Nigerian independent oil and gas company listed on both the Nigerian Stock Exchange and London Stock Exchange, today announces its results for the nine months ended 30 September 2018.

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

"Seplat has continued to deliver on its production targets which, combined with an oil price tailwind, has resulted in yet another consecutive quarter of very strong financial performance and profitability. With the current business generating significant free cash flow and combined with our robust balance sheet which we are in the process of deleveraging further, we plan to build on this performance in the coming quarters as we step up organic development activities across our existing portfolio with headroom to also capitalise on inorganic growth opportunities as and when they may arise, in line with our price disciplined approach".

Highlights

Working interest production for the third quarter and first nine months of 2018(1)

 

·     

9M working interest production of 50,834 boepd remains within guided range; full year working interest production guidance of 48,000 to 55,000 boepd is maintained

·     

Uptime on the Trans Forcados System during Q3 was 88% (year to date 80% in line with budget), while average reconciliation losses stood at 7%

·     

Rig based work on recompletion of Ohaji South oil production wells on OML 53 and one new gas production well at Oben on OMLs 4,38 and 41 set to commence in Q4

 

 

 

9M Working Interest

 

Q3 Working Interest

 

 

Liquids

Gas

Oil equivalent

 

Liquids

Gas

Oil equivalent

Production

Seplat %

bopd

MMscfd

boepd

 

bopd

MMscfd

boepd

OMLs 4, 38 & 41

45.0%

23,764

151

48,902

 

24,400

143

48,209

OPL 283

40.0%

962

-

962

 

1,152

-

1,152

OML 53

40.0%

970

-

970

 

942

-

942

Total

 

25,696

151

50,834

 

26,494

143

50,303

(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.

Seplat continues to record strong financial performance and sustained profitability, interim dividend declared

·     

9M revenue boosted to US$568 million (9M 2017: US$279 million); 9M oil revenues of US$441 million up 97% year-on-year (9M 2017: US$224 million); 9M gas revenues of US$127 million up 48% year-on-year (9M 2017: US$86 million);

·     

Gross profit US$306 million (9M 2017: US$125 million) with 9M average oil price realisation US$71.14/bbl (9M 2017: US$46.49/bbl) and 9M average gas price US$3.06/Mscf (9M 2017: US$3.01/Mscf)

·     

9M operating profit US$264 million (9M 2017: US$53 million) while 9M profit before tax has extended to US$213 million (9M 2017: US$2 million loss); after 9M taxes of US$121 million (including non cash deferred taxes of US$87 million) 9M profit after tax stood at US$91 million (9M 2017: US$5 million loss)

Robust free cash flow translates to balance sheet strength with de-leveraging post period end to optimise capital structure

·     

9M cash generated from operations US$386 million (9M 2017: US$167 million) versus capex incurred of US$29 million (9M 2017: US$22 million); Net cash at 30 September 2018 US$84 million; gross debt US$550 million and cash at bank US$634 million; Post period end, issued notice to the 2022 RCF lending banks to reduce the outstanding balance on the facility to US$100 million thereby reducing overall gross debt to US$450 million

·     

Extended hedging programme with dated Brent puts covering 2 MMbbls at an average strike price of US$55/bbl in H1 2019.  Q4 2018 hedges comprise dated Brent puts covering 1.5 MMbbls at an average strike price of US$50/bbl

·     

Following a review of Seplat's operational, liquidity and financial position the Board has decided to declare an interim dividend of US$0.05 per share in line with our normal dividend distribution timetable. This in effect makes the April 2018 dividend a special dividend payment to normalise returns to shareholders after the board had suspended dividends for 2016 & 2017

Project Updates

·     

ANOH: Signed a Shareholder Agreement and Share Subscription Agreement in August with the Nigerian Gas Processing and Transportation Company ("NGPTC") for it to subscribe for fifty per cent of the shares in ANOH Gas Processing Company Limited ("AGPC") that will process future wet gas production from the upstream unitised gas fields at OML 53 & OML21, which is operated by Shell.  The agreements are an important precursor to the Final Investment Decision ("FID") for the ANOH project which is still expected in Q4 2018

·     

Amukpe to Escravos Pipeline ("AEP"): Based on information provided by the pipeline owners and contractor undertaking completion works and connection to the Escravos terminal and offshore export pipeline the Company maintains its expectation of completion by year end

Important notice

Information contained within this release is un-audited and is subject to further review. 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.

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 / Molly Stewart

seplat@fticonsulting.com

+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/

Interim Condensed Consolidated Financial Statements (Unaudited)
for the third quarter ended 30 September 2018

Expressed in Naira ('NGN')

Condensed consolidated statement of profit or loss and other comprehensive income

for the third quarter ended 30 September 2018

 

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended
30 Sept 2018

3 months ended

30 Sept 2017

 

 

Unaudited

Unaudited

Unaudited

Unaudited

 

Note

'million

'million

'million

'million

Revenue from contracts with customers

7

 173,710

85,190

 68,916

44,873

Cost of sales

8

 (80,200)

   (47,107)

 (28,713)

(23,193)

Gross profit

 

 93,510

38,083

 40,203

21,680

Other income/(expenses)-net

9

 6,259

-

 (2,224)

-

General and administrative expenses

10

 (16,870)

 (17,167)

 (5,101)

(7,611)

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

11

 521

-

 (8)

-

Loss on foreign exchange - net

12

 (208)

  (277)

 (216)

(13)

Fair value loss - net

13

 (2,449)

(4,361)

 (322)

(1,544)

Operating profit

 

 80,763

16,278

 32,332

12,512

Finance income

14

 2,050

483

 720

213

Finance costs                      

14

 (17,760)

(17,521)

 (5,092)

 (4,736)

Profit/(loss) before taxation

 

 65,053

(760)

 27,960

7,330

Taxation

15

 (37,085)

(860)

 (14,836)

(518)

Profit/(loss) for the period

 

 27,968

(1,620)

 13,124

6,812

 

 

 

 

 

 

Other comprehensive income:

 

 

 

 

 

Items that may be reclassified to profit or loss:

 

 

 

 

 

Foreign currency translation difference

 

468

932

315

(117)

 

 

 

 

 

 

Total comprehensive income/(loss) for the period

 

28,436

(688)

13,439

6,695

 

 

 

 

 

 

Earnings/(loss) per share ()

16

47.98

(2.88)

22.52

12.09

Diluted earnings/(loss) per share()

16

47.48

(2.84)

22.28

11.95

 

 

 

 

 

 

 

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

Condensed consolidated statement of financial position

As at 30 September 2018

 

 

As at 30 Sept 2018

As at 31 Dec 2017

 

 

Unaudited

Audited

 

Note

'million

'million

Assets

 

 

 

Non-current assets

 

 

 

Oil and gas properties

 

 374,518

 393,377

Other property, plant and equipment

 

 959

 1,553

Other asset

 

 58,497

 66,368

Deferred tax

15a

 41,836

 68,417

Tax paid in advance

 

 9,670

 9,670

Prepayments

 

 7,744

 287

Total non-current assets                          

 

 493,224

 539,672

Current assets

 

 

 

Inventories

 

 32,007

 30,683

Trade and other receivables

18

 51,245

 94,904

Contract assets

19

 3,401

 -  

Prepayments

 

 829

 595

Cash and cash equivalents

20

 194,067

 133,699

Total current assets

 

 281,549

 259,881

Total assets

 

774,773

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

 6,743

 4,332

Capital contribution

 

 5,932

 5,932

Retained earnings

 

 183,325

 166,149

Foreign currency translation reserve

 

 201,338

 200,870

Total shareholders' equity

 

 479,704

 459,646

Non-current liabilities

 

 

 

Interest bearing loans & borrowings

17

 163,006

 93,170

Contingent consideration

6.4

 5,641

 4,251

Provision for decommissioning obligation

 

 33,210

 32,510

Defined benefit plan                 

 

 2,058

 1,994

Total non-current liabilities

 

 203,915

 131,925

Current liabilities

 

 

 

Interest bearing loans and borrowings

17

 1,329

 81,159

Trade and other payables

22

 78,092

 125,559

Current taxation

 

 11,733

 1,264

Total current liabilities

 

 91,154

 207,982

Total liabilities

 

295,069

 339,907

Total shareholders' equity and liabilities

 

774,773

799,553

 

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

The Group financial statements of Seplat Petroleum Development Company Plc and its subsidiaries for the nine months

ended 30 September 2018 were authorised for issue in accordance with a resolution of the Directors on 30 October 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 October 2018

 

30 October 2018

 

30 October 2018

 

 

 

Condensed consolidated statement of changes in equity continued

for the third quarter ended 30 September 2018

For the third quarter ended 30 September 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

-

-

-

-

-

 (1,620)

-

 (1,620)

Other comprehensive income

-

-

-

-

-

-

          932

 932

Total comprehensive loss for the period

-

-

-

-

-

 

 (1,620)

 

932

 

 (688)

Transactions with owners in their capacity as owners:

 

 

 

 

 

 

 

 

Share based payments

-

-

-

 1,226

-

-

-

 1,226

Total

-

-

-

 1,226

-

 -  

 -  

 1,226

At 30 September 2017 (unaudited)

 283

 82,080

-

 3,823

 5,932

 83,432

 201,361

 376,911

 

 

 

 

 

 

 

For the third quarter ended 30 September 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 31 December 2017 as originally presented

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)

-

-

-

-

-

-

-

-

 

At 1 January 2018 - Restated

283

82,080

-

4,332

5,932

164,370

200,870

457,867

 

Profit for the period

 

 -  

 

 -  

 -  

 27,968

 -  

 27,968

 

Other comprehensive income

 

 

 

 

 

 

 468

 468

 

Total comprehensive income for the period

 -  

 -  

 -  

 -  

 -  

 27,968

 468

 28,436

 

Transactions with owners in their capacity as owners:

 

 

 

 

 

 

 

 

 

Dividends paid

 -  

 -  

 

 -  

 -  

 (9,013)

 -  

 (9,013)

 

Share based payments

 -  

 -  

 

 2,414

 -  

 -  

 -  

 2,414

 

Issue of shares

 13

 -  

 (13)

 

 -  

 -  

 -  

 -  

 

Vested shares

-

 

3

(3)

 

 

 

 

 

Total

 13

 -  

 (10)

 2,411

 -  

 (9,013)

 -  

 (6,599)

 

At 30 September 2018 (unaudited)

 296

 82,080

 (10)

 6,743

 5,932

 183,325

 201,338

 479,704

 

 

 

 

 

 

 

 

 

 

 

 

 

                             

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

Condensed consolidated statement of cash flow

for the third quarter ended 30 September 2018

 

9 months ended
30 Sept 2018

9 months ended 30 Sept 2017

 

'million

'million

                                                                                                            Note

Unaudited

Unaudited

Cash flows from operating activities

 

 

Cash generated from operations                                                              23                                

 118,126

 51,098

Net cash inflows from operating activities

 118,126

 51,098

Cash flows from investing activities

 

 

Investment in oil and gas properties

(8,777)

              (6,726)

Investment in other property, plant and equipment

-

 (157)

Receipts from other property, plant and equipment

1

-

Receipts from other asset                                                                        

7,936

6,913

Interest received

2,050

483

Net cash inflows/(outflows) from investing activities

1,210

 513

Cash flows from financing activities

 

 

Repayments of bank financing

 (176,782)

 (16,744)

Receipts from bank financing

 59,793

-

Dividends paid

 (9,013)

-

Proceeds from senior notes issued

 103,935

-

Repayments on crude oil advance

 (23,704)

(1,346)

Payments for other financing charges

 (1,190)

-

Interest paid on bank financing

 (12,400)

 (15,240)

Net cash outflows from financing activities

(59,361)

 (33,330)

Net increase in cash and cash equivalents

59,975

              18,281

Cash and cash equivalents at the beginning of the period

133,699

48,684

Effects of exchange rate changes on cash and cash equivalents

393

 43

Cash and cash equivalents at the end of the period

194,067

67,008

 

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

 

Notes to the 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 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 activity of the Company is the processing of gas from OML 53.

 

The Company together with its six wholly owned subsidiaries namely, Newton Energy, Seplat Petroleum Development Company UK Limited ('Seplat UK'), Seplat East Onshore Limited ('Seplat East'), Seplat East Swamp Company Limited ('Seplat Swamp'), Seplat Gas Company Limited ('Seplat GAS') and ANOH Gas Processing Company Limited are collectively referred to as the Group.

 

 

Subsidiary

Date of incorporation

Country of incorporation and place of business

Principal activities

Newton Energy Limited

1 June 2013

Nigeria

Oil & gas exploration and production

Seplat Petroleum Development UK

21 August 2014

United Kingdom

Oil & gas exploration and production

Seplat East Onshore Limited

12 December 2014

Nigeria

Oil & gas exploration and production

Seplat East Swamp Company Limited

12 December 2014

Nigeria

Oil & gas exploration and production

Seplat Gas Company

12 December 2014

Nigeria

Oil & gas exploration and production

ANOH Gas Processing Company Limited

18 January 2017

Nigeria

Gas processing

 

2.    Significant changes in the current reporting period

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

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

·      In March 2018, the Group obtained a 91.8 billion revolving facility to refinance of an existing 91.8 billion revolving credit facility due in December 2018. The facility has a tenor of 4 years (due in June 2022) with an initial interest rate of the 6% +Libor. Interest is 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.

·      25,000,000 additional shares were issued. In furtherance of the Group's Long Term Incentive Plan, in February 2018. The additional issued shares, less 5,534,964 shares which vested in April 2018, 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 and 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 condensed consolidated financial statements of the Group for the nine months reporting period ended 30 September 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 Company will not remain a going concern for at least twelve months from the date of these 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, and

·      IFRS 15 Revenue from contracts with customers

·      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.

 

v)     New standards, amendments and interpretations not yet adopted

       

The following standards have been issued but are 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 other 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 amendments before its effective date and is yet to assess the full impact of the amendments on its financial statements.

 

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 amendments before its effective date and is yet to assess the full impact of the amendments on its financial statements.

 

d.     Conceptual framework for financial reporting - Revised

 

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 amendments before its effective date date and is yet to assess the full impact of the amendments on its financial statements.

 

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 amendments before its effective date and is yet to assess the full impact of the amendments on its financial statements.

 

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 also discloses the related accounting policies that have been applied from 1 January 2018, where they are different from those applied in prior periods.

3.3.1.     Impact on the financial statements

 

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 changes in equity on 1 January 2018.

 

The Group has also 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. 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.

 

 

 

 

At 31 December 2017

 

Impact of IFRS 9

 

Impact of IFRS 15

As at 1 January

2018

 

Note

'million

'million

'million

'million

ASSETS

 

 

 

 

 

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 AND LIABILITIES

 

 

 

 

 

Equity

 

 

 

 

 

Retained earnings

 

166,149

(1,779)

-

164,370

Total shareholders' equity

 

459,646

(1,779)

-

457,867

 

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 the adjustments to the amounts recognised in the financial statements. The new accounting policies are set out in notes below. In accordance with the transitional provisions in IFRS 9, comparative figures have not been restated but the impact of adoption has been adjusted through opening retained earnings for the current reporting period.

 

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 were previously classified as loans and receivables (L and R) are now classified as financial assets 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

 

The adoption of IFRS 9 eliminates the policy choice on the treatment of gain or loss from the refinancing of a borrowing. Day one gain or loss can no longer be deferred over the remaining life of the borrowing but 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, 1 January 2018, the financial instruments of the Group were classified as follows:

 

 

           Classification & 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 exclude accruals, provisions, bonus, VAT, Withholding tax, deferred revenue and royalties.

 

The new carrying amounts in the table above have been determined based on the measurement criteria specified in IFRS 9. However, the impact of IFRS 9 expected credit loss impairment has not been considered here. See the subsequent pages for the impact of IFRS 9 ECL on the assets carried at amortised cost.

3.3.2.2.   Impairment of financial assets

The Group has seven types of financial assets that are subject to IFRS 9's new expected credit loss model. Under IFRS 9, the Group is required to revise its previous impairment methodology under IAS 39 for each of these classes of assets. The impact of the change in impairment methodology on the Group's retained earnings is disclosed in the table below.

 

§ Nigerian Petroleum Development Company (NPDC) receivables

§ National Petroleum Investment Management Services (NAPIMS)

§ Receivables from Shell Petroleum Development Company (SPDC)

§ Trade receivables

§ Contract assets

§ Other receivables and;

§ Cash and cash equivalents

 

The total impact on the Group's retained earnings as at 1 January 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)

Total transition adjustments

 

(1,779)

Opening retained earnings 1 January 2018 on adoption of IFRS 9

 

164,370

 

a)  Nigerian Petroleum Development Company (NPDC) receivables

 

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

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.

 

                                                                                                                          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 at default

 

 

                                                                                                                                 30 September 2018

 

Stage 1

Stage 2

Stage 3

Total

 

12-month ECL

Lifetime ECL

Lifetime ECL

 

 

'million

'million

'million

'million

Gross EAD*

-

-

14,827

14,827

Loss allowance as at 30 September 2018

-

-

(1,175)

(1,175)

Net EAD

-

-

13,652

13,652

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 amounts 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 31 December 2017

and 30 September 2018 is as follows:

 

 

'million

Loss allowance as at 31 December 2017 - calculated under IAS 39

-

Amounts adjusted 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

(523)

Loss allowance as at 30 September 2018 - Under IFRS 9

1,175

 

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 (d) for definition of default).

 

Loss given default (LGD)

The 12-month LGD was determined based on management's estimate of expected cash recoveries after considering historical recovery pattern of these receivables. The 12-month LGD assumptions are a reasonable proxy for 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. Historical data on these variables for the last ten years were used to determine the three economic scenarios (base, optimistic and downturn) and their 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

 

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

 

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.

 

                                                                                                                                    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 September 2018

 

Stage 1

Stage 2

Stage 3

Total

 

12-month ECL

Lifetime ECL

Lifetime ECL

 

 

'million

'million

'million

'million

Gross EAD*

-

-

90

90

Loss allowance as at 30 September 2018

-

-

(77)

(77)

Net EAD

-

-

13

13

 

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

 

*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 amounts 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 31 December 2017 and 30 September 2018 is as follows:

 

 

'million

Loss allowance as at 31 December 2017 - calculated under IAS 39

-

Amounts restated through opening retained earnings

81

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

81

Reversal of impairment loss on NAPIMS receivables

(4)

Loss allowance as at 30 September 2018 - Under IFRS 9

77

c)  Receivables from Shell Petroleum Development Company (SPDC)

 

The Group applies the IFRS 9 general model for measuring expected credit losses (ECL) which uses a three-stage approach in recognising the expected loss allowance for receivables from SPDC. Receivables from SPDC represent the outstanding payments due to Seplat from an investment no longer being pursued.

 

 

                                                                                                                                                30 September 2018

 

Stage 1

Stage 2

Stage 3

Total

 

12-month ECL

Lifetime ECL

Lifetime ECL

 

 

'million

'million

'million

'million

Gross EAD*

-

13,627

-

13,627

Loss allowance as at 30 September 2018

-

(6)

-

(6)

Net EAD

-

13,621

-

13,621

 

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

 

*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 amounts 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 receivables from Shell Petroleum Development Company as at 31 December 2017 and 30 September 2018 is as follows:

 

 

'million

Loss allowance as at 31 December 2017 - calculated under IAS 39

-

Amounts restated through opening retained earnings

-

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

-

Increase in provision for impairment loss on SPDC receivables

6

Loss allowance as at 30 September 2018 - Under IFRS 9

6

 

Probability of default (PD)

External data from Standard & Poor's (S&P) for Royal Dutch Shell in an emerging market was used to arrive at a 12-month PD of 0.05%. 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.

 

Loss given default (LGD)

The 12-month LGD was determined based on management's estimate of expected cash recoveries after considering historical recovery pattern of these receivables. The 12-month LGD assumptions are a reasonable proxy for 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. Historical data on these variables for the last ten years were used to determine the three economic scenarios (base, optimistic and downturn) and their 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, 89% of historical GDP growth rate observation falls within the acceptable bounds, 2% of the observation relates to period of boom while 9% of the observation relate to periods of recession/downturn.

d)  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 insignificant 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 from 2014 to model the expected loss rates. Based on this assessment, the identified impairment loss as at 1 January 2018 and 30 September 2018 was insignificant 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.

                                                                       

e)  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. Impairment allowance on receivable amounts were assessed to be insignificant. 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 September 2018 and 31 December 2017 was deemed to be insignificant 718,723 (2017: 4.5 million). The impairment loss was nil under the incurred loss model of IAS 39.

 

f)  Cash and cash equivalents

 

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

 

3.3.2.3.   Hedge accounting

 

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 that 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.

 

As at the reporting periods ended 31 December 2017 and 30 September 2018, the Group had no derivative assets or liabilities.

 

3.3.3. IFRS 9: Financial Instruments - Accounting policies

     

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 at amortised cost, fair value through profit or loss and at fair value through other comprehensive income.

All the Group's financial assets as at 30 September 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 measured 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 receivables from SPDC.

 

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 and other qualitative indicators such as increase in political concerns or other microeconomic factors and the risk of legal action, sanction or other regulatory penalties that may impair future financial performance. Financial assets classified as stage 1 have their ECL measured as a proportion of their lifetime ECL that results from possible default events that can occur within one year, while assets in stage 2 or 3 have their ECL measured on a lifetime basis.

 

Under the three-stage approach, the ECL is determined by projecting the probability of default (PD), loss given default (LGD) and exposure at default (EAD) for each ageing bucket and for each individual exposure. The PD is based on default rates determined by external rating agencies for the counterparties. The LGD assesses the portion of the outstanding receivable that is deemed to be irrecoverable at the reporting period. The EAD is the total amount of outstanding receivable at the reporting period. These three components are multiplied together and adjusted for forward looking information. 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.

 

·      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.

 

Furthermore, 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 using 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 reclassification adjustments resulting from the adoption of IFRS 15 is shown in note 3.3.1 and detailed below:

 

3.3.4.1.   Impact on statement of financial position

 

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.   Impact on statement of profit or loss and other comprehensive income

 

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.

 

c)  Reclassification of barging costs from cost of sales

 

Seplat refunds to Mecuria barging costs incurred on crude oil barrels delivered. Seplat does not enjoy a separate service which it would have to pay another party for. This has been determined to be a consideration payable to a customer and should be accounted for as a direct deduction from revenue. Revenue should therefore be recognised net of barging costs. In the current period, there were no barging costs. In prior periods, barging costs were shown separately in cost of sales.

 

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 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 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/expenses-net.

 

·      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.

 

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 assess 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 September 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.

 

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 third quarter 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 do not 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 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 reporting period. Deferred tax liabilities are not recognised in the reporting 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

 

Actuarial valuations were carried out at the end of the previous financial year. These valuatons included the estimated interest and service costs for the 2018 interim periods. The Group has relied on these valuations to determine its defined benefit liability as it does not expect  material differences in the assumptions used for the current reporting period. 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. Also the deferred revenue was reclassified to accruals and other payables.

 

·      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.

 

·      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/expenses- net.

 

·      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.

 

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 5.64 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 expiring 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.

 

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.

 

 

 

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 September 2018

 

 

 

 

 

 

 

Non - derivatives

 

 

 

 

 

 

 

Fixed interest rate borrowings

 

 

 

 

 

 

 

Senior notes

9.25%

 10,130

 10,075

 10,048

 122,220

-

152,473

Variable interest rate borrowings (bank loans):

 

 

 

 

 

 

 

Stanbic IBTC Bank Plc

6.0% +LIBOR

 624

 1,072

 3,220

 4,335

-

 9,251

The Standard Bank of South Africa L

6.0% +LIBOR

 416

 715

 2,147

 2,890

-

 6,168

Nedbank Limited, London Branch

6.0% +LIBOR

 867

 1,488

 4,472

 6,022

-

 12,849

Standard Chartered Bank

6.0% +LIBOR

 780

 1,340

 4,025

 5,419

-

 11,564

Natixis

6.0% +LIBOR

 607

 1,042

 3,131

 4,215

-

 8,995

FirstRand Bank Limited Acting

6.0% +LIBOR

 607

 1,042

 3,131

 4,215

-

 8,995

Citibank N.A. London

6.0% +LIBOR

 520

 893

 2,683

 3,613

-

 7,709

The Mauritius Commercial Bank Plc

6.0% +LIBOR

 520

 893

 2,683

 3,613

-

 7,709

Nomura International Plc

6.0% +LIBOR

 260

 447

 1,342

 1,806

-

 3,855

Other non - derivatives

 

 

 

 

 

 

 

Trade and other payables**

 

21,340

-

-

-

-

21,340

 

 

36,671

19,007

36,882

158,348

-

250,908

 

 

 

 

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

 

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 Limited

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).

 

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 Sept 2018

As at 31 Dec

2017 

As at 30 Sept

2018

As at 31 Dec

2017 

 

million

million

million

million

Financial assets

 

 

 

 

Trade and other receivables*

 35,558

91,613

 35,558

91,613

Contract assets

 3,401

 -  

 3,401

 -  

Cash and cash equivalents

 194,067

 133,699

 194,067

133,699

 

 233,026

225,312

 233,026

225,312

Financial liabilities

 

 

 

 

Interest bearing loans and borrowings

 164,335

174,329

171,478

174,329

Trade and other payables

 21,340

38,876

21,340

38,876

 

 185,675

213,205

192,818

213,205

*Trade and other receivables excludes NGMC VAT receivables, cash advances 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 third 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 carrying amounts of the other financial instruments are the same as their fair values.

 

The Valuation process

 

The finance & planning team of the Group performs the valuations of financial and non financial assets required for financial reporting purposes, including level 3 fair values. 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.

 

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 nine months ended 30 September 2018, revenue from the gas segment of the business constituted 22% 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 reclassified to match the new structure for the nine months ended 30 September 2018.

 

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

 

6.1.    Segment profit disclosure

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

           

'million

'million

'million

'million

Oil

 (3,457)

 (17,756)

 (1,795)

 1,034

Gas

 31,425

 16,136

 14,919

 5,778

Total profit/(loss) after tax

 27,968

 (1,620)

 13,124

 6,812

 

 

 

 

 

 

 

 

          Oil

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

               

'million

'million

'million

'million

Revenue

 

 

 

 

Crude oil sales

 134,849

 58,928

 56,154

 35,238

Operating profit before depreciation, amortisation

and impairment

 73,569

 8,344

 29,557

 12,823

Depreciation, amortisation and impairment

 (24,231)

 (8,202)

 (7,338)

 (4,537)

Operating profit/(loss)

 49,338

 142

 22,219

 8,286

Finance income

 2,050

 483

 720

 213

Finance expenses

 (17,760)

 (17,521)

 (5,092)

 (6,947)

Profit/(loss) before taxation

 33,628

 (16,896)

 17,847

 1,552

Taxation

 (28,933)

 (860)

 (11,490)

 (518)

(Loss) for the period

 4,695

 (17,756)

 6,357

 1,034

                                                                  

                                                                                                                             Gas

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

               

'million

'million

'million

'million

Revenue

 

 

 

 

Gas sales

 38,861

 26,262

 12,762

 9,635

Operating profit before depreciation, amortisation

and impairment

 35,266

 25,517

 11,388

 9,239

Depreciation, amortisation and impairment

 (3,841)

 (9,381)

 (1,275)

 (3,461)

Operating profit

 31,425

 16,136

 10,113

 5,778

Finance income

 -  

 -  

 -  

 -  

Finance expenses

 -  

 -  

 -  

 -  

Profit before taxation

 31,425

 16,136

 10,113

 5,778

Taxation

 (8,152)

 -  

 (3,346)

 -  

Profit for the period

 23,273

 16,136

 6,767

 5,778

6.1.1. Disaggregation of revenue from contracts with customers

The Group derives revenue from the transfer of commodities at a point in 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 retrospectively using the simplified transition approach. The simplified approach does not require a restatement of comparatives.

 

 

9 months ended

30 Sept

2018

9 months ended

30 Sept

2018

9 months ended

30 Sept

2018

3 months ended

30 Sept

2018

3 months ended

30 Sept

2018

3 months ended

30 Sept

2018

 

Oil

Gas

Total

Oil

Gas

Total

 

'million

'million

'million

million

million

million

Revenue from contract with customers

134,849

38,861

173,710

56,154

12,762

68,916

Timing of revenue recognition

 

 

 

 

 

 

At a point in time

134,849

-

134,849

56,154

-

56,154

Over time

-

38,861

38,861

-

12,762

12,762

 

134,849

38,861

173,710

56,154

12,762

68,916

6.2.    Segment assets

Segment assets are measured in a manner consistent with that of 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 September 2018

652,780

121,993

774,773

31 December 2017

716,657

82,896

799,553

         

 

6.3.    Segment liabilities

Segment liabilities are measured in a manner consistent with that of the financial statements. These liabilities are allocated

based on the operations of the segment.

 

Oil

Gas 

Total

Total segment liabilities 

'million

'million

'million

30 September 2018

285,564

9,505

295,069

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 expiring on 31st January 2020. The fair value loss arising during the reporting period is 5.64 billion.

7.    Revenue from contracts with customers

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

           

'million

'million

'million

'million

Crude oil sales

 134,849

 68,460

 56,154

 34,453

Gas sales           

 38,861

 26,262

 12,762

 9,635

 

 173,710

94,722

 68,916

44,088

(Overlift)/underlift

 -  

(9,532)

 -  

785

Total

 173,710

85,190

 68,916

44,873

 

         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

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

 

'million

'million

'million

'million

Crude handling

 14,450

 5,240

 5,511

 3,709

Barging costs

 -  

 2,787

 -  

 792

Royalties

 29,352

 13,107

 10,293

 7,371

Depletion, depreciation and amortisation

 27,903

 16,546

 9,312

 7,685

Niger Delta Development Commission

 1,573

 1,108

 496

 379

Other rig related expenses

 12

 1,020

 -  

 521

Operations & maintenance expenses

 6,910

 7,299

 3,101

 2,736

 

 80,200

 47,107

 28,713

 23,193

 

 

9.   Other income/(expenses)- net

           

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

 

'million

'million

'million

'million

Underlift/(overlift)

 6,259

-

(2,224)

-

 

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.

10. General and administrative expenses

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

 

'million

'million

'million

'million

Depreciation

 689

 1,035

 (179)

 313

Employee benefits

 7,076

 4,908

 2,400

 1,612

Professional and consulting fees

 2,725

 3,802

 306

 1,905

Auditor's remuneration

 79

 288

 22

 194

Directors emoluments (executive)

 442

 560

 247

 137

Directors emoluments (non-executive)

 765

 718

 266

 242

Rentals

 450

 350

 149

 126

Flight and other travel costs

 1,623

 1,228

 864

 504

Other general expenses

 3,021

 4,278

 1,026

 2,578

 

 16,870

 17,167

 5,101

 7,611

 

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 employee benefits expense.

 

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

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

 

'million

'million

'million

'million

Reversal/(impairment) of loss on NPDC receivables

523

-

(47)

-

Reversal of loss on NAPIMS receivables

4

-

45

-

Impairment loss on SPDC receivables

(6)

-

(6)

-

Net reversal of impairment loss allowance

521

-

(8)

-

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 (note 3.3.2.2). The loss allowance was calculated on a total exposure of 38.3 billion. During the reporting period, the outstanding receivable balance reduced to 14.9 billion. The reduction in the receivables balance led to the reversal of previously recognised loss allowance for the 9 months ended 30 September 2018.

12. Loss on foreign exchange - net

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

 

'million

'million

'million

'million

Exchange loss

(208)

(277)

(216)

 (13)

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

13. Fair value loss - net

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

 

'million

'million

'million

'million

Crude oil hedging payments

 (1,063)

(4,405)

 (303)

(1,399)

Fair value loss on contingent consideration

 (1,386)

 (419)

 (19)

 (145)

Fair value gain on other assets

 -  

 463

 -  

 -  

 

 (2,449)

 (4,361)

 (322)

 (1,544)

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)

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

 

'million

'million

'million

'million

Finance income

 

 

 

 

Interest income

2,050

483

 720

213

Finance costs

 

 

 

 

Interest on bank loan

 (16,561)

              (16,153)

 (4,839)

(4,984)

Interest on advance payments for crude oil sales

(530)

               (1,346)

 -  

                (403)  

Unwinding of discount on provision for decommissioning 

 (669)

(22)

 (253)

 (8)

 

 (17,760)

 (17,521)

 (5,092)

 (5,395)

Finance cost - net

 (15,710)

 (17,038)

 (4,372)

 (5,182)

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 September 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% for crude oil 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 Sept 2018

As at

 30 Sept 2018

As at

30 Sept 2018

As at 31 Dec

2017

As at 31 Dec

2017

 

'million

'million

'million

'million

'million

 

Gross amount at 85%

Gross amount at 30%

Tax effect

Gross amount

Tax effect

Tax losses

-

-

-

14,578

12,392

Other cumulative timing differences:

 

 

 

 

 

Fixed assets

 (97,962)

 (22,907)

 (90,140)

 (105,840)

-89,964

Unutilised Capital Allowance

 130,780

 9,904

 114,134

 149,999

127,499

Provision for Abandonment

 752

 -  

 639

 120

102

Provision for Gratuity

 2,058

 -  

 1,749

 1,471

1,250

Share Equity Reserve

 7,866

 -  

 6,687

 5,446

4,629

Unrealised Forex (Gain)/Loss

 4,957

 -  

 4,213

 4,952

4,209

Overlift / (Underlift)

 3,225

 -  

 2,741

 7,633

6,488

Provision for Doubtful Debt

 2,133

 -  

 1,813

 2,131

1,811

 

 53,809

 (13,003)

 41,836

 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 Sept 2018

As at 30 Sept

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

 18,516

 12,475

14,988

7,869

Tax losses

 8,360

 4,754

14,579

8,908

 

 26,858

 17,218

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.

 

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

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

Diluted
Diluted LPS/EPS 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 period 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.

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

 

'million

'million

'million

'million

 

 

 

 

 

Profit/(loss) for the period

27,968

 (1,620)

13,124

6,812

 

 Share

'000

Share
'000

Share
'000

Share
'000

Weighted average number of ordinary shares in issue

 582,889

563,445

 582,889

563,445

Share awards

 6,157

 6,437

 6,157

 6,437

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

 589,046

 

 569,882

 589,046

 

 569,882

 

Basic earnings/(loss) per share

 47.98

 (2.88)

 22.52

12.09

Diluted earnings/(loss) per share

 47.48

 (2.84)

 22.28

 11.95

 

'million

'million

'million

'million

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

27,968

 (1,620)

13,124

 6,812

 

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

      (81,173)

(95,609)

(176,782)

Interest repayment

(7,915)

(4,475)

(12,390)

Interest accrued

9,243

-

9,243

Effect of loan restructuring

-

 7,320

 7,320

Other financing charges

-

 (1,191)

 (1,191)

Proceeds from loan financing

-

 163,643

 163,643

Exchange differences

15

 148

 163

Balance as at 30 September 2018

1,329

 163,006

 164,335

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 billion four year revolving loan facility.

In the reporting period, the Group also issued 107 billion million 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 5.58 billion using an effective interest rate of 10.4%.

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 is 2.89 billion billion using an effective interest rate of 9.4%. The interest paid was determined using 3-month LIBOR rate + 6% on the last business day of the reporting period. The amortised cost for the senior notes and the borrowings at the reporting period is 104 billion and 60 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 Sept 2018

As at 31 Dec 2017

 

 

'million

'million

 

Trade receivables (note 18a)

 33,435

 33,236

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

 -  

 34,453

National Petroleum Investment Management Services receivables

 89

 3,824

Advances on investment

 -  

20,093

Advances to suppliers

 3,989

 2,404

Other receivables (note 18c)

 13,816

 894

Gross carrying amount

 51,329

94,904

Less: Specific impairment allowance

 (84)

-

 

 51,245

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 17.9 billion (2017: 23 billion) with respect to the sale of gas, for the Group. Also included in trade receivables is an amount of 13 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 is Nil (2017: 34 billion). The outstanding NPDC receivables at the end of the reporting period has been netted off against the gas receipts payable to NPDC as Seplat has a legally enforceable right to settle outstanding amounts on a net basis.

 

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 13.8 billion (2017: nil).

 

19.  Contract assets

 

As at 30 Sept 2018

As at 31 Dec 2017

 

'million

'million

Revenue on gas sales

3,401

-

 

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 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.

19.1.  Reconciliation of contract assets

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

 

As at 30 Sept 2018

As at 31 Dec 2017

 

'million

'million

Impact on initial application of IFRS 15

4,238

-

Gas revenue received during the period

(837)

-

 

3,401

-

20.  Cash and cash equivalents

 

As at 30 Sept 2018

As at 31 Dec 2017

 

'million

'million

Cash on hand

 3

3

Restricted cash

 564

19,166

Cash at bank

 193,500

114,530

 

 194,067

133,699

Included in cash and cash equivalents is the total amount of 46 billion 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 Sept 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 September 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 nine months ended 30 September 2018, 5,534,964 shares were vested (31 December 2017: No shares had vested).

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

-

-

-

2,414

2,414

Share issue

19,465,036

13

(13)

-

-

Vested shares

5,534,964

-

3

(3)

-

Closing balance as at 30 September 2018

588,444,561

296

(10)

6,743

7,029

22. Trade and other payables

 

 

As at 30 Sept 2018

As at 31 Dec 2017

 

'million

'million

Trade payables

 13,023

 19,191

 

Nigerian Petroleum Development Company (NPDC)

 11,505

-

 

Accruals and other payables

 33,318

 45,570

 

Pension payables

 95

 55

 

NDDC levy

 3,189

 2,564

 

Deferred revenue

 -  

41,970

 

Royalties payable

 16,962

 16,209

 

 

 78,092

125,559

 

 

Included in accruals and other payables are field-related accruals of 12 billion (2017: 17 billion) and other vendor payables of 21 billion (2017: 29 billion). Royalties include accruals in respect of gas sales for which payment is outstanding at the end of the period.

 

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 11.5 billion has been reported after adjusting for interest as set out in the JOA and undercash call payments in other currencies. The outstanding NPDC receivables at the end of the reporting period has been netted off against the gas receipts payable to NPDC, and impairment has been calculated on the net NPDC receivables balance.

23. Computation of cash generated from operations

 

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

 

Notes

'million

'million

Profit/(loss) before tax

 

65,053

 (760)

Adjusted for:

 

 

 

Depletion, depreciation and amortisation

8, 10

 28,592

                    17,581

Interest on bank loan

14

 16,561

 16,153

Interest on advance payment for crude oil sales

14

 530

 1,346

Unwinding of discount on provision for decommissioning

14

 669

 22

Interest income

14

 (2,050)

 (483)

Fair value loss on contingent consideration

13

 1,386

                         419

Fair value gain on other assets      

13

 -  

                      (463)

Unrealised foreign exchange loss

12

 208

277

Share based payments expenses

 

 2,413

1,226

Defined benefit expenses

 

 63

365

Reversal of impairment loss on NPDC, NAPIMS and SPDC receivables

11

 (521)

-  

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

 

 34,847

 (9,050)

Contract assets

 

 (3,401)

 -  

Trade and other payables

 

 (24,900)

 23,129

Inventories

 

 (1,324)

 1,311

Net cash from operating activities                                                                            

 

 118,126

 51,098

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 stationary and other general supplies to the field locations.

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.

Neimeth International Pharmaceutical Plc: The chairman of Seplat is also the chairman of this company. The company provides medical supplies and drugs to Seplat, which are used in connection with Seplat's corporate social responsibility and community healthcare programmes.

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

i)      Purchases of goods and services

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

 

'million

'million

Shareholders of the parent company

 

 

SPDCL (BVI)

241

310

Total

241

310

 

 

 

Entities controlled by key management personnel:

 

 

Contracts > $1million in 2018

 

 

Nerine Support Services Limited

1,570

1,191

Cardinal Drilling Services Limited

425

793

Stage Leasing Limited

348

-

 

2,343

1,984

 

 

 

 

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

 

'million

'million

Contracts < $1million in 2018

 

 

Abbey Court trading Company Limited

 232

147

Charismond Nigeria Limited

 22  

13

Keco Nigeria Enterprises

 14

 35

Stage Leasing Limited

 -  

 171

Oriental Catering Services Limited

130  

 95

ResourcePro Inter Solutions Limited

 3

 7

Montego Upstream Services Limited

 20

 80

Neimeth International Pharmaceutical Plc

 -  

1

 

421

549

Total

2,764

2533

       

    * 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 nine months ended 30 September 2018 is 1.6 billion (2017: 1.1 billion).

24c.  Balances

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

 

As at 30 Sept 2018

As at 31 Dec 2017

Prepayments / receivables

'million

'million

Entities controlled by key management personnel

 

 

Cardinal Drilling Services Limited

 1,683

1,681

 

1,683

1,681

 

 

As at 30 Sept 2018

As at 31 Dec 2017

Payables

'million

'million

Entities controlled by key management personnel

 

 

Montego Upstream Services Limited

8

115

Nerine Support Services Limited

2

2

Keco Nigeria Enterprises

-

8

Cardinal Drilling Services Limited

61

292

Oriental Catering Services Ltd

2

-

Resourcepro Inter Solutions Ltd

2

-

 

75

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 September 2018 are:

 

 

As at 30 Sept 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 september 2018 is ₦734 million (2017: 4.7 billion). The contingent liability for the period ended 30 September 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. Dividend

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

Following a review of Seplat's operational, liquidity and financial position as at 30 September 2018, the Board has proposed an interim dividend of  15.29 per share. The total amount of this proposed dividend, expected to be paid out of retained earnings but for which no liability has been recognized in the financial statements is 8.99 billion (September 2017: Nil).

27. Events after the reporting period

Except for the interim dividend proposed at the end of the third quarter (Note 26), there were no significant events 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 Sept 2018

 ₦/$

30 Sept 2017

 ₦/$

31 Dec 2017

 ₦/$

Fixed assets - opening balances

Historical rate

Historical

Historical

Historical

 

Fixed assets - additions

Average rate

305.85

305.82

305.80

 

Fixed assets - closing balances

Closing rate

306.1

305.75

305.81

 

Current assets

Closing rate

306.1

305.75

305.81

 

Current liabilities

Closing rate

306.1

305.75

305.81

 

Equity

Historical rate

Historical

Historical

Historical

 

Income and Expenses:

Overall Average rate

305.85

305.82

305.81

 

                 

 

Interim Condensed Consolidated Financial Statements (Unaudited)
for the third quarter ended 30 September 2018

Expressed in US Dollars ('USD')

Condensed consolidated statement of profit or loss and other comprehensive income

for the third quarter ended 30 September 2018

 

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended
30 Sept 2018

3 months ended

30 Sept 2017

 

 

Unaudited

Unaudited

Unaudited

Unaudited

 

Note

$'000

$'000

$'000

$'000

Revenue from contracts with customers

7

 567,956

 278,560

 225,280

146,746

Cost of sales

8

 (262,218)

 (154,031)

 (93,854)

 (75,844)

Gross profit

 

 305,738

 124,529

 131,426

 70,902

Other income/(expenses)-net

9

 20,463

-

 (7,278)

-

General and administrative expenses

10

 (55,156)

 (56,132)

 (16,674)

 (24,891)

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

11

 1,703

-

 (27)

-

Loss on foreign exchange - net

12

 (679)

 (906)

 (702)

 (40)

Fair value loss - net

13

 (8,004)

 (14,262)

 (1,050)

 (5,052)

Operating profit

 

 264,065

 53,229

 105,695

 40,919

Finance income

14

 6,705

 1,582

 2,354

 699

Finance costs                      

14

 (58,065)

 (57,291)

 (16,641)

 (17,644)

Profit/(loss) before taxation

 

 212,705

 (2,480)

 91,408

 23,974

Taxation

15

 (121,251)

 (2,813)

 (48,498)

 (1,694)

Profit/(loss) for the period

 

 91,454

  (5,293)

 42,910

22,280

 

 

 

 

 

 

Other comprehensive income:

 

 

 

 

 

Items that may be reclassified to profit or loss:

 

 

 

 

 

Foreign currency translation difference

 

-

-

-

-

 

 

 

 

 

 

Total comprehensive income/(loss) for the period

 

91,454

  (5,293)

 42,910

22,280

 

 

 

 

 

 

Earnings/(loss) per share ($)

16

 0.16

(0.01)

 0.07

0.04

Diluted earnings/(loss)  per share($)

16

 0.16

(0.01)

 0.07

0.04

 

 

 

 

 

 

 

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

Condensed consolidated statement of financial position

As at 30 September 2018

 

 

As at 30 Sept 2018

As at 31 Dec 2017

 

 

Unaudited

Audited

 

Note

$'000

$'000

Assets

 

 

 

Non-current assets

 

 

 

Oil and gas properties

 

 1,223,517

 1,286,387

Other property, plant and equipment

 

 3,134

 5,078

Other asset

 

 191,104

 217,031

Deferred tax

15a

 136,674

 223,731

Tax paid in advance

 

 31,623

 31,623

Prepayments

 

 25,269

 939

Total non-current assets                          

 

 1,611,321

 1,764,789

Current assets

 

 

 

Inventories

 

 104,568

 100,336

Trade and other receivables

18

 167,419

 310,345

Contract assets

19

 11,117

 -  

Prepayments

 

 2,707

 1,948

Cash and cash equivalents

20

 633,997

 437,212

Total current assets

 

 919,808

 849,841

Total assets

 

2,531,129

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

 25,690

 17,809

Capital contribution

 

 40,000

 40,000

Retained earnings

 

 1,000,271

 944,108

Foreign currency translation reserve

 

 1,897

 1,897

Total shareholders' equity

 

 1,567,150

 1,503,097

Non-current liabilities

 

 

 

Interest bearing loans & borrowings

17

 532,530

 304,677

Contingent consideration

6.4

 18,430

 13,900

Provision for decommissioning obligation

 

 108,497

 106,312

Defined benefit plan                 

 

 6,724

 6,518

Total non-current liabilities

 

 666,181

 431,407

Current liabilities

 

 

 

Interest bearing loans and borrowings

17

 4,342

 265,400

Trade and other payables

22

 255,127

 410,593

Current taxation

 

 38,329

 4,133

Total current liabilities

 

 297,798

 680,126

Total liabilities

 

963,979

 1,111,533

Total shareholders' equity and liabilities

 

2,531,129

2,614,630

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

The Group financial statements of Seplat Petroleum Development Company Plc and its subsidiaries for the nine months

ended 30 September 2018 were authorised for issue in accordance with a resolution of the Directors on 30 October 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 October 2018

 

30 October 2018

 

30 October 2018

 

Condensed consolidated statement of changes in equity continued

for the third quarter ended 30 September 2018

For the third quarter ended 30 September 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

3,675

1,234,015

 

Loss for the period

-

-

-

-

-

 (5,293)

-

  (5,293)

 

Other comprehensive income

-

-

-

-

-

-

-

-

 

Total comprehensive loss for the period

-

-

-

-

-

(5,293)

-

(5,293)

 

Transactions with owners in their capacity as owners:

 

 

 

 

 

 

 

 

Share based payments

-

-

-

 4,010

-

 -  

 -  

 4,010

 

Total

-

-

-

4,010

-

-

-

4,010

 

At 30 September 2017 (unaudited)

 1,826

 497,457

-

 16,145

 40,000

  673,629

 3,675

 1,232,732

 

 

 

 

 

 

 

 

 

For the third quarter ended 30 September 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 31 December 2017 as originally presented

1,826

497,457

-

17,809

40,000

1,897

1,503,097

 

Impact of change in accounting policy:

 

 

 

 

 

 

 

 

Adjustment on initial application of IFRS 9  (Note 3.3)

-

-

-

-

-

-

(5,816)

 

Adjustment on initial application of IFRS 15 (Note 3.3)

-

-

-

-

-

-

-

 

At 1 January 2018 - Restated

1,826

497,457

-

17,809

40,000

1,897

1,497,281

 

Profit for the period

 -  

 -  

 

 -  

 -  

 91,454

 -  

 91,454

 

Other comprehensive income

 -  

 -  

 

 -  

 -  

 -  

 -  

 -  

 

Total comprehensive income for the period

 -  

 -  

 

 -  

 -  

 91,454

 -  

 91,454

 

Transactions with owners in their capacity as owners:

 

 

 

 

 

 

 

 

Dividends paid

 -  

 -  

-

-

-

 (29,475)

 -  

 (29,475)

 

Share based payments

-

-

-

 7,890

-

 -  

-

 7,890

 

Issue of shares

41

-

(41)

-

-

-

-

-

 

Vested shares

-

-

9

(9)

-

-

-

-

 

Total

 41

 -  

 (32)

 7,881

 -  

 (29,475)

 -  

 (21,585)

 

At 30 September 2018 (unaudited)

 1,867

 497,457

 (32)

 25,690

 40,000

 1,000,271

 1,897

 1,567,150

 

 

 

 

 

 

 

 

 

 

 

 

                         

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

Condensed consolidated statement of cash flow

for the third quarter ended 30 September 2018

 

9 months ended
30 Sept 2018

9 months ended 30 Sept 2017

 

$'000

$'000

                                                                                                            Note

Unaudited

Unaudited

Cash flows from operating activities

 

 

Cash generated from operations                                                              23                                 

 386,300

 167,089

Net cash inflows from operating activities

 386,300

 167,089

Cash flows from investing activities

 

 

Investment in oil and gas properties

(28,671)

(21,993)

Investment in other property, plant and equipment

 

(515)

Receipts from other property, plant and equipment

3

-

Receipts from other asset                                                                       

25,927

22,604

Interest received

6,705

1,582

Net cash inflows from investing activities

3,964

1,678

Cash flows from financing activities

 

 

Repayments of bank financing

 (578,000)

 (54,750)

Receipts from bank financing

 195,499

-

Dividends paid

 (29,475)

 -  

Proceeds from senior notes issued

 339,546

-

Repayments on crude oil advance

(77,499)

 (4,402)

Payments for other financing charges

(3,894)

-

Interest paid on bank financing

(40,507)

 (49,832)

Net cash outflows from financing activities

(194,330)

(108,984)

Net increase in cash and cash equivalents

195,934

59,783

Cash and cash equivalents at the beginning of the period

437,212

159,621

Effects of exchange rate changes on cash and cash equivalents

851

(244)  

Cash and cash equivalents at the end of the period

633,997

219,160

 

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

 

Notes to the 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 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 activity of the Company is the processing of gas from OML 53.

 

The Company together with its six wholly owned subsidiaries namely, Newton Energy, Seplat Petroleum Development Company UK Limited ('Seplat UK'), Seplat East Onshore Limited ('Seplat East'), Seplat East Swamp Company Limited ('Seplat Swamp'), Seplat Gas Company Limited ('Seplat GAS') and ANOH Gas Processing Company Limited are collectively referred to as the Group.

 

Subsidiary

Date of incorporation

Country of incorporation and place of business

Principal activities

Newton Energy Limited

1 June 2013

Nigeria

Oil & gas exploration and production

Seplat Petroleum Development UK

21 August 2014

United Kingdom

Oil & gas exploration and production

Seplat East Onshore Limited

12 December 2014

Nigeria

Oil & gas exploration and production

Seplat East Swamp Company Limited

12 December 2014

Nigeria

Oil & gas exploration and production

Seplat Gas Company

12 December 2014

Nigeria

Oil & gas exploration and production

ANOH Gas Processing Company Limited

18 January 2017

Nigeria

Gas processing

 

2.    Significant changes in the current reporting period

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

·      The offering of 9.25% senior notes with an aggregate principal amount of US$350 million due in April 2023. The notes were issued by the Group in March 2018 and guaranteed by some of its subsidiaries. The proceeds of the notes are being used to refinance existing indebtedness and for general corporate purposes.

·      In March 2018, the Group obtained a US$300 million revolving facility to refinance of an existing US$300 million revolving credit facility due in December 2018. The facility has a tenor of 4 years (due in June 2022) with an initial interest rate of the 6% +Libor. Interest is 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.

·      25,000,000 additional shares were issued. In furtherance of the Group's Long Term Incentive Plan, in February 2018. The additional issued shares, less 5,534,964 shares which vested in April 2018, 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 and 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 condensed consolidated financial statements of the Group for the nine months reporting period ended 30 September 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 Company will not remain a going concern for at least twelve months from the date of these 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, and

·      IFRS 15 Revenue from contracts with customers

·      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.

 

v)       New standards, amendments and interpretations not yet adopted

       

The following standards have been issued but are 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 other 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 amendments before its effective date and is yet to assess the full impact of the amendments on its financial statements.

 

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 amendments before its effective date and is yet to assess the full impact of the amendments on its financial statements.

 

d.     Conceptual framework for financial reporting - Revised

 

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 amendments before its effective date and is yet to assess the full impact of the amendments on its financial statements.

 

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 and is yet to assess the full impact of the amendments on its financial statements.

 

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 also discloses the related accounting policies that have been applied from 1 January 2018, where they are different from those applied in prior periods.

3.3.1. Impact on the financial statements

         

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 changes in equity on 1 January 2018.

 

The Group has also 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. 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.

 

 

 

 

At 31 December 2017

 

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 AND LIABILITIES

 

 

 

 

 

Equity

 

 

 

 

 

Retained earnings

 

944,108

(5,816)

-

938,292

Total shareholders' equity

 

1,503,097

(5,816)

-

1,497,281

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 the  adjustments to the amounts recognised in the financial statements. The new accounting policies are set out in notes below. In accordance with the transitional provisions in IFRS 9, comparative figures have not been restated but the impact of adoption has been adjusted through opening retained earnings for the current reporting period.

 

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 were previously classified as loans and receivables (L and R) are now classified as financial assets 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

 

The adoption of IFRS 9 eliminates the policy choice on the treatment of gain or loss from the refinancing of a borrowing. Day one gain or loss can no longer be deferred over the remaining life of the borrowing but 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, 1 January 2018, the financial instruments of the Group were classified as follows:

 

 

 

           Classification & Measurement category

                 Carrying amount

 

Original

New

Original

New

 

IAS 39

IFRS 9

$ '000

$ '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 exclude accruals, provisions, bonus, VAT, Withholding tax, deferred revenue and royalties.

 

The new carrying amounts in the table above have been determined based on the measurement criteria specified in IFRS 9. However, the impact of IFRS 9 expected credit loss impairment has not been considered here. See the subsequent pages for the impact of IFRS 9 ECL on the assets carried at amortised cost.

 

3.3.2.2.   Impairment of financial assets

The Group has seven types of financial assets that are subject to IFRS 9's new expected credit loss model. Under IFRS 9, the Group is required to revise its previous impairment methodology under IAS 39 for each of these classes of assets. The impact of the change in impairment methodology on the Group's retained earnings is disclosed in the table below.

§ Nigerian Petroleum Development Company (NPDC) receivables

§ National Petroleum Investment Management Services (NAPIMS)

§ Receivables from Shell Petroleum Development Company (SPDC)

§ Trade receivables

§ Contract assets

§ Other receivables and;

§ Cash and cash equivalents

 

The total impact on the Group's retained earnings as at 1 January 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)

Total transition adjustments

 

(5,816)

Opening retained earnings 1 January 2018 on adoption of IFRS 9

 

938,292

 

a)  Nigerian Petroleum Development Company (NPDC) receivables

 

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

 

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.

 

                                                                                                                          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

* Exposure at default

 

                                                                                                                                 30 September 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 September 2018

-

-

(3,840)

(3,840)

Net EAD

-

-

44,599

44,599

 

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 amounts 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 31 December 2017

and 30 September 2018 is as follows:

 

 

$'000

Loss allowance as at 31 December 2017 - calculated under IAS 39

-

Amounts adjusted 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

(1,713)

Loss allowance as at 30 September 2018 - Under IFRS 9

3,840

 

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 (d) for definition of default).

 

Loss given default (LGD)

The 12-month LGD was determined based on management's estimate of expected cash recoveries after considering historical recovery pattern of these receivables. The 12-month LGD assumptions are a reasonable proxy for 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. Historical data on these variables for the last ten years were used to determine the three economic scenarios (base, optimistic and downturn) and their 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

 

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

 

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.

 

                                                                                                                                    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 September 2018

 

Stage 1

Stage 2

Stage 3

Total

 

12-month ECL

Lifetime ECL

Lifetime ECL

 

 

$'000

$'000

$'000

$'000

Gross EAD*

-

-

293

293

Loss allowance as at 30 September 2018

-

-

(251)

(251)

Net EAD

-

-

42

42

 

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

 

*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 amounts 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 31 December 2017 and 30 September 2018 is as follows:

 

 

$'000

Loss allowance as at 31 December 2017 - calculated under IAS 39

-

Amounts restated through opening retained earnings

263

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

263

Reversal of impairment loss on NAPIMS receivables

(12)

Loss allowance as at 30 September 2018 - Under IFRS 9

251

c)  Receivables from Shell Petroleum Development Company (SPDC)

 

The Group applies the IFRS 9 general model for measuring expected credit losses (ECL) which uses a three-stage approach in recognising the expected loss allowance for receivables from SPDC. Receivables from SPDC represent the outstanding payments due to Seplat from an investment no longer being pursued.

                                                                                                                                                30 September 2018

 

Stage 1

Stage 2

Stage 3

Total

 

12-month ECL

Lifetime ECL

Lifetime ECL

 

 

$'000

$'000

$'000

$'000

Gross EAD*

-

44,519

-

44,519

Loss allowance as at 30 September 2018

-

(22)

-

(22)

Net EAD

-

44,497

-

44,497

 

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

 

*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 amounts 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 receivables from Shell Petroleum Development Company as at 31 December 2017 and 30 September 2018 is as follows:

 

 

$'000

Loss allowance as at 31 December 2017 - calculated under IAS 39

-

Amounts restated through opening retained earnings

-

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

-

Increase in provision for impairment loss on SPDC receivables

22

Loss allowance as at 30 September 2018 - Under IFRS 9

22

         

Probability of default (PD)

External data from Standard & Poor's (S&P) for Royal Dutch Shell in an emerging market was used to arrive at a 12-month PD of 0.05%. 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.

 

Loss given default (LGD)

The 12-month LGD was determined based on management's estimate of expected cash recoveries after considering historical recovery pattern of these receivables. The 12-month LGD assumptions are a reasonable proxy for 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. Historical data on these variables for the last ten years were used to determine the three economic scenarios (base, optimistic and downturn) and their 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, 89% of historical GDP growth rate observation falls within the acceptable bounds, 2% of the observation relates to period of boom while 9% of the observation relate to periods of recession/downturn.

d)  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 insignificant 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 from 2014 to model the expected loss rates. Based on this assessment, the identified impairment loss as at 1 January 2018 and 30 September 2018 was insignificant 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.

 

e)  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. Impairment allowance on receivable amounts were assessed to be insignificant. 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 September 2018 and 31 December 2017 was deemed to be insignificant $ 2,348 (2017: $14,598). The impairment loss was nil under the incurred loss model of IAS 39.

 

f)  Cash and cash equivalents

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

 

3.3.2.3.   Hedge accounting

 

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 that 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.

 

As at the reporting periods ended 31 December 2017 and 30 September 2018, the Group had no derivative assets or liabilities.

3.3.3. IFRS 9: Financial Instruments - Accounting policies

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 at amortised cost, fair value through profit or loss and at fair value through other comprehensive income.

 

All the Group's financial assets as at 30 September 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 measured 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 receivables from SPDC.

 

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 and other qualitative indicators such as increase in political concerns or other microeconomic factors and the risk of legal action, sanction or other regulatory penalties that may impair future financial performance. Financial assets classified as stage 1 have their ECL measured as a proportion of their lifetime ECL that results from possible default events that can occur within one year, while assets in stage 2 or 3 have their ECL measured on a lifetime basis.

 

Under the three-stage approach, the ECL is determined by projecting the probability of default (PD), loss given default (LGD) and exposure at default (EAD) for each ageing bucket and for each individual exposure. The PD is based on default rates determined by external rating agencies for the counterparties. The LGD assesses the portion of the outstanding receivable that is deemed to be irrecoverable at the reporting period. The EAD is the total amount of outstanding receivable at the reporting period. These three components are multiplied together and adjusted for forward looking information. 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.

 

·      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.

 

Furthermore, 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 using 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 reclassification adjustments resulting from the adoption of IFRS 15 is shown in note 3.3.1 and detailed below:

 

3.3.4.1.   Impact on statement of financial position

 

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.   Impact on statement of profit or loss and other comprehensive income

 

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.

 

c)  Reclassification of barging costs from cost of sales

 

Seplat refunds to Mecuria barging costs incurred on crude oil barrels delivered. Seplat does not enjoy a separate service which it would have to pay another party for. This has been determined to be a consideration payable to a customer and should be accounted for as a direct deduction from revenue. Revenue should therefore be recognised net of barging costs. In the current period, there were no barging costs. In prior periods, barging costs were shown separately in cost of sales.

 

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 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 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/expenses-net.

 

·      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.

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 assess 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 September 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.

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 third quarter 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 do not 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 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 reporting period. Deferred tax liabilities are not recognised in the reporting 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

 

Actuarial valuations were carried out at the end of the previous financial year. These valuatons included the estimated interest and service costs for the 2018 interim periods. The Group has relied on these valuations to determine its defined benefit liability as it does not expect  material differences in the assumptions used for the current reporting period. 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. Also the deferred revenue was reclassified to accruals and other payables.

 

§  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.

§  Signficant 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 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/expenses - net.

 

§  Barging cost

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.

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 expiring 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.

 

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.

 

 

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 September 2018

 

 

 

 

 

 

 

Non - derivatives

 

 

 

 

 

 

 

Fixed interest rate borrowings

 

 

 

 

 

 

 

Senior notes

9.25%

33,094

32,915

32,825

399,282

-

498,116

Variable interest rate borrowings (bank loans):

 

 

 

 

 

 

 

Stanbic IBTC Bank Plc

6.0% +LIBOR

 2,039

 3,502

 10,520

 14,164

-

 30,225

The Standard Bank of South Africa L

6.0% +LIBOR

 1,359

 2,334

 7,013

 9,442

-

 20,148

Nedbank Limited, London Branch

6.0% +LIBOR

 2,832

 4,863

 14,611

 19,672

-

 41,978

Standard Chartered Bank

6.0% +LIBOR

 2,549

 4,377

 13,150

 17,705

-

 37,781

Natixis

6.0% +LIBOR

 1,983

 3,404

 10,228

 13,770

-

 29,385

FirstRand Bank Limited Acting

6.0% +LIBOR

 1,983

 3,404

 10,228

 13,770

-

 29,385

Citibank N.A. London

6.0% +LIBOR

 1,699

 2,918

 8,767

 11,803

-

 25,187

The Mauritius Commercial Bank Plc

6.0% +LIBOR

 1,699

 2,918

 8,767

 11,803

-

 25,187

Nomura International Plc

6.0% +LIBOR

 850

 1,459

 4,383

 5,902

-

 12,594

Other non - derivatives

 

 

 

 

 

 

 

Trade and other payables**

 

69,716

-

-

-

-

-

 

 

119,803

62,094

120,492

517,313

-

749,986

 

 

 

 

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

31 December 2017

 

 

 

 

 

 

 

Non - derivatives

 

 

 

 

 

 

 

Variable interest rate borrowings (bank loans):

 

 

 

 

 

 

 

Allan Gray

8.5% + LIBOR

 5,546

 5,116

 3,676

 1,759

 -  

 16,097

Zenith Bank Plc

8.5% + LIBOR

 76,006

 70,109

 50,373

 24,104

 -  

 220,592

First Bank of Nigeria Limited

8.5% + LIBOR

 41,957

 38,702

 27,807

 13,306

 -  

 121,772

United Bank for Africa Plc

8.5% + LIBOR

 47,504

 43,818

 31,483

 15,065

 -  

 137,870

Stanbic IBTC Bank Plc

8.5% + LIBOR

 7,119

 6,567

 4,718

 2,258

 -  

 20,662

The Standard Bank of South Africa Limited

8.5% + LIBOR

 7,119

 6,567

 4,718

 2,258

 -  

 20,662

Standard Chartered Bank

6.0% + LIBOR

 18,794

 -  

 -  

 -  

 -  

 18,794

Natixis

6.0% + LIBOR

 18,794

 -  

 -  

 -  

 -  

 18,794

Citibank Nigeria Ltd and Citibank NA

6.0% + LIBOR

 14,617

 -  

 -  

 -  

 -  

 14,617

FirstRand Bank Ltd (Rand Merchant Bank Division)

6.0% + LIBOR

 12,529

 -  

 -  

 -  

 -  

 12,529

Nomura Bank Plc*

6.0% + LIBOR

 12,529

 -  

 -  

 -  

 -  

 12,529

NedBank Ltd, London Branch

6.0% + LIBOR

 12,529

 -  

 -  

 -  

 -  

 12,529

The Mauritius Commercial Bank Plc*

6.0% + LIBOR

 12,529

 -  

 -  

 -  

 -  

 12,529

Stanbic IBTC Bank Plc

6.0% + LIBOR

 9,399

 -  

 -  

 -  

 -  

 9,399

The Standard Bank of South Africa Limited

6.0% + LIBOR

 13,576

 -  

 -  

 -  

 -  

 13,576

Other non - derivatives

 

 

 

 

 

 

 

Trade and other payables**

 

127,128  

 -  

 -  

 -  

 -  

127,128  

 

 

 437,675

 170,879

 122,775

 58,750

 -  

  790,079

*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).

 

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 Sept 2018

As at 31 Dec

2017 

As at 30 Sept

2018

As at 31 Dec

2017 

 

$ '000

$ '000

$ '000

$ '000

Financial assets

 

 

 

 

Trade and other receivables*

116,165

310,345

116,165

310,345

Contract assets

11,117

-

11,117

-

Cash and cash equivalents

633,997

437,212

633,997

437,212

 

761,279

747,557

761,279

747,557

Financial liabilities

 

 

 

 

Interest bearing loans and borrowings

536,872

570,077

560,204

570,077

Trade and other payables

69,716

127,128

69,716

127,128

 

606,588

697,205

629,920

697,205

 

*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 third 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 carrying amounts of the other financial instruments are the same as their fair values.

 

The Valuation process

 

The finance & planning team of the Group performs the valuations of financial and non financial assets required for financial reporting purposes, including level 3 fair values. 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.

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 nine months ended 30 September 2018, revenue from the gas segment of the business constituted 22% 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 reclassified to match the new structure for the nine months ended 30 September 2018.

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

6.1.    Segment profit disclosure

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

           

$ '000

$ '000

$ '000

$ '000

Oil

 15,344

 (58,055)

 20,769

 3,387

Gas

 76,110

 52,762

 22,141

 18,893

Total profit/(loss) after tax

 91,454

 (5,293)

 42,910

 22,280

 

 

 

 

 

 

 

 

          Oil

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

               

$ '000

$ '000

$ '000

$ '000

Revenue

 

 

 

 

Crude oil sales

 440,896

 192,687

 183,564

 115,236

Operating profit before depreciation, amortisation

and impairment

 240,529

 27,283

 96,602

 41,934

Depreciation, amortisation and impairment

 (79,227)

 (26,816)

 (23,987)

 (14,834)

Operating profit/(loss)

 161,302

 467

 72,615

 27,100

Finance income

 6,705

 1,582

 2,354

 (14,888)

Finance expenses

 (58,065)

 (57,291)

 (16,641)

 (7,131)

Profit/(loss) before taxation

 109,942

 (55,242)

 58,328

 5,081

Taxation

 (94,598)

 (2,813)

 (37,559)

 (1,694)

(Loss) for the period

 15,344

 (58,055)

 20,769

 3,387

 

                                                                                                                             Gas

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

               

$ '000

$ '000

$ '000

$ '000

Revenue

 

 

 

 

Gas sales

 127,060

 85,873

 41,716

 31,510

Operating profit before depreciation, amortisation

and impairment

 115,318

 83,435

 37,243

 30,212

Depreciation, amortisation and impairment

 (12,555)

 (30,673)

 (4,163)

 (11,319)

Operating profit

 102,763

 52,762

 33,080

 18,893

Finance income

 -  

 -  

 -  

 -  

Finance expenses

 -  

 -  

 -  

 -  

Profit before taxation

 102,763

 52,762

 33,080

 18,893

Taxation

 (26,653)

 -  

 (10,939)

 -  

Profit for the period

 76,110

 52,762

 22,141

 18,893

 

 

6.1.1. Disaggregation of revenue from contracts with customers

The Group derives revenue from the transfer of commodities at a point in 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 retrospectively using the simplified transition approach. The simplified approach does not require a restatement of comparatives.

 

 

9 months ended

30 Sept

2018

9 months ended

30 Sept

2018

9 months ended

30 Sept

2018

3 months ended

30 Sept

2018

3 months ended

30 Sept

2018

3 months ended

30 Sept

2018

 

Oil

Gas

Total

Oil

Gas

Total

 

$ '000

$ '000

$ '000

$ '000

$ '000

$ '000

Revenue from contract with customers

440,896

127,060

567,956

183,564

41,716

225,280

Timing of revenue recognition

 

 

 

 

 

 

At a point in time

440,896

-

440,896

183,564

-

183,564

Over time

-

127,060

127,060

-

41,716

41,716

 

440,896

127,060

567,956

183,564

41,716

225,280

6.2.    Segment assets

Segment assets are measured in a manner consistent with that of 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        

$ '000

$ '000

$ '000

30 September 2018

2,132,591

398,538

2,531,129

31 December 2017

2,343,553

271,077

2,614,630

         

6.3.    Segment liabilities

Segment liabilities are measured in a manner consistent with that of the financial statements. These liabilities are allocated

based on the operations of the segment.

 

 

Oil

Gas 

Total

Total segment liabilities 

$ '000

$ '000

$ '000

30 September 2018

932,925

31,054

963,979

31 December 2017

1,065,950

45,583

1,111,533

         

 

6.4.    Contingent consideration

 

Contingent consideration of $18.4 million for OML 53 relates solely to the oil segment. This is contingent on oil price rising

above US$ 90/bbl. over a one year period and expiring on 31st January 2020. The fair value loss arising during the reporting

period is $18.4 billion.

7.    Revenue from contracts with customers

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

           

$'000

$'000

$'000

$'000

Crude oil sales

 440,896

223,855

 183,564

112,672

Gas sales           

 127,060

85,873

 41,716

31,510

 

 567,956

309,728

 225,280

144,182

(Overlift)/underlift

 -  

(31,168)

 -  

2,564

Total

 567,956

278,560

 225,280

146,746

 

         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

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

 

$'000

$'000

$'000

$'000

Crude handling

 47,246

 17,134

 18,015

 12,128

Barging costs

 -  

 9,113

 -  

 2,589

Royalties

 95,966

 42,857

 33,644

 24,104

Depletion, depreciation and amortisation

 91,231

 54,105

 30,437

 25,131

Niger Delta Development Commission

 5,143

 3,620

 1,622

 1,239

Other rig related expenses

 38

 3,334

 -  

 1,704

Operations & maintenance expenses

 22,594

  23,868

 10,136

 8,949

 

 262,218

  154,031

 93,854

 75,844

 

9.   Other income/(expenses) -net

           

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

 

$'000

$'000

$'000

$'000

Underlift/(overlift)

 20,463

-

(7,278)

-

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 fair value change, as a result of the remeasurement, is also recognised in profit or loss as other income.

10. General and administrative expenses

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

 

$'000

$'000

$'000

$'000

Depreciation

 2,254

 3,384

 (584)

Employee benefits

 23,134

 16,046

 7,844

Professional and consulting fees

 8,912

 12,432

 1,002

Auditor's remuneration

 256

 940

 70

Directors emoluments (executive)

 1,445

 1,832

 806

Directors emoluments (non-executive)

 2,501

 2,348

 869

Rentals

 1,470

 1,146

 486

Flight and other travel costs

 5,309

 4,015

 2,824

Other general expenses

 9,875

 13,989

 3,357

 8,431

 

 55,156

 56,132

 16,674

 24,891

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 employee benefits expense.

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

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

 

$'000

$'000

$'000

$'000

Reversal/(impairment) of loss on NPDC receivables

1,713

-

(152)

-

Reversal of loss on NAPIMS receivables

12

-

147

-

Impairment loss on SPDC receivables

(22)

-

(22)

-

Net reversal of impairment loss allowance

1,703

-

(27)

-

On initial application of IFRS 9, an impairment loss of $5.8 million was recognised for NPDC and NAPIMS receivables as at 1 January 2018 (note 3.3.2.2). The loss allowance was calculated on a total exposure of $125.2 million. During the reporting period, the outstanding receivable balance reduced to $48.7 million. The reduction in the receivables balance led to the reversal of previously recognised loss allowance for the 9 months ended 30 September 2018.

12. Loss on foreign exchange - net

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

 

$'000

$'000

$'000

$'000

Exchange loss

(679)

(906)

(702)

 (40)

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

13. Fair value loss - net

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

 

$'000

$'000

$'000

$'000

Crude oil hedging payments

 (3,474)

(14,406)

 (990)

(4,579)

Fair value loss on contingent consideration

 (4,530)

 (1,370)

 (60)

 (473)

Fair value gain on other assets

 -  

 1,514

 -  

 -  

 

 (8,004)

 (14,262)

 (1,050)

 (5,052)

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)

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

 

$'000

$'000

$'000

$'000

Finance income

 

 

 

 

Interest income

6,705

1,582

2,354

699

Finance costs

 

 

 

 

Interest on bank loan

 (54,150)

(52,818)

 (15,816)

(16,302)

Interest on advance payments for crude oil sales

 (1,730)

(4,402)

 -  

(1,318)

Unwinding of discount on provision for decommissioning 

 (2,185)

(71)

 (825)

(24)

 

 (58,065)

 (57,291)

 (16,641)

 (17,644)

Finance cost - net

 (51,360)

 (55,709)

 (14,287)

 (16,945)

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 September 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% for crude oil 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 Sept 2018

As at

 30 Sept 2018

As at

30 Sept 2018

As at 31 Dec

2017

As at 31 Dec

2017

 

$'000

$'000

$'000

$'000

$'000

 

Gross amount at 85%

Gross amount at 30%

Tax effect

Gross amount

Tax effect

Tax losses

-

 

-

47,674

40,523

Other cumulative timing differences:

 

 

 

 

 

Fixed assets

 (320,034)

 (74,835)

 (294,479)

 (346,109)

 (294,193)

Unutilised Capital Allowance

 427,245

 32,354

 372,864

490,512

 416,935

Provision for Abandonment

 2,457

 -  

 2,088

393

 334

Provision for Gratuity

 6,723

 -  

 5,714

4,809

 4,088

Share Equity Reserve

 25,699

 -  

 21,844

17,809

 15,138

Unrealised Forex (Gain)/Loss

 16,194

 -  

 13,765

16,194

 13,765

Overlift / (Underlift)

 10,535

 -  

 8,955

24,963

 21,218

Provision for Doubtful Debt

 6,968

 -  

 5,923

6,968

 5,923

 

 175,787

 (42,481)

 136,674

263,213

223,731

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 Sept 2018

As at 30 Sept

2018

As at 31 Dec

2017

As at 31 Dec

2017

 

$'000

$'000

$'000

$'000

 

Gross amount

Tax effect

Gross amount

Tax effect

Other deductible temporary differences

 60,491

 40,752

48,995

25,730

Tax losses

 27,313

 15,534

47,673

29,132

 

 87,804

 56,286

96,668

54,862

 

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.

 

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

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

Diluted
Diluted LPS/EPS 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 period 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.

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

3 months ended

30 Sept 2018

3 months ended

30 Sept 2017

 

$'000

$'000

$'000

$'000

 

 

 

 

 

Profit/(loss) for the period

91,454

(5,293)

42,910

22,280

 

 Share

'000

Share
'000

Share
'000

Share
'000

Weighted average number of ordinary shares in issue

 582,889

563,455

 582,889

563,445

Share awards

 6,157

6,437

 6,157

6,437

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

 589,046

569,882

 589,046

569,882

 

$

$

$

$

Basic earnings/(loss) per share

 0.16

(0.01)

 0.07

(0.04)

Diluted earnings/(loss) per share

 0.16

(0.01)

 0.07

(0.04)

 

$'000

$'000

$'000

$'000

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

91,454

(5,293)

42,910

22,280

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

 

$'000

$'000

$'000

Balance as at 1 January 2018

265,400

304,677

570,077

Principal repayment

(265,400)

(312,600)

(578,000)

Interest repayment

(25,877)

(14,629)

(40,506)

Interest accrued

30,219

-

30,219

Effect of loan restructuring

-

 23,931

 23,931

Other financing charges

-

 (3,894)

 (3,894)

Proceeds from loan financing

-

 535,045

 535,045

Carrying amount as at 30 June 2018

4,342

 532,530

 536,872

Interest bearing loans and borrowings include a revolving loan facility and senior notes. In the reporting period, the Group repaid its US$700 million seven year term loan and its US$300 million four year revolving loan facility.

In the reporting period, the Group also issued US$350million 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 US$18.2 million using an effective interest rate of 10.4%.

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 US$200 million in March 2018. The interest accrued at the reporting period is US$9.45 million using an effective interest rate of 9.4%.  The interest paid was determined using 3-month LIBOR rate + 6 % on the last business day of the reporting period. The amortised cost for the senior notes and the borrowings at the reporting period is US$341 million and US$196 million  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 Sept 2018

As at 31 Dec 2017

 

 

$'000

$'000

 

Trade receivables (note 18a)

 109,231

 108,685

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

 -  

 112,664

National Petroleum Investment Management Services receivables

 293

 12,506

Advances on investment

 -  

 65,705

Advances to suppliers

 13,031

 7,861

Other receivables (note 18c)

 45,137

 2,924

Gross carrying amount

 167,692

310,345

Less: Specific impairment allowance

 (273)

 -  

 

 167,419

 310,345

           

 

18a. Trade receivables:

Included in trade receivables is an amount due from Nigerian Gas Marketing Company (NGMC) and Central Bank of Nigeria (CBN) totaling $58.5 million  (2017: $77 million) with respect to the sale of gas, for the Group. Also included in trade receivables is an amount of $42.8 million (2017: $27 million) 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 is Nil (2017: $113 million). The outstanding NPDC receivables at the end of the reporting period has been netted off against the gas receipts payable to NPDC as Seplat has a legally enforceable right to settle outstanding amounts on a net basis.

 

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 $45.1 million (2017: nil).

 

19.  Contract assets

 

As at 30 Sept 2018

As at 31 Dec 2017

 

$'000

$'000

Revenue on gas sales

11,117

-

 

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 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.

19.1.  Reconciliation of contract assets

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

 

As at 30 Sept 2018

As at 31 Dec 2017

 

$'000

$'000

Impact on initial application of IFRS 15

13,790

-

Gas revenue received during the period

(2,673)

-

 

11,117

-

20.  Cash and cash equivalents

 

As at 30 Sept 2018

As at 31 Dec 2017

 

$'000

$'000

Cash on hand

 7

11

Restricted cash

 1,844

62,674

Cash at bank

 632,146

374,527

 

 633,997

437,212

Included in cash and cash equivalents is the total amount of $150 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 Sept 2018

As at 31 Dec 2017

 

$'000

$'000

Authorised ordinary share capital

 

 

 

 

 

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

3,335

3,335

 

 

 

Issued and fully paid

 

 

 

 

 

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

1,867

1,826

 

21b.  Employee share based payment scheme

As at 30 September 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 nine months ended 30 September 2018, 5,534,964 shares were vested (31 December 2017: No shares had vested).

21c.  Movement in share capital

 

Number of

 shares

Issued share capital

Treasury

 shares

Share based payment reserve

Total

 

Shares

$'000

$'000

$'000

$'000

Opening balance as at 1 January 2018

563,444,561

1,826

-

17,809

19,635

Share based payments

-

-

-

7,890

7,890

Share issue

19,465,036

41

(41)

-

-

Vested shares

5,534,964

-

9

(9)

-

Closing balance as at 30 September 2018

588,444,561

1,867

(32)

25,690

27,525

22. Trade and other payables

 

As at 30 Sept 2018

As at 31 Dec 2017

 

$'000

$'000

Trade payables

 42,548

62,758

 

Nigerian Petroleum Development Company (NPDC)

 37,588

-

 

Accruals and other payables

 108,849

149,020

 

Pension payables

 311

180

 

NDDC levy

 10,417

8,383

 

Deferred revenue

 -  

137,248

 

Royalties payable

 55,414

53,004

 

 

 255,127

410,593

 

 

Included in accruals and other payables are field-related accruals of $40.4 million (2017: $56 million) and other vendor payables of $68.4 million (2017: $94 million). Royalties include accruals in respect of gas sales for which payment is outstanding at the end of the period.

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 $37.6 million has been reported after adjusting for interest (as set out in the JOA) and undercash call payments in other currencies. The outstanding NPDC receivables at the end of the reporting period has been netted off against the gas receipts payable to NPDC, and impairment has been calculated on the net NPDC receivables balance.

23. Computation of cash generated from operations

 

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

 

Notes

$'000

$'000

Profit/(loss) before tax

 

212,705

(2,480)

Adjusted for:

 

 

 

Depletion, depreciation and amortisation

8, 10

 93,485

57,489

Interest on bank loan

14

 54,150

52,818

Interest on advance payment for crude oil sales

14

 1,730

4,402

Unwinding of discount on provision for decommissioning

14

 2,185

71

Interest income

14

 (6,705)

(1,582)

Fair value loss on contingent consideration

13

 4,530

1,370

Fair value gain on other assets      

13

 -  

(1,514)

Unrealised foreign exchange loss

12

 679

906

Share based payments expenses

 

 7,890

 4,010

Defined benefit expenses

 

 206

 1,192

Reversal of impairment loss on NPDC, NAPIMS and SPDC receivables

11

 (1,703)

-

Loss on disposal of other property,plant and equipment

 

 -  

82

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

 

 

 

Trade and other receivables, including prepayments

 

 113,843

 (29,593)

Contract assets

 

 (11,117)

-

Trade and other payables

 

 (81,346)

 75,630

Inventories

 

 (4,232)

 4,288

Net cash from operating activities                                                                            

 

 386,300

167,089

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 stationary and other general supplies to the field locations.

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.

Neimeth International Pharmaceutical Plc: The chairman of Seplat is also the chairman of this company. The company provides medical supplies and drugs to Seplat, which are used in connection with Seplat's corporate social responsibility and community healthcare programmes.

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.

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

The following transactions were carried by Seplat with related parties:

24b.  Related party relationships

 

ii)     Purchases of goods and services

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

 

$'000

$'000

Shareholders of the parent company

 

 

SPDCL (BVI)

788

1,013

Total

788

1,013

 

 

 

Entities controlled by key management personnel:

 

 

Contracts > $1million in 2018

 

 

Nerine Support Services Limited

5,133

3,894

Cardinal Drilling Services Limited

1,389

2,592

Stage Leasing Limited

1,138

-

 

7,660

6,486

 

 

 

 

 

9 months ended

30 Sept 2018

9 months ended

30 Sept 2017

 

$'000

$'000

Contracts < $1million in 2018

 

 

Abbey Court trading Company Limited

758

482

Charismond Nigeria Limited

71

43

Keco Nigeria Enterprises

47

115

Stage Leasing Limited

-

560

Oriental Catering Services Limited

424

311

ResourcePro Inter Solutions Limited

9

24

Montego Upstream Services Limited

67

262

Neimeth International Pharmaceutical Plc

-

2

 

1,376

1,799

Total

9,036

8,285

       

 

* 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 nine months ended 30 September 2018 is $5.1 million (2017: $3.9 million).

24c.  Balances

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

 

 

As at 30 Sept 2018

As at 31 Dec 2017

Prepayments / receivables

$'000

$'000

Entities controlled by key management personnel

 

 

Cardinal Drilling Services Limited

5,498

5,498

 

5,498

5,498

 

 

As at 30 Sept 2018

As at 31 Dec 2017

Payables

$'000

$'000

Entities controlled by key management personnel

 

 

Montego Upstream Services Limited

26

375

Nerine Support Services Limited

8

8

Keco Nigeria Enterprises

-

25

Cardinal Drilling Services Limited

198

954

Oriental Catering Services Ltd

5

-

Resourcepro Inte Solutions Ltd

6

-

 

243

1,362

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 September 2018 are:

 

 

As at 30 Sept 2018

As at 31 Dec 2017

 

$'000

$'000

Not later than one year

-

2,382

Later than one year and not later than five years

-

1,846

 

-

4,228

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 september 2018 is $2.4 million (2017: $15.5 million). The contingent liability for the period ended 30 September 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. Dividend

         The directors paid an interim dividend of $29.4 million (2017: Nil) per fully paid ordinary share. The aggregate amount of the dividend was paid out of retained earnings as at 31 March 2018.

Following a review of Seplat's operational, liquidity and financial position as at 30 September 2018, the Board has proposed an interim dividend of US$0.05 per share. The total amount of this proposed dividend expected to be paid out of retained earnings but for which no liability has been recognized in the financial statements is $29.4 million  (September 2017: Nil).

27. Events after the reporting period

Except for the interim dividend proposed at the end of the third quarter (Note 26), there were no significant events that would have a material effect on the Group after the reporting period.

General information

 

Board of Directors

 

 

Ambrosie Bryant Chukwueloka Orjiako

Chairman

 

Ojunekwu Augustine Avuru

Managing Director and Chief Executive Officer

 

Roger Thompson Brown

Chief Financial Officer (Executive Director)

British

Effiong Okon

Executive Operations Director

 

*Michel Hochard

Non-Executive Director

French

Macaulay Agbada Ofurhie

Non-Executive Director

 

Michael Richard Alexander

Senior Independent Non-Executive Director

British

Ifueko M. Omoigui Okauru

Independent Non-executive Director

 

Basil Omiyi

Independent Non-executive Director

 

Charles Okeahalam

Independent Non-executive Director

 

Lord Mark Malloch-Brown

Independent Non-executive Director

British

Damian Dinshiya Dodo

Independent Non-executive Director

 

*Madame Nathalie Delapalme acts as alternate Director to Michel Hochard

 

 

Company secretary

Mirian Kachikwu

 

Registered office and business

address of directors

25a Lugard Avenue

Ikoyi

Lagos

Nigeria

 

Registered number

RC No. 824838

 

FRC number

FRC/2015/NBA/00000010739

 

Auditor

Ernst & Young

(10th & 13th Floor), UBA House

57 Marina Lagos, Nigeria.

 

Registrar

DataMax Registrars Limited

2c Gbagada Expressway

Gbagada Phase 1

Lagos

Nigeria

 

Solicitors

Olaniwun Ajayi LP

Adepetun Caxton-Martins Agbor & Segun ("ACAS-Law")

White & Case LLP

Herbert Smith Freehills LLP

Whitehall Solicitors

Chief J.A. Ororho & Co.

Ogaga Ovrawah & Co.

Consolex LP

Banwo-Ighodalo

Latham & Watkins LLP

V.E. Akpoguma & Co.

Thompson Okpoko & Partners

G.C. Arubayi & Co.

Chukwuma Chambers

Abraham Uhunmwagho & Co

Walles & Tarres Solicitors

Streamsowers & Kohn

 

Bankers

First Bank of Nigeria Limited

Stanbic IBTC Bank Plc

United Bank for Africa Plc

Zenith Bank Plc

Citibank Nigeria Limited

Standard Chartered Bank

HSBC Bank

FirstRand Bank Limited Acting

Natixis

Nedbank Limited

Nomura International Plc

The Standard Bank of South Africa

The Muaritius Commercial Bank

 

 


This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact rns@lseg.com or visit www.rns.com.
 
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