Interim Management Statement and Consolidated Interim Financial Results for the Nine Months Ended 30 September 2018

Company SEPLAT Petroleum Development Company Ltd 
Tags Reserve Update, Strategy - Upstream, Capital Spending, Guidance, Strategy - Corporate, Financial & Operating Data
Date October 30, 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 
    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   173,710  85,190   68,916  44,873 
Cost of sales   (80,200)     (47,107)   (28,713)  (23,193) 
Gross profit     93,510  38,083   40,203  21,680 
Other income/(expenses)-net   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  Capitalcontribution  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  Capitalcontribution  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)           
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 
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 
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 
Loss allowance as at 30 September 2018 - Under IFRS 9 

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  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 
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) 
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   -    
  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  115 
Nerine Support Services Limited 
Keco Nigeria Enterprises 
Cardinal Drilling Services Limited  61  292 
Oriental Catering Services Ltd 
Resourcepro Inter Solutions Ltd 
  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   567,956   278,560   225,280  146,746 
Cost of sales   (262,218)   (154,031)   (93,854)   (75,844) 
Gross profit     305,738   124,529   131,426   70,902 
Other income/(expenses)-net   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  Capitalcontribution  Retained earnings  Foreign currency translation reserve  Total equity      
  $'000  $'000  $'000  $'000  $'000  $'000  $'000  $'000   
At 1 January 2017  1,826  497,457  12,135  40,000  678,922  3,675  1,234,015   
Loss for the period   (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  Capitalcontribution  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  944,108  1,897  1,503,097   
Impact of change in accounting policy:                   
Adjustment on initial application of IFRS 9  (Note 3.3)  (5,816)  (5,816)   
Adjustment on initial application of IFRS 15 (Note 3.3)   
At 1 January 2018 - Restated  1,826  497,457  17,809  40,000  938,292  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)   
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 
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 ofproduction.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)   1,022 
Employee benefits   23,134   16,046   7,844   5,270 
Professional and consulting fees   8,912   12,432   1,002   6,230 
Auditor's remuneration   256   940   70   634 
Directors emoluments (executive)   1,445   1,832   806   450 
Directors emoluments (non-executive)   2,501   2,348   869   793 
Rentals   1,470   1,146   486   414 
Flight and other travel costs   5,309   4,015   2,824   1,647 
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) 
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 $68.4million (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  24 
Montego Upstream Services Limited  67  262 
Neimeth International Pharmaceutical Plc 
  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 
Keco Nigeria Enterprises  25 
Cardinal Drilling Services Limited  198  954 
Oriental Catering Services Ltd 
Resourcepro Inte Solutions Ltd 
  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).

Source: EvaluateEnergy® ©2019 EvaluateEnergy Ltd