Q1 2021 Results

Source Press Release
Company Seplat Petroleum Development Company Plc 
Tags ESG/CSR, Hedging, Production/Development, Exploration, Upstream Activities, Strategy - Upstream, Capital Spending, Guidance, Financial & Operating Data, Strategy - Corporate
Date April 29, 2021

Seplat Petroleum Development Company Plc ("Seplat" or the "Company"), a leading Nigerian independent energy company listed on both the Nigerian Stock Exchange and the London Stock Exchange, today announces its unaudited results for the three months ended 31 March 2021.  

Operational highlights

·      Working-interest oil and production within guidance at 48,239 boepd

·      Average daily volumes of nearly 54,000 boepd achieved in first 21 days of April 

·      Liquids production of 28,541 bopd in Q1 2021

·      Gas production of 114 MMscfd (19,698 boepd)

·      Low unit cost of production of $8.70/boe

·      Oben-50 gas well now producing, Oben-51 drilled and completed with gas expected to flow in May

·      Safety record extended to more than 17 million hours without LTI on Seplat-operated assets

Financial highlights

·      Board adopts quarterly dividend policy; declares Q1 2021 dividend of US2.5 cents per share

·      Revenue up 16.8% to $152.4 million

·      EBITDA of $77.8 million

·      Cash at bank $236.3 million, net debt of $458.1 million

·      Successful issue of $650 million 7.75% senior notes to redeem existing $350 million 9.25% senior notes
and repay $250 million drawn on $350 million RCF    

·      Refinanced $100 million Westport RBL facility

·      Total capital expenditure of $32.6 million 

Corporate updates

·      Seeking shareholder approval at the AGM on 20 May 2021 to change name to Seplat Energy PLC to reflect evolving strategy

·      ANOH project now fully funded following successful $260 million debt issue

·      Plan to host Capital Markets Day on 29 July 2021

Outlook

·      Expected production unchanged at 48-55 kboepd for full year, subject to market conditions 

·      Capex guidance unchanged, expected to be $150 million for the full year

·      5.0MMbbls hedged at $35-$45/bbl from Q2 to Q4 2021

Roger Brown, Chief Executive Officer, said:"

We have made a progressive start to the year, delivering oil and gas production volumes of 48,239 boepd, within our guidance range. With the Gbetiokun field at OML40 now back in production, we are currently achieving average daily volumes of nearly 54 kboepd so far in April and we will build on this as we add additional oil and gas wells this year.

Our flagship ANOH gas project is proceeding as planned and was fully funded in February when our joint venture company, AGPC successfully raised $260 million of debt financing. In addition, the success of our $650 million Eurobond issuance in March demonstrates investor confidence in our prudent financial management and the exciting future ahead for the Company and its stakeholders.

As we drive forward our strategy of being a low-cost energy provider delivering reliable, affordable and sustainable energy to the young, fast-growing population of Nigeria, energy transition - which delivers on Nigeria's social development goals in tandem with the climate agenda - is essential. This is the backbone of Seplat's strategy and we will be communicating how we plan to achieve this over the coming months. To that end, the Board took the decision to change our name to Seplat Energy PLC, which more adequately reflects our ambitions of providing a broader energy mix. We will present the name change to our shareholders for approval at the AGM on 20 May 2021."

Interim condensed consolidated statement of profit or loss and other comprehensive income for the three months ended 31 March 2021

Summary of performance

  US$ million    ₦ billion 
  3M 2021  3M 2020  % change  3M 2021  3M 2020 
Revenue  152.4  130.5  16.8%  57.9  42.4 
Gross profit  52.8  33.1  59.5%  20.1  10.8 
Operating profit (loss)  44.4  (77.0)    16.9  (25.0) 
Profit before tax  28.0  (95.7)    10.6  (31.1) 
Cash flow from operations    5.3  64.5  (91.8%)  2.0  23.3 
Working interest production (boepd)  48,239  47,986  0.5%     
Average realised oil price (US$/bbl)  60.76  49.85  21.9%     
Average realised gas price (US$/Mscf)  2.76  2.89  (4.5%)     

Outlook for 2021

For 2021 we expect to produce an average of 48,000 - 55,000 boepd, taking into account the impact of OPEC+ quotas. We continue to hedge against oil price volatility and expect a higher proportion of revenues to come from long-term gas contracts at stable prices.   

We have significant cash resources and will continue to manage our finances prudently in 2021, expecting to invest $150 million of capital expenditure across the full year, with nearly $33 million already invested. We remain confident that our ongoing cost-cutting initiatives and prudent management of cash will enable further reductions in debt, whilst supporting dividend payments and investment for growth.  

Following its successful funding, the completion of the ANOH project remains a major priority. Although we expect some COVID-19 related delays to push completion into early 2022, following a cost optimisation programme we now expect the project to cost no more than $650 million, substantially below the $700 million budget previously stated at Final Investment Decision.

Proposal to change name to Seplat Energy PLC

We are seeking shareholder approval to change our name to Seplat Energy PLC to reflect the future direction of the Company. The change of name will be accompanied by a new corporate brand identity that we plan to unveil at the Seplat Energy Summit in September. Before that, we intend to host a Capital Markets Day on 29 July 2021 to outline the Company's strategic direction and its plans to develop its New Energy business.

Adoption of quarterly dividend

On 28 April 2021 the Board approved the payment of quarterly dividends, commencing with an interim dividend of US2.5 cents, in a change to Seplat's previous policy of declaring dividends twice a year in the Q3 results and the full-year results. The change in policy is intended to provide more frequent returns to shareholders.  

Operating review

Group reserves

Total working-interest 2P reserves, as assessed independently by Ryder Scott Company, L.P., at 1 January 2021, stood at 499.4 MMboe, comprising 240.5 MMbbls of oil and condensate and 1,501.3 Bscf of natural gas. The change represents an organic decrease in overall 2P reserves of 1.9% year-on-year, due to production of 12.3 MMbbls but mitigated by upward revisions of previous estimates. Working-interest 2C resources stood at 94.8 MMboe, comprising 59.7 MMbbls of oil and condensate and 203.3 Bscf of natural gas.

Consequently, the Group's working-interest 2P reserves and 2C resources stood at 594.1 MMboe at 1 January 2021, comprising 300.2 MMbbls oil and condensate and 1,704.7 Bscf of natural gas.

Drilling programme

During the first quarter of 2021 we completed the Oben-50 gas well, which is now producing as expected. We also drilled and completed Oben-51 and expect gas to be flowing in May. We plan workover activity at Oben-44 and Oben-46 as an alternative to new drilling. We also plan a development well and an appraisal well at our Eastern Asset in the second half of the year, as well as three wells at Gbetiokun and an exploration well at Sibiri (formerly called Amobe). Shell, the unitised operator, has commenced drilling the gas wells at ANOH, with a total of four wells being planned for this year.

HSE performance

Staff and contractors worked a total of 1.9 million hours with no fatalities, lost-time injuries or minor injuries. The Company has achieved more than 17 million hours without LTI on Seplat-operated assets. There were 23 HSE incidents in total, compared to 26 in Q1 2020, including four spills and four gas leaks, all of which were remediated with limited environmental impact. By the end of March we had conducted 4,471 COVID-19 tests, with a positivity rate of 2%. We continue to enforce all infection control protocols at our field operations and offices.  

Working-interest production for the three months ended 31 March 2021

Average working-interest production for the first quarter of 2021 was within guidance at 48,239 boepd, which represents an overall increase of 0.5% year-on-year. Within this, liquids production was down 13.2% to 28,541 bopd because of delays in siting a new storage vessel at OML 40 to replace the MT Harcourt, which was damaged in November 2020. There was 84% uptime for the Trans Forcados Pipeline during the period and the produced liquid volumes from OMLs 4, 38 and 41 were subject to 12.6% reconciliation losses.

Working-interest gas production increased by nearly 30% to 114 MMscfd, compared to Q1 2020 in which maintenance was undertaken at the Oben Gas Processing plant.    

    3M 2021    3M 2020 
    Liquids(1)  Gas  Oil equivalent    Liquids  Gas  Oil equivalent 
  Seplat %  bopd  MMscfd  boepd    bopd  MMscfd  boepd 
OMLs 4, 38 & 41  45%         19,842             114         39,540    19,722  88  34,844 
OML 40  45%           3,615                -              3,615    8,807    8,807 
OML 53  40%           3,570                -              3,570    2,886  2,886 
OPL 283  40%           1,178                -              1,178    705  705 
Ubima  88%  337  337    744  744 
Total           28,541             114         48,239    32,863  88  47,986 
                     

1.  Liquid production volumes as measured at the LACT unit for OMLs 4, 38, 41 and OML40, and at the flow station for OPL 283.
Volumes stated are subject to reconciliation and will differ from sales volumes within the period. 

Oil business performance

Seplat's oil operations produced an average 28,541 bopd on a working-interest basis in Q1 2021. Although output increased at OMLs 4,38, 41, OML 53 and OPL 283, the delays at OML 40 noted above resulted in significantly lower volumes in the first quarter. Production at the Gbetiokun field on OML 40 resumed in March and we expect volumes to normalise in the second quarter. Similarly, the Extended Well Test at Ubima has been completed and the production phase commenced in March.

The average price realised per barrel in the first quarter of 2021 was $60.76 (2020: $49.85), following the recovery of Brent prices on the receding threat from the Covid-19 pandemic and a return to previous levels of economic activity. 

In accordance with the revised OML 55 commercial arrangement that was agreed in July 2016, which provides for a discharge sum of $330 million to be paid to Seplat over a six-year period through allocation of crude oil volumes produced from OML 55, Seplat received payments amounting to $4.9 million in Q1 2021.

Update on export route

The minor completion works on the 160,000 bopd Amukpe-Escravos Pipeline are not within Seplat's control and have been slower than anticipated due to a combination of challenges associated with access to the Escravos terminal owing to COVID-19 and issues relating to ownership of the pipeline. Our partner, the NPDC, now owns a direct stake in the pipeline and we understand they are working with the other pipeline owner and their banks to enable the completion of the project. We have consequently adjusted our plan and budgets to expect commencement of export of the initial permitted volume of 40,000 bopd through the Escravos terminal in the second half of 2021. Once completed, we believe it will significantly improve the assets' production uptime (84% in Q1 2021) and reduce losses from crude theft and reconciliation (12.6% in Q1 2021).

Gas business performance 

Seplat's working interest production for the first quarter of 2021 was 114 MMscfd (19,698 boepd) at an average selling price of $2.76/Mscf. Gas volumes were higher than Q1 2020 (88 MMscfd), during which period we undertook turnaround maintenance at the Oben Gas Plant. Gas contributed 40.8% of Group volumes on a boepd basis, and 18.6% of Group revenues.      

Sapele Gas Plant

Work continues on the new Sapele Gas Plant with modules now being fabricated overseas and foundation work being conducted at the site. The project is expected to be completed in the second half of 2022, with Sapele's processing capacity increasing from 60 MMscfd to 75MMscfd. The upgraded facility will produce gas that meets export specifications, and the LPG processing unit module will enhance the economics of the plant, as well as ensuring that any gas flaring is eliminated. We are currently accelerating the installation of AG Booster Compressors at Sapele which will reduce the gas flare at the site. This is expected to be completed and operational in Q4 this year.

ANOH gas plant development

The ANOH Gas Processing Plant development at OML 53 (and adjacent OML 21 with which the upstream project is unitised) will drive the next phase of growth for Seplat's expanding gas business. The project will comprise a Phase One 300 MMscfd midstream gas processing plant.

The ANOH plant, is being built by AGPC, which is an IJV owned equally between Seplat and the Nigerian Gas Company ("NGC"), a wholly owned subsidiary of Nigerian National Petroleum Corporation ("NNPC"). In February 2021, AGPC successfully raised $260 million in debt to fund completion of the ANOH project. The project is now fully funded following completion of equity investments of $210 million by each partner ($420 million combined).

ANOH is one of Nigeria's most strategic gas projects. It will help Nigeria to accelerate its transition away from small-scale diesel generators to cleaner, less expensive fuels such as natural gas for power generation.

The upstream development, including the drilling of six production wells, will be delivered by the upstream unit operator Shell Petroleum Development Company (SPDC), with four wells expected to be completed in 2021. We have made excellent progress on the project despite the COVID-19 challenges, and we expect the major gas processing units to arrive in Nigeria in Q3 2021. We hope to commence installation before the end of the year, with mechanical completion and pre-commissioning in Q1 2022, and have first gas flowing to customers by the end of H1 2022. The initial total project cost was budgeted at $700 million. Following a cost optimisation programme, the AGPC construction cost is now expected to be no more than $650 million, inclusive of financing costs and taxes, significantly lower than the original projected cost at FID.

Financial review

Revenue, production and commodity prices

On an average daily basis, Brent crude oil traded between $51.1/bbl and $69.6/bbl in the first quarter of 2021, ending the period at around $63.5/bbl. Brent prices averaged $61.3/bbl for the quarter, 20.5% higher compared to $50.9/bbl in Q1 2020, which was affected by the pandemic.

Total revenue for the period was $152.4 million, up 16.8% from the $130.5 million achieved in 2020. Crude oil revenue was $124.1 million (Q1 2020: $107.4 million) a 15.5% increase compared to 2020, reflecting higher realised oil prices. The average oil price realised in the first quarter of 2021 was $60.8/bbl (Q1 2020: $49.9/bbl).

Average working-interest liquids production was 28,541 bopd, down 13.2% from 32,863 bopd in 2020, whilst the total volume of crude lifted in the period was 2.0 MMbbls compared to 2.1 MMbbls in 2020. The lower oil production in OML 40 was caused by a shut-in of production from Gbetiokun in January and February, after the MV Harcourt was damaged in November 2020, and there were delays in siting the replacement storage vessel for evacuating oil produced from the field.

Gas sales revenue increased by 22.8% to $28.4 million (Q1 2020: $23.1 million), due to higher gas sales volumes achieved of 10.3Bcf (Q1 2020: 7.9Bcf) reflective of the new gas wells brought onstream during the period. The average realised gas price was lower at $2.76/Mscf (Q1 2020: $2.89/Mscf).

Gas sales contributed 18.6% of total Group revenue in the period (Q1 2020: 17.7%).

Gross profit

Gross profit increased by 59.5% to $52.8 million (Q1 2020: $33.1 million) as a result of higher revenues. Cost of sales in the period totaling $99.7 million was comparable with $97.4 million in the same period last year. The higher production opex of $37.6 million includes maintenance costs to support asset integrity works carried out in the period, offset by lower crude handling charges as the Liquid Heater Treater became operational with minimal water volumes being evacuated through TFP. Consequently, production opex for the period was $8.7/boe (Q1 2020: $7.7/boe). Non-production costs primarily consisting of royalties and DDA, which were $59.3 million comparable to $59.8 million in the prior year reflect the lower production volumes from OML 40.

The 43.1% reduction in general and administrative (G&A) expenses resulted from a combination of the effect of cost reduction initiatives (such as office maintenance, telecommunication, travel and logistics) across the business, one-off payments made for emoluments to former Eland directors in prior period and G&A costs correctly classified in Q3 2020.

Operating profit

The operating profit was $44.4 million after recognising other income from tariffs (fee from use of Group's pipeline to the Warri refinery) of $6.6 million and underlift (shortfalls of crude lifted below the share of production, which is priced at date of lifting) of $8.1 million. This compared to a $77.0 million operating loss in Q1 2020, which was impacted primarily by a $145.5 million IAS 36 impairment charge in the period. We achieved an EBITDA of $77.8 million in the period, when adjusted for non-cash items.

Tax

The Group's tax expense for the first quarter of 2021 was $3.2 million, compared to a tax expense of $10.8 million for the same period in 2020. The tax expense is made up of a deferred tax credit of $4.7 million and current tax charge of $7.9 million. The effective tax rate for the period was 11.3%.

Net profit

The profit before tax adjustments was $28.0 million (Q1 2020: $95.7 million loss). The net finance charge was $16.8 million, compared to $20 million in 2020. The net profit for Q1 2021 was $24.9 million (Q1 2020: $106.6 million net loss).

The resultant basic EPS was $0.06 in Q1 2021, compared to a loss per share of $0.19 in Q1 2020.

Hedging

Seplat's hedging policy aims to guarantee appropriate levels of cash flow assurance in times of oil price weakness and volatility. The 2021 hedging programme consists of up-front premium put options as follows: for Q1, 1.0MMbbls at a strike price of $30/bbl and 1.0MMbbls at a strike price of $35/bbl; for Q2, 2.0MMbbls at a strike price of $35/bbl; for Q3, 1.0MMbbls at a strike price of $35/bbl and 1.0MMbbls at a strike price of $40/bbl; and for Q4, 1.0MMbls at a strike price of $45/bbl. The Board and management team continue to closely monitor prevailing oil market dynamics and will consider further measures to provide appropriate levels of cash flow assurance in times of oil price weakness and volatility.

Cash flows from operating activities

Operating cash flow before movements in working capital was $84.1 million (Q1 2020: $81.0 million). For the purposes of cash flow statements, restricted cash of $54.5 million has been excluded from the cash balance at the end of the period. Cash generated in the period was also affected by timing differences in the lifting dates that were scheduled towards the end of the quarter and resultant settlement dates that included $36.8 million for sale of crude oil in trade receivables. Consequently, net cash flows from operating activities, after movements in working capital, were $5.3 million (Q1 2020: $64.5 million).

Seplat received a total of $16.4 million towards the settlement of outstanding dollar-denominated cash calls and $51.0 million (Naira equivalent) to offset Naira cash calls, totalling $67.4 million in Q1 2021. The major JV receivable balance now stands at $97.2 million, down from $107.0 million in December 2020. Seplat has continued discussions with major partners to ensure that receivables are settled promptly.

Cash flows from investing activities

Capital expenditures were $32.6 million in the period and included drilling costs of $18.7 million in relation to the completion of two gas development wells, pre-drill and ongoing batch drilling operations costs for two ANOH upstream gas wells at OML 53. Other expenditure included $8.7 million for costs associated with the Sapele Gas Plant upgrade and $5.2 million for other oil and gas facilities and engineering costs.

The Group received total proceeds of $4.9 million from partner BelemaOil under the revised commercial arrangement at OML 55, for the monetisation of 94.2 kbbls of crude oil during the period.

After adjusting for interest receipts, the net cash outflow from investing activities for the period was $27.7 million (Q1 2020: $44.8 million).

Cash flows from financing activities

Net cash outflows from financing activities were $20.4 million (Q1 2020: $15.9 million). This reflects lower interest paid on loans of $20.4 million, compared to the previous year, after $100 million was paid down on the RCF.

Net debt reconciliation at 31 March 2021  $ million  Coupon  Maturity 
Senior Notes  345.8  9.25%  June 2023 
Revolving Credit Facility (RCF)  250.7  Libor+6.00%  June 2022 / December 2023 
Westport RBL   97.9  Libor+8%  March 2026 
Total borrowings  694.4     
Cash and cash equivalents  236.3     
Net debt  458.1     

Overall, Seplat's aggregate indebtedness at 31 March 2021 stood at $694.4 million, with cash at bank of $236.3 million, leaving net debt at $458.1 million.

Reserve-Based Loan (RBL) Refinancing

Eland's existing RBL was consolidated into the Group's balance sheet in 2020. The initial RBL was entered into in November 2018, via the Group's subsidiary Westport, and was a five-year loan agreement with interest payable semi-annually. The RBL is secured against the Group's producing assets in OML 40 via the Group's shares in Elcrest, and by way of a debenture that creates a charge over certain assets of the Group, including its bank accounts. The available facility is capped at the lower of the available commitments and the borrowing base.

On 17th March 2021, Westport signed an amendment and restatement agreement regarding the RBL. As part of the new agreement, the debt utilised and interest rate remain unchanged at $100 million and 8% + LIBOR respectively, however, the maturity date was extended by either five years after the effective date of the loan (March 2026) or by the reserves tail date (expected to be March 2025).

Events after the reporting period

During the period, the Group offered 7.75% senior notes with an aggregate principal of $650 million due in April 2026. The notes, which were priced on 25 March and closed on 1 April 2021, were issued by the Group in March 2021 and guaranteed by certain of its subsidiaries. The gross proceeds of the Notes were used to redeem the existing $350 million 9.25% senior notes due in 2023, to repay in full drawings of $250 million under the existing $350 million RCF for general corporate purposes, and to pay transaction fees and expenses. The RCF remains available for drawing if required.

Interim Condensed Consolidated Financial Statements (Unaudited)
for the three months ended 31 March 2021
(Expressed in Nigerian Naira and US Dollars)

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

for the three months ended 31 March 2021

    3 Months ended 31 March 2021  3 Months ended 31 March 2020  3 Months ended 31 March 2021  3 Months ended 31 March 2020 
    Unaudited  Unaudited  Unaudited  Unaudited 
  Notes  ₦ million  ₦ million  $'000  $'000 
           
Revenue from contracts with customers   57,930   42,408   152,448   130,493 
Cost of sales   (37,871)   (31,651)   (99,659)   (97,387) 
Gross profit     20,059   10,757   52,789   33,106 
Other income   5,781   15,646   15,214   48,141 
General and administrative expenses  10   (6,919)   (10,396)   (18,220)   (31,994) 
Impairment loss on financial assets  11   (269)  (47,270)   (707)  (145,453) 
Fair value (loss)/gain  12   (1,776)   6,226   (4,676)   19,158 
Operating profit/(loss)     16,876   (25,037)   44,400   (77,042) 
Finance income  13   3   347   7   1,067 
Finance cost  13   (6,391)   (6,943)   (16,817)   (21,364) 
Finance cost-net     (6,388)  (6,596)   (16,810)  (20,297) 
Share of profit from joint venture accounted for using the equity method     159   522   418   1,607 
Profit/(loss) before taxation     10,647   (31,111)   28,008   (95,732) 
Income tax expense  14   (1,198)   (3,516)   (3,152)   (10,819) 
Profit/(loss) for the period     9,449   (34,627)   24,856   (106,551) 
Attributable to:           
Equity holders of the parent     13,550   (34,627)   35,647   (106,551) 
Non-controlling interests     (4,101)   -      (10,791)   -    
     9,449   (34,627)   24,856   (106,551) 
Other comprehensive income:           
Items that may be reclassified to profit or loss:           
Foreign currency translation difference     93,911   -      -    
           
Total comprehensive income/(loss) for the period (net of tax)     9,449   59,284    24,856   (106,551) 
Earnings/(Loss) per share attributable to the equity shareholders:           
Basic earnings per share (₦) ($)  24   23.29   (60.19)   0.06   (0.19) 
Diluted earnings per share (₦)/($)  24   23.03   (59.95)   0.06   (0.18) 


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

Interim condensed consolidated statement of financial position

As at 31 March 2021

    31 March 2021  31 Dec 2020  31 March 2021  31 Dec 2020 
    Unaudited  Audited  Unaudited  Audited 
  Notes  ₦ million  ₦ million  $'000  $'000 
Assets           
Non-current assets           
Oil & gas properties     609,903  609,475   1,605,003  1,603,888 
Other property, plant and equipment     4,814   5,330   12,667   14,027 
Right-of-use assets     3,572   3,965   9,401   10,435 
Intangible assets     22,301  22,301   58,687   58,687 
Other asset     42,769  44,630   112,551   117,448 
Investment accounted for using equity accounting     84,800   84,642   223,159   222,741 
Prepayments     24,777   23,463   65,202   61,744 
Deferred tax asset  14   289,877  289,877   762,833  762,833 
Total non-current assets     1,082,813  1,083,683   2,849,503  2,851,803 
Current assets           
Inventories     28,643   28,337   75,377   74,570 
Trade and other receivables  15   108,149   96,774   284,600   254,671 
Prepayments     1,219   1,385   3,208   3,644 
Contract assets  16   3,263   2,343   8,586   6,167 
Cash and cash equivalents  18   89,779   98,315   236,257   258,718 
Total current assets     231,053   227,154   608,028   597,770 
Total assets     1,313,866  1,310,837   3,457,531  3,449,573 
Equity and Liabilities           
Equity           
Issued share capital  19   293   293   1,855   1,855 
Share premium  19   86,917   86,917   511,723   511,723 
Share based payment reserve  19   6,958  7,174   27,023   27,592 
Capital contribution     5,932   5,932   40,000   40,000 
Retained earnings     225,386   211,790   1,151,846   1,116,079 
Foreign currency translation reserve     331,289   331,289   992   992 
Non-controlling interest     (15,159)   (11,058)   (44,987)   (34,196) 
Total shareholders' equity     641,616   632,337   1,688,452   1,664,045 
Non-current liabilities           
Interest bearing loans and borrowings  20   242,606  229,880   638,436  604,947 
Lease Liabilities     1,737   1,591   4,570   4,187 
Provision for decommissioning obligation     61,941  61,795   163,002  162,619 
Deferred tax liabilities  14   200,197  202,020   526,835  531,632 
Defined benefit plan     4,453  4,063   11,718  10,691 
Total non-current liabilities     510,934  499,349   1,344,561  1,314,076 
Current liabilities           
Interest bearing loans and borrowings  20   21,268  35,518   55,968  93,468 
Lease Liabilities     511   679   1,345   1,787 
Derivative financial instruments  17   1,841  626   4,844  1,648 
Trade and other payables  21   122,720  130,468   322,952  343,340 
Contract liabilities  22   3,599   3,599   9,470   9,470 
Current tax liabilities     11,377   8,261   29,939   21,739 
Total current liabilities     161,316   179,151   424,518   471,452 
Total liabilities     672,250  678,500   1,769,079  1,785,528 
Total shareholders' equity and liabilities     1,313,866  1,310,837   3,457,531  3,449,573 

The above interim 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 (The Group) for three months ended 31 March 2021 were authorised for issue in accordance with a resolution of the Directors on 28 April 2021 and were signed on its behalf by

A. B. C. Orjiako  R.T. Brown  E. Onwuka 
FRC/2013/IODN/00000003161  FRC/2014/ANAN/00000017939  FRC/2020/003/00000020861 
Chairman  Chief Executive Officer  Chief Financial Officer 
29 April 2021  29 April 2021  29 April 2021 

Interim condensed consolidated statement of changes
in equity

for the three months ended 31 March 2021

  Issued
share
capital 
Share
premium 
Share
based payment reserve 
Capital
contribution 
Retained earnings  Foreign currency translation reserve  Non- controlling interest  Total equity 
  ₦ million  ₦ million  ₦ million  ₦ million  ₦ million  ₦ million  ₦ million  ₦ million 
At 1 January 2020   289   84,045   8,194   5,932   259,690   202,910   (7,252)   553,808 
Loss for the period   -      -      -      (34,627)   -      -      (34,627) 
Other comprehensive income   -      -      -      -      -      93,911   -      93,911 
Total comprehensive income for the period   -   -   -   -   (34,627)   93,911   -   59,284 
Transactions with owners in their capacity as owners:                 
Share based payments   -      -      636   -      -      -      -      636 
Total   -      -      636   -      -      -      -      636 
At 31 March 2020 (unaudited)   289   84,045   8,830   5,932   225,063   296,821   (7,252)   613,728 
                 
At 1 January 2021   293  86,917  7,174   5,932  211,790  331,289   (11,058)  632,337 
Profit / (loss) for the period   -      -      -      13,550   -      (4,101)   9,449 
Other comprehensive income   -      -      -      -      -      -        -    
Total comprehensive income for the period   -   -   -   -   13,550   -      (4,101)   9,449 
Transactions with owners in their capacity as owners:                 
Unclaimed dividend   -      -      -      -      46   -      -      46 
Share based payments   -      -      544   -      -      -      -      544 
Vested shares   -      -      (760)   -      -      -      -      (760) 
Total   -      -      (216)   -     46   -      -      (170) 
At 31 March 2021 (unaudited)   293   86,917   6,958   5,932   225,386   331,289   (15,159)   641,616 
                                     

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

  Issued
share
capital 
Share
premium 
Share
based payment reserve 
Capital
contribution 
Retained earnings  Foreign currency translation reserve  Non-controlling interest  Total equity 
  $'000  $'000  $'000  $'000  $'000  $'000  $'000  $'000 
At 1 January 2020   1,845   503,742   30,426   40,000   1,249,156   2,391   (23,621)   1,803,939 
Loss for the period   -      -      -      -      (106,551)   -      -      (106,551) 
Other comprehensive income   -      -      -      -      -      -    
Total comprehensive loss for the period   -   -   -   -   (106,551)   -   -   (106,551) 
Transactions with owners in their capacity as owners:                 
Share based payments   -      -      1,957   -      -      -        1,957 
Total   -      -      1,957   -      -      -      -      1,957 
At 31 March 2020(Unaudited)  1,845   503,742   32,383   40,000   1,142,605   2,391   (23,621)   1,699,345 
                 
At 1 January 2021   1,855   511,723   27,592   40,000  1,116,079   992   (34,196)  1,664,045 
Profit / (loss) for the period   -      -      -      -      35,647   -      (10,791)   24,856 
Other comprehensive income   -      -      -      -            
Total comprehensive loss for the period   -   -   -   -   35,647   -      (10,791)   24,856 
Transactions with owners in their capacity as owners:                 
Unclaimed dividend   -      -      -      -      120   -      -      120 
Share based payments   -      -      1,431   -      -      -      -      1,431 
Vested shares   -      -      (2,000)   -      -      -      -      (2,000) 
Total   -      -      (569)   -     120   -      -     (449) 
At 31 March 2021(Unaudited)   1,855   511,723   27,023   40,000   1,151,846   992   (44,987)   1,688,452 
                                           

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

Interim condensed consolidated statement of cash flows

for the three months ended 31 March 2021

    3 months ended  3 months ended  3 months ended  3 months ended 
    31-Mar-21  31-Mar-20  31-Mar-21  31-Mar-20 
  Note  ₦ million  ₦ million  $'000  $'000 
Cash flows from operating activities           
Cash generated from operations  23  2,005  23,326   5,266  64,508 
Hedge premium paid    (441)   (1,160) 
Income tax credit    95   251 
Net cash inflows from operating activities    1,660  23,326  4,357  64,508 
Cash flows from investing activities           
Payment for acquisition of oil and gas properties     (12,382)              (16,558)   (32,585)            (45,866) 
Payment for acquisition of other property, plant and equipment     (17)                    -      (45)                  -    
Receipts from other assets     1,861                    -      4,897 
 Interest received     3  347   7  1,067 
Net cash outflows from investing activities     (10,535)              (16,211)   (27,726)            (44,799) 
Cash flows from financing activities           
Proceeds from loans     -     3,610   -     10,000 
Lease payment     (2)  (42)   (4)  (117) 
Payments for other financing charges     -     (941)   -     (2,606) 
Interest paid on loans     (7,746)   (8,369)   (20,384)   (23,184) 
Net cash outflows from financing activities     (7,748)               (5,742)   (20,388)            (15,907) 
Net (decrease)/increase in cash and cash equivalents     (16,623)               1,373   (43,757)              3,802 
Cash and cash equivalents at beginning of the year     85,554             100,184   225,137           326,330 
Effects of exchange rate changes on cash and cash equivalents     225               17,337   607                (788) 
Cash and cash equivalents at end of the period     69,156             118,894   181,987           329,344 

For the purposes of the cash flow statements, the restricted cash balance of ₦5.1 billion ($13.5 million) has been excluded from the cash and cash equivalents at the end of the period. These amounts are subject to legal restrictions and are therefore not available for general use by the Group.

An additional ₦7.9 billion ($20.8 million) of funds deposited in Access bank Plc bank accounts in the ordinary course of business are being unilaterally restricted by Access bank Plc in connection with the court case between Seplat Petroleum Development Company Plc and Access Bank Plc.

Also included in the restricted cash balance is a cash-backed guarantee of ₦7.6 billion ($20 million) set aside with Zenith Bank Plc to fulfil the requirement of an order of the Court of Appeal, to seek the release of any order relating to the case between Seplat Development Petroleum Company Plc and Access Bank Plc.


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

Notes to the interim condensed consolidated financial statements

1.   Corporate Structure and business

Seplat Petroleum Development Company Plc ('Seplat' or the 'Company'), the parent of the Group, was incorporated on 17 June 2009 as a private limited liability company and re-registered as a public company on 3 October 2014, under the Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria 2004. The Company commenced operations on 1 August 2010. The Company was principally engaged in oil and gas exploration and production and gas processing activities. The Company's registered address is: 16a Temple Road (Olu Holloway), 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 OML 4, OML 38 and OML 41 located in Nigeria.

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% Participant interest in producing assets: the Umuseti/Igbuku marginal field area located within OPL 283 (the 'Umuseti/Igbuku Fields').

On 21 August 2014, the Group incorporated a new subsidiary, Seplat Petroleum Development UK Limited. The subsidiary provides technical, liaison and administrative support services relating to oil and gas exploration activities.

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 and gas processing. On 12 December 2014, the Group also incorporated a new subsidiary, Seplat East Swamp Company Limited with the principal activity of oil and gas exploration and production.

In 2015, the Group purchased a 40% participating interest in OML 53, onshore north eastern Niger Delta (Seplat East Onshore Limited), from Chevron Nigeria Ltd for ₦79.6 billion.

On 16 January 2018, the Group incorporated a subsidiary, Seplat West Limited ('Seplat West'). Seplat West was incorporated to manage the producing assets of Seplat Plc.

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 using the ANOH gas processing plant.

In order to fund the development of the ANOH gas processing plant, on 13 August 2018, the Group entered into a shareholder's agreement with Nigerian Gas Processing and Transportation Company (NGPTC). Funding is to be provided by both parties in equal proportion representing their ownership share and will be used to subscribe for the ordinary shares in ANOH. The agreement was effective on 18 April 2019, which was the date the Corporate Affairs Commission (CAC) approval was received. Given the change in ownership structure as at 31 December 2019, the Group no longer exercises control and has deconsolidated ANOH in the consolidated financial statements. However, its retained interest qualifies as a joint arrangement and has been recognised accordingly as investment in joint venture.

On 31 December 2019, Seplat Petroleum Development Company acquired 100% of Eland Oil and Gas Plc's issued and yet to be issued ordinary shares. Eland is an independent oil and gas company that holds interest in subsidiaries and joint ventures that are into production, development and exploration in West Africa, particularly the Niger Delta region of Nigeria.

On acquisition of Eland Oil and Gas Plc (Eland), the Group acquired indirect interest in existing subsidiaries of Eland.

Eland Oil & Gas (Nigeria) Limited, is a subsidiary acquired through the purchase of Eland and is into exploration and production of oil and gas.

Westport Oil Limited, which was also acquired through purchase of Eland is a financing company.

Elcrest Exploration and Production Company Limited (Elcrest) who became an indirect subsidiary of the Group purchased a 45 percent interest in OML 40 in 2012. Elcrest is a Joint Venture between Eland Oil and Gas (Nigeria) Limited (45%) and Starcrest Nigeria Energy Limited (55%). It has been consolidated because Eland is deemed to have power over the relevant activities of Elcrest to affect variable returns from Elcrest at the date of acquisition by the Group. (See details in Note 4.1.vi) The principal activity of Elcrest is exploration and production of oil and gas.

Wester Ord Oil & Gas (Nigeria) Limited, who also became an indirect subsidiary of the Group acquired a 40% stake in a licence, Ubima, in 2014 via a joint operations agreement. The principal activity of Wester Ord Oil & Gas (Nigeria) Limited is exploration and production of oil and gas.

Other entities acquired through the purchase of Eland are Tarland Oil Holdings Limited (a holding company), Brineland Petroleum Limited (dormant company) and Destination Natural Resources Limited (dormant company).

On 1 January 2020, Seplat Petroleum Development Company Plc transferred its 45% participating interest in OML 4, OML 38 and OML 41 ("transferred assets") to Seplat West Limited. As a result, Seplat ceased to be a party to the Joint Operating Agreement in respect of the transferred assets and became a holding company. Seplat West Limited became a party to the Joint Operating Agreement in respect of the transferred assets and assumed its rights and obligations.

The Company together with its subsidiaries as shown below are collectively referred to as the Group.

Subsidiary  Date of incorporation  Country of incorporation and place of business  Percentage
holding 
Principal activities  Nature of holding 
Newton Energy Limited  1 June 2013  Nigeria  100%  Oil & gas exploration
and production 
Direct 
Seplat Petroleum Development Company UK Limited  21 August 2014  United Kingdom  100%  Technical, liaison and administrative support services relating to oil & gas exploration and production  Direct 
Seplat Gas Company Limited  12 December 2014  Nigeria  100%  Oil & gas exploration and production and gas processing  Direct 
Seplat East Onshore Limited  12 December 2014  Nigeria  100%  Oil & gas exploration and production  Direct 
Seplat East Swamp Company Limited  12 December 2014  Nigeria  100%  Oil & gas exploration and production  Direct 
Seplat West Limited  16 January 2018  Nigeria  100%  Oil & gas exploration and production  Direct 
Eland Oil & Gas Limited  28 August 2009  United Kingdom  100%  Holding company  Direct 
Eland Oil & Gas (Nigeria) Limited  11 August 2010  Nigeria  100%  Oil and Gas Exploration and Production  Indirect 
Elcrest Exploration and Production Nigeria Limited  6 January 2011  Nigeria   45%  Oil and Gas Exploration and Production  Indirect 
Westport Oil Limited   8 August 2011  Jersey  100%  Financing  Indirect 
Tarland Oil Holdings Limited   16 July 2014  Jersey  100%  Holding Company  Indirect 
Brineland Petroleum Limited   18 February 2013  Nigeria  49%  Dormant  Indirect 
Wester Ord Oil & Gas (Nigeria) Limited   18 July 2014  Nigeria  100%  Oil and Gas Exploration and Production  Indirect 
Wester Ord Oil and Gas Limited   16 July 2014  Jersey  100%  Holding Company  Indirect 
Destination Natural Resources Limited  Dubai  70%  Dormant  Indirect 



2.   Significant changes in the current reporting period

The following significant changes occurred during the reporting period ended 31 March 2021:

·    During the period, the Group offered 7.75% senior notes with an aggregate principal of $650 million (₦247 billion) due in April 2026. The notes, which were priced on 25 March and closed on 1 April 2021, were issued by the Group in March 2021 and guaranteed by certain of its subsidiaries.

3.   Summary of significant accounting policies

3.1    Introduction to summary of significant accounting policies

This note provides a list of the significant accounting policies adopted in the preparation of these interim condensed consolidated financial statements. These accounting policies have been applied to all the periods presented, unless otherwise stated. The interim financial statements are for the Group consisting of Seplat Plc and its subsidiaries.

3.2    Basis of preparation  

The interim condensed consolidated financial statements of the Group for the first quarter ended 31 March 2021 have been prepared in accordance with the accounting standard IAS 34 Interim financial reporting. This interim condensed consolidated financial statement does not include all the notes normally included in an annual financial statement of the Group. Accordingly, this report is to be read in conjunction with the annual report for the year ended 31 December 2020 and any public announcements made by the Group during the interim reporting period.

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

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

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

3.3    New and amended standards adopted by the Group

The accounting policies adopted in the preparation of the interim condensed consolidated financial statements are consistent with those followed in the preparation of the Group's annual consolidated financial statements for the year ended 31 December 2020, except for the adoption of new standards effective as of 1 January 2021. The Group has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.

Several amendments and interpretations apply for the first time in 2021, but do not have an impact on the interim condensed consolidated financial statements of the Group.

a)   Amendments to IFRS 7, IFRS 9, IAS 39, IFRS 4 and IFRS 16: Interest Rate Benchmark Reform - Phase 2

The amendments provide temporary reliefs which address the financial reporting effects when an interbank offered rate (IBOR) is replaced with an alternative nearly risk-free rate (RFR). The amendments include a practical expedient to require contractual changes, or changes to cash flows that are directly required by the reform, to be treated as changes to a floating interest rate, equivalent to a movement in a market rate of interest. The practical expedient is required for entities applying IFRS 4 that are using the exemption from IFRS 9 (and, therefore, apply IAS 39) and for IFRS 16 Leases, to lease modifications required by IBOR reform. The amendments also permit changes required by IBOR reform to be made to hedge designations and hedge documentation without the hedging relationship being discontinued. Any gains or losses that could arise on transition are dealt with through the normal requirements of IFRS 9 and IAS 39 to measure and recognise hedge ineffectiveness. In addition, the amendments provide temporary relief to entities from having to meet the separately identifiable requirement when an RFR instrument is designated as a hedge of a risk component. These amendments had no impact on the consolidated financial statements of the Group as it does not have any interest rate hedge relationships.

This amendment had no impact on the consolidated financial statements of the Group.

3.4    Standards issued but not yet effective

The new and amended standards and interpretations that are issued, but not yet effective, up to the date of issuance of the Group's interim financial statements are disclosed below. The Group intends to adopt these new and amended standards and interpretations, if applicable, when they become effective. Details of these new standards and interpretations are set out below:

·    IFRS 17 Insurance Contracts - Effective for annual periods beginning on or after 1 January 2023

·    Classification of Liabilities as Current or Non-current - Amendments to IAS 1 - Effective for annual periods beginning on or after 1 January 2022.

·    Amendments to IAS 16 Property, Plant and Equipment - Effective date for annual periods beginning on or after 1 January 2022

·    Amendments to IAS 8 Accounting Policies and Accounting Estimates - Effective date for annual periods beginning on or after 1 January 2022

·    Amendments to IAS 37 Onerous Contracts - Costs of Fulfilling a Contract - Effective date for annual periods beginning on or after 1 January 2022

·    Amendments to IFRS 3 Business Combination - Reference to the Conceptual Framework - Effective date for annual periods beginning on or after 1 January 2022

·    Amendments to IFRS 9 Financial Instruments - Fees in the '10 per cent' test for derecognition of financial liabilities - Effective date for annual periods beginning on or after 1 January 2022

·    Amendments to IAS 41 Agriculture - Taxation in fair value measurements - Effective date for annual periods beginning on or after 1 January 2022

3.5    Basis of consolidation          

The consolidated financial statements comprise the financial statements of the Company and its subsidiaries as at 31 March 2021.

This basis of consolidation is the same adopted for the last audited financial statements as at 31 December 2020.

3.6    Functional and presentation currency

Items included in the financial statements of each of the Group's 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 the UK subsidiary which is the Great Britain Pound. The interim condensed consolidated financial statements are presented in 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. They are deferred in equity if attributable to net investment in foreign operations.

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 date of the reporting date.

·    income and expenses for statement of profit or loss and other 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 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. Goodwill and fair value adjustments arising on the acquisition of a foreign operation are treated as assets and liabilities of the foreign operation and translated at the closing rate.

4.   Significant accounting judgements estimates and assumptions

4.1    Judgements

Management judgements at the end of the first quarter are consistent with those disclosed in the 2020 Annual financial statements. The following are some of the judgements which have the most significant effect on the amounts recognised in this interim consolidated financial statement.

iii.  OMLs 4, 38 and 41

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

iv.  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.

v.   Lease liabilities

In 2018, the Group entered into a lease agreement for its new head office building. The lease contract contains an option to purchase and right of first refusal upon an option of sales during the initial non-cancellable lease term of five (5) years.

In determining the lease liability/right-of-use assets, management considered all fact and circumstances that create an economic incentive to exercise the purchase option. Potential future cash outflow of $45 million (Seplat's 45% share of $100 million), which represents the purchase price, has not been included in the lease liability because the Group is not reasonably certain that the purchase option will be exercised. This assessment will be reviewed if a significant event or a significant change in circumstances occurs which affects the initial assessment and that is within the control of the management.

vi.  Foreign currency translation reserve

The Group has used the CBN rate to translate its Dollar currency to its Naira presentation currency. Management has determined that this rate is available for immediate delivery. If the rate used was 10% higher or lower, revenue in Naira would have increased/decreased by ₦5.8 billion, 2020: ₦4.2 billion.

vii. Consolidation of Elcrest

On acquisition of 100% shares of Eland Oil and Gas Plc, the Group acquired indirect holdings in Elcrest Exploration and Production (Nigeria) Limited. Although the Group has an indirect holding of 45% in Elcrest, Elcrest has been consolidated as a subsidiary for the following basis:

·    Eland Oil and Gas Plc has power over Elcrest through due representation of Eland in the board of Elcrest, and clauses contained in the Share Charge agreement and loan agreement which gives Eland the right to control 100% of the voting rights of shareholders.

·    Eland Oil and Gas Plc is exposed to variable returns from the activities of Elcrest through dividends and interests.

·    Eland Oil and Gas Plc has the power to affect the amount of returns from Elcrest through its right to direct the activities of Elcrest and its exposure to returns.

viii.        Revenue recognition

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 gas customers 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 transfers the crude to Mercuria and when payment for the crude is received 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 Operating arrangement (JOA) 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 JOA partners involves sharing in the production of crude oil, and for which the settlement of the transaction is non-monetary. The JOA partners have been assessed to be partners not customers. Therefore, shortfalls or excesses below or above the Group's share of production are recognised in other income/ (expenses) - net.

Exploration and evaluation assets

The accounting for exploration and evaluation ('E&E') assets require management to make certain judgements and assumptions, including whether exploratory wells have discovered economically recoverable quantities of reserves. Designations are sometimes revised as new information becomes available. If an exploratory well encounters hydrocarbon, but further appraisal activity is required in order to conclude whether the hydrocarbons are economically recoverable, the well costs remain capitalised as long as sufficient progress is being made in assessing the economic and operating viability of the well. Criteria used in making this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected additional development activities, commercial evaluation and regulatory matters. The concept of 'sufficient progress' is an area of judgement, and it is possible to have exploratory costs remain capitalised for several years while additional drilling is performed or the Group seeks government, regulatory or partner approval of development plans.

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 2020 annual financial statements.

The following are some of the estimates and assumptions made.

i.  Defined benefit plans (pension benefits)

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.  Oil and gas reserves

Proved oil and gas reserves are used in the units of production calculation for depletion as well as the determination of the timing of well closure for estimating decommissioning liabilities and impairment analysis. There are numerous uncertainties inherent in estimating oil and gas reserves. Assumptions that are valid at the time of estimation may change significantly when new information becomes available. Changes in the forecast prices of commodities, exchange rates, production costs or recovery rates may change the economic status of reserves and may ultimately result in the reserves being restated.

iii.   Share-based payment reserve

Estimating fair value for share-based payment transactions requires determination of the most appropriate valuation model, which depends on the terms and conditions of the grant. This estimate also requires determination of the most appropriate inputs to the valuation model including the expected life of the share award or appreciation right, volatility and dividend yield and making assumptions about them. The Group measures the fair value of equity-settled transactions with employees at the grant date.

The Group makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. Such estimates and assumptions are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances.

iv.  Provision for decommissioning obligations

Provisions for environmental clean-up and remediation costs associated with the Group's drilling operations are based on current constructions, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology.

v.  Property, plant and equipment

The Group assesses its property, plant and equipment, including exploration and evaluation assets, for possible impairment if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable, or at least at every reporting date.

If there are low oil prices or natural gas prices during an extended period, the Group may need to recognise significant impairment charges. The assessment for impairment entails comparing the carrying value of the cash-generating unit with its recoverable amount, that is, higher of fair value less cost to dispose and value in use. Value in use is usually determined on the basis of discounted estimated future net cash flows. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation on operating expenses, discount rates, production profiles and the outlook for regional market supply-and-demand conditions for crude oil and natural gas.

The Group uses the higher of the fair value less cost to dispose and the value in use in determining the recoverable amount of the cash-generating unit. In determining the value, the Group uses a forecast of the annual net cash flows over the life of proved plus probable reserves, production rates, oil and gas prices, future costs (excluding (a) future restructurings to which the entity is not yet committed; or (b) improving or enhancing the asset's performance) and other relevant assumptions based on the year end Competent Persons Report (CPR). The pre-tax future cash flows are adjusted for risks specific to the forecast and discounted using a pre-tax discount rate which reflects both current market assessment of the time value of money and risks specific to the asset.

Management considers whether a reasonable possible change in one of the main assumptions will cause an impairment and believes otherwise.

vi.  Useful life of other property, plant and equipment

The Group recognises depreciation on other property, plant and equipment on a straight-line basis in order to write-off the cost of the asset over its expected useful life. The economic life of an asset is determined based on existing wear and tear, economic and technical ageing, legal and other limits on the use of the asset, and obsolescence. If some of these factors were to deteriorate materially, impairing the ability of the asset to generate future cash flow, the Group may accelerate depreciation charges to reflect the remaining useful life of the asset or record an impairment loss.

vii. 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.

viii.        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.

ix.  Intangible asset

The contract based intangible assets were acquired as part of a business combination. They are recognised at their fair value at the date of acquisition and are subsequently amortised on a straight-line bases over their estimated useful lives which is also the economic life of the asset.

The fair value of contract based intangible assets is estimated using the multi period excess earnings method. This requires a forecast of revenue and all cost projections throughout the useful life of the intangible assets. A contributory asset charge that reflects the return on assets is also determined and applied to the revenue but subtracted from the operating cash flows to derive the pre-tax cash flow. The post-tax cashflows are then obtained by deducting out the tax using the effective tax rate.

Discount rates represent the current market assessment of the risks specific to each CGU, taking into consideration the time value of money. The discount rate calculation is based on the specific circumstances of the Group and its operating segments and is derived from its weighted average cost of capital (WACC). The WACC takes into account both debt and equity. The cost of equity is derived from the expected return on investment by the Group's investors. The cost of debt is based on the interest-bearing borrowings the Group is obliged to service.

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  Interest bearing loans and 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 bank balances, 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   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 bank balances as well as credit exposures to customers (i.e. Mercuria, Shell western, Pillar, Azura, Geregu Power, Sapele Power and Nigerian Gas Marketing Company (NGMC) receivables), and other parties (i.e. NAPIMS receivables, NPDC receivables and other receivables).

a)   Risk management

The Group is exposed to credit risk from its sale of crude oil to Mercuria, VitolEni Trading and Shell western. There is a 30-day payment term after Bill of Lading date in the off-take agreement with Mercuria (OMLs 4, 38 &41) which runs for five years until 31 July 2021 and on  Vitol off-take agreement (OML53 - Ohaji South Field) which expires in May 2021. While payment term is 10 days in the  Eni off-take agreement (OML53 - Jisike Field) which expires in December 2021. 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 its customers.

The credit risk on cash and cash balances is managed through the diversification of banks in which the balances are held. The risk 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. 

5.1.2   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 deposit 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
year 
2 - 3
years 
3 - 6
years 
Total 
  ₦ million  ₦ million  ₦ million  ₦ million  ₦ million 
31 March 2021             
Non - derivatives             
Fixed interest rate borrowings             
Senior notes  9.25%   -      -     133,000   -     133,000 
Variable interest rate borrowings             
Citibank, N.A., London Branch  6% + Libor   5,790   5,067   -      -      10,857 
Nedbank Limited London  6% + Libor   5,790   5,067   -      -      10,857 
Stanbic IBTC Bank Plc  6% + Libor   2,895   2,533   -      -      5,428 
The Standard Bank of South Africa Limited  6% + Libor   2,895   2,533   -      -      5,428 
RMB International (Mauritius) Limited  6% + Libor   5,790   5,067   -      -      10,857 
The Mauritius Commercial Bank Ltd  6% + Libor   5,790   5,067   -      -      10,857 
JPMorgan Chase Bank, N.A., London Branch  6% + Libor   4,343   3,800   -      -      8,143 
Standard Chartered Bank  6% + Libor   4,343   3,800   -      -      8,143 
Natixis  6% + Libor   4,343   3,800   -      -      8,143 
Société Générale, London Branch  6% + Libor   2,171   1,900   -      -      4,071 
Zenith Bank Plc  6% + Libor   2,171   1,900   -      -      4,071 
United Bank for Africa Plc  6% + Libor   2,171   1,900   -      -      4,071 
First City Monument Bank Limited  6% + Libor   2,172   1,900   -      -      4,072 
The Mauritius Commercial Bank Ltd  8% + Libor   -      -      2,918   11,674  14,592 
Stanbic IBTC Bank Plc  8% + Libor   -      -      2,979   11,917  14,896 
Standard Bank of South Africa  8% + Libor   -      -      1,702   6,810  8,512 
             
Total variable interest borrowings      50,664    44,334   7,599   30,401  132,998 
Other non - derivatives             
Trade and other payables**    122,720  122,720 
Lease liability     933   1,551   731   25   3,240 
     123,653   1,551   731   25   125,960 
Total      174,317  45,885  141,330  30,426   391,958 
  Effective interest rate  Less than
1 year 
1 - 2
year 
2 - 3
years 
3 - 5
years 
Total 
  ₦ million  ₦ million  ₦ million  ₦ million  ₦ million 
31 December 2020             
Non - derivatives             
Fixed interest rate borrowings             
Senior notes  9.25%   -      -     133,000   -     133,000 
Variable interest rate borrowings             
Citibank, N.A., London Branch  6% + Libor   724   10,133   -      -      10,857 
Nedbank Limited London  6% + Libor   724   10,133   -      -      10,857 
Stanbic IBTC Bank Plc  6% + Libor   362   5,067   -      -      5,429 
The Standard Bank of South Africa Limited  6% + Libor   362   5,067   -      -      5,429 
RMB International (Mauritius) Limited  6% + Libor   724   10,133   -      -      10,857 
The Mauritius Commercial Bank Ltd  6% + Libor   724   10,133   -      -      10,857 
JPMorgan Chase Bank, N.A., London Branch  6% + Libor   543   7,600   -      -      8,143 
Standard Chartered Bank  6% + Libor   543   7,600   -      -      8,143 
Natixis  6% + Libor   543   7,600   -      -      8,143 
Société Générale, London Branch  6% + Libor   271   3,800   -      -      4,071 
Zenith Bank Plc  6% + Libor   271   3,800   -      -      4,071 
United Bank for Africa Plc  6% + Libor   271   3,800   -      -      4,071 
First City Monument Bank Limited  6% + Libor   271   3,800   -      -      4,071 
First Bank of Nigeria  8% + Libor   1,140   2,993   428   -      4,561 
The Mauritius Commercial Bank Ltd  8% + Libor   3,268   8,579   1,226   -      13,073 
Stanbic IBTC Bank Plc/ The Standard Bank of South Africa Limited  8% + Libor   5,092   13,367   1,910   -      20,369 
             
Total variable interest borrowings     15,833   113,605   3,564  133,002 
Other non - derivatives             
Trade and other payables**     130,468   130,468 
Lease liability     933   895   731   25   2,584 
     131,401   895   731   25   133,052 
Total     147,234   114,500   137,295   25   399,054 
  Effective
interest rate 
Less than
1 year 
1 - 2
year 
2 - 3
years 
3 - 6
years 
Total 
  $'000  $'000  $'000  $'000  $'000 
31 March 2021             
Non - derivatives             
Fixed interest rate borrowings             
Senior notes  9.25%   -      -     350,000   -     350,000 
Variable interest rate borrowings             
Citibank, N.A., London Branch  6% + Libor   15,238   13,333   -      -      28,571 
Nedbank Limited London  6% + Libor   15,238   13,333   -      -      28,571 
Stanbic IBTC Bank Plc  6% + Libor   7,619   6,667   -      -      14,286 
The Standard Bank of South Africa Limited  6% + Libor   7,619   6,667   -      -      14,286 
RMB International (Mauritius) Limited  6% + Libor   15,238   13,333   -      -      28,571 
The Mauritius Commercial Bank Ltd  6% + Libor   15,238   13,333   -      -      28,571 
JPMorgan Chase Bank, N.A., London Branch  6% + Libor   11,429   10,000   -      -      21,429 
Standard Chartered Bank  6% + Libor   11,429   10,000   -      -      21,429 
Natixis  6% + Libor   11,429   10,000   -      -      21,429 
Société Générale, London Branch  6% + Libor   5,714   5,000   -      -      10,714 
Zenith Bank Plc  6% + Libor   5,714   5,000   -      -      10,714 
United Bank for Africa Plc  6% + Libor   5,714   5,000   -      -      10,714 
First City Monument Bank Limited  6% + Libor   5,715   5,000   -      -      10,715 
The Mauritius Commercial Bank Ltd  8% + Libor   -      -     7,680  30,720  38,400 
Stanbic IBTC Bank Plc  8% + Libor   -      -     7,840  31,360  39,200 
Standard Bank of South Africa  8% + Libor   -      -     4,480  17,920  22,400 
             
             
Total variable interest borrowings      133,334    116,666   20,000  80,000  350,000 
Other non - derivatives               
Trade and other payables**  322,952   -      -      -     322,952 
Lease liability  2,455  4,082  1,924  67  8,528 
  325,407  4,082  1,924  67  331,480 
Total  458,741  120,748  371,924  80,067  1,031,480 
                             
  Effective
interest rate 
Less than
1 year 
1 - 2
year 
2 - 3
years 
3 - 5
years 
Total 
  $'000  $'000  $'000  $'000  $'000 
31 December 2020             
Non - derivatives             
Fixed interest rate borrowings             
Senior notes  9.25%   -      -     350,000   -     350,000 
Variable interest rate borrowings             
Citibank, N.A., London Branch  6% + Libor   1,905   26,667   -      -      28,572 
Nedbank Limited London  6% + Libor   1,905   26,667   -      -      28,572 
Stanbic IBTC Bank Plc  6% + Libor   952   13,333   -      -      14,285 
The Standard Bank of South Africa Limited  6% + Libor   952   13,333   -      -      14,285 
RMB International (Mauritius) Limited  6% + Libor   1,905   26,667   -      -      28,572 
The Mauritius Commercial Bank Ltd  6% + Libor   1,905   26,667   -      -      28,572 
JPMorgan Chase Bank, N.A., London Branch  6% + Libor   1,429   20,000   -      -      21,429 
Standard Chartered Bank  6% + Libor   1,429   20,000   -      -      21,429 
Natixis  6% + Libor   1,429   20,000   -      -      21,429 
Société Générale, London Branch  6% + Libor   714   10,000   -      -      10,714 
Zenith Bank Plc  6% + Libor   714   10,000   -      -      10,714 
United Bank for Africa Plc  6% + Libor   714   10,000   -      -      10,714 
First City Monument Bank Limited  6% + Libor   713   10,000   -      -      10,713 
First Bank of Nigeria  8% + Libor   3,000   7,875   1,125   -      12,000 
The Mauritius Commercial Bank Ltd  8% + Libor   8,600   22,575   3,225   -      34,400 
Stanbic IBTC Bank Plc/ The Standard Bank of South Africa Limited  8% + Libor   13,400   35,175   5,025   -      53,600 
             
Total variable interest borrowings     41,666   298,959   9,375   -     350,000 
Other non - derivatives               
Trade and other payables**  343,341   -      -      -     343,324 
Lease liability  2,455  2,354  1,924  67  6,800 
  345,796  2,354  1,924  67  350,141 
Total  387,462  301,313  361,299  67  1,050,142 
                             

** Trade and other payables (exclude non-financial liabilities such as provisions, taxes, pension and other non-contractual payables).

5.1.3   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 31 March 2021  As at 31 Dec 2020  As at 31 March 2021  As at 31 Dec 2020 
  ₦ million  ₦ million  ₦ million  ₦ million 
Financial assets at amortised cost         
Trade and other receivables*   102,963  58,398   102,963  58,398 
Contract assets   3,263   2,343   3,263   2,343 
Cash and bank balances   89,779  98,315   89,779  98,315 
   196,005  159,056   196,005  159,056 
Financial liabilities at amortised cost         
Interest bearing loans and borrowings   263,874  265,398   273,776   277,170 
Trade and other payables**   122,720   93,537   122,720   93,537 
   386,594   358,935   396,496   370,707 
Financial liabilities at fair value         
Derivative financial instruments (Note 17)  1,841  626  1,841  626 
  1,841  626  1,841  626 
  Carrying amount  Fair value 
  As at 31 March 2021  As at 31 Dec 2020  As at 31 March 2021  As at 31 Dec 2020 
  $'000  $'000  $'000  $'000 
Financial assets at amortised cost         
Trade and other receivables*   270,956  153,680   270,956  153,680 
Contract assets   8,586   6,167   8,586   6,167 
Cash and bank balances   236,257  258,718   236,257  258,718 
   515,799  418,565   515,799  418,565 
Financial liabilities at amortised cost         
Interest bearing loans and borrowings   694,404  698,415   720,463  729,395 
Trade and other payables**   322,952   246,150   322,952   246,150 
   1,017,356  944,565   1,043,415   975,545 
Financial liabilities at fair value         
Derivative financial instruments (Note 17)  4,844  1,648  4,844  1,648 
  4,844  1,648  4,844  1,648 
             

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

** Trade and other payables (exclude non-financial liabilities such as provisions, taxes, pension and other non-contractual payables), trade and other receivables (excluding prepayments), contract assets and cash and bank balances are financial instruments whose carrying amounts as per the financial statements approximate their fair values. This is mainly due to their short-term nature.

5.1.4   Fair Value Hierarchy

As at the reporting period, the Group had classified its financial instruments into the three levels prescribed under the accounting standards. There were no transfers of financial instruments between fair value hierarchy levels during the year.

·    Level 1 - Quoted (unadjusted) market prices in active markets for identical assets or liabilities.

·    Level 2 - Valuation techniques for which the lowest level input that is significant to the fair value measurement is directly or indirectly observable.

·    Level 3 - Valuation techniques for which the lowest level input that is significant to the fair value measurement is unobservable.

The fair value of the financial instruments is included at the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

The fair value of the Group's derivative financial instruments has been determined using a proprietary pricing model that uses marked to market valuation. The valuation represents the mid-market value and the actual close-out costs of trades involved. The market inputs to the model are derived from observable sources. Other inputs are unobservable but are estimated based on the market inputs or by using other pricing models.

The fair value of the Group's interest-bearing loans and borrowings is 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 fair value of the Group's contingent consideration is determined using the discounted cash flow model. The cash flows were determined based on probable future oil prices. The estimated future cash flow was discounted to present value using a discount rate.

The valuation process

The finance & planning team of the Group performs the valuations of financial and non-financial assets required for financial reporting purposes. This team reports directly to the General Manager (GM) Commercial who reports to the Chief Financial Officer (CFO) and the Audit Committee (AC). Discussions of valuation processes and results are held between the GM 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 the Group's internal organisation and management reporting structure. The Group'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 and processing of gas. These two reportable segments make up the total operations of the Group.

For the period ended 31 March 2021, revenue from the gas segment of the business constituted 19% 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 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 its cash flows, will be largely independent of other business units within the Group, it is regarded as a separate segment.

The result is two reporting segments, Oil and Gas. There were no intersegment sales during the reporting periods under consideration, therefore all revenue was from external customers.

Amounts relating to the gas segment are determined using the gas cost centres, with the exception of depreciation. Depreciation relating to the gas segment is determined by applying a percentage which reflects the proportion of the Net Book Value of oil and gas properties that relates to gas investment costs (i.e. cost for the gas processing facilities).

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

6.1    Segment profit disclosure

  3 Months ended 31 March 2021  3 Months ended 31 March 2020  3 Months ended 31 March 2021  3 Months ended 31 March 2020 
  ₦'million  ₦'million  $'000  $'000 
Oil   3,895   (43,395)   10,240  (133,530) 
Gas   5,554   8,768   14,616   26,979 
Total profit from continued operations for the period   9,449  (34,627)   24,856  (106,551) 

Oil                                                                                

  3 Months ended 31 March 2021  3 Months ended 31 March 2020  3 Months ended 31 March 2021  3 Months ended 31 March 2020 
  ₦'million  ₦'million  $'000  $'000 
Revenue from contract with customers         
Crude oil sales    47,152   34,900   124,084   107,389 
Operating profit before depreciation, depletion and amortisation   20,092   14,654   52,862   45,093 
Depreciation and impairment   (12,311)   (47,937)   (32,398)    (147,507) 
Operating profit/(loss)   7,781  (33,283)   20,464   (102,414) 
Finance income   3   347   7   1,067 
Finance costs   (6,391)   (6,943)   (16,817)   (21,364) 
Profit/(Loss) before taxation   1,393  (39,879)   3,654  (122,711) 
Income tax credit/(expense)   2,502   (3,516)   6,586   (10,820) 
Profit/(Loss) for the period   3,895   (43,395)   10,240  (133,530) 

Gas

  3 Months ended 31 March 2021  3 Months ended 31 March 2020  3 Months ended 31 March 2021  3 Months ended 31 March 2020 
  ₦'million  ₦'million  $'000  $'000 
Revenue from contract with customer         
Gas sales   10,778   7,508   28,364   23,104 
Operating profit before depreciation, depletion and amortisation   9,112   8,257   23,980   25,407 
Depreciation, amortization and impairment   (17)   (11)   (44)   (35) 
Operating profit   9,095   8,246   23,936   25,372 
Finance income   -      -      -      -    
Finance cost   -      -      -      -    
Share of profit from joint venture accounted for using equity accounting   159   522   418   1,607 
Profit before taxation   9,254   8,768   24,354   26,979 
Taxation   (3,700)   -      (9,738)   -    
Profit for the period   5,554   8,768   14,616   26,979 

6.1.1   Disaggregation of revenue from contracts with customers

The Group derives revenue from the transfer of commodities at a point in time or over time and from different geographical regions. 

  3 Months ended March 2021  3 Months ended March 2021  3 Months ended March 2021  3 Months ended March 2020  3 Months ended March 2020  3 Months ended March 2020 
  Oil  Gas  Total  Oil  Gas  Total 
  ₦'million  ₦'million  ₦'million  ₦'million  ₦'million  ₦'million 
Geographical markets             
Nigeria   11,587  10,778   22,365   9,246  7,508   16,754 
Switzerland   35,565     35,565   25,654     25,654 
Revenue from contract with customers   47,152  10,778   57,930   34,900  7,508  42,408 
Timing of revenue recognition             
At a point in time   47,152   -      47,152   34,900   -      34,900 
Over time   -     10,778   10,778   -      7,508   7,508 
Revenue from contract with customers   47,152  10,778   57,930   34,900   7,508   42,408 
                   
  3 Months ended March 2021  3 Months ended March 2021  3 Months ended March 2021  3 Months ended March 2020  3 Months ended March 2020  3 Months ended March 2020 
  Oil  Gas  Total  Oil  Gas  Total 
  $'000  $'000  $'000  $'000  $'000  $'000 
Geographical markets             
Nigeria   30,492  28,364   58,856   28,451  23,104   51,555 
Switzerland   93,592   -      93,592   78,938     78,938 
Revenue from contract with customers   124,084  28,364   152,448  107,389  23,104  130,493 
Timing of revenue recognition             
At a point in time  124,084   -     124,084   107,389   -      107,389 
Over time   -      28,364  28,364   -      23,104   23,104 
Revenue from contract with customers  124,084  28,364   152,448   107,389   23,104   130,493 
                   

The Group's transactions with its major customer, Mercuria, constitutes more than 10% (₦35.6 billion, $94 million) of the total revenue from the oil segment and the Group as a whole. Also, the Group's transactions with Azura (₦3.7 billion, $11.8 million) accounted for more than 10% of the total revenue from the gas segment and the Group as a whole.

6.1.2   Impairment loss/(reversal) on financial assets by reportable segments

  3 Months ended March 2021  3 Months ended March 2021  3 Months ended March 2021  3 Months ended March 2020  3 Months ended March 2020  3 Months ended March 2020 
  Oil  Gas  Total  Oil  Gas  Total 
  ₦'million  ₦'million  ₦'million  ₦'million  ₦'million  ₦'million 
Impairment loss/(reversal)   252  17     269   (187)   -      (187) 
  3 Months ended March 2021  3 Months ended March 2021  3 Months ended March 2021  3 Months ended March 2020  3 Months ended March 2020  3 Months ended March 2020 
  Oil  Gas  Total  Oil  Gas  Total 
  $'000  $'000  $'000  $'000  $'000  $'000 
Impairment loss/(reversal)   663   44      707   (575)   -      (575) 

6.1.3   Impairment loss/(reversal) on non-financial assets by reportable segments

  3 Months ended March 2021  3 Months ended March 2021  3 Months ended March 2021  3 Months ended March 2020  3 Months ended March 2020  3 Months ended March 2020 
  Oil  Gas  Total  Oil  Gas  Total 
  ₦'million  ₦'million  ₦'million  ₦'million  ₦'million  ₦'million 
Impairment loss/(reversal)   -      -      -      47,457   -      47,457 
  3 Months ended March 2021  3 Months ended March 2021  3 Months ended March 2021  3 Months ended March 2020  3 Months ended March 2020  3 Months ended March 2020 
  Oil  Gas  Total  Oil  Gas  Total 
  $'000  $'000  $'000  $'000  $'000  $'000 
Impairment loss/(reversal)   -      -      -      146,028   -      146,028 

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. The Group had no non-current assets domiciled outside Nigeria.

  Oil  Gas   Total  Oil  Gas   Total 
Total segment assets               ₦'million  ₦'million  ₦'million  $'000  $'000  $'000 
31 March 2021   1,232,834   81,032   1,313,866   3,244,289   213,242   3,455,331 
31 December 2020  1,101,463  209,374  1,310,837  2,898,588  550,985  3,449,573 

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  Oil  Gas   Total 
Total segment liabilities         ₦'million  ₦'million  ₦'million  $'000  $'000  $'000 
31 March 2021   659,298   12,952   672,250   1,734,996   34,083   1,769,079 
31 December 2020  654,095  24,405  678,500  1,721,305  64,223  1,785,528 

7.   Revenue from contracts with customers

  3 months ended 31 March 2021  3 months ended 31 March 2020  3 months ended 31 March 2021  3 months ended 31 March 2020 
  ₦ million  ₦ million  $'000  $'000 
Crude oil sales    47,152  34,900   124,084  107,389 
Gas sales   10,778  7,508   28,364  23,104 
   57,930  42,408   152,448  130,493 

The major off takers for crude oil are Mercuria and Shell West. The major off takers for gas are Geregu Power, Sapele Power, Nigerian Gas Marketing Company and Azura.

8.   Cost of sales 

  3 months ended 31 March 2021  3 months ended 31 March 2020  3 months ended 31 March 2021  3 months ended 31 March 2020 
  ₦ million  ₦ million                $'000  $'000 
Royalties   10,793  10,400   28,404  32,002 
Depletion, depreciation and amortisation   11,748  9,021   30,915  27,758 
Crude handling fees   4,749  6,575   12,498  20,230 
Nigeria Export Supervision Scheme (NESS) fee   55  29   145  88 
Niger Delta Development Commission Levy   977  1,132   2,571  3,484 
Barging/Trucking   824   2,167 
Operational & maintenance expenses   8,725   4,494   22,959   13,826 
   37,871   31,651   99,659   97,387 

Operational & maintenance expenses mainly relates to maintenance costs, warehouse operations expenses, gas flare penalty fees, security expenses, community expenses, clean-up costs, fuel supplies and catering services.

9.   Other income/(losses)

  3 months ended 31 March 2021  3 months ended 31 March 2020  3 months ended 31 March 2021  3 months ended 31 March 2020 
  ₦ million  ₦'million                $'000  $'000 
Underlift/(Overlift)   3,115   15,217   8,198   46,823 
Gains/(loss) on foreign exchange              114   425   301   1,308 
Others   25   66  10 
Tariffs   2,527   6,649 
   5,781  15,646   15,214  48,141 

Overlifts are excess crude lifted above the share of production. It may exist when the crude oil lifted by the Group during the period is above its ownership share of production. Overlifts are initially measured at the market price of oil at the date of lifting and recognised as other expenses. At each reporting period, overlifts are remeasured at the current market value. The resulting change, as a result of the remeasurement, is also recognised in profit or loss.

Underlifts are shortfalls of crude lifted below the share of production. It may exist when the crude oil lifted by the Group during the period is less than its 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.

Gains on foreign exchange are principally as a result of translation of naira denominated monetary assets and liabilities.

Tariffs which is a form of crude handling fee, relate to income generated from the use of the Group's pipeline.

10. General and administrative expenses      

  3 months ended 31 March 2021  3 months ended 31 March 2020  3 months ended 31 March 2021  3 months ended 31 March 2020 
  ₦ million  ₦'million                $'000  $'000 
Depreciation and amortisation   532  492   1,404  1,517 
Depreciation of right-of-use assets   315  186   830  572 
Professional and consulting fees   1,082   1,389   2,848   4,275 
Directors' emoluments (executive)   263   824   692   2,534 
Directors' emoluments (non-executive)   548   320   1,441   984 
Employee benefits   3,975  4,301   10,467  13,234 
Flights and other travel costs   198   266   522   817 
Rentals       6   45   16   140 
Other general expenses   -      2,573   -      7,920 
   6,919   10,396   18,220   31,994 

Directors' emoluments have been split between executive and non-executive directors. Included in executive directors' emoluments are one-off termination payments of $2.3m made to the directors of Eland in respect of the acquisition of Eland in 2020. Included in the non-executive directors' emoluments are amounts paid to four new non-executive directors. Other general expenses relate to costs such as office maintenance costs, telecommunication costs, logistics costs and others.

11. Impairment (loss)/reversal

  3 months ended 31 March 2021  3 months ended 31 March 2020  3 months ended 31 March 2021  3 months ended 31 March 2020 
  ₦ million  ₦ million  $'000  $'000 
Impairment (loss)/reversal on financial assets  (269)  187  (707)  575 
Impairment loss on non-financial assets  (47,457)  (146,028) 
  (269)  (47,270)         (707)         (145,453) 

Impairment reversal on financial assets relates to the reversal of previously recognised impairment losses on other receivables.

12. Fair value gain/(loss)

  3 months ended 31 March 2021  3 months ended 31 March 2020  3 months ended 31 March 2021  3 months ended 31 March 2020 
  ₦ million  ₦ million  $'000  $'000 
Realised fair value gain/(loss) on derivatives   (562)  6,226   (1,480)  19,158 
Unrealised fair value loss on derivatives   (1,214)   (3,196) 
   (1,776)  6,226   (4,676)             19,158 

Fair value loss on derivatives represents changes arising from the valuation of the crude oil economic hedge contracts charged to profit or loss.

13. Finance income/(cost)

  3 months ended 31 March 2021  3 months ended 31 March 2020  3 months ended 31 March 2021  3 months ended 31 March 2020 
  ₦ million  ₦ million  $'000  $'000 
Finance income         
Interest income   347   1,067 
Finance cost         
Interest on bank loans   (6,222)   (6,584)   (16,373)   (20,259) 
Interest on lease liabilities   (57)   (123)   (149)   (379) 
Unwinding of discount on provision for decommissioning   (112)   (236)   (295)   (726) 
   (6,391)   (6,943)   (16,817)   (21,364) 
Finance (cost) - net   (6,388)   (6,596)   (16,810)   (20,297) 

Finance income represents interest on short-term fixed deposits.

14. 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 rate used for the period to 31 March 2021 is 85% for crude oil activities and 30% for gas activities. As at 31 December 2020, the applicable tax rate was 85%, 65.75% and 30% respectively.

The effective tax rate for the period was 11.25% (2020: 101.5%)

The major components of income tax expense in the interim condensed consolidated statement

  3 months ended 31 March 2021  3 months ended 31 March 2020  3 months ended 31 March 2021  3 months ended 31 March 2020 
  ₦ million  ₦ million  $'000  $'000 
Current tax:         
Current tax expense on profit for the period   (2,565)   (219)   (6,750)   (674) 
Education tax   (456)  (35)   (1,199)   (108) 
Total current tax   (3,021)   (254)   (7,949)   (782) 
Deferred tax:         
Deferred tax income/(expense) in profit or loss   1,823   (3,262)   4,797   (10,037) 
Total tax expense in statement of profit   (1,198)   (3,516)   (3,152)   (10,819) 

14.1  Deferred tax

The analysis of deferred tax assets and deferred tax liabilities is as follows:

  As at
31 March 2021 
As at
31 Dec 2020 
As at
31 March 2021 
As at
31 Dec 2020 
  ₦'million  ₦'million  $'000  $'000 
Deferred tax assets         
Deferred tax asset to be recovered in less than 12 months  9,437    9,437    33,151    33,151   
Deferred tax asset to be recovered after more than 12 months   280,440   280,440  729,682  729,682 
  289,877  289,877  762,833  762,833 
  As at
31 March 2021 
As at
31 Dec 2020 
As at
31 March 2021 
As at
31 Dec 2020 
  ₦'million  ₦'million  $'000  $'000 
Deferred tax liabilities         
Deferred tax liabilities to be settled in less than 12 months  (459)  (2,282)  (2,659)    (7,456) 
Deferred tax liabilities to be settled after more than 12 months  (199,738)  (199,738)  (524,176)  (524,176) 
  (200,197)  (202,020)  (526,835)  (531,632) 
         
Net deferred tax asset   89,680  87,857   235,998  231,201 

15. Trade and other receivables

      31 March 2021  31 Dec 2020      31 March 2021  31 Dec 2020 
  ₦ million  ₦ million  $'000  $'000 
Trade receivables   33,971   20,662   89,394   54,375 
Nigerian Petroleum Development Company (NPDC) receivables   36,932  40,681   97,191  107,053 
National Petroleum Investment Management Services (NAPIMS) receivables   11,885   11,353   31,276  29,876 
Underlift   10,473  7,827   27,561  20,600 
Advances to suppliers   7,115  10,280   18,724  27,053 
Receivables from ANOH   5,269   4,926   13,865  12,963 
Other receivables   2,504  1,045   6,589  2,751 
Total   108,149  96,774   284,600  254,671 

15.1  Trade receivables

Included in trade receivables is an amount due from Geregu Power ₦8.7 billion, $23.1 million (Dec 2020: ₦8.6 billion, $22.9 million), Sapele Power ₦3 billion, $7.9 million (Dec 2020: ₦2.7 billion, $7 million) and Nigerian Gas Marketing Company (NGMC) ₦3.7 billion, $9.8 million (Dec 2020: ₦1.3 billion, $3.4 million) totalling ₦15.4 billion, $40.9 million (Dec 2020: ₦13.6 billion, $33.3 million) with respect to the sale of gas. Also included in trade receivables is an amount of ₦12.9 billion (Dec 2020: ₦0) $34.2 million (Dec 2020: $0) and ₦1 billion (Dec 2020: ₦7 billion) $2.6 million (Dec 2020: $19 million) million due from Mercuria and Shell Western for sale of crude respectively.

15.2  NPDC receivables

The outstanding cash calls due to Seplat from its JOA partner, NPDC is ₦36.9 billion (Dec 2020: ₦44 billion) $97.1 million (Dec 2020: $107 million).

15.3  Other receivables

Other receivables are amounts outside the usual operating activities of the Group.

16. Contract assets

  31 March 2021  31 Dec 2020  31 March 2021  31 Dec 2020 
  ₦'million  ₦'million  $'000  $'000 
Revenue on gas sales   3,270   2,343   8,605    6,167 
Impairment on contract assets   (7)   -      (19)   -    
   3,263   2,343   8,586   6,167 

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

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

16.1  Reconciliation of contract assets

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

    31 March 2021  31 Dec 2020    31 March 2021  31 Dec 2020 
  ₦'million  ₦'million  $'000  $'000 
Balance as at 1 January   2,343   6,527   6,167   21,259 
Addition during the period   3,279   29,200   8,628   91,115 
Receipts for the period   (2,352)   (32,895)   (6,167)   (106,161) 
Price Adjustments   -      (13)   (23)   (46) 
Impairment   (7)   -      (19)   -    
Exchange difference   (476) 
Balance as at 31 December   3,263   2,343   8,586   6,167 

17. Derivative financial instruments

The Group uses its derivatives for economic hedging purposes and not as speculative investments. However, where derivatives do not meet the hedge accounting criteria, they are accounted for at fair value through profit or loss. They are presented as current liabilities.

The fair value of the derivative financial instrument as at 31 March 2021 is as a result of a fair value gain on crude oil hedges. The fair value has been determined using a proprietary pricing model which generates results from inputs. The market inputs to the model are derived from observable sources. Other inputs are unobservable but are estimated based on the market inputs or by using other pricing models.

    31 March 2021  31 Dec 2020  31 March 2021  31 Dec 2020 
  ₦'million  ₦'million  $'000  $'000 
Foreign currency options-crude oil hedges  (1,841)  (626)  (4,844)  (1,648) 
  (1,841)  (626)  (4,844)  (1,648) 

18. Cash and bank balances

Cash and bank balances in the statement of financial position comprise of cash at bank and on hand, short-term deposits with a maturity of three months or less and restricted cash balances.

    31 March 2021  31 Dec 2020  31 March 2021  31 Dec 2020 
  ₦'million  ₦'million  $'000  $'000 
Cash on hand   2,464  2,620   6,484  6,896 
Short-term fixed deposits   66  160   175  422 
Cash at bank   66,626  82,867   175,328  218,065 
Gross cash and cash equivalent   69,156  85,647   181,987  225,383 
Loss allowance   (93)   (93)   (246)   (246) 
Net cash and cash equivalents per cash flow statement   69,063  85,554   181,741  225,137 
Restricted cash   20,716  12,761   54,516  33,581 
Cash and bank balance   89,779  98,315   236,257  258,718 

Included in restricted cash, is a balance of ₦5.1 billion ($13.5 million) set aside in the Stamping Reserve account for the revolving credit facility (RCF). The amount is to be used for the settlement of all fees and costs payable for the purposes of stamping and registering the Security Documents at the stamp duties office and at the Corporate Affairs Commission (CAC). The amounts are restricted for a period of three (3) years, which is the contractual period of the RCF. These amounts are subject to legal restrictions and are therefore not available for general use by the Group. These amounts have therefore been excluded from cash and bank balances for the purposes of cash flow.

An additional ₦7.9 billion ($20.8 million) of funds deposited in Access bank Plc bank accounts in the ordinary course of business are being unilaterally restricted by Access bank Plc in connection with the court case between Seplat Petroleum Development Company Plc and Access Bank Plc.

Also included in the restricted cash balance is a cash-backed guarantee of ₦7.6 billion ($20 million) set aside with Zenith Bank Plc to fulfil the requirement of an order of the Court of Appeal, to seek the release of any order relating to the case between Seplat Development Petroleum Company Plc and Access Bank Plc.

19. Share Capital

19.1  Authorised and issued share capital

    31 March 2021  31 Dec 2020  31 March 2021  31 Dec 2020 
  ₦'million  ₦'million  $'000  $'000 
Authorised ordinary share capital         
1,000,000,000 ordinary shares denominated in
Naira of 50 kobo per share 
500  500  3,335  3,335 
Issued and fully paid         
581,840,856 (2020: 581,840,856) issued shares
denominated in Naira of 50 kobo per share 
293  293  1,856  1,856 

The Group's issued and fully paid as at the reporting date consists of 581,840,856 ordinary shares (excluding the additional shares held in trust) of ₦0.50k each, all with voting rights. Fully paid ordinary shares carry one vote per share and the right to dividends. There were no restrictions on the Group's share capital.

19.2  Movement in share capital and other reserves

    Number of shares  Issued share capital  Share Premium  Share based payment reserve  Total 
    Shares  ₦'million  ₦'million  ₦'million  ₦'million 
Opening balance as at 1 January 2021    581,840,856   293  86,917  7,174   94,384 
Share based payments     -      -      544   544 
Vested shares     -      -      (760)   (760) 
Closing balance as at 31 March 2021    581,840,856   293  86,917  6,958   94,168 
    Number of shares  Issued share capital  Share Premium  Share based payment reserve  Total 
    Shares  $'000  $'000  $'000  $'000 
Opening balance as at 1 January 2021    581,840,856   1,855  511,723  27,592  541,170 
Share based payments     -      1,431   1,431 
Vested shares     -      (2,000)   (2,000) 
Closing balance as at 31 March 2021    581,840,856   1,855  511,723  27,023  540,601 

19.3  Employee share-based payment scheme

As at 31 March 2021, the Group had awarded 60,487,999 shares (Dec 2020: 60,487,999 shares) to certain employees and senior executives in line with its share-based incentive scheme. During the three months ended 31 March 2021, 1,809,857 shares were vested (Dec 2020: 6,519,258 shares).

20. Interest bearing loans and borrowings

20.1  Net debt reconciliation

Below is the net debt reconciliation on interest bearing loans and borrowings for 31 March 2021:

  Borrowings due within
1 year 
Borrowings due above
1 year 
 Total  Borrowings due within
1 year 
Borrowings due above
1 year 
 Total 
  ₦ million  ₦ million  ₦ million  $'000  $'000  $'000 
Balance as at 1 January 2021   35,518   229,880   265,398   93,468   604,947   698,415 
Addition   -      -      -      -      -      -    
Interest accrued   6,222   -      6,222   16,373   -      16,373 
Principal repayment   -      -      -      -      -      -    
Interest repayment   (7,746)   -      (7,746)   (20,384)   -      (20,384) 
Other financing charges   -      -      -      -      -      -    
Transfers   (12,726)   12,726   -      (33,489)   33,489   -    
Exchange differences   -      -      -      -      -      -    
Carrying amount as at 31 March 2021   21,268   242,606   263,874   55,968   638,436   694,404 


Below is the net debt reconciliation on interest bearing loans and borrowings for 31 December 2020:

  Borrowings due within
1 year 
Borrowings due above
1 year 
 Total  Borrowings due within
1 year 
Borrowings due above
1 year 
 Total 
  ₦ million  ₦ million  ₦ million  $'000  $'000  $'000 
Balance as at 1 January 2020   34,486   207,863   242,349   112,333   677,075   789,408 
Interest accrued   17,504   -      17,504  48,634   -     48,634 
Interest capitalized  5,449    5,449  15,140    15,140 
Principal repayment   (35,991)   -      (35,991)   (100,000)   -      (100,000) 
Interest repayment   (23,310)   -      (23,310)   (64,767)   -      (64,767) 
Proceeds from loan financing   -      3,599   3,599   -      10,000   10,000 
Transfers  29,559   (29,559)   -     82,128   (82,128)   -    
Exchange differences   7,821   47,977   55,798   -      -      -    
Carrying amount as at 31 December 2020  35,518   229,880  265,398  93,468  604,947  698,415 

$350 million Senior notes - March 2018

Interest bearing loans and borrowings include revolving loan facility and senior notes. In March 2018 the Group issued ₦107 billion, $350 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 were expected to mature in April 2023. The interest accrued at the reporting date is ₦3.3 billion ($8.7 million) using an effective interest rate of 9.85%. Transaction costs of ₦2.1 billion ($7 million) have been included in the amortised cost balance at the end of the reporting period. The amortised cost for the senior notes at the reporting period is ₦131.4 billion (December 2020: ₦134.3 billion) $345.8 million (December 2020: $353.8 million).

$350 million Revolving credit facility - December 2019

The Group's parent company on 20 December 2019 also entered into a four-year revolving loan agreement with interest payable semi-annually. There is a two-year moratorium on the principal which ends on 1 July 2021 but will be extended to 1 July 2022 if the Notes are not refinanced before then. The revolving loan has an initial contractual interest rate of 6% +Libor (7.9%) and a settlement date of 31 December 2023.

The interest rate of the facility is variable. The interest accrued at the reporting period is ₦1.6 billion ($4.3 million) using an effective interest rate of 6.92%. The interest paid was determined using 3-month LIBOR rate + 6 % on the last business day of the reporting period. The outstanding amount of this borrowing as the reporting period is ₦95.2 billion (Dec 2020: ₦94.2 billion) $250.7 million (Dec 2020: $250 million).

$125 million Reserved based lending (RBL) facility - December 2018

The Group through its subsidiary Westport on 28 November 2018 entered into a five-year loan agreement with interest payable semi-annually. The RBL facility has an initial contractual interest rate of 8% +Libor as at half year (8.30%) and a final maturity date of 29 November 2023.The RBL is secured against the Group's producing assets in OML 40 via the Group's shares in Elcrest, and by way of a debenture which creates a charge over certain assets of the Group, including its bank accounts.

The available facility is capped at the lower of the available commitments and the borrowing base. The current borrowing base is more than $100 million, with the available commitments at $100 million. The commitments are scheduled to reduce to $87.5 million on 31 March 2021. The first reduction in the commitments occurred on 31st December 2019 in line with the commitment reduction schedule contained within the Facility Agreement. This resulted in the available commitments reducing from N45 billion ($125.0 million) to N40.6 billion ($112.5 million), with a further reduction to N36.1 billion ($100.0 million) as at December 2020.

The RBL has a maturity of five years, the repayments of principal are due on a semi-annual basis so that the outstanding balance of the RBL will not exceed the lower of (a) the borrowing base amount and (b) the total commitments. Interest rate payable under the RBL is LIBOR plus 8%, so long as more than 50% of the available facility is drawn.

On 4th February 2020 Westport drew down a further ₦3.6 billion ($10 million) increasing the debt utilised under the RBL from ₦32.4 billion ($90 million) to ₦36.1 billion ($100 million).

The interest rate of the facility is variable. The interest accrued at the reporting period is ₦1.3 billion ($3.5 million) using an effective interest rate of 8.3%. The interest paid was determined using 6-month LIBOR rate + 8 % on the last business day of the reporting period.

On 17th March 2021, Westport signed an amendment and restatement agreement regarding the RBL. As part of the new agreement, the debt utilised and interest rate remain unchanged at ₦38 billion ($100 million) and 8% + LIBOR respectively, however, the maturity date was extended by either five years after the effective date of the loan (March 2026) or by the reserves tail date (expected to be March 2025). Due to the modification of the original agreement and based on the facts and circumstances, it was determined that the loan modifications were substantial. Therefore, the existing facility was derecognised, and a new liability was recognised, and the present value of the loan commitment was moved to long term liabilities (Borrowings due above 1 year). The outstanding amount of this borrowing as at the reporting period is ₦37 billion (Dec 2020: ₦37.4 billion) $97.9 million (Dec 2020: $98.6 million).

21. Trade and other payables

    31 March 2021  31 Dec 2020  31 March 2021  31 Dec 2020 
  ₦ million  ₦ million  $'000  $'000 
Trade payable   45,908  51,351   120,810  135,134 
Accruals and other payables   57,614  56,816   151,619  149,521 
NDDC levy   1,287  4,780   3,387  12,578 
Royalties payable   11,361   10,500   29,898   27,632 
Overlift   6,550  7,021   17,238  18,475 
   122,720  130,468   322,952  343,340 

Included in accruals and other payables are field accruals of ₦22.6 billion (Dec 2020: ₦41 billion) $59.4 million (Dec 2020: $109 million), and other vendor payables of ₦5.3 billion (Dec 2020: ₦19 billion) $14.1 million (Dec 2020: $49 million). Royalties payable include accruals in respect of crude oil and gas production for which payment is outstanding at the end of the period.

22. Contract liabilities

    31 March 2021  31 Dec 2020  31 March 2021  31 Dec 2020 
  ₦ million  ₦ million  $'000  $'000 
  3,599  3,599  9,470  9,470 

22.1  Reconciliation of contract liabilities

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

    31 March 2021  31 Dec 2020  31 March 2021  31 Dec 2020 
  ₦ million  ₦ million  $'000  $'000 
Opening balance  3,599  5,005  9,470  16,301 
Recognised as revenue during the year  (1,406)  (6,831) 
  3,599  3,599  9,470  9,470 

Contract liabilities represents take or pay volumes contracted with Azura for 2019 which is yet to be utilized. In line with contract, Azura can make a demand on the makeup gas but only after they have taken and paid for the take or pay quantity for the respective year. The contract liability is accrued for two years after which the ability to take the makeup gas expires and any outstanding balances are recognised as revenue from contracts with customers.

23. Computation of cash generated from operations

    3 months ended  3 months ended  3 months ended  3 months ended 
    31-Mar-21  31-Mar-20  31-Mar-21  31-Mar-20 
    ₦ million  ₦ million  $'000  $'000 
Profit/(Loss) before tax    10,647   (31,111)  28,008   (95,732) 
Adjusted for:           
Depletion, depreciation and amortization     12,281  9,513   32,319  29,275 
Depreciation of right-of-use asset     315  186   830  572 
Impairment losses/(reversal) on financial assets     269  (187)   707  (575) 
Interest income     (3)  (347)   (7)  (1,067) 
Interest expense on bank loans     6,222  6,584   16,373  20,259 
Interest on lease liabilities     57  123   149  379 
Unwinding of discount on provision for decommissioning     112  236   295  726 
Unrealised fair value (gain)/loss on derivatives     1,214  (6,226)   3,196  (18,673) 
Realised fair value gain     562     1,480   
Unrealised foreign exchange loss/(gain)       (114)  2,944   (301)  (525) 
Impairment loss on non-financial assets     -     47,457    146,028 
Share based payment expenses     544  636  1431  1,957 
Share of profit in joint venture     (159)  (522)   (418)  (1,607) 
Defined benefit expenses     -      
Changes in working capital:     -          
Trade and other receivables      (11,966)  24,980    (31,489)  69,196 
Prepayments     (1,148)  (945)   (3,022)  (2,617) 
Contract assets     (919)  6,335   (2,419)  17,549 
Trade and other payables      (7,647)  (34,525)    (20,124)  (95,637) 
Contract liabilities     -     (3,743)   -     (10,369) 
Restricted Cash     (7,955)  (3)   (20,935)  (7) 
Inventories     (307)  1,941   (807)  5,376 
Net cash inflow from operating activities     2,005  23,326   5,266  64,508 

24. Earnings per share (EPS)

Basic

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

Diluted

Diluted EPS is calculated by dividing the profit after taxation attributable to the parent entity by the weighted average number of ordinary shares outstanding during the year plus all the dilutive potential ordinary shares (arising from outstanding share awards in the share-based payment scheme) into ordinary shares.

  31 March 2021  31 Dec 2020  31 March 2021  31 Dec 2020 
  ₦ million  ₦ million  $'000  $'000 
(Loss)/profit attributable to Equity holders of the parent   13,550   (34,627)   35,647   (106,551) 
(Loss)/profit attributable to Non-controlling interests   (4,101)   -      (10,791)   -    
(Loss)/profit for the year   9,449   (34,627)   24,856   (106,551) 
  Shares '000  Shares '000  Shares '000  Shares '000 
Weighted average number of ordinary shares in issue   581,841  579,638   581,841  579,638 
Outstanding share-based payments (shares)   6,604  8,807   6,604  8,807 
Weighted average number of ordinary shares adjusted for the effect of dilution   588,445  588,445   588,445  588,445 
Basic (loss)/earnings per shares  ₦  ₦ 
Total basic (loss)/earnings per share attributable to the ordinary equity holders of the Group  23.29   (46.42)  0.06   (0.13) 
Diluted (loss)/earnings per shares  ₦  ₦ 
Total diluted (loss)/earnings per share attributable to the ordinary equity holders of the Group  23.03   (45.72)  0.06   (0.13) 

The weighted average number of issued shares was calculated as a proportion of the number of months in which they were in issue during the reporting period.

25. Proposed dividend

The Group's directors propose an interim dividend of 2.5 cents per share for the reporting period (2020: Nil).

26. Related party relationships and transactions

The Group is controlled by Seplat Petroleum Development Company Plc (the parent Company). The parent Company is owned 6.43% either directly or by entities controlled by A.B.C Orjiako (SPDCL(BVI)) and members of his family and 12.19% either directly or by entities controlled by Austin Avuru (Professional Support Limited and Platform Petroleum Limited). The remaining shares in the parent Company are widely held.

The goods and services provided by the related parties are disclosed below. The outstanding balances payable to/receivable from related parties are unsecured and are payable/receivable in cash.

x.   Shareholders of the parent company

Shebah Petroleum Development Company Limited SPDCL ('BVI'): The Chairman of Seplat is a director and shareholder of SPDCL (BVI). The company provided consulting services to Seplat. Services provided to the Group during the period amounted to ₦77.3 million (2020: ₦408 million) $203.7 thousand (2020: $1.255 million).

xi.  Entities controlled by key management personnel (Contracts>$1million in 2021)

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. Transactions with this related party amounted to nil (2020: ₦1.249 billion, $3.843 million). Payables amounted to nil in the current period (payables in 2020: ₦775million, $2.1 million).

xii. Entities controlled by key management personnel (Contracts<$1million in 2021)

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. This amounted to ₦30.4 million, $80 thousand during the period (2020: ₦20 million, $63 thousand).

Stage leasing (Ndosumili Ventures Limited): is a subsidiary of Platform Petroleum Limited. The company provides transportation services to Seplat. This amounted to ₦99.6 million, $262 thousand (2020: ₦111 million, $343 thousand). Receivables and payables were nil in the current period.

27. Commitments and contingencies

27.1  Contingent liabilities

The Company is involved in a number of legal suits as defendant. The estimated value of the contingent liabilities is ₦152 million, $0.4 million (Dec 2020: ₦23.2 million, $0.61 million). The contingent liability for the year 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 Company's solicitors are of the opinion that the Company will suffer no loss from these claims.

28. Events after the reporting period

During the period, the Group offered 7.75% senior notes with an aggregate principal of $650 million (₦247 billion) due in April 2026. The notes, which were priced on 25 March and closed on 1 April 2021, were issued by the Group in March 2021 and guaranteed by certain of its subsidiaries. The gross proceeds of the Notes were used to redeem the existing $350 million 9.25% senior notes due in 2023, to repay in full drawings of $250 million under the existing $350 million revolving credit facility for general corporate purposes, and to pay transaction fees and expenses.

29. Exchange rates used in translating the accounts to Naira

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

    Basis  31 March 2021  31 March 2020  31 Dec 2020 
    ₦/$  ₦/$  ₦/$ 
Fixed assets - opening balances  Historical rate   Historical   Historical  Historical 
Fixed assets - additions  Average rate  380.00  324.98  359.91 
Fixed assets - closing balances  Closing rate  380.00  361.00  380 
Current assets  Closing rate  380.00  361.00  380 
Current liabilities  Closing rate  380.00  361.00  380 
Equity  Historical rate  Historical  Historical  Historical 
Income and Expenses:  Overall Average rate  380.00  324.98  359.91 
Source: EvaluateEnergy® ©2021 EvaluateEnergy Ltd