Q1 2022 Results

RNS Number : 6155J
Seplat Energy PLC
28 April 2022
 

Seplat Energy
Unaudited results for the three months ended 31 March 2022

Lagos and London, 28 April 2022: Seplat Energy Plc ("Seplat Energy" or "the Company"), a leading Nigerian independent energy company listed on both the Nigerian Exchange Limited and the London Stock Exchange, announces its unaudited results for the three months ended 31 March 2022.

Operational highlights

Strong safety record extended to 26.1 million hours without LTI from Seplat Energy operated assets
(2.0m hours in Q1 2022)

Working interest production averaged 47,603 boepd (liquids 29,079 bopd, gas 18,524 boepd) 

Full-year guidance remains unchanged at 50-60 kboepd

Amukpe-Escravos Pipeline mechanically completed, all commercial terms have been agreed and are moving through counterparty approval processes for signature. Expected to be fully operational by end of Q2 2022.

Sibiri exploration well drilled and successful, data analysis underway, working with partner to secure regulatory approval for Extended Well Test

Decision to exit Ubima to focus on more profitable assets; agreement reached to sell Seplat Energy's share to its JV partner for $55 million.  2P reserves reduce by 2 MMboe from 457mmboe to 455 MMboe.

Financial highlights  

Revenues up 58.6% to $241.8 million 

EBITDA up 81.6% to $147.4 million (adjusted for non-cash items)

Strong cash generation of $178.7 million, capex of $25.7 million 

Strong balance sheet with $312.2 million cash at bank, net debt of $442.6 million 

Q1 interim dividend of US2.5 cents per share 

Update on proposed acquisition of Mobil Producing Nigeria Unlimited

Sales & Purchase Agreement signed on 25 February to acquire Exxon's shallow water operations in Nigeria, Mobil Producing Unlimited, Nigeria (MPNU)

Acquisition remains on track and awaiting necessary approvals, expected to complete in H2 2022

 

Roger Brown, Chief Executive Officer, said:

"Seplat Energy delivered a good quarter that benefited from higher oil pricing, which offset lower production owing to continuing problems with the Trans Forcados Pipeline. However, the alternative Amukpe-Escravos Pipeline is mechanically complete and once we have signed the commercial agreements, we expect Chevron to be lifting our oil through the Escravos Terminal in the third quarter. 

Our proposed acquisition of MPNU remains on course. We are awaiting the necessary approvals from government and regulators and expect the transaction to complete in the second half of this year. The effective date of 1 January 2021 means we will benefit from higher recent oil prices and as we have previously reported, the addition of MPNU will nearly treble our production and double our reserves on a pro forma 2020 basis. The acquisition will reinforce our leadership of Nigeria's indigenous energy sector and enabling us to generate strong future cash flows that will underpin our investment in Nigeria's energy transition and improve our overall stakeholder returns. It will also bring a significant undeveloped gas resource base which, alongside our ANOH gas project development, will underpin Nigeria's energy transition and drive domestic and export revenues when developed.

We announce the decision to divest the Group's interest in the Ubima marginal field for a consideration of $55million, which marginally reduces the company's 2P reserves by 2 MMboe to 455 MMboe. 

We have proven we have the financial strength and credibility to attract international finance into Nigeria's energy sector and this will help us in our aim to deliver energy transition and provide cleaner, more reliable and more affordable energy for Nigeria's young and growing population." 

 

Summary of performance

 

$ million

 

billion

 

3M 2022

3M 2021

% change

3M 2022

3M 2021

Revenue

241.8

152.448

58.6%

100.6

57.9

Gross profit

117.3

52.8

122.3%

48.8

20.1

EBITDA *

147.4

81.2

81.6%

61.3

30.8

Operating profit (loss)

102.1

44.4

130.0%

42.5

16.9

Profit (loss) before tax

83.4

28.0

197.8%

34.7

10.6

Cash generated from operations

178.7

4.4

3,961%

74.4

1.7

Working interest production (boepd)

47,603

48,239

(1.3%)

 

 

Average realised oil price ($/bbl)

$97.53

$60.76

60.5%

 

 

Average realised gas price ($/Mscf)

$2.76

$2.76

0%

 

 

        

* Adjusted for non-cash items

 

Responsibility for publication

This announcement has been authorised for publication on behalf of Seplat Energy by Emeka Onwuka, Chief Financial Officer, Seplat Energy Plc.

 

Signed:

 

Emeka Onwuka

Chief Financial Officer 

 

Important notice

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

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

 

 

 

Enquiries:

Seplat Energy Plc

 

Emeka Onwuka, Chief Financial Officer

+234 1 277 0400

Carl Franklin, Head of Investor Relations

 

Ayeesha Aliyu, Investor Relations

 

Chioma Nwachuku, Director External Affairs & Sustainability

 

 

 

FTI Consulting

 

Ben Brewerton / Christopher Laing

+44 203 727 1000

seplatenergy@fticonsulting.com

 

 

Citigroup Global Markets Limited

 

Tom Reid / Luke Spells

+44 207 986 4000

 

 

Investec Bank plc

 

Chris Sim / Charles Craven / Jarrett Silver

+44 207 597 4000

 

Notes to editors

Seplat Energy Plc is Nigeria's leading indigenous energy company. It is listed on the Nigerian Exchange Limited (NGX: SEPLAT) and the Main Market of the London Stock Exchange (LSE: SEPL).

Seplat Energy is pursuing a Nigeria-focused growth strategy through participation in asset divestments by international oil companies, farm-in opportunities, and future licensing rounds. The Company is a leading supplier of gas to the domestic power generation market. For further information please refer to the Company website, http://seplatenergy.com/

 

 

Operating review

HSE performance

Safe and responsible operations are critical to the delivery of Seplat Energy's strategy. Staff and contractors worked a total of 2.0 million man-hours with no fatalities, lost-time injuries, or major injuries in the period.

The Company has now achieved more than 26 million man-hours without LTI on its operated assets. There were 20 HSE incidents in total, compared to 22 incidents in the first three months of 2021, including one reportable spill and two gas leaks, all of which were remediated with limited environmental impact.The Group established appropriate processes and safeguards for its people and operations against Covid-19.

By the end of March 2022, we had conducted nearly 18,000 Covid-19 tests since the start of the pandemic, with a positivity rate of 2.8%. We have a vaccination policy for Covid-19 management and continue to enforce all Covid-19 control protocols at our field operations and offices, with no major Covid-19 related incidents.

Working interest production for the three months ended 31 March 2022

 

 

 3M 2022

 

3M 2021

Liquids(1)

Gas

Total

 

Liquids

Gas

Total

 

Seplat %

bopd

MMscfd

boepd

 

bopd

MMscfd

boepd

OMLs 4, 38 & 41

45%

17,655

107.4

36,180

 

19,842

114

39,540

OML 40

45%

7,420

-

7,420

 

3,615

-

3,615

OML 53

40%

2,712

-

2,712

 

3,570

-

3.570

OPL 283

40%

1,291

-

1,291

 

1,178

-

1,178

Ubima

82%

-

-

-

 

337

-

337

Total

 

29,078

107.4

47,603

 

28,541

114

48,239

          

Liquid production volumes as measured at the LACT unit for OMLs 4, 38 and 41; OML 40 and OPL 283 flow station.
Volumes stated are subject to reconciliation and may differ from sales volumes within the period.

Working interest production for 3M 2022 averaged 47,603 boepd, (3M 2021: 48,239),with an oil and gas mix of 61% and 39% respectively. Within this, liquids production was up 1.9% year-on-year, to 29,078 bopd, with significantly higher volumes from OML 40 slightly offsetting lower volumes from OML 4, 38 and 41 due to further outages in the Trans Forcados System, which experienced higher than planned downtime of 18% in the first three months of this year. The impact of future FOT outages on production from OMLs 4, 38 and 41 will be alleviated by our use of the long-delayed Amukpe-Escravos Pipeline, which, having been completed mechanically, awaits finalisation of commercial agreements. We expect to be using the AEP in the third quarter.

Despite 23% downtime as a result of outages on the TEP and the TFP, produced volumes from OML 40 were higher than Q1 2021, as the four Gbetiokun wells drilled in the previous year came onstream. We expect to sustain higher production throughout the year.

Gas volumes were down 6.1% year-on-year to 107.4 impacted by lower gas offtake due to price renegotiation and issues with the hot oil burner at Obenthat affected production. Price discussions with customers have been concluded and a new Burner-C was installed and commissioned late February, and gas production volumes have subsequently improved in March. 

We have not reported any production for Ubima in Q1 2022 as the Seplat Energy Board approved an exit from the Ubima asset in April 2022. The Ubima asset, operated by All Grace Energy Limited (AGEL) was acquired in 2019 as part of the Eland acquisition. A settlement agreement of $55 million has been agreed with AGEL and we expect to receive payments in due course.

Ubima is in a high operating cost environment, with major evacuation challenges currently being experienced in the Niger Delta. Because substantial capital expenditure would be required to create more secure evacuation routes, the decision to exit will enable us to invest in other parts of our business that generate higher returns. Current reserves in Ubima stand at approximately 2 MMbbls and necessary adjustments to the financial statements will be made in the second quarter and reported in the 6M 2022 results.

 

Drilling activities

During the period, we spudded two wells (Amukpe and Sibiri) and completed a Gbetiokun well that was spudded in 2021. 

In OML 38, the Amukpe-05 drilling commenced and is expected to be completed by the end of April 2022. In OML 53, we spudded the Owu appraisal well in early April and drilling operations are progressing.

Project activities associated with preparation for drilling the high-impact, near-field Sibiri (formerly Amobe) exploration well in OML 40 were completed in 2021 and the well was drilled in Q1 2022. The well has been drilled to TD, with initial indications it has encountered eight oil-bearing reservoirs with 353 ft of gross hydrocarbon pay, net pay of 229 ft. Further data acquisition and analysis on the well is underway. We are working with our partners to secure regulatory approval to carryout extended well testing (EWT), to confirm producibility, among other parameters critical to full field development.

The Gbetiokun-09 well, drilled late 2021 came onstream in the first quarter and is producing c.3.5 kbopd from both long and short strings, taking the Gbetiokun field to a production rate of c.21 kbopd IPSC. For the three-infill development wells campaign, the first Opuama well (OP-12) was spudded in April 2022 with drilling progressing according to planwith on stream date estimated to be late May 2022. 

Oil business performance

Seplat Energy's liquids (oil and condensate) operations produced 2.6 MMbbls on a working interest basis in 3M 2022
(3M 2021: 2.6 MMbbls). The average realised price per barrel in the period was $97.53 (3M 2021: $60.76), the increase being mostly attributable to the impact of the Ukraine conflict on global energy prices.

Amukpe-Escravos Pipeline commissioning

Following the introduction of hydrocarbons into the pipeline in December 2021 as part of the start-up and testing process, mechanical completion has now been achieved. Commercial terms have been agreed and are moving through counterparty approval processes for signature. Once we have signed the commercial agreements, we expect Chevron to be lifting our oil through the Escravos Terminal in the third quarter.   

Gas business performance

Working interest gas volumes for the period was 107.4 MMscfd at an average selling price of $2.76/Mscf (3M 2021: 114 MMscfd, $2.76/Mscf). The Gas business contributed 38.9% of the Group's volumes on a boepd basis and 10.6% of Group revenues. During the period we signed GSAs with three new customers, two of which commenced offtake at a combined rate of 66 MMscfd in January and March.

ANOH Gas Processing Plant

We have made progress on the ANOH plant but have seen some delays in shipments and releasing equipment essential to the project from the ports. To date, we have achieved 85% overall project completion at the gas plant site. Our government partner, the Nigerian Gas Company, (NGC) is delivering the pipelines that will take the gas from ANOH to Oben, namely the 23km spur line and the Obiafu-Obrikom-Oben (OB3) pipeline. 

The OB3 pipeline project has seen a number of failed attempts to complete the 1.85km river crossing, which is needed to complete the pipeline. However, the latest contractor is making progress and the HDD drilling stands at around 25% complete.  We do not anticipate the OB3 pipeline to delay the completion of the overall ANOH project.

The Spur Line project has seen significant delays due to contracting issues and payments. We have been informed that the milling of the line pipes, which is being undertaken in China, will now commence in Q2 and therefore will not arrive in Nigeria until later this year. The latest schedule provided by NGC shows completion in Q1 2023.

We had earlier communicated a first gas date by mid-year 2022, but based on our current risking, we now expect further delays of between 9-12 months to the original timeline, with the spur line expected to be the last piece of infrastructure delivered.  The upstream development, including the drilling of six production wells, will be delivered by the upstream unit operator SPDC. We expect that the two wells on which drilling commenced in 2021 will be completed this year.

Outlook and update on MPNU acquisition

The proposed acquisition of MPNU remains on track and necessary regulatory approvals are anticipated. We expect completion to occur in the second half of 2022 and MPNU will then operate as a standalone subsidiary of Seplat Energy. 

Full-year production guidance for 2022 remains at 50,000 to 60,000 boepd on a working interest basis, comprising 30,000 to 35,000 bopd liquids and 116 to 150 MMscfd (20,000 to 25,000 boepd) gas production. This guidance does not include any contribution from MPNU and the ANOH Gas Plant.

Capital expenditure for 2022 is expected to be around $160 million. We expect to drill a minimum of ten wells, including the Sibiri exploration well completed and the Owu appraisal well already spudded; we plan to complete ongoing projects, invest in maintenance capex to secure the existing assets, and continue investments in gas. The 2022 drilling programme is designed to address production decline and along with completion of maintenance activities, will support long-term production levels from the assets.

 

 

Financial review

Revenue and other income

Revenue from oil and gas sales in 3M 2022 was $241.8 million, a 58.6% increase from the $152.4 million achieved in 3M 2021. Adjusted for an underlift of $13.6 million, total revenues were $255.5 million.

Crude oil revenue was 74.2% higher at $216.2 million (3M 2021: $124.1 million), reflecting higher average realised oil prices of $97.53/bbl for the period (3M 2021: $60.76/bbl).The total volume of crude lifted in the year was 2.2 MMbbls, higher than the 2.1 MMbbls lifted in 3M 2021. In addition, the Group's 3M 2022 produced liquid volumes were subject to reconciliation losses of 10.2%. We expect these to improve when we evacuate the bulk of our crude through the Amukpe-Escravos underground pipeline. 

Gas sales revenue decreased by 9.7% to $25.6million (3M 2021: $28.4 million),due to lower gas sales volumes of 9.7 Bscf compared to 10.3 Bscf in 3M 2021, as a result of lower customer offtake, production stoppages at Oben in February and March, as well as TFP outages during the same months.

The average realised gas price was unchanged at $2.76/Mscf and this reflects the reduction applied to the DSO gas-to-power volumes from August 2021.

Other income of $8.9 million includes an underlift of $13.6 million (shortfalls of crude lifted below Seplat's share of production, which is priced at the date of lifting and recognised as other income) representing 214 kbbls, as well as a $0.4 million tariff income generated from the use of the Company's pipelines, offset by an unrealised $6.0 million loss on foreign exchange. 

Gross profit

Gross profit increased by 122.3% to $117.3 million (3M 2021: $52.8million). Non-production costs consisted primarily of $50.2 million royalties and DD&A of $33.8 million, compared to $28.4 million royalties and $30.9 million DD&A in the prior year. The higher royalties were the result of higher oil prices.

Direct operating costs, which include crude-handling fees and operation and maintenance costs, amounted to $37.4 million in 3M 2022 (3M 2021: $37.4 million). 

On a cost-per-barrel equivalent basis, production opex was $8.7/boe, in line with 3M 2021. 

Operating profit

The operating profit for the first quarter was $102.1 million, compared to $44.4 million in 3M 2021, an increase of 130%.

General and administrative expenses remained largely flat at $19.0 million (3M 2021: $18.2 million).

An EBITDA of $147.8 million adjusts for non-cash items which include impairment and exchange losses, equating to a margin of 60.9% for the year (3M 2021: $81.2 million; 53.2%).

Net result

The profit before tax was $83.4 million (3M 2021: $28.0 million). The income tax expense of $63.5 million includes a current tax charge of $17.9 million and deferred tax charge of $45.6 million. The deferred tax charge is mainly driven by the unwinding of previously unutilised capital allowances and higher under-lift in current year. The effective tax rate for the period was 76% (2021: 11%)

The profit for the period was $19.9 million (3M 2021: $24.9 million) with a resultant basic earnings per share of $0.03 in 3M 2022, compared to $0.06 per share in 3M 2021.

Cash flows from operating activities

Cash generated from operations in 3M 2022 was $180.9 million (3M 2021: $5.6 million).Net cash flows from operating activities were $178.7 million (3M 2021: $4.4 million), after accounting for tax payments of $0.4 million (3M 2021: $0.3 million) and a hedge premium of $1.8 million (3M 2021: $1.5 million).

In Q1 2022 the Group received $95.0 million from the JV partners towards the settlement of cash calls. The major JV receivable balance now stands at $51.0 million, down from $83.9 million at the end of 2021. 

Cash flows from investing activities

Net capital expenditure of $26.0 million included $16.0 million invested in drilling and $8.6 million in engineering projects.

An outflow of $128.3 million was recorded as deposit for the Company's proposed acquisition of Mobil Producing Nigeria Unlimited, announced in February. 

Cash flows from financing activities

Net cash outflows from financing activities were $30.6 million (3M 2021: $20.4 million), including $28.4 million interest paid on loans and $2.1 million commitment fee incurred on the $350 million revolving credit facility. 

Liquidity

The balance sheet continues to remain healthy with a solid liquidity position. 

Net debt reconciliation
at 31 March 2022

$ million

$ million drawn

Coupon

Maturity

Senior notes*

636.1

650.0

7.75%

April 2026

Westport RBL*

108.4

110.0

Libor+8%

March 2026

Off-take facility*

10.3

11.0

Libor+10.5%

April 2027

Total borrowings

754.8

771.0

 

 

Cash and cash equivalents (exclusive of restricted cash)

312.2

312.2

 

 

Net debt

442.6

 

 

 

* Including amortised interest

Seplat Energy ended the first quarter with gross debt of $754.8 million (with maturities in 2026 and 2027) and cash at bank of $312.2 million, leaving net debt at $442.6 million.

Dividend

The Board has approved the Q1 2022 interim dividend of US2.5 cents per share (subject to appropriate WHT) to be paid to shareholders whose names appear in the Register of Members as at the close of business on 30 May 2022.

Hedging

Seplat's hedging policy aims to guarantee appropriate levels of cash flow assurance in times of oil price weakness and volatility. For 2022, the Group has dated Brent put options of 6.0 MMbbls through Q3 2022 at an average premium of $1.42/bbl as follows: (i) for Q1, 1.0 MMbbls at a strike price of $50/bbl and 1.0 MMbbls at a strike price of $55/bbl; (ii) for Q2, 2.0 MMbbls at a strike price of $55/bbl; and (iii) for Q3, 1.0 MMbbls at a strike price of $55/bbl and 1.0mmbbls are protected at $60/bbl.Further barrels are expected to be hedged for 2022 in the coming months in line with the approach to target hedging two quarters in advance.

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.

Elimination of related-party transactions

In our continuous efforts to promote world-class governance, related-party transactions (RPT) were eliminated from
1 January 2022. 

Share dealing policy

We confirm that, to the best of our knowledge, there has been compliance with the Company's share dealing policy during the period.

Board appointments

On 22 April 2022, the Company announced the appointment of three new directors: Mrs. Bashirat Odunewu will join as an Independent Non-Executive Director of the Company; Mr. Kazeem Raimi will join as a Non-Executive Director and nominee of Platform Petroleum Limited replacing Mr. Austin Avuru, who stepped down from the Board of Seplat Energy on 1st March 2022; and Mr. Ernest Ebi will join as a Non-Executive Director and a nominee of Shebah Petroleum Development Company Limited (BVI), replacing Dr. A.B.C. Orjiako who will step down from the Board on 18th May 2022 after the Annual General Meeting. The three appointees will join the Seplat Energy Board with effect from 18 May 2022. 

The Board is pleased to welcome the new Directors and looks forward to the contributions they will make to the Group.

Interim Consolidated Financial Statements (Unaudited)
For the three months ended 31 March 2022
(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 2022

 

 

 

 

3 Months ended

31 March 2022

3 Months ended 31 March 2021

3 Months ended

31 March 2022

3 Months ended 31 March 2021

 

 

U naudited

Unaudited

U naudited

Unaudited

 

Notes

million

million

$'000

$'000

 

 

 

 

 

 

Revenue from contracts with customers

7

100,618

 57,930

241,837

 152,448

Cost of sales

8

(51,7 85 )

 (37,871)

(124,490)

 (99,659)

Gross profit

 

48,833

 20,059

117,347

 52,789

Other income

9

3 ,710

 5,781

8 ,916

 15,214

General and administrative expenses

10

( 7,913)

 (6,919)

( 19,018)

 (18,220)

Impairment loss on financial assets

11

(509)

 (269)

(1,223)

 (707)

Fair value loss

12

(1,639)

 (1,776)

(3,941)

 (4,676)

Operating profit

 

4 2,482

 16,876

1 02,081

 44,400

Finance income

13

13

 3

32

 7

Finance cost

13

(7,731)

 (6,391)

(18,582)

 (16,817)

Finance cost-net

 

(7,718)

 (6,388)

(18,550)

 (16,810)

Share of (loss)/profit from joint venture accounted for using the equity method

 

(52)

 159

(124)

 418

Profit before taxation

 

3 4,712

 10,647

8 3,407

 28,008

Income tax expense

14

( 26,422)

 (1,198)

( 63,505)

 (3,152)

Profit for the period

 

8 ,290

9,449

1 9,902

 24,856

Attributable to:

 

 

 

 

 

Equity holders of the parent

 

6 ,868

 13,550

16,484

 35,647

Non-controlling interests

 

1 ,422

 (4,101)

3,418

 (10,791)

 

 

8 ,290

 9,449

19,902

 24,856

Other comprehensive income:

 

 

 

 

 

Items that may be reclassified to profit or loss:

 

 

 

 

Foreign currency translation difference

 

7 ,374

-

-

 - 

Total comprehensive income for the period (net of tax)

 

1 5,664

 9,449

1 9,902

   24,856

 

Earnings per share attributable to the equity shareholders:

 

 

 

Basic earnings per share /$

26

11.76

 23.29

0.03

 0.06

Diluted earnings per share /$

26

11.70

 23.03

0.03

 0.06


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 2022

 

 

31 March 2022

31 December

2021

31 March 2022

31 December

 2021

 

 

Unaudited

Audited

Unaudited

Audited

 

Notes

million

million

$'000

$'000

Assets

 

 

 

 

 

Non-current assets

 

 

 

 

 

Oil & gas properties

15

665,025

660,745

1,597,662

1,604,025

Other property, plant and equipment

 

10,902

11,228

26,190

27,255

Right-of-use assets

 

2,685

3,050

6,450

7,404

Intangible assets

16

54,291

54,045

130,430

131,200

Other assets

 

46,849

46,363

112,551

112,551

Investment accounted for using equity accounting

17

93,722

92,795

225,158

225,270

Prepayments

 

27,814

27,512

66,820

66,788

Deferred tax asset

14. 1

433,485

428,986

1,041,406

1,041,406

Total non-current assets

 

1,334,773

1,324,724

3,206,667

3,215,899

Current assets

 

 

 

 

 

Inventories

 

30,884

30,878

74,196

74,957

Trade and other receivables

18

140,464

105,274

337,455

255,557

Prepayments

 

1,063

711

2,554

1,726

Contract assets

19

3,298

1,679

7,922

4,076

Cash and cash equivalents

21

129,973

133,667

312,242

324,490

Restricted cash

21.1

6,732

6,603

16,172

16,029

Total current assets

 

312,414

278,812

750,541

676,835

Total assets

 

1,647,187

1,603,536

3,957,208

3,892,734

Equity and Liabilities

 

 

 

 

 

Equity

 

 

 

 

 

Issued share capital

22

296

296

1,862

  1,862

Share premium

22

90,383

90,383

520,138

520,138

Share based payment reserve

2 2

5,454

4,914

23,487

22,190

Treasury shares

 

(2,027)

(2,025)

(4,920)

(4,915)

Capital contribution

 

5,932

5,932

40,000

40,000

Retained earnings

 

246,372

239,429

1,201,747

1,185,082

Foreign currency translation reserve

 

392,722

385,348

1,933

1,933

Non-controlling interest

 

(19,491)

(20,913)

(55,386)

(58,804)

Total shareholders' equity

 

719,641

703,364

1,728,861

1,707,486

Non-current liabilities

 

 

 

 

 

Interest bearing loans and borrowings

23

288,950

290,803

694,174

705,953

Lease Liabilities

 

607

198

1,459

481

Provision for decommissioning obligation

 

64,620

63,709

155,244

154,659

Deferred tax liabilities

14. 1

365,755

343,179

878,693

833,101

Defined benefit plan

 

4,900

4,181

11,772

10,149

Total non-current liabilities

 

724,832

702,070

1,741,342

1,704,343

Current liabilities

 

 

 

 

 

Interest bearing loans and borrowings

23

25,250

24,988

60,661

60,661

Lease Liabilities

 

871

1,273

2,092

3,090

Derivative financial instruments

20

1,848

1,543

4,439

3,745

Trade and other payables

24

148,162

151,204

355,949

367,058

Current tax liabilities

 

26,583

19,094

63,864

46,351

Total current liabilities

 

202,714

198,102

487,005

480,905

Total liabilities

 

927,546

900,172

2,228,347

2,185,248

Total shareholders' equity and liabilities

 

1,647,187

1,603,536

3,957,208

3,892,734

 

 

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

The Group financial statements of Seplat Energy Plc and its subsidiaries (The Group) for three months ended 31 March 2022 were authorised for issue in accordance with a resolution of the Directors on 28 April 2022 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

28 April 2022

28 April 2022

28 April 2022

 

 

 

 

Interim condensed consolidated statement of changes in equity

For the three months ended 31 March 2022

 

 

 

Issued
share
capital

Share
premium

Share
based payment

reserve

Treasury shares

Capital contribution

Retained

earnings

Foreign

currency

translation

reserve

 

 

Non- controlling interest

Total equity

 

million

million

million

million

million

million

million

million

million

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/(loss) 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

 

 

 

 

 

 

 

 

 

 

 

 

At 1 January 2022

296

90,383

4,914

(2,025)

5,932

239,429

385,348

(20,913)

703,364

Profit for the period

-

-

  -

-

-

6,868

-

1,422

8,290

Other comprehensive income

-

-

  -

-

-

-

7,374

-

7,374

Total comprehensive income for the period

-

-

  -

-

-

6,868

7,374

1,422

15,664

Transactions with owners in their capacity as owners:

 

 

 

 

 

 

 

 

 

Unclaimed dividend

-

  -

  -

-

-

75

-

-

75

Share based payments

-

-

540

-

-

-

-

-

540

Vested shares

 

-

-

-

-

-

-

-

-

Shares re-purchased

-

-

-

(2)

-

-

-

-

(2)

Total

-

-

540

(2)

-

75

-

-

613

At 31 March 2022 (unaudited)

296

90,383

 

  5,454

(2,027)

5,932

246,372

392,722

(19,491)

719,641

                     

 

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

Treasury shares

Capital contribution

Retained

earnings

Foreign

currency

translation

reserve

Non-controlling interest

Total

equity

 

$'000

$'000

$'000

$'000

$'000

$'000

$'000

$'000

$'000

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 income/(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

 

-

 

4 0,000

 1,151,846

 992

 (44,987)

 1,688,452

 

 

 

 

 

 

 

 

 

 

 

 

At 1 January 2022

 1,862

  520,138

22,190

(4,915)

 40,000

 1,185,082

1,933

(58,804)

1,707,486

Profit for the period

-

-

-

-

-

16,484

-

3,418

19,902

Other comprehensive income

-

-

-

-

-

-

-

-

-

Total comprehensive income for the period

-

-

-

-

-

16,484

-

3,418

19,902

Transactions with owners in their capacity as owners:

 

 

 

 

 

 

 

 

 

Unclaimed dividend

-

-

-

-

-

181

-

-

181

Share based payments

-

-

1,297

-

-

-

-

-

1,297

Vested shares

-

-

-

-

-

-

-

-

-

Shares re-purchased

-

-

-

(5)

-

-

-

-

(5)

Total

-

-

1,297

(5)

-

181

-

-

1,473

At 31 March 2022(Unaudited)

1,862

520,138

23,487

(4,920)

40,000

1,201,747

1,933

(55,386)

1,728,861

                     

 

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 2022

 

 

3 months ended

3 months ended

3 months ended

3 months ended

 

 

31-Mar-22

31-Mar-21

31-Mar-22

31-Mar-21

 

Note

₦ million

₦ million

$'000

$'000

Cash flows from operating activities

 

 

 

 

 

Cash generated from operations

25

75,280

2,127

180,906

 5,586

Hedge premium paid

 

(743)

(562)

(1,787)

 (1,480)

Income tax (paid)/credit

 

(166)

95

(400)

 251

Net cash inflows from operating activities

 

74,371

1,660

178,719

4,357

Cash flows from investing activities

 

 

 

 

 

Payment for acquisition of oil and gas properties

 

(10,721)

 (12,382)

(25,767)

 (32,585)

Deposit for investment

 

(53,405)

-

(128,300)

-

Payment for acquisition of other property, plant and equipment

 

(114)

 (17)

(273)

 (45)

Proceeds from disposal of other property, plant and equipment

 

2

-

4

-

Receipts from other assets

 

-

 1,861

-

 4,897

Interest received

 

13

 3

32

 7

Net cash outflows from investing activities

 

(64,225)

 (10,535)

(154,304)

 (27,726)

Cash flows from financing activities

 

 

 

 

 

Shares purchased for employees*

 

(2)

-

(5)

-

Interest paid on lease liability

 

(20)

-

(47)

-

Lease payment

 

(21)

 (2)

(51)

 (4)

Payments for other financing charges**

 

(874)

 - 

(2,100)

 - 

Interest paid on loans

 

(11,821)

 (7,746)

(28,412)

 (20,384)

Net cash outflows from financing activities

 

(12,738)

 (7,748)

(30,615)

 (20,388)

Net decrease in cash and cash equivalents

 

(2,592)

 (16,623)

(6,200)

 (43,757)

Cash and cash equivalents at beginning of the year

 

133,667

 85,554

324,490

 225,137

Effects of exchange rate changes on cash and cash equivalents

 

(1,102)

 225

(6,048)

 607

Cash and cash equivalents at end of the period

 

129,973

 69,156

312,242

 181,987

             

Included in the restricted cash balance is $8 million, 3.3 billion and $6.2 million, 2.6 billion set aside in the stamping reserve account and debt service reserve account respectively for the revolving credit facility. Also included in the restricted cash balance is $0.9 million, 0.4 billion and $1.1 million, 0.4 billion for rent deposit and unclaimed dividend respectively.

*Shares purchased for employees of $5,000, 2 million represent shares purchased in the open market for employees for the long-term incentive plan of the Group.

**Other financing charges include $2.1 million commitment fee incurred on the $350 million Revolving Credit Facility.  

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

 

 

Notes to the interim condensed consolidated financial statement

1.  Corporate Structure and business

Seplat Energy Plc (hereinafter referred to as 'Seplat' or the 'Company'), the parent of the Group, was incorporated on 17 June 2009 as a private limited liability company and re-registered as a public company on 3 October 2014, under the Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria 2004. The Company commenced operations on 1 August 2010. The Company is principally engaged in oil and gas exploration and production 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 $259.4 million.

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 Energy 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 Energy Plc 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. 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 Energy 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.

On 20 May 2021, following a special resolution by the Board in view of the Company's strategy of transitioning into an energy Company promoting renewable energy, sustainability, and new energy, the name of the Company was changed from Seplat Petroleum Development Company Plc to Seplat Energy Plc under Companies and Allied Matters Act 2020.

On 7 February 2022, the Group incorporated a subsidiary, Seplat Energy Offshore Limited. The Company was incorporated for oil and gas exploration and production.

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

99.9%

Oil & gas exploration
and production

Direct

Seplat Energy UK Limited

21 August 2014

United Kingdom

100%

Corporate, technical, liaison and administrative support services relating to oil & gas exploration and production

Direct

Seplat Gas Company Limited

12 December 2014

Nigeria

99.9%

Oil & gas exploration and production and gas processing

Direct

Seplat East Onshore Limited

12 December 2014

Nigeria

99.9%

Oil & gas exploration and production

Direct

Seplat East Swamp Company Limited

12 December 2014

Nigeria

99.9%

Oil & gas exploration and production

Direct

Seplat West Limited

16 January 2018

Nigeria

99.9%

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

Elandale Nigeria Limited

17 January 2019

Nigeria

40%

Receive, store, handle, transport, deliver $ discharge petroleum and petroleum products

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

Seplat Energy Offshore Limited

7 February 2022

Nigeria

100%

Oil and Gas exploration and production

Direct

MSP Energy Limited

27 March 2013

Nigeria

100%

Oil and Gas exploration and production 

Direct

 

2.  Significant changes in the current reporting period

The following significant changes occurred during the reporting period ended 31 March 2022:

· During the period, Seplat Energy Offshore Limited was incorporated on 7 February 2022. The percentage ownership of the Company is 100%.

· The Group made a deposit of $128.3 million to Exxon Mobil Corporation, Delaware as part of the consideration to acquire the entire share capital of Mobil Producing Nigeria Unlimited. The completion of the transaction is subject to ministerial consent and other required regulatory approvals.

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 Energy 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 2022 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 2021 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 Group applied for the first-time certain standards and amendments, which are effective for annual periods beginning on or after 1 January 2022. The Group has not early adopted any other standard, interpretation or amendment that has been issued but is not yet effective.

a)  Onerous Contracts - Costs of Fulfilling a Contract - Amendments to IAS 37

An onerous contract is a contract under which the unavoidable costs (i.e., the costs that the Group cannot avoid because it has the contract) of meeting the obligations under the contract exceed the economic benefits expected to be received under it.

The amendments specify that when assessing whether a contract is onerous or loss-making, an entity needs to include costs that relate directly to a contract to provide goods or services include both incremental costs (e.g., the costs of direct labour and materials) and an allocation of costs directly related to contract activities (e.g., depreciation of equipment used to fulfil the contract as well as costs of contract management and supervision). General and administrative costs do not relate directly to a contract and are excluded unless they are explicitly chargeable to the counterparty under the contract.

In accordance with the transitional provisions, the Group applies the amendments to contracts for which it has not yet fulfilled all its obligations at the beginning of the annual reporting period in which it first applies the amendments (the date of initial application) and has not restated its comparative information. 

b)  Reference to the Conceptual Framework - Amendments to IFRS 3 

The amendments replace a reference to a previous version of the IASB's Conceptual Framework with a reference to the current version issued in March 2018 without significantly changing its requirements. 

The amendments add an exception to the recognition principle of IFRS 3 Business Combinations to avoid the issue of potential 'day 2' gains or losses arising for liabilities and contingent liabilities that would be within the scope of IAS 37 Provisions, Contingent Liabilities and Contingent Assets or IFRIC 21 Levies, if incurred separately. The exception requires entities to apply the criteria in IAS 37 or IFRIC 21, respectively, instead of the Conceptual Framework, to determine whether a present obligation exists at the acquisition date. The amendments also add a new paragraph to IFRS 3 to clarify that contingent assets do not qualify for recognition at the acquisition date. 

These amendments had no impact on the interim condensed consolidated financial statements of the Group as there were no contingent assets, liabilities and contingent liabilities within the scope of these amendments arisen during the period. 

c)  Property, Plant and Equipment: Proceeds before Intended Use - Amendments to IAS 16 

The amendment prohibits entities from deducting from the cost of an item of property, plant and equipment, any proceeds of the sale of items produced while bringing that asset to the location and condition necessary for it to be capable of operating in the manner intended by management. Instead, an entity recognises the proceeds from selling such items, and the costs of producing those items, in profit or loss.

These amendments had no impact on the interim condensed consolidated financial statements of the Group as there were no sales of such items produced by property, plant and equipment made available for use on or after the beginning of the earliest period presented. 

d)  IFRS 1 First-time Adoption of International Financial Reporting Standards - Subsidiary as a first-time adopter 

The amendment permits a subsidiary that elects to apply paragraph D16(a) of IFRS 1 to measure cumulative translation differences using the amounts reported in the parent's consolidated financial statements, based on the parent's date of transition to IFRS, if no adjustments were made for consolidation procedures and for the effects of the business combination in which the parent acquired the subsidiary. This amendment is also applied to an associate or joint venture that elects to apply paragraph D16(a) of IFRS 1.

These amendments had no impact on the interim condensed consolidated financial statements of the Group as it is not a first-time adopter. 

e)  IFRS 9 Financial Instruments - Fees in the '10 per cent' test for derecognition of financial liabilities 

The amendment clarifies the fees that an entity includes when assessing whether the terms of a new or 
modified financial liability are substantially different from the terms of the original financial liability. These fees include only those paid or received between the borrower and the lender, including fees paid or received by either the borrower or lender on the other's behalf. There is no similar amendment proposed for IAS 39 Financial Instruments: Recognition and Measurement. 

These amendments had no impact on the interim condensed consolidated financial statements of the Group as there were no modifications of the Group's financial instruments during the period. 

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

Amendments to IAS 1: Classification of Liabilities as Current or Non-current - Effective for annual periods beginning on or after 1 January 2023

Amendments to IAS 8 Accounting Policies and Accounting Estimates: Definition of Accounting Estimates - Effective date for annual periods beginning on or after 1 January 2023

Disclosure of Accounting Policies - Amendments to IAS 1 and IFRS Practice Statement 2- Effective date for annual periods beginning on or after 1 January 2023

Amendments regarding deferred tax on leases and decommissioning obligations - Effective date for annual periods beginning on or after 1 January 2023

 

3.5  Basis of consolidation 

The consolidated financial statements comprise the financial statements of the Company and its subsidiaries as at 31 March 2022.

This basis of consolidation is the same adopted for the last audited financial statements as at 31 December 2021.

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 2021 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.

i.  OMLs 4, 38 and 41

OMLs 4, 38, 41 are grouped together as a cash generating unit for the purpose of impairment testing. These three OMLs are grouped together because they each cannot independently generate cash flows. They currently operate as a single block sharing resources for 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.

ii.  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.

iii.  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, 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.

iv.  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 10 billion, 2021: 5.8 billion.

v.  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.

vi.  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 Vice President (Finance), the Director (New Energy) 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 2021 annual financial statements.

The following are some of the estimates and assumptions made.

i.  Defined benefit plans

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

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

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

ii.  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 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 expired in February 2022. The Group also has an off-take agreement with Shell Western Supply and Trading Limited which expires in September 2023. The Group is exposed to further credit risk from outstanding cash calls from Nigerian Petroleum Development Company (NPDC) and Nigerian National Petroleum Corporation (NNPC).

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. 

b)  Estimation uncertainty in measuring impairment loss

The table below shows information on the sensitivity of the carrying amounts of the Group's financial assets to the methods, assumptions and estimates used in calculating impairment losses on those financial assets at the end of the reporting period. These methods, assumptions and estimates have a significant risk of causing material adjustments to the carrying amounts of the Group's financial assets.

 

i.  Significant unobservable inputs

 

The table below demonstrates the sensitivity of the Group's profit before tax to movements in the loss given default (LGD) for financial assets, with all other variables held constant:

 

 

 

Effect on profit before tax

31 March 2022

Effect on other components of equity before tax

31 March 2022

Effect on profit before tax

31 March 2022

Effect on other components of equity before tax

31 March 2022

 

 

million

million

$'000

$'000

Increase/decrease in loss given default

 

 

 

 

 

+10%

 

(179)

-

(450)

-

-10%

 

179

-

450

-

        

 

 

 

Effect on profit before tax

31 Dec 2021

Effect on other components of equity before tax

31 Dec 2021

Effect on profit before tax

31 Dec 2021

Effect on other components of equity before tax

31 Dec 2021

 

 

million

million

$'000

$'000

Increase/decrease in loss given default

 

 

 

 

 

+10%

 

(717)

-

(1,800)

-

-10%

 

717

-

1,800

-

        

The table below demonstrates the sensitivity of the Group's profit before tax to movements in probabilities of default, with all other variables held constant:

 

 

Effect on profit before tax

31 March 2022

Effect on other components of equity before tax

31 March 2022

Effect on profit before tax

31 March 2022

Effect on other components of equity before tax

31 March 2022

 

 

million

million

$'000

$'000

Increase/decrease in probability of default

 

 

 

 

 

+10%

 

(170)

-

(426)

-

-10%

 

170

-

426

-

        

 

 

 

 

 

 

Effect on profit before tax

31 Dec 2021

Effect on other components of equity before tax

31 Dec 2021

Effect on profit before tax

31 Dec 2021

Effect on other components of equity before tax

31 Dec 2021

 

 

million

million

$'000

$'000

Increase/decrease in probability of default

 

 

 

 

 

+10%

 

(679)

-

(1,704)

-

-10%

 

679

-

1,704

-

        

 

The table below demonstrates the sensitivity of the Group's profit before tax to movements in the forward-looking macroeconomic indicators, with all other variables held constant:

 

 

 

Effect on profit before tax

31 March 2022

Effect on other components of equity before tax

31 March 2022

Effect on profit before tax

31 March 2022

Effect on other components of equity before tax

31 March 2022

 

 

million

million

$'000

$'000

Increase/decrease in forward looking macroeconomic indicators

 

 

 

 

 

+10%

 

(5)

-

(12)

-

-10%

 

5

-

12

-

        

 

 

 

Effect on profit before tax

31 Dec 2021

Effect on other components of equity before tax

31 Dec 2021

Effect on profit before tax

31 Dec 2021

Effect on other components of equity before tax

31 Dec 2021

 

 

million

million

$'000

$'000

Increase/decrease in forward looking macroeconomic indicators

 

 

 

 

 

+10%

 

(19)

-

(48)

-

-10%

 

19

-

48

-

        

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 interest bearing current accounts and time 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 2022

 

 

 

 

 

 

Non - derivatives

 

 

 

 

 

 

Fixed interest rate borrowings

 

 

 

 

 

 

Senior notes

7.75%

 10,776

 21,260

 21,318

 302,481

 355,835

Variable interest rate borrowings

 

 

 

 

 

 

The Mauritius Commercial Bank Ltd

 8.00% + USD LIBOR

 1,322

 4,452

 6,539

 7,738

 20,051

The Stanbic IBTC Bank Plc

 8.00% + USD LIBOR

 1,350

 4,545

 6,675

 7,899

 20,469

The Standard Bank of South Africa Limited

 8.00% + USD LIBOR

 771

 2,597

 3,814

 4,514

 11,696

First City Monument Bank Limited

8.00% + USD LIBOR

 344

 1,159

 1,703

 2,015

 5,222

Shell Western Supply and Trading Limited

10.5% + USD LIBOR

 495

 940

 892

 4,479

 6,806

Total variable interest borrowings

 

 4,282

 13,695

 19,623

 26,644

 64,243

 

 

 

 

 

 

 

Other non - derivatives

 

 

 

 

 

 

Trade and other payables**

 

157,015

-

-

-

157,015

Lease liability

 

 1,970

 67

 28

 - 

 2,065

 

 

 158,985

 67

 28

 - 

 159,081

Total

 

 174,043

 35,021

 40,969

 329,125

 579,159

 

 

Effective interest rate

Less than
1 year

1 - 2
year

2 - 3
years

3 - 5
years

Total

 

%

million

million

million

million

million

31 December 2021

 

 

 

 

 

 

Non - derivatives

 

 

 

 

 

 

Fixed interest rate borrowings

 

 

 

 

 

 

Senior notes

7.75%

20,751

20,751

20,751

298,881

361,134

Variable interest rate borrowings

 

 

 

 

 

 

The Mauritius Commercial Bank Ltd

 8.00% + USD LIBOR

1,298

4,390

6,456

7,650

19,794

The Stanbic IBTC Bank Plc

 8.00% + USD LIBOR

1,324

4,481

6,590

7,810

20,205

The Standard Bank of South Africa Limited

 8.00% + USD LIBOR

757

2,561

3,766

4,463

11,547

First City Monument Bank Limited

8.00% + USD LIBOR

338

1,143

1,681

1,992

5,154

Shell Western Supply and Trading Limited

10.5% + USD LIBOR

486

924

876

4,422

6,708

Total variable interest borrowings

 

4,203

13,499

19,369

26,337

63,408

 

 

 

 

 

 

 

Other non - derivatives

 

 

 

 

 

 

Trade and other payables**

 

151,204

-

-

-

151,204

Lease liability

 

1,950

66

28

-

2,044

 

 

153,154

66

28

-

153,248

Total

 

178,108

34,316

40,148

325,218

577,790

 

 

Effective
interest rate

Less than
1 year

1 - 2
year

2 - 3
years

3 - 6
years

Total

 

%

$'000

$'000

$'000

$'000

$'000

31 March 2022

 

 

 

 

 

 

Non - derivatives

 

 

 

 

 

 

Fixed interest rate borrowings

 

 

 

 

 

 

Senior notes

7.75%

 25,887

 51,075

 51,215

 726,682

 854,858

Variable interest rate borrowings

 

 

 

 

 

 

The Mauritius Commercial Bank Ltd

 8.00% + USD LIBOR

 3,176

 10,697

 15,709

 18,589

 48,170

The Stanbic IBTC Bank Plc

 8.00% + USD LIBOR

 3,242

 10,919

 16,036

 18,976

 49,174

The Standard Bank of South Africa Limited

 8.00% + USD LIBOR

 1,853

 6,240

 9,164

 10,843

 28,099

First City Monument Bank Limited

8.00% + USD LIBOR

 827

 2,786

 4,091

 4,841

 12,544

Shell Western Supply and Trading Limited

10.5% + USD LIBOR

 1,189

 2,259

 2,143

 10,760

 16,350

Total variable interest borrowings

 

 10,286

 32,900

 47,142

 64,009

 154,338

 

 

 

 

 

 

 

Other non - derivatives

 

 

 

 

 

 

 

Trade and other payables**

377,217

 -

 -

 -

377,217

Lease liability

4,733

160

67

-

4,960

 

 381,950

 160

 67

 - 

 382,177

Total

 418,123

 84,135

 98,424

 790,691

 1,391,373

                

 

 

Effective
interest rate

Less than
1 year

1 - 2
year

2 - 3
years

3 - 5
years

Total

 

%

$'000

$'000

$'000

$'000

$'000

31 December 2021

 

 

 

 

 

 

Non - derivatives

 

 

 

 

 

 

Fixed interest rate borrowings

 

 

 

 

 

 

Senior notes

7.75%

50,375

 50,375

 50,375

 725,563 

 876,688

Variable interest rate borrowings

 

 

 

 

 

 

The Mauritius Commercial Bank Ltd

 8.00% + USD LIBOR

3,150 

 10,656

 15,672 

18,572 

 48,050

The Stanbic IBTC Bank Plc

 8.00% + USD LIBOR

 3,215 

 10,878

 15,998 

 18,959 

 49,050

The Standard Bank of South Africa Limited

 8.00% + USD LIBOR

1,837 

6,216

9,142 

 10,834 

 28,029

First City Monument Bank Limited

8.00% + USD LIBOR

820 

 2,775

 4,081 

 4,836 

 12,512

Shell Western Supply and Trading Limited

10.5% + USD LIBOR

1,179

 2,243

2,126

10,734 

 16,282

Total variable interest borrowings

 

10,201

32,768

 47,019

63,935

 153,923

 

 

 

 

 

 

 

Other non - derivatives

 

 

 

 

 

 

 

Trade and other payables**

367,058

-

-

-

367,058

Lease liability

4,733

160

67

-

4,960

 

371,791

160

67

-

372,018

Total

432,367

 83,303

 97,461

789,498 

1,402,629

               

** 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

2022

As at 31 Dec

2021

As at 31 March

2022

As at 31 Dec

2021

 

million

million

million

million

Financial assets at amortised cost

 

 

 

 

Trade and other receivables*

71,449

78,869

71,449

78,869

Contract assets

3,298

1,679

3,298

1,679

Cash and bank balances

129,973

133,667

129,973

133,667

 

204,720

214,215

204,720

214,215

Financial liabilities at amortised cost

 

 

 

 

Interest bearing loans and borrowings

314,200

315,791

318,143

307,447

Trade and other payables**

142,464

136,619

142,464

136,619

 

456,664

452,410

460,607

444,066

Financial liabilities at fair value

 

 

 

 

Derivative financial instruments (Note 20)

1,848

1,543

1,848

1,543

 

1,848

1,543

1,848

1,543

 

 

Carrying amount

Fair value

 

As at 31 March

2022

As at 31 Dec

2021

As at 31 March

2022

As at 31 Dec

2021

 

$'000

$'000

$'000

$'000

Financial assets at amortised cost

 

 

 

 

Trade and other receivables*

171,651

191,463

171,651

191,463

Contract assets

7,922

4,076

7,922

4,076

Cash and bank balances

312,242

324,490

312,242

324,490

 

491,815

520,029

491,815

520,029

Financial liabilities at amortised cost

 

 

 

 

Interest bearing loans and borrowings

754,835

766,614

764,308

746,358

Trade and other payables**

342,260

331,655

342,260

331,655

 

1,097,095

1,098,269

1,106,568

1,078,013

Financial liabilities at fair value

 

 

 

 

Derivative financial instruments (Note 20)

4,439

3,745

4,439

3,745

 

4,439

3,745

4,439

3,745

       

Trade and other receivables exclude Geregu power, Sapele power, 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 non-financial assets), 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 derivative financial instruments are in level 2.

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 2022, revenue from the gas segment of the business constituted 11% of the Group's revenue. Management is committed to continued growth of the gas segment of the business, including through increased investment to establish additional offices, create a separate gas business operational management team and procure 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 the gas business segment's revenues, results and cash flows are 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 2022

3 Months ended 31 March 2021

3 Months ended

31 March 2022

3 Months ended 31 March 2021

 

'million

'million

$'000

$'000

Oil

2,400

 3,895

5,746

 10,240

Gas

5,890

 5,554

14,156

 14,616

Total profit from continued operations for the period

8,290

 9,449

19,902

 24,856

 

Oil     

 

3 Months ended

31 March 2022

3 Months ended 31 March 2021

3 Months ended

31 March 2022

3 Months ended 31 March 2021

 

'million

'million

$'000

$'000

Revenue from contract with customers

 

 

 

 

Crude oil sales 

89,955

 47,152

216,209

 124,084

Operating profit before depreciation, depletion

and amortisation

 

49,051

 

 20,092

 

117,865

 

52,862

Depreciation and impairment

(15,172)

 (12,311)

(36,460)

 (32,398)

Operating profit

33,879

 7,781

81,405

 20,464

Finance income

13

 3

32

 7

Finance costs

(7,731)

 (6,391)

(18,582)

 (16,817)

Profitbefore taxation

26,161

 1,393

62,855

 3,654

Income tax (expense)/credit

(23,761)

 2,502

(57,109)

 6,586

Profit for the period

2,400

 3,895

5,746

 10,240

 

Gas

 

3 Months ended

31 March 2022

3 Months ended 31 March 2021

3 Months ended

31 March 2022

3 Months ended 31 March 2021

 

'million

'million

$'000

$'000

Revenue from contract with customer

 

 

 

 

Gas sales

10,663

 10,778

25,628

 28,364

Operating profit before depreciation, depletion

and amortisation

8,868

 

 9,112

 

21,314

 

 23,980

Depreciation, amortization and impairment

(265)

 (17)

(638)

 (44)

Operating profit

8,603

 9,095

20,676

 23,936

Share of (loss)/profit from joint venture accounted

for using equity accounting

 

(52)

 159

(124)

 418

Profit before taxation

8,551

 9,254

20,552

 24,354

Income tax expense

(2,661)

 (3,700)

(6,396)

 (9,738) 

Profit for the period

5,890

 5,554

14,156

 14,616

 

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 2022

3 Months ended

March 2022

3 Months ended

March 2022

3 Months ended

March 2021

3 Months ended

March 2021

3 Months ended

March 2021

 

 

Oil

Gas

Total

Oil

Gas

Total

 

 

'million

'million

'million

'million

'million

'million

 

Geographical markets

 

 

 

 

 

 

 

Bahamas

10,022

-

10,022

-

-

-

 

Nigeria

-

10,663

10,663

 11,587

10,778

 22,365

 

Switzerland

69,564

-

69,564

 35,565

-

 35,565

 

United Kingdom

10,369

-

10,369

-

-

-

 

Revenue from contract with customers

89,955

10,663

100,618

 47,152

10,778

 57,930

 

Timing of revenue recognition

 

 

 

 

 

 

 

At a point in time

89,955

-

89,955

 47,152

 - 

 47,152

 

Over time

-

10,663

10,663

 - 

10,778

 10,778

 

Revenue from contract with customers

89,955

10,663

100,618

 47,152

10,778

 57,930

 

 

3 Months ended

March 2022

3 Months ended

March 2022

3 Months ended

March 2022

3 Months ended

March 2021

3 Months ended

March 2021

3 Months ended

March 2021

 

Oil

Gas

Total

Oil

Gas

Total

 

$'000

$'000

$'000

$'000

$'000

$'000

Geographical markets

 

 

 

 

 

 

Bahamas

24,088

-

24,088

-

-

-

Nigeria

-

25,628

25,628

 30,492

28,364

 58,856

Switzerland

167,199

-

167,199

 93,592

 - 

 93,592

United Kingdom

24,922

-

24,922

-

-

-

Revenue from contract with customers

216,209

25,628

241,837

 124,084

28,364

 152,448

Timing of revenue recognition

 

 

 

 

 

 

At a point in time

216,209

-

216,209

124,084

 - 

124,084

Over time

-

25,628

25,628

 - 

 28,364

28,364

Revenue from contract with customers

216,209

25,628

241,837

124,084

28,364

 152,448

            

The Group's transactions with its major customer, Mercuria, constitutes more than 69% (69.6 billion, $167 million) of the total revenue from the oil segment and the Group as a whole. Also, the Group's transactions with Geregu Power, Sapele Power, NGMC and Azura (10.7 billion, $25.6 million) accounted for the total revenue from the gas segment.

6.1.2  Impairment loss on financial assets by reportable segments

 

3 Months ended

March 2022

3 Months ended

March 2022

3 Months ended

March 2022

3 Months ended

March 2021

3 Months ended

March 2021

3 Months ended

March 2021

 

Oil

Gas

Total

Oil

Gas

Total

 

'million

'million

'million

'million

'million

'million

Impairment loss

82

427

509

 252

17 

 269

 

 

3 Months ended

March 2022

3 Months ended

March 2022

3 Months ended

March 2022

3 Months ended

March 2021

3 Months ended

March 2021

3 Months ended

March 2021

 

Oil

Gas

Total

Oil

Gas

Total

 

$'000

$'000

$'000

$'000

$'000

$'000

Impairment loss

196

1,027

1,223

 663

 44 

 707

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 2022

1,417,916

229,271

 1,647,187

 3,406,408

 550,800

3,957,208

31 December 2021

1,393,987

209,549

1,603,536

3,384,033

508,701

3,892,734

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 2022

  786,267

141,279

927,546

1,888,937

339,410

 2,228,347

31 December 2021

775,644

124,528

900,172

1,882,945

302,203

2,185,248

7.  Revenue from contracts with customers

 

3 months ended

31 March 2022

3 months ended

31 March 2021

3 months ended

31 March 2022

3 months ended

31 March 2021

 

million

million

$'000

$'000

Crude oil sales 

89,955

 47,152

216,209

 124,084

Gas sales

10,663

 10,778

25,628

 28,364

 

100,618

 57,930

241,837

 152,448

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 2022

3 months ended

31 March 2021

3 months ended

31 March 2022

3 months ended

31 March 2021

 

million

million

  $'000

$'000

Royalties

20,883

 10,793

50,195

 28,404

Depletion, depreciation and amortisation

14,083

 11,748

33,848

 30,915

Crude handling fees

5,370

 4,749

12,908

 12,498

Nigeria Export Supervision Scheme (NESS) fee

90

 55

217

 145

Niger Delta Development Commission Levy

1,193

 977

2,867

 2,571

Barging/Trucking

1,230

 824

2,957

 2,167

Operational & maintenance expenses

8,936

 8,725

21,498

 22,959

 

51,785

  37,871

124,490

 99,659


Operational & maintenance expenses mainly relates to maintenance costs, warehouse operations expenses, security expenses, community expenses, clean-up costs, fuel supplies and catering services. Also included in operational and maintenance expenses is gas flare penalty of 686 million, $1.7 million.

Barging and Trucking costs relates to costs on the OML 40 Gbetiokun field and OML 17 Ubima field respectively under Eland Group.

9.  Other income.

 

3 months ended

31 March 2022

3 months ended

31 March 2021

3 months ended

31 March 2022

3 months ended

31 March 2021

 

million

'million

  $'000

$'000

Underlift

5,666

 3,115

13,618

 8,198

(Loss)/gains on foreign exchange  

(2,517)

 114

(6,048)

 301

Others

375

 25

900

 66

Tariffs

186

 2,527

446

 6,649

 

3,710

 5,781

8,916

 15,214

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.

(Loss)/gains on foreign exchange are principally as a result of translation of Naira, Pounds and Euro 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 2022

3 months ended

31 March 2021

3 months ended

31 March 2022

3 months ended

31 March 2021

 

million

'million

  $'000

$'000

Depreciation

435

 532

1,042

 1,404

Depreciation of right-of-use assets

410

 315

985

 830

Professional and consulting fees

972

 1,082

2,336

 2,848

Directors' emoluments (executive)

319

 263

766

 692

Directors' emoluments (non-executive)

561

 548

1,348

 1,441

Employee benefits

4,432

 3,975

10,657

 10,467

Loss on disposal of property, plant & equipment

5

-

12

-

Donation

11

-

26

-

Flights and other travel costs

702

 198

1,687

 522

Rentals 

66

 6

159

 16

 

7,913

 6,919

19,018

 18,220

Directors' emoluments have been split between executive and non-executive directors.

11.  Impairment loss

 

3 months ended

31 March 2022

3 months ended

31 March 2021

3 months ended

31 March 2022

3 months ended

31 March 2021

 

million

million

$'000

$'000

Impairment loss on financial assets

509

269

1,223

707

 

509

269

1,223

  707

 

12.  Fair value loss

 

3 months ended

31 March 2022

3 months ended

31 March 2021

3 months ended

31 March 2022

3 months ended

31 March 2021

 

million

million

$'000

$'000

Realised fair value loss on derivatives

743

 562

1,787

 1,480

Unrealised fair value loss on derivatives

896

 1,214

2,154

 3,196

 

1,639

 1,776

3,941

 4,676

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 2022

3 months ended

31 March 2021

3 months ended

31 March 2022

3 months ended

31 March 2021

 

million

million

$'000

$'000

Finance income

 

 

 

 

Interest income

13

3

32

7

Finance cost

 

 

 

 

Interest on bank loans

(7,468)

 (6,222)

(17,950)

 (16,373)

Interest on lease liabilities

(20)

 (57)

(47)

 (149)

Unwinding of discount on provision for decommissioning

(243)

 (112)

(585)

 (295)

 

(7,731)

 (6,391)

(18,582)

 (16,817)

Finance (cost) - net

(7,718)

 (6,388)

(18,550)

 (16,810)

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 2022 is 85% for crude oil activities and 30% for gas activities.

The effective tax rate for the period was 76% (2021: 11.25%)

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

 

 

3 months ended

31 March 2022

3 months ended

31 March 2021

3 months ended

31 March 2022

3 months ended

31 March 2021

 

million

million

$'000

$'000

Current tax:

 

 

 

 

Current tax expense on profit for the period

(6,347)

 (2,565)

(15,255)

 (6,750)

Education tax

(1,106)

 (456)

(2,658)

 (1,199)

Total current tax

(7,453)

 (3,021)

(17,913)

 (7,949)

Deferred tax:

 

 

 

 

Deferred tax (expense)/credit in profit or loss

(18,969)

 1,823

(45,592)

 4,797

Total tax expense in statement of profit

(26,422)

 (1,198)

(63,505)

 (3,152)

 

 

14.1  Deferred tax

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

 

As at
31 March 2022

As at
31 Dec 2021

As at
31 March 2022

As at
31 Dec 2021

 

'million

'million

$'000

$'000

Deferred tax assets

 

 

 

 

Deferred tax asset to be recovered in less than 12 months

40,703

40,280

97,785

97,785

Deferred tax asset to be recovered after more than 12 months

392,782

388,706

943,621

943,621

 

433,485

428,986

1,041,406

1,041,406

 

 

As at
31 March 2022

As at
31 Dec 2021

As at
31 March 2022

As at
31 Dec 2021

 

'million

'million

$'000

$'000

Deferred tax liabilities

 

 

 

 

Deferred tax liabilities to be settled in less than 12 months

(117,085)

 

(121,995)

(281,286)

(296,156)

Deferred tax liabilities to be settled after more than 12 months

(248,670)

 

(221,184)

(597,406)

(536,945)

 

(365,755)

(343,179)

(878,693)

(833,101)

 

 

 

 

 

Net deferred tax asset

67,730

85,807

162,713

208,305

15.  Oil & Gas properties

During the three months ended 31 March 2022, the Group acquired assets amounting to ₦10.7 billion, $25.8 million (Dec 2021: ₦54.6 billion, $136.4 million).

16.  Intangible Asset

 

License

Total

License

Total

Cost

million

million

$'000

$'000

At 1 January 2022

60,435

60,435

146,713

146,713

Additions

-

-

-

-

Exchange difference

634

634

-

-

At 31 March 2022

61,069

61,069

146,713

146,713

Amortisation

 

 

 

 

At 1 January 2022

6,390

6,390

15,513

15,513

Charge for the period

320

320

770

770

Exchange difference

68

68

-

-

At 31 March 2022

6,778

6,778

16,283

16,283

Net Book Value (NBV)

 

 

 

 

At 31 March 2022

54,291

54,291

130,430

130,430

At 31 December 2021

54,045

54,045

131,200

131,200

 

17.  Investment accounted for using equity method

 

31 March 2022

31 Dec 2021

31 March 2022

31 Dec 2021

 

million

million

$'000

$'000

Investment in Joint venture (ANOH)

93,722

92,795

225,158

225,270

Total

93,722

92,795

225,158

225,270

18.  Trade and other receivables

 

31 March 2022

31 Dec 2021

31 March 2022

31 Dec 2021

 

million

million

$'000

$'000

Trade receivables

15,860

25,923

38,101

62,929

Nigerian Petroleum Development Company (NPDC) receivables

21,247

34,571

51,046

83,924

Nigerian National Petroleum Corporation (NNPC) receivables

12,637

10,154

30,359

24,650

Underlift

24,018

20,657

57,702

50,147

Advances to suppliers

6,312

5,746

15,163

13,947

Receivables from ANOH

5,154

5,259

12,382

12,766

Other receivables

55,236

2,964

132,702

7,194

Total

140,464

105,274

337,455

255,557

18.1  Trade receivables

Included in trade receivables is an amount due from Geregu Power ₦8.17 billion, $19.6 million (Dec 2021: ₦7.1 billion, $17.1 million), Sapele Power ₦2.25 billion, $5.40 million (Dec 2021: ₦ 2.4 billion, $5.9 million) and Nigerian Gas Marketing Company (NGMC) 4.23 billion, $10.2 million (Dec 2021: 3 billion, $7.3 million) totalling ₦14.65 billion, $35.17 million (Dec 2021: 12.5 billion, $30.3 million) with respect to the sale of gas. Also included in trade receivables is an amount of ₦1.67 million (Dec 2021: ₦3.04 billion) $4 thousand (Dec 2021: $7.4 million) and nil (Dec 2021: ₦11.6 billion) nil (Dec 2021: $28.1 million) million due from Mercuria and Shell Western for sale of crude respectively.

18.2  NPDC receivables

The outstanding cash calls due to Seplat from its JOA partner, NPDC is ₦21.2 billion (Dec 2021: 34.6 billion) $51 million (Dec 2021: $83.9 million).

18.3  Other receivables

Other receivables include a deposit of $128.3 million transferred to Exxon Mobil Corporation, Delaware as part of the consideration to acquire the entire share capital of Mobil Producing Nigeria Unlimited. All other receivables are amounts outside the usual operating activities of the Group.

18.4  Reconciliation of trade receivables

 

31 March 2022

31 Dec 2021

31 March 2022

31 Dec 2021

 

million

million

$'000

$'000

Gross carrying amount

24,616

34,698

59,136

84,230

Less: Impairment allowance

(8,756)

(8,775)

(21,035)

(21,301)

Balance as at 31 March 2022

15,860

25,923

38,101

62,929

 

18.5  Reconciliation of NPDC receivables

 

31 March 2022

31 Dec 2021

31 March 2022

31 Dec 2021

 

million

million

$'000

$'000

Gross carrying amount

26,255

39,514

63,077

95,924

Less: Impairment allowance

(5,008)

(4,943)

(12,031)

(12,000)

Balance as at 31 March 2022

21,247

34,571

51,046

83,924

 

18.6  Reconciliation of NNPC receivables

 

31 March 2022

31 Dec 2021

31 March 2022

31 Dec 2021

 

million

million

$'000

$'000

Gross carrying amount

13,465

10,819

32,348

26,265

Less: Impairment allowance

(828)

(665)

(1,989)

(1,615)

Balance as at 31 March 2022

12,637

10,154

30,359

24,650

 

18.7  Reconciliation of other receivables

 

31 March 2022

31 Dec 2021

31 March 2022

31 Dec 2021

 

million

million

$'000

$'000

Gross carrying amount

74,100

21,632

178,021

52,513

Less: Impairment allowance

(18,864)

(18,668)

(45,319)

(45,319)

Balance as at 31 March 2022

55,236

2,964

132,702

7,194

19.  Contract assets

 

31 March 2022

31 Dec 2021

31 March 2022

31 Dec 2021

 

'million

'million

$'000

$'000

Revenue on gas sales

3,298

1,679

7,923

4,077

Impairment on contract assets

-

-

(1)

(1)

 

3,298

1,679

7,922

4,076


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 Geregu power, Sapele power and NGMC for the delivery of gas supplies which the three Companies 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 Geregu power, Sapele Power and NGMC authorising the quantities, this will be reclassified from contract assets to trade receivables.

19.1  Reconciliation of contract assets

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

 

  31 March 2022

31 Dec 2021

  31 March 2022

31 Dec 2021

 

'million

'million

$'000

$'000

Balance as at 1 January

1,679

2,343

4,076

6,167

Addition during the period

3,296

44,849

7,923

111,987

Receipts for the period

(1,696)

(45,662)

(4,077)

(114,017)

Price Adjustments

-

(24)

-

(60)

Impairment

-

-

-

(1)

Exchange difference

19

173

-

-

Balance as at 31 December

3,298

1,679

7,922

4,076

 

20.  Derivative financial instruments

The Group uses its derivatives for economic hedging purposes and not as speculative investments. Derivatives are measured at fair value through profit or loss. They are presented as current liability to the extent they are expected to be settled within 12 months after the reporting period.

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 2022

31 Dec 2021

31 March 2022

31 Dec 2021

 

'million

'million

$'000

$'000

Foreign currency options-crude oil hedges

1,848

1,543

4,439

3,745

 

1,848

1,543

4,439

3,745

21.  Cash and bank equivalents

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.

 

  31 March 2022

31 Dec 2021

31 March 2022

31 Dec 2021

 

'million

'million

$'000

$'000

Cash on hand

12,583

5,916

30,233

14,361

Short-term fixed deposits

203

29,040

488

70,498

Cash at bank

117,289

98,812

281,767

239,877

Gross cash and cash equivalent

130,075

133,768

312,488

324,736

Loss allowance

(102)

(101)

(246)

(246)

Net Cash and cash equivalents

129,973

133,667

312,242

324,490

 

21.1 Restricted cash

 

  31 March 2022

31 Dec 2021

31 March 2022

31 Dec 2021

 

'million

'million

$'000

$'000

Restricted cash (Current)

6,732

6,603

16,172

16,029

 

6,732

6,603

16,172

16,029

 

Included in the restricted cash balance is $8 million, 3.3 billion and $6.2 million, 2.6 billion set aside in the stamping reserve account and debt service reserve account respectively for the revolving credit facility. 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).

Also included in the restricted cash balance is $0.9 million, 0.4 billion and $1.1 million, 0.4 billion for rent deposit and unclaimed dividend respectively.

These amounts are subject to legal restrictions and are therefore not available for general use by the Group.

22.  Share Capital

22.1  Authorised and issued share capital

 

  31 March 2022

31 Dec 2021

31 March 2022

31 Dec 2021

 

'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

 

 

 

 

584,035,845 (2021: 584,035,845) issued shares
denominated in Naira of 50 kobo per share

296

296

1,862

1,862

Fully paid ordinary shares carry one vote per share and the right to dividends. There were no restrictions on the Group's share capital.

22.2  Movement in share capital and other reserves

 

 

Number of

shares

Issued share capital

Share

Premium

Share based payment reserve

Treasury shares

Total

 

 

Shares

'million

'million

'million

'million

'million

Opening balance as at 1 January 2022

 

584,035,845

 296

90,383

4,914

(2,025)

 93,568

Share based payments

 

-

-

-

540

-

540

Share re-purchased

 

-

-

-

-

(2)

(2)

Closing balance as at 31 March 2022

 

584,035,845

 296

90,383

5,454

(2,027)

94,106

 

 

 

Number of

shares

Issued share capital

Share

Premium

Share based payment reserve

Treasury shares

Total

 

 

Shares

$'000

$'000

$'000

$'000

$'000

Opening balance as at 1 January 2022

 

584,035,845

 1,862

520,138

22,190

(4,915)

539,275

Share based payments

 

-

-

-

1,297

-

1,297

Share re-purchased

 

-

-

-

-

(5)

(5)

Closing balance as at 31 March 2022

 

584,035,845

1,862

520,138

23,487

(4,920)

540,567

22.3  Employee share-based payment scheme

As at 31 March 2022, the Group had awarded 79,272,577 shares (Dec 2021: 73,966,540 shares) to certain employees and senior executives in line with its share-based incentive scheme. During the three months ended 31 March 2022, no new shares were vested (Dec 2021: 7,151,098 shares).

22.4  Treasury shares

This relates to Share buy-back programme for Group's Long-Term Incentive Plan. The programme commenced from 1 March 2021 and are held by the Trustees under the Trust for the benefit of the Group's employee beneficiaries covered under the Trust.

23.  Interest bearing loans and borrowings

23.1  Net debt reconciliation

Below is the net debt reconciliation on interest bearing loans and borrowings for 31 March 2022:

 

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 2022

24,988

290,803

315,791

60,661

705,953

766,614

Addition

  -

-

-

-

-

-

Interest accrued

7,468

-

7,468

17,950

-

17,950

Interest capitalized

326

-

326

783

-

783

Principal repayment

-

-

-

-

-

-

Interest repayment

(11,821)

-

(11,821)

(28,412)

-

(28,412)

Other financing charges

(874)

-

(874)

(2,100)

-

(2,100)

Transfers

4,901

(4,901)

-

11,779

(11,779)

-

Exchange differences

262

3,048

3,310

-

-

-

Carrying amount as at 31 March 2022

25,250

288,950

314,200

60,661

694,174

754,835


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

Additions

268,725

-

268,725

671,000

-

671,000

Interest accrued

29,765

-

29,765

74,322

-

74,322

Interest capitalized

4,995

-

4,995

12,473

-

12,473

Principal repayment

(240,291)

-

(240,291)

(600,000)

-

(600,000)

Interest repayment

(27,728)

-

(27,728)

(69,236)

-

(69,236)

Other financing charges

(8,154)

-

(8,154)

(20,360

-

(20,360)

Transfers

(40,451)

40,451

-

(101,006)

101,006

-

Exchange differences

2,609

20,472

23,081

-

-

-

24,988

290,803

315,791

60,661

705,953

766,614

650 million Senior notes - April 2021

In March 2021, 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 revolving credit facility for general corporate purposes, and to pay transaction fees and expenses. The amortised cost for the senior notes as at the reporting period is $636.1 million, although the principal is $650 million.

 

$110 million Reserved based lending (RBL) facility - March 2021 

The Group through its subsidiary Westport on 5th December 2019 entered into a five-year loan agreement with interest payable semi-annually. The RBL facility has an initial contractual interest rate of 8% + USD LIBOR as at March 2022 (8.2%) and a settlement 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 were 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 $125.0 million to $122.5million, with a further reduction to $100.0 million as at December 2020.

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 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 USD LIBOR plus 8%, as long as more than 50% of the available facility is drawn. 

On 4th February 2020 Westport drew down a further $10 million increasing the debt utilised under the RBL from $90 million to $100 million. 

 

The interest rate of the facility is variable. The interest accrued at the reporting period is $2.2 million using an effective interest rate of 8.2%. The interest paid was determined using 6-month USD 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 $100 million and 8% + USD 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). 

On 24 May 2021 Westport drew down a further $10 million increasing the debt utilized under the RBL from $100 million to $110 million. The amortized cost for this as at the reporting period is $108.4 million (Dec 2021: $108.8 million), although the principal is $110 million.

 

$50 million Reserved based lending (RBL) facility - July 2021 

In July 2021, the Group raised a $50 million offtake line to the Reserved Based Lending Facility. The Facility has a 6-year tenor, maturing in 2027. The amortised cost for this as at the reporting period is $10.3 million, although the principal is $11 million.

24.  Trade and other payables

 

  31 March 2022

31 Dec 2021

31 March 2022

31 Dec 2021

 

million

million

$'000

$'000

Trade payable

27,933

49,607

67,107

120,426

Accruals and other payables

76,878

67,630

184,694

164,175

NDDC levy

6,133

5,283

14,734

12,826

Royalties payable

25,005

14,100

60,073

34,228

Overlift

12,213

14,584

29,341

35,403

 

148,162

151,204

355,949

367,058

Included in accruals and other payables are field accruals of 17.1 billion (Dec 2021: 34.4 billion) $41.2 million (Dec 2021: $83.5 million), and other vendor payables of ₦33.33 billion (Dec 2021: ₦6.4 billion) $80.07 million (Dec 2021: $15.6 million). Royalties payable include accruals in respect of crude oil and gas production for which payment is outstanding at the end of the period.

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 in profit or loss. 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 and any amount unpaid at the end of the year is recognised in overlift payable.

25.  Computation of cash generated from operations

 

 

3 months ended

3 months ended

3 months ended

3 months ended

 

 

31-Mar-22

31-Mar-21

31-Mar-22

31-Mar-21

 

 

million

million

$'000

$'000

Profit before tax

 

34,712

10,647

83,407

28,008

Adjusted for:

 

 

 

 

 

Depletion, depreciation and amortization

 

14,518

 12,281

34,890

 32,319

Depreciation of right-of-use asset

 

410

 315

985

 830

Impairment losses on financial assets

 

509

 269

1,223

 707

Interest income

 

(13)

 (3)

(32)

 (7)

Interest expense on bank loans

 

7,468

 6,222

17,950

 16,373

Interest on lease liabilities

 

20

 57

47

 149

Unwinding of discount on provision for decommissioning

 

243

 112

585

 295

Unrealised fair value loss on derivatives

 

896

 1,214

2,154

 3,196

Realised fair value loss on derivatives

 

743

 562

1,787

1,480

Unrealised foreign exchange loss/(gain) 

 

2,517

 (114)

6,048

 (301)

Loss on disposal of property, plant & equipment

 

5

-

12

-

Share based payment expenses

 

540

 544

1,297

1,431

Share of loss/(profit) in joint venture

 

52

 (159)

124

 (418)

Defined benefit expenses

 

675

 - 

1,623

-

Changes in working capital:

 

 

 

 

 

Trade and other receivables

 

18,308

  (11,844)

  44,004

  (31,169)

Prepayments

 

(358)

 (1,148)

(860)

 (3,022)

Contract assets

 

(1,601)

 (919)

(3,847)

 (2,419)

Trade and other payables

 

(4,622)

  (7,647)

(11,109)

  (20,124)

Restricted Cash

 

(59)

 (7,955)

(143)

 (20,935)

Inventories

 

317

 (307)

761

 (807)

Net cash inflow from operating activities

 

75,280

 2,127

180,906

 5,586

 

26.  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 2022

31 March 2021

31 March 2022

31 March 2021

 

million

million

$'000

$'000

Profit attributable to Equity holders of the parent

6,868

13,550

16,484

35,647

(Loss)attributable to Non-controlling interests

1,422

(4,101)

3,418

(10,791)

Profit for the year

8,290

9,449

19,902

24,856

 

Shares '000

Shares '000

Shares '000

Shares '000

Weighted average number of ordinary shares in issue

584,036

581,841

584,036

581,841

Outstanding share-based payments (shares)

2,801

6,604

2,801

6,604

 

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

586,837

588,445

586,837

588,445

Basicearnings per shares

$

$

Total basic earnings per share attributable to the ordinary equity holders of the Group

11.76

23.29

0.03

0.06

Diluted earnings per shares

$

$

Total diluted earnings per share attributable to the ordinary equity holders of the Group

11.70

23.03

0.03

0.06


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.

The decrease in the weighted average number of ordinary shares adjusted for the effect of dilution was due to the shares forfeited (share award scheme) in 2021.

27.  Proposed dividend

The Group's directors proposed an interim dividend of 2.5 cents per share for the reporting period (2021: 2.5 cents).

28.  Related party relationships and transactions

The Group is controlled by Seplat Energy 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 party is disclosed below. The outstanding balances payable to/receivable from related parties are unsecured and are payable/receivable in cash.

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 $430,206, 179 million (2021: $203,661, 77.3 million). Payables amounted to $532,037, 221 million (2021: $101.8 thousand, 41.9 million).

29.  Commitments and contingencies

29.1  Contingent liabilities

The Group is involved in a number of legal suits as defendant. The estimated value of the contingent liabilities is 11.5 billion, $27.6 million (Dec 2021: 7.9 billion, $19.2 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.

30.  Events after the reporting period

During the period, the Group agreed a $55 million settlement with the operator (All Grace Energy Limited) of Ubima asset which was acquired in 2019 during the acquisition of Eland, the agreed settlement will be paid in due course. The board approved an exit from the asset's operations in April 2022. The current reserve of the asset stands at circa 2mmbbls. However, the Group did not report any production under Ubima in the interim financial statements.

31.  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 2022

31 March 2021

31 Dec 2021

 

 

₦/$

₦/$

₦/$

Fixed assets - opening balances

Historical rate

 Historical

 Historical

Historical

Fixed assets - additions

Average rate

416.06

380.00

400.48

Fixed assets - closing balances

Closing rate

416.25

380.00

411.93

Current assets

Closing rate

416.25

380.00

411.93

Current liabilities

Closing rate

416.25

380.00

411.93

Equity

Historical rate

Historical

Historical

Historical

Income and Expenses:

Overall Average rate

416.06

380.00

400.48

 

 

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