Seplat Energy Regulatory News (SEPL)

Seplat EnergyUnaudited 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

Financial highlights  

Update on proposed acquisition of Mobil Producing Nigeria Unlimited

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

* 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

Enquiries:

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

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 Oben that 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 plan with 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.

* 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 from1 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

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

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:

Interim condensed consolidated statement of changes in equity

For the three months ended 31 March 2022

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

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

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.

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:

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:

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:

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;

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.

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:

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:

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:

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.

** 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: