Seplat FY22 Financial Results

Please see the Full Audited Results in attached PDF

http://www.rns-pdf.londonstockexchange.com/rns/2227R_1-2023-2-28.pdf

Audited results
for the year ended
31 December 2022

28 February 2023

Lagos and London, 28 February 2023: Seplat Energy Plc ("Seplat Energy" or "the Company"), a leading Nigerian independent energy company listed on the Nigerian Exchange Limited and the London Stock Exchange, announces its audited results for the full year ended 31 December 2022.

Special Dividend

§  Board recommends special dividend of US5.0 cents per share in addition to final dividend of US2.5 cents per share

Operational highlights   

§  Working interest production averaged 44 kboepd, impacted by outages of key infrastructure predominantly in Q3

§  Use of Amukpe-Escravos Pipeline (AEP) enables high uptime in December, exit rate of 53 kboepd

§  Completed 13 wells including two wells for the ANOH gas processing plant

§  ANOH Gas Processing Plant 95% mechanically complete, awaiting third-party infrastructure completion 

§  Safety culture maintained, one LTI recorded in October, LTIF for the full year is 0.12

Financial highlights  

§  Revenues of $951.8 million, up 29.8%

§  Adjusted EBITDA $416.9 million, up 12.1%

§  Strong full year cash generation of $571.2million against capex of $163.3million and $140.3million transaction deposits

§  Strong balance sheet with $404.3 million cash at bank, net debt of $365.9 million

§  Full year production cost of $10.3/boe

§  2022 Ubima divestment receipts were $18.6 million out of $55.0 million (additional $0.9million received in Jan 2023)

Corporate updates

§  Continue to pursue approvals for acquisition of entire share capital of MPNU 

§  Finalised New Energy investment plan, identified near term opportunities for consideration and FID late 2023

§  Commenced implementation of roadmap to achieving net zero by 2050

§  Provisional applications for voluntary conversion of operated Oil Mining Leases under Petroleum Industry Act

§  Work on-going to spin out Midstream Gas business in line with PIA provisions

§  First Climate Risk and Resilience Report to be published at end of March 2023 under TCFD guidelines

§  Carbon intensity of production figure published: 23.9Kg/boe

Outlook for 2023

§  Full year production guidance of 45-55 kboepd (excluding ANOH), capex expected to be $160 million

§  Increased use of AEP will improve revenue assurance

§  Sibiri appraisal wells indicating results on high side of initial Oil In-Place estimates, FID targeted by end 2023

§  ANOH first gas guidance moved to Q4 2023 owing to delays in third-party infrastructure

§  MPNU: continuing to pursue a reaffirmation of the Ministerial approval received on the 8 August 2022.

Roger Brown, Chief Executive Officer, said:

"I am delighted that our strong financial performance will enable the payment of a US7.5 cent final dividend, despite the significantly disrupted production we experienced in the second half of the year. The full-year dividend of US15 cents represents a dividend yield of around 11% at the current LSE share price.

As we enter 2023, the business is in a very healthy state, with new wells coming onstream, encouraging appraisal drilling underway at Sibiri, and alternative export routes ensuring good export performance in January and February this year. Our gas business continues to develop, with first gas expected from ANOH in Q4 this year, and we are now in the process of separating our Midstream Gas business from the Upstream unit to unlock new value for shareholders.

We are continuing to pursue the Presidential approval received on the 8 August 2022 for the MPNU acquisition and we remain focused on concluding the transaction within the remaining term of President Buhari before a new president is sworn into office at the end of May 2023.

We are implementing our roadmap to net zero and have made encouraging progress with a 35% reduction in emission intensity last year. The major reduction in carbon emissions is routine flaring which we are on target to eliminate by the end of 2024. Alongside these efforts, and as part of our stated strategy to become Nigeria's energy champion across the entire value chain, we are planning to invest in gas-to-power and solar power projects with FID targeted for later this year if the projected returns meet our internal hurdle rates.

We are confident in our outlook for 2023, with the new Amukpe-Escravos Pipeline working well, our drilling cost reductions and efficiencies being delivered, and ANOH's first gas expected in Q4 once 3^rd party infrastructure is completed, our business is on a firm footing to facilitate significant growth and higher returns for stakeholders."

Summary of performance

* FY 2021 includes reversal of $74.7m impairment charge under IAS 36

** Adjusted for impairment, fair value loss and decommissioning

Responsibility for publication

The Board member responsible for arranging the release of this announcement on behalf of Seplat Energy is
Emeka Onwuka, CFO 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.

Investor call

At 09:00 GMT / 10.00 WAT on Tuesday 28 February 2023, the Executive Management team will host a conference call and webcast to present the Company's results.  

The presentation can be accessed remotely via a live webcast link and pre-registering details are below. After the meeting, the webcast recording will be made available and access details of this recording are also set out below. 

A copy of the presentation will be made available on the day of results on the Company's website at https://seplatenergy.com/ .

The Company requests that participants dial in 10 minutes ahead of the call. When dialling in, please follow the instructions that will be emailed to you following your registration. 

Enquiries:

About Seplat Energy

Seplat Energy PLC (Seplat) is Nigeria's leading indigenous energy company. Listed on the Nigerian Exchange Limited (NGX: SEPLAT) and the Main Market of the London Stock Exchange (LSE: SEPL), we are pursuing a Nigeria-focused growth strategy in oil and gas, as well as developing a Power & New Energy business to lead Nigeria's energy transition.

Seplat's energy portfolio consists of seven oil and gas blocks in the prolific Niger Delta region of Nigeria, which we operate with partners including the Nigerian Government and other oil producers. We also have a revenue interest in OML 55. We operate a 465MMscfd gas processing plant at Oben, in OML4, and are building the 300MMscfd ANOH Gas Processing Plant in OML53 and a new 85MMscfd gas processing plant at Sapele in OML41, to augment our position as a leading supplier of gas to the domestic power generation market.

For further information please refer to our website, http://seplatenergy.com/

Operating review

Upstream business performance

Reserves and Resources

The Group's audited 2P reserves, as assessed independently by Ryder Scott Company, L.P., decreased by 19 MMboe from 457 MMboe at the end of 2021 to 438 MMBoe at the end of 2022. The change is mostly due to production of 9 MMbbls of liquids and 41.0 Bscf of gas (7 MMboe). The divestment of Ubima, the discovery at Sibiri, and reclassifications and revisions of previous estimates makes up the difference.

1.       Eland has a 45% working interest in OML40 until the Westport loan is fully repaid in accordance with the loan agreement, reverting to 20.25%  

2.       Eland had an 82% working interest in the Ubima marginal field

3.       Quantities of oil equivalent are calculated using a gas-to-oil conversion factor of 5,800 scf of gas per barrel of oil equivalent.

The Group's audited 2C resources decreased by 7.3% from 75 MMboe to 70 MMBoe, comprising 43 MMbbls of oil and condensate and 159 Bscf of natural gas. The decrease in 2C gas resources (boe) is mostly due to revisions in Emebiam, Owu and Oben fields.

Abiala has not been included in 2C resources because the farm in agreement had not been concluded at the time of closure of the reserves audit

Consequently, the Group's working interest 2P reserves and 2C resources stood at 507.5 MMboe as of 31 December 2022, comprising 248.5 MMbbls oil and condensate and 1,502.2 Bscf of natural gas (259 MMBoe).

Production

Full-year total working interest production for 2022 was 16.1 MMboe. Within this, liquids production was 9.03 MMbbls, down 26.6% year-on-year, and gas production was 7.1 MMBoe (41.0 Bscf), up 4.1% year-on-year. In addition, the Group recorded a total downtime of 37%, primarily because of problems with third-party export infrastructure.

Liquid production volumes as measured at the LACT (Lease Automatic Custody Transfer) unit for OMLs 4, 38 and 41; OML 40 and OPL 283 flow station.

Gas conversion factor of 5.8 boe per scf.

Following the decision to exit from the Ubima asset in April 2022, volumes from the marginal field have not been reported in 2022

Volumes stated are subject to reconciliation and will differ from sales volumes within the period.

Working interest production by quarter

Following the 2020 marginal field bid round in Nigeria, Naphta Global E&P Ltd. (Naphta) was awarded 100% equity in the Abiala marginal field carved out of OML 40 by the NUPRC. The marginal field contains 2C gross oil resources of approximately 40 MMbbls.

Elcrest (45% owned by Seplat Energy) has entered into an agreement with Naphta for a 95% equity farm-in to the Abiala marginal field, while Naphta will have a 5% carried interest. Elcrest will also assume the role of Operator and Technical & Financial Partner in the Elcrest/Naphta Joint Venture. The partners executed Heads of Agreement with a signature bonus of $12 million paid to NUPRC. The transaction represents a consolidation of the Company's strategic position on the OML 40 block. It provides an early monetisation opportunity using existing OML 40 facilities, subject to agreement with NEPL (NNPC E&P Limited, formerly NPDC), which operates the OML 40 Asset.

In developing the field, Elcrest is targeting first oil by the end of Q2 2023 and plans to focus on low-cost development with early monetisation opportunities that leverage existing contractual positions to accelerate the field's development. Seplat Energy will also explore optimising its tax position to the extent possible under the new PIA.

Drilling activities

The drilling programme for 2022 spudded thirteen wells and successfully delivered eleven wells below budgeted costs. An additional two wells (ANOH-03 & ANOH-04) were spudded by SPDC in 2022 but will not be completed until 2023 due to delays in the gas plant on-stream date.

In OML 4, 38 & 41, we spudded and delivered four wells: the Amukpe-5ST2, Oben-52, Oben-53 and Ethiope-02 wells, which are expected to produce a combined gross rate of c.5,000 bopd and c.3.1 MMscfd of gas.

In OML 53, we spudded three wells and delivered one well: the Owu-02 appraisal well was spudded and completed. The OHS-08 was completed in January 2023 and the OHS-07 expected to be completed later in Q1 2023. The expected peak production from OHS-07 and OHS-08 is c.3,500 bopd.

In OML 40, we spudded and delivered six wells: the Opuama-12, Opuama-13, Opuama-14, Opuama-15, Opuama-16 wells and Sibiri-1. The Opuama wells have commenced production, with gross combined production of approximately c.9,000 bopd.

Total expected peak production for the production wells spudded in 2022 is expected to be c.17,500 bopd of oil and c.3.1 MMscfd of gas or working interest: c.7,700 bopd and 1.4 MMscfd.

In OML 40, the Sibiri oil discovery is being appraised by two wells. The Sibiri-1 discovery well was drilled in Q1 2022 and as reported in our 2021 full-year results last year, encountered eight oil-bearing reservoirs with 353 ft of gross oil pay and 229 ft of net pay. The post discovery Oil In-Place was estimated in the range 24-34-94 million barrels.

Appraisal drilling of Sibiri-2, with the objectives of testing the eastern and south-western flanks, commenced on 30 January 2023 and reached TD on 23 February, with initial results indicating significant uplift in mid-case Oil-In-Place volumes. In the eastern flank, four oil bearing reservoirs with 68 ft of gross oil and 48 ft net pay were encountered. In the south-western flank, nine oil bearing reservoirs with an initial estimate of 292 ft of gross oil and 180 ft net pay, including two new pay zones, were encountered. These preliminary results are in line with the high side of pre-appraisal Oil In-Place evaluation. Further well data acquisition is ongoing and subsequent technical studies are required to confirm the initial results.

The extended well testing (EWT) of Sibiri-1 commenced on 21 February 2023 via a 6km flow line to the OML40 Opuama facilities. Testing and evaluation of crude properties is ongoing.

The Field Development Plan is on schedule to be completed in Q4 2023, leading to the Final Investment Decision for the full field development soon after. Development drilling is anticipated in Q1 2024 with expected peak production of 5,000-6,000 barrels of oil per day in 2024-25.

Export infrastructure diversification

We continue to pursue alternative crude oil evacuation options for production at all assets, to increase our export flexibility reduce over-reliance on any one third-party operated export system. In line with this objective, we successfully commenced evacuation through the AEP export route during the third quarter of 2022. Crude oil production from OMLs 4, 38 and 41 is now sent via the Trans Forcados Pipeline (TFP) and AEP, with significant volumes now flowing through the latter. For a third export route, we intend to establish regular exports of 10,000 bopd (gross) through the Warri Refinery jetty, from which it will be sold FOB to our off-taker at the jetty. We intend to keep this option available for the foreseeable future.

All three export routes will provide significant flexibility and ensure we have adequate redundancy in evacuation routes, significantly reducing downtime to promote higher levels of revenue assurance and profitability.

For OML 53, we have engaged with our J.V. partner NUIMS (formerly NAPIMS) and the NUPRC to operationalise an alternative evacuation option of trucking for the Jisike and Ohaji South fields in OML 53, and we will commence a pilot test when approvals are secured.

At OML 40, the partners are exploring the potential of barging operations to evacuate liquids from the Gbetiokun fields to the LEC floating storage and offloading facility (FSO) to mitigate the impact of increasing FOT/TEP unavailability.

Towards a permanent solution, the partners have begun constructing a pipeline from Gbetiokun to Adagbassa to replace the more expensive barging operation that we currently run. The 30cm x 30km pipeline will take produced crude from the Gbetiokun field in OML 40 to the Adagbassa manifold, from where the pipeline will tie into the existing 36km Opuama-Otumara export pipeline.

Midstream Gas business separation from Upstream

The decision to convert to the PIA regime considered the implications for our Midstream Gas business. In line with the provisions of the PIA, we believe the Midstream gas business could achieve a higher value when operated as a separate, standalone unit, independent of our Upstream business. This will unlock new value for the Company and increase returns for stakeholders. An implementation roadmap for the spin-out opportunity has been developed and the process is expected to take 12 to 18 months, subject to regulatory approval and stakeholder engagement.

Additional third-party volumes

We are focused on developing third-party gas resource opportunities that can utilise the remaining processing capacity at Oben. Securing additional volumes from counterparties will secure long-term supplies of raw natural gas from which we can maximise the plant's utilisation and generate tolling revenues. We progressed discussions with targeted third-party gas producers during the year and are finalising contracting to facilitate a tripartite gas development workshop with three producers.

ANOH Gas Processing Plant

To date, the IJV (AGPC) has achieved 95% overall mechanical project completion at the gas plant site, and we expect the plant to be mechanically complete in Q2 2023.  Our government partner, NGIC, is delivering the pipelines that will take the gas from ANOH to the demand centres, namely the 23km spur line and the Obiafu-Obrikom-Oben (OB3) pipeline.

The OB3 pipeline has been affected by the collapsing of the HDD wall in a section of the river crossing.  Experts from the UK have been brought in to 'grout' the section and grouting will commence in March with the drilling and pipe installation to commence thereafter. NGIC has confirmed that they expect the pipeline to be complete before the end of Q2 2023.

Line pipes for the 23km spur line are in country and project completion is almost 70%, with the revised completion date communicated by NGIC as 30 June 2023.

Despite estimated completion for the pipeline infrastructure being Q2 2023, we have further risked the completion dates and have moved the first gas to the final quarter of 2023. Once completed, ANOH will deliver two income streams for Seplat Energy: from OML 53's wet gas sales to the plant, and from dividends returned to Seplat Energy from the joint venture ANOH Gas Processing Company, which will operate the plant.

The upstream development, including the drilling of six production wells, will be delivered by the upstream unit operator SPDC. We expect the drilling of ANOH-03 and ANOH-04 by SPDC to be completed in Q2 2023.

Sapele Gas Plant

Work continues on the new Sapele Gas Plant, with project progress at 60%. Upon completion, the processing capacity will be 85 MMscfd. The upgraded facility will produce gas that meets export specifications, and the LPG processing unit module will enhance the economics of the plant and reduce routine gas flaring. During this period, we accelerated the installation of A.G. Compressors to reach mechanical completion, and we have commenced commissioning activities to meet our target to end routine flares by the end of 2024.

New Energy business

At our Capital Markets Day in 2021, we announced our intention to invest in opportunities that will capture more value across the entire energy value chain, including renewable energy generation, on a medium to large scale.

We have completed evaluation studies and finalised a ten-year integrated Gas and New Energy Investment Plan. Near-term opportunities we have identified in gas-to-power and solar energy will be subject to technical and business evaluation assessments, environment and social impact assessments, and project licensing, and we expect to move to FID before the end of 2023. The key investment opportunities being considered include selective entry to off-grid power generation using gas-fired generation integrated with solar. Natural gas will be the mainstay of our energy transition programme and this in turn will ensure the sustainability and financial viability of the renewables program. We are also pursuing carbon offset possibilities on a wide range of emission reduction activities in various global carbon markets. The identified opportunities have considered advancement in technology, availability of resources within Nigeria and feasibility of execution.

Sustainability initiatives

First TCFD Report

Alongside our 2022 Annual Report we will publish a separate Sustainability Report and our first Climate Risk and Resilience Report, which will include the disclosures recommended by the Task Force on Climate-related Financial Disclosures (TCFD). These reports will describe our commitment to the environment and our approach to managing climate risk and represent disclosure of initiatives within our corporate strategy to Build a sustainable business and Deliver energy transition. In addition, the Corporate Scorecard for 2022 is tied to climate-related and other sustainability KPIs, which are expressly linked to executive pay. ESG accounts for 15% of KPIs in 2022, and safety 10%.

HSE performance

Safe and responsible operations are critical to the delivery of Seplat Energy's strategy. Staff and contractors completed a total of 8.6 million hours in the period, and there were 93 HSE incidents in total, compared to 88 in 2021.

After achieving 31 million hours with zero LTI recorded over the last four years, a non-operating incident was recorded in October when a third-party contractor fractured his right leg while crossing the road during a community awareness campaign. The contributing factors to the incident were determined, and lessons learned have been adopted to prevent such accidents and expand the scope of safety beyond our operations.

During 2022 we updated our environmental policy and EMS manual in line with the ISO 14001 standard, as well as relevant local, national, and international regulations, and industry best practice.

Despite an increase in the number of Tier 2 incidents from three to five (>0.75bbl or equivalent to 1kg) because of sabotage to facilitate theft from the pipelines, the volume of operational oil spills decreased by 50% in 2022, and all spills were remediated with limited environmental impact. Throughout our activities, we took proactive measures to protect biodiversity and groundwater, and zero groundwater contamination was maintained.

During an internal process review, it was discovered that data pertaining to emissions sources contained discrepancies caused by an inadequate accounting system. Therefore, we launched a new GHG Emissions Accounting System and recalculated historical GHG emissions data. This exercise revealed a 49% overestimation of our GHG emissions for 2020 and 43% for 2021; the restated figures are 1.4 and 1.2 MMtonnes CO₂ equivalent, respectively.

The Scope 1 and 2 emissions recorded for 2022 were 0.7 MMtonnes CO₂ equivalent, resulting in a carbon intensity of 23.9kg/boe (2021: 36.6kg/boe), slightly above the upstream industry carbon intensity average of 18.9kg/boe (Oil & Gas Climate Initiative).

LRQA Group (a leading global assurance provider) has independently verified the new GHG accounting system. The same standards and methodologies in previous years were applied- API and IPPC.

Reducing our emissions towards Net Zero

Our primary commitment is to reduce our GHG emissions resulting from its direct operations. In addition, we have established a broad set of investment activities designed to reduce emissions from its operated facilities and offset residual emissions.

Outlook

Seplat Energy's long-term outlook is positive, with the AEP now operating as expected and the ANOH Gas Processing Plant due to come onstream in the final quarter of this year. Full-year production guidance for 2023 is set at 45,000 to 55,000 boepd on a working interest basis. This guidance does not include any expected contribution from MPNU or ANOH.

Capital expenditure for 2023 is expected to be around $160 million, and we plan to drill 18 new wells across our operated and non-operated assets as follows:

·      OMLs 4, 38 & 41: Eight wells (Three oil wells, three gas wells, one water disposal well and one exploration well)

·      OML 53: One oil well;

·      OML 40: Five wells (Four oil wells and one appraisal well; Abiala: Development of one workover and one oil well);

·      ANOH: Two gas wells.

The 2023 drilling programme will address production decline and, along with the completion of maintenance activities, will support long-term production levels from the assets. Facilities and engineering projects will focus on completing an upgraded integrated gas processing facility at Sapele. The year under review showed the importance of the sustainability of our evacuation options, and we will prioritise alternative route projects in 2023.

Achieving our ESG performance targets is a primary focus for 2023, and in our climate strategy, where we have committed to being carbon neutral in 2050, ending routine flares by the end of 2024 is a priority. We plan to complete the Oben, Amukpe, Sapele & Jisike Flares Out projects, which will capture and monetise gas for productive use and significantly reduce our carbon intensity. In addition, we plan to contribute to the growth of our communities by equipping hospitals and schools with reliable power and, in return, progress our goal to increase access to energy while developing our power and renewable capabilities on socially important projects.

We will exercise discretion over drilling investments and selectively consider opportunities in our existing portfolio, focusing on delivering the highest cash return whilst diligently preserving a strong balance sheet.

The Board is confident in the future prospects of the business, underpinned by its strong balance sheet, and reflecting this confidence the Board has decided to approve the payment of a special dividend of US5 cents to shareholders, in addition to the final dividend of US2.5 cents.

Financial review

Revenue

Revenue from oil and gas sales in 2022 was $951.8 million, a 29.8% increase from the $733.2 million achieved in 2021. 

Crude oil revenue was 35.8% higher than for the same period in the previous year at $839.5 million (2021: $618.4 million), reflecting higher average realised oil prices of $101.7/bbl. for the period (2021: $70.5/bbl.). The increase is attributable to the impact of the conflict in Ukraine on global energy prices and the steady post-pandemic recovery in global oil demand, particularly in China and the United States. The total volume of crude lifted in the period was 8.3 MMbbls, 6.8% lower than the 8.9 MMbbls lifted in 2021. The lower volumes lifted in 2022 resulted from a drop in production output, especially in the third quarter, because of the prolonged unavailability of the export terminals. However, significant improvements were made in Q4 2022 as we began to evacuate the bulk of our crude through the newly operational Amukpe-Escravos underground pipeline. The average reconciliation loss factor for the Group was 10.7%.

Gas sales revenue declined marginally by 2.1% to close the year at $112.5 million (2021: $114.8 million) because of weaker average realised gas prices following price reviews conducted in the second quarter of the year, down 1.1% to $2.82/Mscf (2021: $2.85/Mscf). Nevertheless, gas sales volumes improved despite the effect of oil evacuation curtailments and increased 4.1% to 41.0 Bscf, compared to 39.4 Bscf in 2021.

Gross profit

Gross profit increased by 63.0% to $464.7 million (2021: $285.2 million) and benefitted from higher realised oil prices.
Non-production costs consisted primarily of $180.8 million in royalties, which was higher compared to $129.8 million in 2021 because of higher oil prices, and DD&A of $128.7 million, which was lower compared to $141.1 million in 2021, reflecting lower depletion of reserves because of decreased production compared to the prior year.  

Direct operating costs, which include crude-handling fees, barging/trucking, operation and maintenance costs, amounted to $166.1 million in 2022, 3.1% lower than the $172.1 million incurred in 2021. However, on a cost-per-barrel equivalent basis, production opex was $10.3/boe, 4.4% higher than the $9.9/boe incurred in 2021, primarily because of the effect of lower produced volumes, an excess storage charge on use of the Escravos terminal, and the higher cost of crude handling on the AEP, when compared to the TFP.

Operating profit

The operating profit for the period was $274.7 million, an increase of 9.6%, compared to $250.7 million in 2021. 

The Group recognised a financial asset charge of $6.4 million related to the ageing of some government receivables, which is expected to reverse once recoveries are secured. Included in other income was a $13.1 million loss on disposal for the sale of the Ubima field. In addition, there was an over-lift charge of $27.2 million, representing 263 kbbl. and a $1.1 million loss on foreign exchange, principally due to the translation of Naira, Pounds and Euro-denominated monetary assets and liabilities.

General and administrative expenses of $137.4 million were 71.5% higher than the 2021 costs of $80.1 million. The increase was driven by the impact of global inflationary trends on expenses, including travel and training costs (activities having increased following the relaxation of travel restrictions), increased spending on professional and consulting fees associated with business growth strategies and the upward adjustments to staff salaries and emoluments to reflect the true cost of living. The bulk of the staff costs are denominated and paid in Naira but translated in the financial statements at the NAFEX currency exchange rate, which does not reflect fully the macroeconomic reality of the strength of the Naira against the USD. A correction downwards in the exchange rate will lower the USD reported costs accordingly.

After adjusting for non-cash items, which include impairment and exchange losses, the EBITDA of $416.9 million, equates to a margin of 43.8% for the period (2021: $371.8 million; 50.7%).

Taxation

Net result

The profit before tax was 15.2% higher at $204.4 million (2021: $177.3 million). The profit for the year was $104.7 million (2021: $117.2 million) with a resultant basic earnings per share of $0.11 in 2022, compared to $0.24 per share in 2021.

Cash flows from operating activities

Cash generated from operations in 2022 was $571.2 million, 51.6% higher than $376.8 million generated in 2021. Net cash flows from operating activities were 41.6% higher at $497.3 million (2021: $352.3 million) after accounting for tax paid of $57.5 million (2021: $13.0 million) and a hedging premium of $10.3 million (2021: $9.0 million).  The Group continued to record improvements in the recovery of receivables from the major JV partner and, in 2022, received $259 million towards the settlement of cash calls. As a result, the major JV receivable balance now stands at $91 million (2021: $83.9 million); these are mainly cash calls owed within the last 60 days and are expected to be settled within Q1 2023. As of February 2023 we have received more than $70 million as part settlement of the 2022 outstanding amounts.

Cash flows from investing activities

Net capital expenditure of $163.3 million included $94 million invested in drilling and $64 million in oil and gas engineering projects. 

Deposits for investment of $140.3 million include a $128.3 million (which is refundable) deposit for the proposed acquisition announced in February 2022 of Mobil Producing Nigeria Unlimited and the $12.0 million farm-in fee for the Abiala marginal field carved out of OML 40. 

The Group received total proceeds of $10.8 million in the period under the revised OML 55 commercial arrangement with BelemaOil for the monetisation of 298.4 kbbls of crude oil. In 2022, recovery was affected by sabotage along the Nembe Creek Trunk Line and the Trans Niger Pipeline, with theft factors ranging from 30% to 90%.

Cash flows from financing activities

The Company paid $58.8 million dividends to shareholders in the period. Other financing charges of $12.5 million reflect the commitment fee and other transaction costs on the Group's facilities, and $63.3 million reflects interest paid on loans and borrowings.

Liquidity

The balance sheet remains healthy with a solid liquidity position.

* including amortised interest

Seplat Energy ended the year with gross debt of $770.2 million (with maturities in 2026 and 2027) and cash at bank of $404.3 million, leaving net debt at $365.9 million. The restricted cash balance of $23.9 million includes $8.0 million and $12.5 million set aside in the stamping reserve and debt service reserve accounts for the revolving credit facility; in addition to $0.8 million and $1 million for rent deposit and unclaimed dividend, respectively. We monitor the gearing ratio with the objective to maintain a net debt to gearing ratio of 20%-40%. The ratio for 2022 was 17% (2021: 21%).

Refinancing of the $350 million revolving credit facility (RCF)

On 30 September 2022, Seplat Energy Plc refinanced its existing $350 million revolving credit facility due in December 2023 with a new three-year $350 million revolving credit facility due in June 2025. The RCF includes an automatic maturity extension until December 2026 once a refinancing of the existing $650 million bond due in April 2026 is implemented. The RCF is scheduled to reduce from July 2024, with such date automatically extended to July 2025 once the existing $650million bond is refinanced. The RCF carries an initial interest of 6% over the base rate (SOFR plus applicable credit adjustment spread), with the margin reducing to 5% after production flowing through the Amukpe-to-Escravos pipeline is stabilised at an average working interest production of at least 15,000 bopd over a period of 45 consecutive days, which was achieved on 1 February 2023 The pricing is in line with the current RCF pricing, although it reflects a change in the base rate from LIBOR to SOFR plus the applicable credit adjustment spread.

Final and Special Dividend

Board has recommended a final dividend of US2.5 cents per share for the financial year 2022 and following a review of Seplat's operational, liquidity and financial position post refinancing the Board has decided to declare an additional special dividend of US5.0 cents per share to be paid after approval at the Annual General Meeting, which will be held in Lagos, Nigeria, on 10 May 2023.  This brings the total dividend declared for 2022 to US15 cents per share (2021: US10 cents per share). The payment of the special dividend reflects the Board's confidence in the future of the business and is underpinned by a strong balance sheet.   

The Petroleum Industry Bill was signed into law on 16 August 2021 and provides for the voluntary conversion of existing prospecting licenses and mining leases to the terms of the PIA within 18 months, i.e., February 2023 or at the expiration of such licenses and leases.

In October 2022, following the Group's review of the fiscal provisions of the PIA, Seplat West Limited (OMLs 4, 38 & 41) and Seplat East Onshore Limited (OML 53) together with their respective joint venture partners (NEPL and NNPCL) made provisional applications to NUPRC "the Commission" for the voluntary conversion of operated Oil Mining Leases according to section 92 and 93 of the PIA in October 2022. NEPL, the operator of OML 40, together with Elcrest, also made a conversion application.

The pursuit of conversion was based on our assessment of the new PIA fiscal terms, specifically the improved oil and gas royalty structure and rates, tax system and introduction of production-based allowance, all of which resulted in an overall net favourable position for Seplat Energy.

In fulfilment of section 92 (4) - (6) of the PIA, Seplat executed the conversion contract on 15 February 2023, which confers on applicants the right but not an obligation to complete the conversion to the PIA. The contract includes a longstop date of 30 April 2023 (or any later date agreed by the Commission), by which time key regulations and guidelines are expected to be issued by the Commission, and all conversion conditions have either been satisfied by the applicant or waived ("effective date"). Ministerial approval of the conversion of OMLs/OPLs to PMLs/PPLs will remain subject to meeting all Conditions Precedent.

Seplat continues to monitor the regulatory landscape ahead of 30 April and reserves the right to withdraw or amend the application following when the full scope of the PIA's impact on its assets is assessed.

Credit ratings

Seplat maintains corporate credit ratings with Moody's Investor Services (Moody's), Standard & Poor's (S&P) Rating Services and Fitch. The current corporate ratings are as follows: (i) Moody's Caa1 (stable); (ii) S&P B (stable) and (ii) Fitch B- (stable).

The Group's substantial exposure to the Nigerian operating environment led to a downgrade by Fitch and Moody's, in November 2022 and February 2023 respectively, as both agencies downgraded the Sovereign. Fitch downgraded Seplat Energy Plc's Long-Term Issuer Default Rating (IDR) and senior unsecured rating to 'B-' from 'B', and Moody's downgraded the ratings to Caa1 from B3.