SEPL Seplat Energy Plc

Please see the Full Audited Results in attached PDF

http://www.rns-pdf.londonstockexchange.com/rns/1941Z_1-2025-3-4.pdf

Audited results for the year ended 31 December 2024

4 March 2025

Overview

Lagos and London, 4 March 2025: Seplat Energy PLC ("Seplat Energy" or "the Company"), a leading Nigerian independent energy Company listed on both the Nigerian Exchange and the London Stock Exchange, announces its audited results for the twelve months ended 31 December 2024.

Summary

Strong operational and strategic progress in 2024 culminating with the transformational acquisition of Mobil Producing Nigeria Unlimited ('MPNU') (renamed Seplat Energy Producing Nigeria Unlimited 'SEPNU'). Confidence in business outlook underpinned by special dividend, lifting total 2024 distribution to US$ 16.5 cents per share, up 10% on 2023.

Operational highlights

•   Production (onshore assets) averaged 48,618 boepd up 2% from 2023 (47,758 boepd), and within guidance. Including 19 days of SEPNU production (annualised average contribution of 4,329 kboepd), reported production reached 52,947 boepd, 11% higher than 2023.

•   YE 2024 independently audited 2P reserves up 85% to 886 MMboe (YE 2023: 478 MMboe), 65% liquids.

•   Group 2P+2C increases by 125% to 1,217 MMboe (YE 2023: 540 MMboe), 55% liquids.

•   Organic reserve replacement ratio in Seplat's onshore assets of 176%, reflects positive drilling results.

•   ANOH gas plant is planning to test with third party dry gas in 1H 2025, tunnelling operations on OB3 resumed during 1Q 2025.

•   Trans Niger Pipeline ('TNP') resumed 24hr operations in 4Q 2024. OML 53 oil production grew 60% on 2023, on improved export availability.

•   Sapele Integrated Gas Plant ('IGP') was commissioned in 4Q 2024 and achieved first commercial gas sales in early 2025.

•   Carbon emissions intensity for Seplat onshore assets: 32.3 kg CO2/boe (2023: 29.4 kg CO2/boe). End of routine flaring on track for H2 2025.

•   Achieved more than 11.0 million hours (2023: 8.7 million hours) without Lost Time Injury (LTI) on Seplat-operated assets in 2024.

Financial highlights  

•   Revenue $1,116 million up 5% (FY 2023: $1,061 million), including 19 days contribution from SEPNU. Underlying adjusted revenue stable at $961 million (FY 2023: $962 million).

•   Seplat Onshore unit production opex of $12.3/boe (2023: $10.4/boe)

•   Cash generated from operations of $384 million, down 26% on 2023, impacted by; timing of liftings, one-off costs predominately associated with SEPNU acquisition and working capital acquired on consolidation of SEPNU.

•   Cash capex of $208 million (FY 2023: 184 million).

•   Balance sheet remains robust, year-end cash at bank $469.9 million (2023: $450.1 million), excluding $132.2 million restricted cash.

•   Net debt at year end 2024 of $898 million (YE 2023: $306 million). Pro-forma ND/EBITDA 0.7x.

SEPNU highlights post completion

•   Strong production performance since completion, averaging net 81.1 kboepd, FY 2024 average working interest production 69.4 kboepd. 

•   First 100 day integration plan well advanced.

•   2025 work program and budget discussions with JV partner progressed but subject to final approval. Strong alignment on increasing investment to improve integrity and reliability and strengthen the asset base for long term growth.

Special Dividend

•   Q4 2024 declared dividend of US$ 3.6c/shr, total core dividend declared for 2024 of US 13.2c/shr, up 10% on 2023

•   The Board recommends a US$ 3.3c/shr special dividend for 2024. Reflecting the strength of balance sheet and confidence in our outlook.

•   Total dividend declared for 2024 US$ 16.5c/shr, also up 10% on 2023.

2025 Outlook

•   2025 average production guidance of 120-140 kboepd (Seplat Onshore 48-56 kboepd, SEPNU 72-84 kboepd).  

•   Initial 2025 capex guidance $260-320 million. (Seplat Onshore $180-220 million, SEPNU $80-100 million). Plan includes 13 new wells onshore, replacement of an inlet gas exchanger on East Area Project (EAP) NGL project offshore and other capex projects.

•   Unit operating costs for the group are expected to be $14.0-15.0/boe. Strategic maintenance and integrity activities will be the focus for SEPNU in 2025. Targeting short cycle oil growth and laying a foundation for sustained improvements in uptime to support our longer term growth ambitions. 

•   Capital Markets Day in 3Q 2025, where we will detail our medium to long term growth ambitions. 

Roger Brown, Chief Executive Officer, said:

"2024 was truly a defining year for Seplat Energy. In addition to delivering key growth projects in our existing onshore business, we closed out 2024 by completing the acquisition of SEPNU, the largest in the Company's history, which adds significant scale and attractive low-cost growth potential.  In the first few months since the acquisition, it has already become clear that there is significant prize in the offshore shallow water, operating a closed loop system from well-head production to hydrocarbon sales at the terminal.

This year we will focus on re-opening previously shut in wells in SEPNU, alongside another full drilling campaign for our onshore assets and we look forward to delivering first gas at ANOH. We will also accelerate the subsurface work and contracting needed to commence an infill drilling campaign at SEPNU.

Our confidence in the future trajectory for the enlarged business, combined with our strong financial position, means that we are delighted to declare a special dividend again for 2024, lifting the total dividend for 2024 to $16.5 cents per share, an uplift of 10% from 2023.

The Seplat Energy team is rightly proud of its achievements in 2024, and we fully intend to continue our mission to create significant shared value and enhance prosperity for all our stakeholders in Nigeria and beyond."

Summary of performance

*Throughout results FY24 reported figures consolidate SEPNU contribution from the completion date of 12 December 2024

** FY24 reported revenue excludes an underlift of $11 million, FY23 includes an overlift of $99 million

*** Adjusted for non-cash items

Responsibility for publication

This announcement has been authorised for publication on behalf of Seplat Energy by Eleanor Adaralegbe, Chief Financial Officer, Seplat Energy PLC.

Signed:

Eleanor Adaralegbe

Chief Financial Officer     

Investor call

At 12:00 GMT / 13.00 WAT on Tuesday 4th March 2025, 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 the same as for the webcast. 

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). Through our strategy to Build a sustainable business and Deliver energy transition, we are transforming lives by delivering affordable, reliable and sustainable energy that drives social and economic prosperity.

Following the acquisition of Mobil Producing Nigeria Unlimited, Seplat Energy's enlarged portfolio consists of eleven oil and gas blocks in onshore and shallow water locations in the prolific Niger Delta region of Nigeria, which we operate with partners including the Nigerian Government and other oil producers. Furthermore, we have an operated interest in three export terminals including the Qua Iboe export terminal and Yoho FSO, as well as an operated interest in the Bonny River Terminal (BRT) NGL recovery plant. We operate two gas processing plants onshore, at Oben in OML 4 and Sapele in OML 41, and are soon to open the 300 MMscfd ANOH Gas Processing Plant in OML 53 as a joint venture with NGIC. Combined, these gas facilities augment Seplat Energy's position as a leading supplier of natural gas to the domestic power generation market.

For further information please refer to our website; https://www.seplatenergy.com/

Operating review

Reserves and Resources

Following completion of the acquisition of Mobil Producing Nigeria Unlimited ('MPNU'), now renamed Seplat Energy Producing Nigeria Unlimited ('SEPNU'), the Company's oil & gas portfolio now comprises direct interests in eleven oil and gas blocks all of which are located in shallow water, onshore and swamp areas of the Niger Delta. This portfolio provides the Group with a strong inventory of oil and gas reserves and production capacity, as well as material upside opportunities to add reserves through future development activities.

The Group's audited 2P reserves, were assessed independently by Ryder Scott Company, L.P for the onshore assets and by ERC Equipoise for the SEPNU assets. Total 2P reserves increased by 408 MMboe from 478 MMboe at the end of 2023 to 886 MMboe at the end of 2024. The increase in 2P reserves is attributed to 395 MMboe from SEPNU and positive revisions to reserves at OMLs 4, 38, 41 and OML 53.

Working interest 2P reserves as of 1st January 2025

*Due to integrated nature of the SEPNU fields, gas and NGLs resources have not been classified across individual assets

**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% 

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 increased by 432% to 330 MMboe, comprising 89 MMbbls of oil & condensates and 1,402 Bscf of natural gas. The increase was supported by the MPNU acquisition, positive revisions on resources in place, and revision of Abiala 2P gas reserves to 2C resource. Excluding the impact of SEPNU, 2C resources rose 35% to 84 MMboe, comprising 46 MMboe oil & condensates and 220 Bscf of gas.

Working interest 2C reserves as of 1st January 2025

Consequently, the Group's working interest 2P reserves and 2C resources stood at 1,217 MMboe as of 31 December 2024, comprising 669 MMbbls liquids and 3,175 Bscf of natural gas (547 MMBoe). Onshore reserves & resources amounted to 575 MMboe (comprising 274 MMbbls of liquids and 1,745 Bscf of gas) and offshore amounted to 641 MMboe (comprising 394 MMbbls of liquids and 1,430 Bscf of gas).

Note: In the Operating review section, "Seplat Onshore" refers to the legacy assets owned by Seplat Energy prior to the acquisition of MPNU. "SEPNU/Seplat Offshore" refers to the recently acquired shallow water assets.

Group Production

Working interest production for the twelve months ended 31 December 2024

2024 includes 19 days of SEPNU production averaged across the calendar year

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.

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

In 2024, total liquids production improved on 2023, as the Company produced 11.0 MMbbls of oil, 7.1% higher than 10.3 MMbbls delivered in 2023, on a like for like basis. Including the benefit of SEPNU assets from completion, production increased by 19.3% to 12..2 MMbbls. This was partially offset by gas production which was  5.1% lower at 39.5 Bcf (2023: 41.6 Bcf) when comparing on a like for like basis. Including SEPNU's post-completion gas production, total gas production closed at 40.8 Bcf, 2.1% lower than 2023's production. Following completion of the acquisition of MPNU, the Company produced 99.7 kbbls of NGLs in the final 19 days of the year. The production mix, including SEPNU, was 63.2% oil, 36.3% gas, and 0.5% NGLs.

2024 working interest production by quarter 

4Q 2024 includes 19 days of SEPNU production averaged across the quarter

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.

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

Average daily working interest production, excluding SEPNU's production contribution, increased by 1.8% to 48,618 boepd, modestly above the midpoint of our guidance range (46,000-50,000 boepd). The improvement in production was broadly supported by higher production on our Eastern assets following resumption of evacuation via the Trans Niger Pipeline (TNP). In addition, strong well performance from the 2023 drilling program at OML 40 contributed to sustained strong production during the period. Average daily working interest production (inclusive of SEPNU's production) increased by 10.9% to 52,947 boepd in 2024, compared to 47,758 boepd in 2023. As such, reported production, was delivered above the top end of our guidance range.

Seplat Energy Producing Nigeria Unlimited (SEPNU)

Seplat completed the acquisition of SEPNU (previously Mobil Producing Nigeria Unlimited, MPNU) on 12 December 2024. The cash consideration on closing was $800 million, including $128.3 million deposit paid in 2022. All operations have been consolidated since this point and are included in reported accounts. Since the completion of the transaction Seplat has focused on integration of the businesses across people and systems, and budget planning for 2025. These workstreams are progressing well. As part of the transaction up to $300 million may also be paid, subject to certain performance conditions over the period 5 year period 2022-2026. For 2022 and 2023 a total of $43 million was paid (included in closing consideration). For 2024 contingent payment three (CP3) was not paid as the volume performance target was not met.

For the full year 2024, MPNU recorded average working interest production of 69.4 kboepd, down 9% on 2023. Across product lines, 85% was Crude and Condensate, 4% NGL, 12% gas. The Amenam-Kpono field (A/K) contributed 4.0 kboepd to average daily production. 

From 12 December 2024 to year end the annualised average contribution of SEPNU to Seplat daily average working interest production was 4,329 boepd (Liquids: 3,468 bopd, NGLs: 272 bpd, Gas: 3.1 MMscfd).

Since completion of the acquisition the key focus points have been; integration and 2025 budget planning with our JV partner. These discussions have commenced with strong partner alignment to increase opex and capex activities, which are designed to improve integrity, reliability and deliver sustained production growth. The most significant 2025 investments include contracting two additional barges (one for integrity work and the other for well work to restore production from idle wells) and replacement of the Inlet Gas Exchanger (IGE) on EAP NGL facility.

In addition a number of projects will be undertaken, within operating and maintenance ('O&M'). The work program is designed to provide a strong foundation that will lead to improved uptime supporting further production growth in 2026 and beyond.

The Company has also begun planning for longer term growth activities including drilling of new production well stock, which requires contracting a jack-up rig, and other key growth opportunities such as new field developments and commercialisation of the large gas resource base.

Seplat Onshore

Western Assets

In OMLs 4, 38, & 41, working interest liquids production rose by 0.8% to 14,992 bopd (2023: 14,866 bopd). The marginal improvement in liquids production was due to improved export route availability through the year compared to 2023 when the Trans Forcados Pipeline (TFP) - Forcados Oil Terminal (FOT) export route was unavailable for a combined 69 days in the second half of 2023. Some operational challenges on the TFP-FOT route were experienced as leak repairs were carried out on the line in September and October incurring 40-days downtime. However, due to availability of the AEP-EOT route, impact on operations was minimal, again highlighting the benefit of having multiple evacuation route options. Total deferments on our western assets for 2024 was 18%, a significant improvement on 2023's 26%.

Elcrest

Production at OML 40 continued to improve during the year as average daily working interest production rose by 10.1% to 11,506 bopd, from 10,455 bopd in 2023. The improved production is due to the impact of a successful drilling campaign, improved well performance, and improved availability of evacuation routes during the year. For context, overlapping downtime on our alternative evacuation routes was one day in 2024. Total deferments on OML 40 was 13%, significantly lower than 30% recorded in 2023. 

Sibiri oil field

In our FY 2023 results, we communicated the receipt of regulatory approval for the full lifecycle field development plan for Sibiri oil discovery in February 2024. The well performance recorded at Sibiri has been strong, reflected in OML 40 growth 2024 vs. 2023) and supports additional development drilling.

We are pleased to confirm plans to drill three wells (Sibiri-C, Sibiri-D, & Sibiri-E) at the Sibiri field in the 2025 drilling program as part of the development phase of the project. The Sibiri well program will commence in H2-2025, and are expected to produce at a gross rate of approximately 4,800 bopd when onstream.

Abiala oil development

We achieved first oil at the Abiala Marginal Field on 15th September following completion of an extended well test at Abiala-01. Abiala produced crude through an extended well test ('EWT') during part of Q4 2024, resulting in the production of 6,978 barrels of oil (annualised average 19 bopd) which was barged and trucked to storage.

The EWT was renewed in January 2025 and the well has been producing, via a single production string, at c.1,000 bopd through the test separator. On 13th February 2025 the field development approval ('FDP') was received from the Nigerian Upstream Petroleum Regulatory Commission (NUPRC), and as such, work has commenced to begin production from all four production strings across the two wells (Abiala 1 W/O and Abiala-2). We retain our target for gross field production at c.5,000 bopd, and forecast reaching this level in Q2 2025.   

Eastern Assets

In OML 53, daily working interest production increased 60% to 1,933 bopd in 2024, from 1,212 bopd in 2023, due to improved access to evacuation routes for the asset during the year. We reported in our Q1 2024 results that the TNP export line resumed preliminary operations before progressing to daylight operations, and during Q4 2024 the pipeline re-commenced 24-hour operations. Production from our Ohaji field is now split between the Waltersmith refinery (WSR) and the TNP line for export via the Bonny terminal.  

Production from our Jisike field improved significantly in the final quarter of the year as the reliability of the Antan-Ebocha-Brass terminal route improved. The line had an uptime of 89% in the final four months of the year, compared to 31% in the first eight months. For context, the magnitude of improvement in production from OML 53 in Q3 and Q4 2024 is reflected in production increasing by 85% and 129% respectively.

In OPL 283, production declined marginally by 0.5% to 1,547 bopd (2023: 1,554 bopd).

Drilling activities

In our 2024 drilling programme, we completed 11 of the 13 well plan during the year, with the final two wells completing shortly after year end. The campaign focused on our assets in OMLs 4, 38, & 41 and OML 40. Eight wells from the 2024 programme are currently contributing to production, adding a combined 6,000 bopd and 46 MMscf/d on a gross basis.

In OML 4, 38, & 41, we delivered seven wells (Ovhor-21, Ovhor-22, Ovhor-23, Sapele-38, Oben-55, Oben-56, & Oben-54) within the financial year. All the completed wells except Ovhor-23 are now onstream and contributing to production. Ovhor-23 which has been completed is currently shut-in, pending completion of bottom hole pressure (BHP) survey. The final two wells in the 2024 plan, Ovhor-24 and Oben-57 finalised installation of their respective production strings early in 2025. The wells are expected to produce at a combined gross rate of 3,500 bopd and 3.9 MMscfd, once onstream.

At OML 40 and Abiala marginal field, we completed the four wells in the drilling program for 2024. Gbetiokun-12, Gbetiokun-13, Abiala-1 W/O, and Abiala-2 were the wells completed during the year. Production has commenced from Gbetiokun-12. Production is expected to commence from Gbetiokun-13, Abiala-1 W/O  and Abiala-2 in Q1-2025 with a combined target gross production of approximately 6,500 bopd.

Midstream Gas business performance

Seplat Energy continues to play a critical role in expanding the domestic gas market to fuel the Nigerian economy's growth. During the period, the Company delivered 40.8 Bcf (2023: 41.6 Bcf) of gas, and 39.5 Bcf excluding the contribution from SEPNU. The average daily working interest gas production volumes decreased by 2.3% to 111.4 MMscfd, from 114.1 MMscfd in 2023. Excluding SEPNU's production, average daily working interest gas production volumes decreased by 5.3% to 108.0 MMscfd. The decline in gas production was due to the two-week shutdown of the Oben gas plant for the turnaround maintenance (TAM) activities as well as the impact of delays in bringing new gas wells onstream in the first half of the year. As detailed below, progress on major onshore gas midstream projects continues and we expect onshore gas production to grow in 2025.

The business continues to pursue growth opportunities to maximise the utilisation of the Oben gas plant. During the year, the Company signed three new Gas Sales Agreements (GSA) in addition to existing contracts. The new off-takers are taking up to a combined 100 MMscfd. We continue to negotiate with additional potential buyers for new gas sales contracts as gas demand continues to grow in the domestic market.

Oben Gas Plant

The turnaround maintenance (TAM) activities of the Oben gas plant were successfully carried out during August. The TAM was completed ahead of schedule and under budget with the gas plant restarting on August 28th, one day ahead of plan. Alongside statutory activities, a number of additional activities were delivered concurrently, such as; debottlenecking of condensate separators, conversion of in-let valves to support lower pressure production, tie-ins for western assets flares out projects, an upgrade of the gas metering system and a power upgrade for a new 1.2 MVA gas Gen Set, delivering on our corporate diesel displacement initiatives.

Following completion of the TAM activities, gas production has significantly improved, with average daily working interest production of 121.1 MMscfd in Q4 2024, this includes peak working interest daily production of 132.3 MMscfd recorded on 11 December.

Sapele Gas Plant

The Sapele Gas Plant is an 90 MMscfd plant, capable of processing both Non-Associated Gas (NAG) and Associated Gas (AG) which meets export specifications and LPG processing module which would supply LPG to the domestic market. The project will also contribute significantly to Seplat's target to end routine flaring by the end of 2025.

Work at the new Sapele Gas Plant has continued through the year. The initial 30 MMscfd Mechanical Refrigeration Unit ('MRU') was completed in Q4 2024, inline with expectations. The start of commercial operations began in February 2025, and the first module is currently ramping up to full capacity. 

In 2025, work will continue for the second MRU, which will lift total production capacity to 90 MMscfd. The upgraded facility will produce gas that meets export specifications, and the LPG processing module will enhance the economics of the plant and eliminate routine gas flaring.

We note that in early 2025, the combination of Oben and Sapele gas plants in operation has seen onshore gas production regularly exceed 300 MMscfd on a gross basis (>135 MMscfd on a working interest basis).

ANOH Gas  

In 2024, AGPC achieved 14.7 million man-hours without Lost Time Injury. We are pleased to note that the ANOH gas plant is now ready to receive commissioning gas, doing so in the early part of 2025.

The river crossing element of the OB3 line in H2 2024 has continued to prove technically challenging for NGIC and at the year end the tunnelling operations remained at 1.12 km of the 1.85 km of the river crossing. Significant additional equipment has been delivered to site and tunnelling should be restarted this week with a target completion in early 2Q 2025. This is a top priority for NNPC as well as the government, and we monitor progress on a continuous basis.

The ANOH gas plant commissioning plan continues to progress. The original plan was to use processed gas (dry gas) from the OB3 pipeline to commission the plant, but given the segment of the OB3 line needed is not yet operational, the Company has opted to purchase gas from a third party to complete plant commissioning, which will enable the plant to be ready for startup during 2Q 2025, in line with our revised plan.

As reported previously the upstream wells and partner operated spur line are in a state of readiness for operation.

With support of our partner, we are advancing discussions with 3^rd party gas offtakers in the Eastern part of Nigeria who do not require the OB3 (one of which had previously executed a 50MMScfd gas supply agreement, with a desire to increase to 100MMscfd in the first half of 2026) thereby allowing the startup of the ANOH gas plant, while we wait for completion of the OB3 pipeline to enable the plant to reach full production.  We expect volumes of gas to flow to other customers from 3Q 2025 with a potential to flow up to half the capacity of the plant. 

As we have done in the past, we have added 6 months to the expected date for commissioning of the pipeline as communicated by our partner and thus we have subsequently moved the date for transporting gas through the OB3 to 4Q 2025.

New Energy Business

In line with our strategy to deliver energy transition, we continue to assess various midstream gas, power, and renewable investment opportunities that are focused on increasing energy supply and reliability, while lowering costs and reducing the carbon intensity of Nigeria's electricity consumption.

In 2024, following detailed review, we decided not to progress a potential investment in the power sector due to timing in relation to closing out the MPNU acquisition. In 2025 we continue to assess a number of potential investment opportunities, and in the early part of the year are interrogating an opportunity in Compressed Natural Gas (CNG) market. Furthermore we are exploring options to bring third party gas into Oben gas plant in order to increase long term gas plant utilisation.

Ending routine flaring

Reducing the carbon intensity of our operations is a key strategic focus. Seplat has implemented its end of routine flaring (EORF) roadmap, which includes investments across our production facilities to minimise Scope 1 & 2 greenhouse gas emissions and improve overall energy efficiency.

The carbon intensity recorded on Seplat onshore for the period was 32.3 kg CO2/boe, higher than the 29.4 kg CO2/boe recorded in 2023. The increase in carbon intensity was primarily driven by increased production from our Eastern assets following reinstatement of TNP Zone 6. Wells in our Eastern asset are gas-rich which leads to associated gas emissions as production increases. The shutdown of the Oben Gas Plant during the TAM activities carried out in August led to higher emissions during the two-week period, also contributing to higher carbon intensity compared to last year.

As we stated in earlier sections (Sapele Gas Plant), the first module of SIGP has commenced operations and is now producing. Once the plant is operating at capacity, expected during 2025, it has the potential to materially reduce the Group Scope 1 emissions.

Other ongoing key flare-out projects, including the Western Asset Flares Out (installation of vapour recovery unit compressors), Sapele LPG Storage & Offloading Facility, Oben LPG Project and Ohaji Flares Out Project. The Company is on track to end routine flaring of gas across its onshore assets in 2H 2025.

We are currently assessing the flaring regime within SEPNU, and will report on emissions from 2025. Current planning includes potential strategies which may be deployed to reduce emissions.

HSE Performance

The Company achieved a total of 11.0-million hours without any Lost Time Injury (LTI) on its operated assets in 2024 (2023: 8.7-million hours), which reflects the Company's strong focus on safety and the dedication of its workforce to maintaining a secure work environment. Till date, the Company has achieved a cumulative 21.5-million-man hours since last LTI recorded (on 13th October 2022). In addition, TRIR was flat at 0.046 with five medical cases reported during this period. No Tier 2 Process Safety Loss of Primary Containment (LOPC) incident were recorded during the period. We note that there we no LTIs, nor TRIRs on SEPNU assets in the period post completion.

The Company is on a path to achieve ISO 45001 and 14001 standards certifications, demonstrating its commitment to top-tier safety and environmental performance. During the year, we completed stage one regulatory audit for ISO 14001 while stage one regulatory audit for ISO 45001 is expected to be completed in March. Overall, we expect to achieve these standards certifications by the end of Q2-2025 after completion of stage two regulatory audits. These certifications are globally acknowledged benchmarks for occupational health and safety management systems and environmental management systems, respectively.

Several activities took place during the year as part of efforts to continue to strengthen our safety protocols. We conducted stakeholder engagement on work at height, lifting & hoisting, and excavation procedures to ensure safety excellence in operations. We also completed biodiversity action plans (BAP) field data gathering, GHG scope 3 emissions employee surveys, and installation of water meters across all our assets.

Petroleum Industry Act (PIA) Implementation Status

Seplat made a conditional application to convert its onshore assets to the PIA in October 2022 and executed conversion contracts with the commission in February 2023 to preserve its right to convert to the PIA subject to the evolution and resolution of the regulatory landscape.  Through 2024, the Company undertook extensive technical reviews with the commission to delineate its acreages with the purpose of determining mining leases and prospecting license areas for retention, areas for relinquishment as well as the minimum work program commitments on retained license areas. These engagements were completed in November 2024 and Seplat made its final submission to the Commission in December 2024 based on agreed position. Seplat is pleased with the completion of this technical process which has been on the critical path to completing the Company's PIA conversion process.

After the period end, On 25^th February, 2025 the Commission wrote to Seplat acknowledging that delineation has been made based on principles established in section 93 of the PIA, 2021. The Commission has requested documentations from Seplat that would facilitate the preparation of legal transfer documents on the retained PMLs and PPLs. Seplat will progress this accordingly.

Following the acquisition of MPNU, Seplat will be engaging with the Commission to resume the process of conversion of its offshore assets to PIA. Further updates will be provided in due course.

Outlook

Production guidance

Seplat Energy's production operations were robust in 2024, supported by measures to diversify evacuation routes and continued positive security environment. This is expected to continue in 2025 where we target growth from both onshore and offshore operations.

Initial 2025 production guidance is set at 120-140 kboepd. This includes:

•   Seplat Onshore: 48-56 kboepd. mid-point delivers 7% growth on 2024. Production in 2025 is set to benefit from well stock delivered in 2024, plus contribution from ANOH from 2H25, Sapele Gas Plant and Abiala through the year. We also see growth on OML 53 oil given resumption of 24-hour operations on TNP.

•   SEPNU: 72-84 kboepd. mid-point delivers 12% growth on 2024. We are targeting growth from restoration of idle wells, investment in improving reliability of the NGL facilities and other activities which will improve uptime and provide the basis for longer term growth plans. 

Capex guidance

Working interest capital expenditure for 2025 is expected to be in the range of $260-$320 million.

•   Seplat Onshore: $180-220 million. Key focus is new well stock to offset natural decline

•    Program includes drilling 13 new wells: OMLs 4, 38 & 41: Seven, OML 53: Two, OML 40: Four. Of these, 9 are oil wells and 4 are gas wells

•    Completion of the second MRU at the Sapele IGP

•    Delivery of Oben, Amukpe, Sapele & Ohaji flares out projects

•   SEPNU: $80-100 million. Key focus on capital projects and long term planning to improve reliability, uptime and safety

•    Installation of the Inlet Gas Exchanger on the East Area Project (EAP) NGL facility

•    Long lead items for 2026+ drilling program

Opex guidance

Unit operating costs for the Company are expected be in the range of $14.0-15.0/boe. This increase in unit operating costs versus prior years reflects increased investment in O&M activities across our offshore assets, mainly re-opening previously shut-in wells. Our expectation is that unit opex will moderate post 2025 as production grows and as investment pivots towards capital projects. In 2025 the major cost items are: 

•   Contracting two barges to operate across the offshore license area from early 2Q 2025, one targeting integrity works and the other working on idle wells, targeting 20+ wells in 2025.

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The primary goal of the 2025 opex plan is to increase reliability and integrity offshore which will set a solid foundation from which to grow production over time. Due to the nature of the installed infrastructure offshore, the 2025 plan necessitates partial asset shut-downs, particularly in 2Q and 3Q 2025.

Sustainability

Our ESG (Environmental, Social, and Governance) performance and 2025 targets reflect our continued emphasis on ESG measurement and reporting. In line with our climate strategy, which includes a commitment to achieving carbon neutrality by 2050, our immediate priority is to eliminate routine flares across our onshore assets by the end of 2025. This is a major project covering multiple production locations, completion is planned for 2H 2025 and will align our commitment to environmental sustainability and regulatory compliance. This initiative will significantly reduce our carbon intensity and contribute to our broader sustainability objectives.

We recognise the importance of the sustainability of our evacuation options and strive to bolster security measures along our evacuation routes to safeguard our operations. These initiatives are geared towards maximising the volume of oil sales and revenue for the Company, highlighting our commitment to operational efficiency and financial sustainability. These deliverables underscore our dedication to innovation, sustainability, and value creation across all operations.

Financial & Strategic guidance

Our financial strategy ensures we can appropriately fund our capital expenditure, meet necessary debt repayments, and return cash to our shareholders. It is a strategy which provides the flexibility required to realise the value of our asset base. Our revenue stream is biased to US dollar denominated oil exports, while we also have a Naira revenue stream via gas sales and domestic oil supply that funds our significant Naira cost base. We continue to closely monitor the performances of oil prices, currency fluctuations and evacuation routes, and their implications on cash generation to appropriately scale and phase our capital allocation, ensuring that we have a sound financial platform from which we can grow.

The tenor of the Company's $350m revolving credit facility is tied to the refinancing of the $650 million notes, whereby the current final maturity date of 30 June 2025 will automatically extend to 31 December 2026 if the notes are refinanced before 30 May 2025.

With respect to G&A, in 2025, we forecast normalisation of cost coupled with the benefit of higher group production levels, as such we forecast unit G&A in a $4.5-5.0/boe range.

With respect to shareholder returns, we will maintain our policy of paying a progressive quarterly core dividend in the near term, with an option of a special dividend subject to performance.

In order to provide more granular details on our medium and long term plans for SEPNU and the business as a whole we will host a Capital Markets Day, which is planned for 3Q 2025. We will also present an updated CPR which reconciles the reserves and resources indicated by the ERCE and the SEPNU management estimates as carried by Exxon prior to the sale.

Financial review

2024 results benefited from higher production, particularly oil production. This was partially offset by Brent oil price which averaged 3% lower than in 2023 at $79.86/bbl, and lower gas production. Our onshore operations, recorded average realised oil price of $81.48/bbl, a $1.62/bbl premium to Brent, while our blended realised gas price delivered strong growth, averaging $3.16/Mscf, a 9% increase on 2023. SEPNU's operations have been consolidated post 12 December 2024 completion, as such average realised oil and gas prices reported for 2024 were modestly lower at $80.04/bbl, principally given weaker commodity pricing in 4Q 2024 while average realised gas price was $3.06/Mscf for the enlarged group.

Revenue

Total revenue from oil and gas sales for 2024, including the consolidation of SEPNU, rose 5.2% to $1,116.2 million from $1,061.3 million in 2023. Adjusting reported revenue for 2024 underlifts and 2023 overlifts, total oil and gas sales were $1,126.7 million ($10.5 million underlift), 17.1% higher than 2023's equivalent revenue figure of $962.4 million ($98.9 million overlift).

Excluding the impact of SEPNU, and adjusting for underlift(overlift), total oil & gas revenue was stable at $961.2 million. 

Reported crude oil revenue, including consolidation of SEPNU, rose 6% to $991.0 million in 2024 from $937.9 million in 2023, supported by 2.6 MMbbls of crude lifted in SEPNU between completion and year end 2024. Excluding the impact of SEPNU, crude oil revenue fell 14.9% to $798.5 million in 2024. The lower crude oil revenue on our onshore assets was principally due to lower liftings during the period. Total onshore crude oil liftings in 2024 fell 13% to 9.8 MMbbls in 2024 (2023: 11.3 MMbbls).

Reported gas revenue rose by 1.3%, reaching $124.9 million in 2024, compared to $123.4 million in 2023. Gas sales represented 11% of total reported revenue in 2024. Excluding the impact of SEPNU, gas sales for the onshore business was $121.8 million (2023: $123.4 million), representing 13% of total sales. The decline in gas sales is attributed to the 5.0% decline in gas sales volume, which offset the 9.0% increase in realised gas prices by Seplat Onshore.  

The business recorded $0.3 million revenue from Natural Gas Liquids (NGLs) sales during the 19-day operating period of SEPNU in 2024.

The group's average reconciliation loss factor remained stable at 3.4% in 2024 (compared to 3.5% in 2023), attributed to enhanced security measures and strengthened asset integrity management during the period.

Note: throughout the Financial review section (pages 11-15) "FY-2024 Reported" includes 19 days of SEPNU on the income statement and cashflow items. "FY2024 Onshore" reflects the Company's 2024 performance excluding SEPNU. This has been included to illustrate the underlying performance of the Company prior to the combination. "FY-2023 Reported" reflects the Company's 2023 performance. The 2024 balance sheet is consolidated.

Gross profit

In 2024, gross profit fell 9.8% to $479.9 million, from $532.0 million in 2023. Excluding the impact of SEPNU, gross profit declined 31.9% to $362.5 million. The decline is attributed to lower oil liftings and higher direct operating costs.

Direct operating costs, which encompass expenses related to crude-handling charges (CHC), barging/trucking, operations & maintenance, amounted to $295.5 million in 2024, of which $75.8 million were related to SEPNU operations. SEPNU operating cost included certain costs related to the transaction which are not expected to repeat in 2025. Excluding the impact of SEPNU direct operating costs rose to $219.7 million, a 20.6% increase on the $182.2 million incurred in 2023. The increase in costs was principally due to due exceptional costs of $21.9 million related to legacy regulatory payments and due to a higher gas flare penalty which rose $16.1 million to $27.7 million, following an upward revision in the unit cost basis of the gas flare penalty by the Nigerian government.

Non-production costs decreased by 2.3% to $325.3 million, made up of $146.0 million in royalties (2023: $183.4 million), of which SEPNU contributed -$10.6 million, and $179.3 million in depreciation, depletion, and amortisation (2023: $149.6 million), of which SEPNU contributed $26.0 million. The lower royalties payment in 2024 is due to recovery of OML 53 JV partner share of royalties incurred on sale of crude to the Walter Smith Refinery ("WSR") between 2022 and 2024. Prior to the agreement reached with NUIMS to begin sharing in crude sales to WSR, Seplat had been the lone seller in the JV and as a result incurred 100% of the royalties. With an agreement now in place to net off the overlift position against outstanding cash calls, we were able to recover NUIMS 60% share of the royalties.  

Considering the cost per barrel equivalent basis, on a reported basis production operating expenses (opex) were $15.2/boe. Excluding the impact of SEPNU, unit opex in the onshore business amounted to $12.3/boe in 2024, elevated due to items noted above and higher than the to $10.4/boe in 2023.

Operating profit

In 2024, reported operating profit rose 75.6% to $437.9 million, from $249.4 million in 2023. Excluding the impact of SEPNU, operating profit grew by 42.4% to $355.1 million.

The increase in reported operating profit was driven primarily by the gain on bargain purchase of $86.0 million recorded on the acquisition of Mobil Producing Nigeria Unlimited ("MPNU"). Other drivers include FX gain of $30.1 million and underlift of $10.5 million in 2024 compared to FX loss of $27.5 million and overlift of $98.9 million in 2023. The FX gain reported in the period is further to the agreement with our JV partner, NUIMS, to net off outstanding cash calls in OML 53 and our subsequent re-denomination of overlift liabilities in Naira. This is in contrast to the FX loss reported in prior year arising from the Naira devaluation. The FX gain reported in the period is further to the agreement with our JV partner, NUIMS, to net off outstanding cash calls in OML 53 and our subsequent re-denomination of overlift liabilities in Naira. This is in contrast to the FX loss reported in prior year arising from the Naira devaluation.

Reported G&A expenses amounted to $147.2 million, modestly higher than the figure reported in the prior year (2023: $143.6 million). G&A expenses have been elevated since 2022, in 2024 the higher G&A costs were principally due to fees associated with the acquisition of MPNU. These are not expected to repeat in 2025. Reported unit G&A cost for the year was $8.2/boe, excluding exceptional items, unit G&A expenses for Seplat Onshore and the enlarged group would have been approximately $5.7/boe and $5.2/boe respectively. 

Seplat remains committed to managing costs across the business effectively in 2025. We also expect some of the one-off costs in recent years associated with professional fees to wind down in 2025. 

Adj. EBITDA

After adjusting for non-cash items such as impairment, fair value, and exchange losses, the adjusted EBITDA for the period was $539.0 million (2023: $447.9 million), resulting in a margin of 48.3% (2023: 42.2%). Excluding the impact of SEPNU, adjusted EBITDA was $440.0 million resulting in a margin of 47.8%.

Taxation

The income tax expense of $234.7 million (2023: $67.3 million) includes a current tax charge of $193.7 million (2023: $84.1 million) and a deferred tax charge of $41.0 million (2023: $16.8 million credit). Excluding the impact of SEPNU, the total income tax expense for the onshore business was $170.5 million, including a deferred tax liability of $97.7 million (2023: deferred tax asset of $16.8 million). We note that current tax expense component for Seplat onshore of $72.8 million is lower than 2023 ($84.1 million) after adjusting for the impact SEPNU's current tax expense.

Cash taxes paid in 2024 was $68.0 million, modestly higher than the $62.1 million paid in 2023, representing approximately 17.7% of operating cash flow. The cash tax paid reflects continuing investments across our asset base.

Net result

On a reported basis profit before tax rose 98.4%, amounting to $379.4 million, compared to $191.2 million in 2023. Profit after tax grew by 16.9% to $144.8million in 2024, from $123.9 million in 2023. Excluding the impact of SEPNU, profit after tax was flat at $122.9 million.

The profit attributable to equity holders of the parent Company, representing shareholders, was $153.3 million in 2024, which resulted in basic earnings per share of $0.26 for the period (2023: $0.14/share).

Cash flows from operating activities

During the period, the Company generated $383.5million in cash from its operating activities, a 26.2% decrease from the $519.9 million generated in 2023 predominantly due to, the underlift reported in the period, alongside transaction costs and the working capital effects associated with consolidating SEPNU. Excluding these elements, cash flow from operations would have been approximately $83 million higher.

Net cash flow from operating activities amounted to $310.0 million in 2024, compared to $442.0 million in 2023. This figure includes modestly higher cash tax payments of $68.0 million and a hedging premium of $5.0 million paid during the current period, while in the previous year, cash tax payments were $62.1 million, and the hedging premium paid was $5.4 million.

Seplat Onshore had a strong year for cash call collection, highlighting our continued good relationship with our JV partners. On the NEPL/Seplat JV for OML 4, 38, 41, we received a total of $352 million in cash call settlement for 2024, bringing the cash call receivable balance for the year to $69 million (2023: $83 million). On the NUIMS/Seplat JV for OML 53, we received $66 million in cash call settlement which brought the year end balance to $16 million (2023: $21 million). Total cash call payments received in 2024 was 47% higher than 2023 receipts.

Due to the SEPNU acquisition, we took over several working capital balances that impacted cash flow from operating activities in 2024.

Cash flows from investing activities

In 2024, the total net cash outflow from investing activities was $658.9 million, an increase on the $159.3 million expended in 2023. The significant increase in net cash outflow from investing activities is primarily due to the costs associated with the MPNU acquisition. Net transaction cost of $489.6 million, reflects the completion amount of $672.3 million net of $182.7 million cash balance acquired on closing.

The cash capital expenditure on oil & gas assets during the period was $202.6 million (2023: $179.0 million), including $139.0 million in drilling activities and $63.5 million in engineering projects. Total capex (including other fixed assets) was $208.1 million (2023: $183.9 million). Capital expenditure was slightly above plan in the year, predominantly due to higher drilling costs.

During the year, the Company completed the negotiation for the sale of Turnkey rigs (formerly known as Cardinal Drilling Rigs) for the sum of $12.3 million. At year end the Company had received $8.5 million, a further $1.0 million was received in January 2025.  In addition, we received $6.2 million related to our disposal of Ubima, and $10.9 million related to our interest in OML 55.

Cash flows from financing activities

Net cash inflow from financing activities was $409.6 million, compared to an outflow of $196.7 million in 2023.

The net cash inflow recorded in 2024 is reflective of proceeds from RCF drawdown and Advanced Payment Facility with ExxonMobil Trading, totalling $650.0 million. The proceeds were used to fund the completion payment for the MPNU acquisition. Outflows included dividends paid to Shareholders amounting to $91.4 million (2023: $98.8 million paid) and a charge of $19.5 million relating to Seplat Energy's Long-Term Incentive Plan. The Trustees hold the shares under a Trust for the benefit of Seplat Energy employee beneficiaries covered under the Trust. In addition, $62.5 million for interest on loans and borrowings, was flat versus 2023. A further $21.5 million for other financing charges is associated with commitment fees and other transaction costs incurred on interest-bearing loans and borrowings. The loan repayments of $38.5 million, in two $19.25 million tranches, during the period represent principal repayments of the Eland Senior RBL Facility.

Debt Repayments

The $110 million Westport RBL Facility (RBL Facility) commenced amortising on 31 March 2023. The reduction in facility commitments will be on a semi-annual basis on March and September of each year until final maturity in 2026. In 2024, Seplat paid $38.5 million in principal repayments under the RBL Facility in two tranches on 31 March 2024 and 30 September 2024  As at 31 December 2024, $49.5 million is outstanding under the RBL Facility. The next reduction in commitments will be on 31 March 2025 for an amount of $19.25 million.

As the Company continuously reviews its funding and maturity profile, it continues to monitor the market to ensure that it is well positioned for any refinancing and or buyback opportunities for the current debt facilities - including potentially the $650 million 7.75% 144A/Reg S bond which matures in April 2026.

The tenor of the Company's $350m revolving credit facility is tied to the refinancing of the $650 million notes, whereby the current final maturity date of 30 June 2025 will automatically extend to 31 December 2026 if the notes are refinanced before 30 May 2025.

Liquidity

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

*      Including amortised interest and

**     accrual for the RCF (undrawn) commitment fee

*** $1,353.5 million in adjusted EBITDA 2024 represents the FY 2024 pro-forma adjusted EBITDA for Seplat and SEPNU combined

Seplat Energy ended the year with gross debt of $1,367.6 million (2023: $755.4 million) and cash at bank of $469.9 million (2023: $450.1 million), leaving net debt at $897.7 million (2023: $305.3 million). The increase in the debt balance reflects the addition of the $350 million RCF and the $300 million advance payment facility, both drawn to fund the completion payment of the MPNU acquisition. Excluding the impact of MPNU related borrowings, gross debt would have declined by 7.3% to $700.5 million.

We continue to monitor the Net Debt-to-EBITDA ratio of the Company with a focus to keep it under 2.0x (Debt covenant - 3.0x). At the end of 2024, proforma Net Debt-to-EBITDA ratio closed at 0.66x, from 0.68x in 2023.

Dividend

The Board has approved/recommended a core dividend of US$ 3.6 cents per share for the final quarter 2024 (subject to appropriate WHT).  This brings the total core dividend declared for 2024 to US$ 13.2 cents per share, a 10% increase on 2023. In addition, following a review of Seplat's operational performance and business outlook, the Board has decided to declare an additional special dividend of US$ 3.3 cents per share (subject to appropriate WHT). The 4Q 2024 and special dividends will be paid to shareholders whose names appear in the Register of Members as at the close of business on 9 May 2025 (LSE), 12 May 2025 (NGX). This brings the total dividend declared for 2024 to US$ 16.5 cents per share, a 10% increase on 2023. The payment of the special dividend reflects the Board's continued confidence in the outlook for the Company and is underpinned by a strong balance sheet. The Company will review its dividend policy through 2025 as part of the overall capital allocation policy of the enlarged group.

Hedging

Seplat Energy's hedging policy aims to guarantee appropriate levels of cash flow assurance in times of oil price weakness and volatility. The total volume hedged in 2024 was 6.0 MMbbls at a weighted average premium of $0.81/bbl and a weighted average strike price of $60.0/bbl.

The 2025 hedging program has commenced using an equivalent strategy as previously employed, at larger scale. Year to date 15.75 MMbbls have been hedged for 1Q-3Q 2025 at a weighted average premium of $0.76/bbl and a weighted average strike price of $55.0/bbl. Additional barrels are expected to be hedged for 4Q 2025 later in the year. The Board and management team closely monitor prevailing oil market dynamics and given the relatively softer oil price outlook for 2025 have hedged three quarters in advance, providing longer dated cash flow assurance than our typical, two quarter in advance, strategy.

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 (positive) (ii) S&P B (stable) (iii) Fitch B- (positive).

In October 2024 Fitch maintained our corporate rating at B-, but upgraded our outlook to positive, this was linked to an upgraded outlook for the Nigerian sovereign long term rating and the agency's view of a stronger business profile post the completion of the MPNU acquisition. Our ratings with S&P and Moody's were reaffirmed in April 2024 and December 2024 respectively.