Please see the Full Audited Results in attached PDF

http://www.rns-pdf.londonstockexchange.com/rns/3520G_1-2025-4-27.pdf

Unaudited results for the three months ended 31 March 2025

28 April 2025

Overview

Lagos and London, 28 Apr 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 three months ended 31 March 2025.

Summary

Delivered robust production and cost performance during 1Q 2025, at a new scale, and firmly on track to deliver FY 2025 guidance. Strong cash position supports early repayment of $250 million reducing the RCF to $100 million, and an increase in our quarterly dividend to US$ 4.6c/share.

Operational highlights

Financial highlights  

Dividend & Board

2025 Outlook

Roger Brown, Chief Executive Officer, said:

"2025 has started positively for Seplat. As we deliver the business at a significantly enhanced scale, our focus is on the successful integration of the combined companies, and I am pleased to report that we are making good progress. It is clear that we can benefit greatly from the combined expertise of our onshore and offshore workforce.

Production has been strong, showing the benefit of the continuous drilling programme, investment in asset integrity and the availability of multiple evacuation routes. Financial performance was also strong, allowing us to be pro-active in materially reducing gross debt, maintaining low balance sheet leverage, and further strengthening our company as the near term global economic outlook becomes less predictable.

We remain conservative in our approach, but our confidence in the future trajectory for our business, combined with our strong financial position, means that we are delighted to increase our quarterly dividend to $ 4.6c/share,  an 28% increase in our quarterly dividend versus 4Q 2024. Our assets are high quality, and while we will remain agile to the prevailing oil price environment, our business plan is designed to be robust at lower oil prices and our gas revenues, which are largely delinked to oil prices, provide long-term stability for the business. We are committed to our plan of growth and maximising value for our stakeholders."

Summary of performance

*Throughout results 1Q 2025 reported figures consolidate SEPNU contribution, while 1Q 2024 information relates solely to Seplat's Onshore assets

** 1Q 2025 reported revenue includes an overlift of $53.5 million, 1Q 2024 excludes an underlift of $56.4 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     

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

Group Production

Working interest production for the three months ended 31 March 2025

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 1Q 2025, total crude & condensate production increased by 224% to 9.0 MMbbls, compared to the 2.8 MMbbls produced in 1Q 2024. Total gas produced during the quarter also rose 50% to 14.9 Bscf (1Q 2024: 10.0 Bscf), and we also produced 304 kbbls of NGLs in 1Q 2025. As such, aggregate production for the quarter rose 164% to 11.8 MMboe (1Q 2024: 4.5 MMboe). This reflects the transformational impact of the SEPNU consolidation and strong performance on our onshore assets. We provide more details on drivers of this performance in subsequent sections.

Average daily working interest production for the group was 131,561 boepd (1Q 2024: 49,258 boepd), slightly above the midpoint of our production guidance of 120,000 - 140,000 boepd. 

Production performance in our onshore assets was strong, up 14% from the equivalent period in 2024 (1Q 2025: 56,196 boepd; 1Q 2024: 49,258 boepd), aided by a confluence of several positive catalysts including good performance of the new wells in the 2024 drilling campaign, commencement of gas production from Sapele Integrated Gas Plant (SIGP), improved gas production from Oben following turnaround maintenance, and continuation of 24-hour operations at the Trans Niger Pipeline (TNP).

Seplat Energy Producing Nigeria Unlimited (SEPNU)

Production across the offshore assets started the year in-line with expectations with daily average working interest production during 1Q 2025 of 75,365 boepd. January and February benefited from high uptime, while in March we commenced a number of planned shutdown operations to improve long term asset performance.

Across product lines, production was 88% crude and condensates, 4% NGL, and 8% gas. The Amenam-Kpono field (A/K) contributed 3.1 kboepd to average daily production of which 26% was crude and condensate and the balance gas.

During 1Q 2025 we commenced the 2025 work programme, and we are pleased to report that, after period end, we achieved 2025 budget planning sign-off with our JV partners

The programme to resume production from idle wells across the license commenced during the period. At period end, approximately 11 kboepd gross production capacity has been reinstated from the idle well restoration programme. This has been achieved from 10 idle wells, that could be accessed directly from certain existing platforms. The jack-up barge has now moved to well work activities and commenced well interventions after the period end. Combining both platform and well work barge activities, we are now targeting production restoration work on over 50 of the idle well inventory in 2025.

The East Area Project ('EAP') Inlet Gas Exchanger (IGE) replacement project will increase gross JV NGL production at EAP by 8 to 10 kboepd when operational. Fabrication of the IGE unit was completed in the OEM facility (Germany) and transported in-country. Construction works, including onshore interconnect piping fabrication and offshore installation campaign have commenced and installation is expected to complete during 3Q 2025.

Other planned maintenance activities increased during March, included a nested shutdown across three major platforms to address full function testing of critical safety devices and replacement of multiple valves, rises and piping. These activities impacted production across Crude, NGL and gas in the period. Gas sales were also impacted by a leak on third party infrastructure.

Seplat Onshore Operations Update

Western Assets

In OMLs 4, 38, & 41, working interest liquids production rose by 8% to 16,291 bopd (1Q 2024: 15,089 bopd). The growth was aided by the successful 2024 drilling campaign which helped to arrest decline on the assets and support growth. In addition, export route availability remained strong during the quarter with only two days overlapping downtime between the Amukpe-Escravos pipeline ('AEP') and Trans Forcados pipeline ('TFP') routes. While overall asset performance was strong, it was partially offset by some operational challenges on the TFP and at the Escravos Oil Terminal ('EOT'). As such, total deferments on the asset in 1Q 2025 rose to 17% (1Q 2024: 13%). 

Elcrest

Production at OML 40 recorded marginal improvement, rising by 1.7% to 12,676 bopd (1Q 2024: 12,470 bopd). Well performance at OML 40 continues to remain strong while export route availability has also been a positive for production. Total deferments on OML 40 during the quarter were 22%. Elcrest recorded 0.7 million LTI free man hours in 1Q 2025.

Sibiri oil field

As communicated in our FY 2024 results, following persistent strong well performance at Sibiri, we plan to drill three wells (Sibiri-C, Sibiri-D, & Sibiri-E) at the Sibiri field in the 2025 drilling plan. Drilling of the wells will commence in 2H 2025. 

Abiala oil field

In our FY 2024 results, we reported receipt of field development approval (FDP) from the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) on 14th February, 2025. In the period since, we have ramped up production from all four producing strings, reaching approximately 3,500 bopd gross. By March 2025, Abiala's total production reached approximately 130,000 barrels, with the first crude export of 30,000 barrels on March 21, 2025.

In April 2025, the field was shut in as we commenced operations to switch production from the extended well test facility ('EWT') to an early production facility ('EPF'). Production is expected to resume during 2Q 2025 following installation, integration, and commissioning of the Abiala EPF. We are pleased to report that following positive initial observations, gross production potential from the two development wells is now estimated at 8,000 bopd, up from our previous estimate of 5,000 bopd. We also secured an additional storage vessel to support optimised production and evacuation from the Abiala field. 

Eastern Assets

In OML 53, average daily working interest production increased by 132% to 2,935 bopd in 1Q 2025, from 1,263 bopd in 1Q 2024, due to continuous availability of the evacuation routes for the asset, principally the Trans Niger Pipeline ('TNP'). During the quarter a section of the TNP, near the Bodo-Bonny road, was impacted by attempted sabotage, however the episode caused minimal disruption to our Ohaji operations, with normal production restored within days. Total uptime for the TNP-BOT evacuation route in 1Q 2025 was 88% (1Q 2024: 0%). We also continued to supply the Waltersmith refinery during the quarter.   

Production from our Jisike field continued to improve as the reliability of the Antan-Ebocha-Brass terminal route was sustained in 1Q 2025. Uptime on the route improved to 73% (1Q 2024: 29%).

In OPL 283, production was stable at 1,535 bopd (1Q 2024: 1,564 bopd).

Drilling activities

As communicated in our FY 2024 results, our 2025 drilling programme involves delivery of 13 new wells on our onshore assets (Western Assets - 7 wells; Eastern Assets - 2 wells; Elcrest - 4 wells). No wells from the 2025 plan were completed during 1Q 2025, while four are expected to complete during 2Q 2025. The 2025 well programme is expected to arrest production decline and support organic growth ambitions.

In 1Q 2025, we spudded two wells (Orogho KZGF-02 and Okporhuru-10) on OMLs 4, 38, & 41, both of which are set to be completed in May 2025. A third well is also planned on our Western asset in 2Q 2025, together, the three wells are estimated to add 3,100 bopd and 45 MMscfd gross JV production volumes.

At OML 40, implementation of the drilling programme will commence in 2Q 2025 once the rig arrives at location. Rig maintenance work is ongoing while all regulatory permits needed to commence drilling are being finalised. We plan to deliver one well in 2Q 2025.

On our Eastern assets, we are in the process of securing a land rig and obtaining the necessary regulatory permits required to commence drilling. Drilling activities are expected to start during 3Q 2025.

Offshore activity related to drilling is currently focused on planning for future drilling campaigns, including identification of potential drilling contractors and long lead items.

Midstream Gas business performance

During the quarter, the Company delivered 14.9 Bcf of gas, representing a 50% increase on 1Q 2024's 10.0 Bcf . The average daily working interest gas production volumes increased by 51% to 165.6 MMscfd, from 109.5 MMscfd in 1Q 2024. Consolidation of SEPNU's gas production added 33.6 MMscfd to the group's average daily working interest gas production during the quarter. On our onshore assets, average daily working interest gas production increased by 21% to 132.0 MMscfd (1Q 2024: 109.5 MMscfd). The increase was supported by commencement of production at the Sapele gas plant, gas wells coming onstream, and improved efficiency at the Oben gas plant following the 2024 turnaround maintenance activities.

2025 Domestic Gas Price Update

On 1st April, the Nigerian Midstream and Downstream Petroleum Regulatory Authority (NMDPRA) announced a downward review of gas price for Domestic Gas Delivery Obligation (DGDO) contracts for a year from April 2025, to $2.13/MMbtu, from $2.42/MMbtu previously. We continue to work with industry members to engage with the regulator to review the decision.

Sapele Gas Plant

The Sapele Gas Plant is a 90 MMscfd plant, capable of processing both Non-Associated Gas (NAG) and Associated Gas (AG) which meets export specifications and an LPG processing module which will 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.

As previously reported the initial 30 MMscfd Mechanical Refrigeration Unit ('MRU') was completed in Q4 2024, in line with expectations. The start of commercial operations began in February 2025. Throughput has been very strong, averaging c.28 Mmscf/d high quality gas, with strong condensate recovery of c.2 kbopd gross volumes. We have seen high demand for the gas due to its specification, which augurs well for the start up on the second 60 MMscf MRU.

The second MRU, which will lift total production capacity to 90 MMscfd, is on track for completion during 2Q 2025 with sales commencing in the third quarter. 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. During 1Q 2025 associated gas commercialisation through Sapele gas plant resulted in approximately a 30% reduction in emissions intensity at the Sapele flow station, illustrating the potential of the programme.

We note that in early 2025,  Oben and Sapele gas plants combined operations has regularly exceeded 300 MMscfd on a gross JV basis, peaking at 333 MMscfd (c. 150 MMScfd net working interest) during the quarter.

ANOH Gas  

AGPC continued its strong safety performance achieving a cumulative total of 15.4 million man-hours LTI free by the end of 1Q 2025. We are pleased to announce that the ANOH Gas plant construction project achieved commissioning (dry) gas Ready for Start-Up ('RFSU') milestone during the quarter, and will shortly introduce dry gas for commissioning.

Beyond the gas plant execution work, much of the focus in 1Q 2025 has been on securing alternative evacuation options, given continued delays to completion of the OB3 pipeline. During the period AGPC agreed preliminary heads of terms for delivery of gas into the export market through the Nigeria LNG ('NLNG') terminal. This will act as an interim outlet for gas monetization and work is currently ongoing to make the necessary pipeline modifications to enable gas sales to commence in 3Q 2025.

During the quarter the Incorporated Joint Venture ('IJV') partners agreed to an additional equity investment of $20 million (Seplat share; $10 million) to support final project execution costs in advance of revenue generation from production.

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 emissions intensity recorded on Seplat's onshore operations for the period was 30.6 kg CO2/boe, lower than the 31.1 kg CO₂/boe recorded in 1Q 2024. On a quarter-on-quarter basis, carbon emissions intensity onshore fell by 5% from 32.3 kgCO₂/boe reported in 4Q 2024. The improvement in carbon emissions intensity was driven by the completion and commencement of operations from the 30 MMscfd MRU at the Sapele gas plant. As stated above, the first module of SIGP has commenced operations and is now producing. Partial commercialisation of the associated gas flares was achieved, which resulted in a reduction of c.30% in CO₂ emissions at the Sapele flow station, versus 4Q 2024. Further reductions are expected as full injection of associated gas into Sapele gas plant is achieved later in 2025. 

Other ongoing key flare-out projects include, 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 continue to assess the emissions and flaring regime within SEPNU and alignment with Seplat reporting methodology. The intention is to begin reporting SEPNU emissions data during 2025.

HSE Performance

The Company achieved a total of 2.5-million hours without any Lost Time Injury (LTI) on its operated onshore assets in 1Q 2025 (1Q 2024: 2.3-million hours), which reflects the Company's strong focus on safety and the dedication of its workforce to maintaining a secure work environment. The Company has achieved a cumulative 23.0-million-man hours since last LTI recorded (on 13th October 2022) across our operated onshore assets. In the period we recorded two Process Safety Tier 1 incidents of which one was related to an oil spill and one due to a gas release, and one further oil spill related Tier 2 loss of primary containment incident. Other key HSE performance metrics remain positive with no fatality, LTI, nor TRIR recorded during the quarter.

As we disclosed in our FY 2024 results, we remain on the path towards achieving ISO 45001 and 14001 standards certifications. In 1Q 2025, we progressed the stage 2 audit for ISO 45001 and expect to complete it in time to receive the certification in Q2 2025. We also completed the stage 2 regulatory audit for ISO 14001 and remain on track to achieve completion in Q2 2025. Working to achieve these certifications further demonstrates our commitment top-tier safety and environmental performance.

SEPNU recorded 4.8 million hours worked without a LTI during the period, as such SEPNU has now achieved a cumulative 14.1-million-man-hours since its last LTI.

Petroleum Industry Act (PIA) Implementation Status

In our onshore business, we have progressed the process towards securing approval to convert our onshore assets to the PIA regime. In our FY 2024 release, we communicated that delineation had been made based on principles established in section 93 of the PIA, 2021 and that the Commission has requested documentation from Seplat that would facilitate the preparation of legal transfer documents on the retained PMLs and PPLs.

We are pleased to report that post the FY 2024 results release, we have submitted to NUPRC, all relevant technical data on areas to be relinquished. We have also commenced work with the commission's recommended surveyor to standardise vertices and coordinates of the retention areas, in line with statutory requirements for boundary maps and conversion documentation. Completing this process will facilitate the preparation of legal transfer documents on the retained PMLs and PPLs.

For SEPNU, conversations are ongoing with the regulators to resume the process of conversion of the offshore assets to PIA. 

Board Changes

Following their recent appointments to the Board of NNPC Limited by the President of the Federal Republic of Nigeria,  Mr. Bello Rabiu, Senior Independent Non-Executive Director ('SINED') and Mr. Babs Omotowa, Independent Non-Executive Director ('INED') notified the Board of their resignations. The Board has subsequently appointed Mrs. Bashirat Odunewu as our new SINED.

Financial review

Our 1Q 2025 results represent the first complete quarter as an enlarged business, resulting in a significant step change in financial performance, with reported revenues 350% higher than in 1Q 2024. This was partially offset by weakness in Brent oil price versus the prior year, a factor which has continued after the period end. We recorded an average realised oil price of $76.42/bbl, a $1.55/bbl premium to Brent, but down 12% on prior year. Our NGL realised price of $44.8/boe was equivalent to approximately 60% of Brent. Our blended realised gas price averaged $3.01/Mscf, a 3% decrease on 1Q 2024.

Revenue

*Overlift/Underlift balance in the quarter comprised 672 kbbl crude oil overlift (valued at $54.9 million) and 77 kbbl NGL underlift (valued at $1.4 million).

Total revenue from oil and gas sales for 1Q 2025, rose 350% to $809.3 million from $179.8 million in 1Q 2024. Adjusting reported revenue for 1Q 2025 overlifts and 1Q 2024 underlifts, total oil and gas sales were $755.8 million ($53.5 million overlift), 220% higher than 1Q 2024's equivalent revenue figure of $236.2 million ($56.4 million underlift).

Reported crude oil revenue, rose 404% to $759.8 million in 1Q 2025 from $150.8 million in 1Q 2024. The increase in crude oil revenue reflects the full impact of the acquired SEPNU business as total crude oil volume lifted for the period rose 450% to 9.9 MMbbls in 1Q 2025, from the 1.8 MMbbls lifted in 1Q 2024. As such, despite an 11% decline in average realised oil price to $76.42/bbl in 1Q 2025 (1Q 2024: $86.17/bbl), the strong increase in volumes lifted supported crude oil revenue growth. The impact of a liquids-heavy acquired business  is now reflected in the fact that crude oil revenue contributed 94% of revenues in 1Q 2025 compared to 84% in 1Q 2024.

Reported gas revenue rose by 53% to $44.5 million in 1Q 2025, compared to $29.0 million in 1Q 2024. Gas sales represented 5% of total reported revenue in 1Q 2025 (1Q 2024: 16%).  The increase in gas revenue is due to higher gas sales volume of 14.9 Bscf (1Q 2024: 10.0 Bscf) which offset the impact of lower realised gas price of $3.01/Mscf (1Q 2024: $3.11/Mscf). Higher gas sales for the period reflects the impact of strong gas production growth at the Oben gas plant, beginning of commercial operations at the Sapele gas plant, and gas production from SEPNU. The lower realised gas price reflects the impact of adding SEPNU's gas sales into the portfolio. The average realised gas price for SEPNU gas was $2.42/Mscf while for our onshore assets, it was $3.18/Mscf.

The business recorded $5.0 million revenue from Natural Gas Liquids (NGLs) sales in 1Q 2025. Total NGL production volume was 304 kbbls while total NGLs lifted during the period was 138 kbbls. Average realised price was $44.79/bbl (59% of realised crude price).

Production deferment in the period was 19% onshore (1Q 2024: 22%) and 23% offshore. Onshore deferments were ahead of plan given reduced third party related downtime, while offshore was in line with plan. The group's average reconciliation loss factor for the onshore assets remained both stable and low at 3.2% in 1Q 2025, attributed to continued focus on security measures and asset integrity management.

Gross profit

In 1Q 2025, gross profit rose 727% to $353.0 million, from $42.7 million in 1Q 2024, reflecting the impact of bigger operations.

Direct operating costs, which encompass expenses related to crude-handling charges (CHC), barging/trucking, operations & maintenance, amounted to $149.1 million in 1Q 2025 (1Q 2024: $42.8 million) due to consolidation of SEPNU's production costs. On our onshore operations, total direct operating costs was $53.3 million (1Q 2024: $42.7 million), reflecting the impact of higher production on our onshore assets. For our offshore assets, total direct operating costs was $95.8 million.

Non-production costs increased by 226% to $307.2 million, made up of $130.2 million in royalties (1Q 2024: $50.8 million), $164.0 million in depreciation, depletion, and amortisation (1Q 2024: $41.4 million), and regulatory fees/levies of $12.9 million (1Q 2024: $2.0 million). The increase in group non-production costs reflect consolidation of SEPNU's costs. Across asset categories, non-production costs on our onshore assets increased to $98.3 million (1Q 2024: $94.3 million) due to higher DD&A charge for the quarter arising due to higher production volumes. On our offshore assets, total non-production costs were $208.9 million. 

Considering the cost per barrel equivalent basis, our onshore assets, production opex per boe was $10.5/boe while for SEPNU, it was $14.6/boe. Our consolidated production opex per boe of $12.6/boe is lower than our 2025 guidance ($14.0/boe - $15.0/boe) largely due to timing of maintenance and workover well activities scheduled to commence later in the year.

Operating profit and Adjusted EBITDA

General and Administrative ('G&A') expenses amounted to $64.9 million, versus $24.1 million in 1Q 2024 further reflecting the consolidation of SEPNU. G&A cost per boe for the group was $5.5/boe. We continue to invest efforts in improving administrative efficiency in order to bring costs lower while we also limit the impact of non-recurring costs.   

During the period, we recorded overlift of $53.5 million, translating to 672 kbbls, compared to underlift of $56.4 million (translating to 849 kbbls) which was adjusted for in the Other income line item in the Income statement. We also recorded foreign exchange gain of $5.9 million (1Q 2024: $6.0 million) due to optimized cash working capital management and a more stable naira this  period.

Overall, we reported operating profit of $238.2 million in 1Q 2025 (29.4% margin), from $81.9 million in 1Q 2024 (45.6% margin). The increase in reported operating profit also reflects the increased scale of the business.

After adjusting for non-cash items such as impairment, fair value, and exchange gains or losses, the adjusted EBITDA for the quarter was $400.6 million (1Q 2024: $123.3 million), resulting in a margin of 49.5%.

Taxation

The income tax expense of $184.1 million (1Q 2024: $71.2 million) includes a current tax charge of $215.0 million (1Q 2024: $13.9 million) and a deferred tax credit of $30.9 million (1Q 2024: $57.3 million charge). The higher tax charge in the income statement reflects the current tax due in SEPNU. For the offshore assets, we expect the current tax charge to moderate overtime as the pool of available capital allowances increases as we increase our investments across the asset base.

Net result

Profit before tax rose 199%, amounting to $207.4 million, compared to $69.3 million in 1Q 2024. Profit after tax for the quarter was $23.3 million, compared to a $1.9 million loss in 1Q 2024.

The profit attributable to equity holders of the parent Company, representing shareholders, was $20.2 million in 1Q 2025, which resulted in basic earnings per share of $0.03 for the period (1Q 2024: $0.002/share).

Cash flows from operating activities

In 1Q 2025, the Company generated pre-tax cashflow from operating activities of $306.5 million (1Q 2024: $16.9 million). The substantial improvement reflects the impact of the significantly enhanced production base, alongside relatively lower costs, partially offset by a working capital build of $114.2 million.

Net cash flow from operating activities amounted to $216.6 million in 1Q 2025, compared to $14.9 million in 1Q 2024. This figure includes cash tax payments of $36.2 million and a hedging premium of $1.7 million paid during the current period, while in the previous year, cash tax payments were $0.5 million, and the hedging premium paid was $1.4 million. Overall, the cash taxes paid represents 12% of operating cashflow. We anticipate the effective cash tax rate to increase in subsequent quarters during 2025 due to the addition of the offshore assets. Longer term, our planned investments in SEPNU via capital projects such as the East Area Project IGE will help build-up a capital allowance balance in SEPNU which will be deductible against future assessable profits. 

Our onshore business continues to record strong cash call collection in 1Q 2025. During the quarter, on the NEPL/Seplat JV for OMLs 4, 38 & 41 and OML 40, we received $119.4 million in cash calls from our JV partner, bringing the receivables balance on the JV to $28.4 million (FY 2024: $41.4 million). On our NUIMS/Seplat JV for OML 53, we received $9.0 million in cash call settlement in 1Q 2025 with cash call obligations fully paid up.

For our SEPNU/NNPC JV, though we received $153.0 million for cash call settlements out of $253.0 million due for the period, the balance on the JV receivables rose to $419.0 million (FY 2024: $318.0 million). We note that we received the balance of the 2025 cash call payments post the reporting period. On the legacy cash call receivable balance, which represents approximately 75% of the total balance, we have had positive interactions with our partner to reconcile these cash calls and progress to settlement. We anticipate that we will begin to recover these balances from 4Q 2025.

Cash flows from investing activities

*Others include Interest received, and deposit for asset held for sale.

In 1Q 2025 the total net cash outflow from investing activities was $43.3 million, an increase on the $32.5 million reported in 1Q 2024.

The cash capital expenditure on oil & gas assets during the period was $39.9 million (1Q 2024: $46.4 million), down from the prior year given limited drilling activity in the quarter. Total capex (including other fixed assets) was $40.2 million (1Q 2024: $47.1 million).

As a result of the strong operating performance in 1Q 2025, the business generated $176.4 million of free cashflow, compared to the negative free cashflow of $32.2 million generated in 1Q 2024.

During the period the Company provided an additional $10 million in equity funding to the AGPC IJV,

Cash flows from financing activities

Net cash outflow from financing activities was $310.8 million, compared to an outflow of $67.4 million in 1Q 2024. The principal driver for the outflow was debt movements among the Company's principal borrowing facilities, described below. Interest charges increased 13% on the prior period due to an increase in drawn debt facilities. Other finance charges predominantly relates to repayment of leases and interest on leases. No shares were purchased for the obligations under the long-term incentive plan (1Q 2024: $8.5 million).

Debt Movements

On 21 March 2025 the Company successfully refinanced its $650 million 7.75% 144A/Reg S bond, which was set to mature in March 2026, with a new $650 million 9.125% 144A/Reg S bond maturing in April 2030. The offering was strongly over-subscribed, despite challenging market conditions. We are pleased to note that the offering, our third since 2018, priced inside the Nigerian sovereign for the first time, testament to our strong reputation in public credit markets.

Subsequent to our bond refinancing, the Company's $350 million revolving credit facility ('RCF') maturity was automatically extended to 31 December 2026. In late March, the Company took the opportunity, due to its strong cash position, to pay down $250 million of its previously fully drawn facility. As such, at 31 March 2025, $100 million was drawn under the $350 million revolving credit facility.

The $110 million Westport RBL Facility (RBL Facility) commenced amortising on 31 March 2023. The reduction in facility commitments occurs on a semi-annual basis in March and September of each year until final maturity in 2026. In March 2025, Seplat's wholly owned subsidiary, Westport (and the borrower of record under the RBL facility) paid $19.25 million in principal repayments under the RBL Facility. As at 31 March 2025, $30.25 million is now outstanding under the RBL Facility. The next reduction in commitments will be on 30 September 2025 for an amount of $19.25 million.

In total, the Company repaid approximately 21% of its outstanding gross debt during the period. There were no changes in the principal amount outstanding under the Seplat group's other facilities (including, the $300m advanced payment facility with ExxonMobil, which is fully drawn, or the $50 million Westport off-take loan, of which $11 million is outstanding). See note 22.2 for further details on debt movements during the period.

Liquidity

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

*      Including amortised interest and accrual for the RCF (undrawn) commitment fee

** Adjusted EBITDA 2024 represents the FY 2024 pro-forma adjusted EBITDA for Seplat and SEPNU combined, 1Q 2025 adjusted EBITDA includes pro-forma adjusted EBITDA from Seplat and SEPNU between 2Q-4Q 2024 plus 1Q 2025 adjusted EBITDA as reported.

Seplat Energy ended the period with gross debt of $1,081.6 million (YE 2024: $1,376.6 million) and cash at bank of $334.6 million (YE 2024: $469.9 million), leaving net debt at $747 million (YE 2024: $898 million). Net debt declined by 17% due to a combination of debt repayments and free cash generation during the quarter. 

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 March 2025, proforma Net Debt-to-EBITDA ratio improved to 0.56x, from 0.66x at end 2024.

Dividend

The Board has approved a quarterly dividend of US$ 4.6 cents per share for the first quarter 2025 (subject to appropriate WHT).  This is a 28% increase on 4Q 2024 core dividend, and a 53% increase on the equivalent core dividend in 1Q 2024. On the basis of maintaining this level through 2025 it will result in a total dividend of $18.4 cents per share, an 11% increase in the total dividend declared for 2024 ($16.5 cents per share). We expect to set out an updated capital allocation policy in our capital markets day scheduled for September this year.

Hedging

Seplat Energy's hedging policy aims to guarantee appropriate levels of cash flow assurance in times of oil price weakness and volatility.

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 in line with our policy and as soon as the right opportunity presents especially in view of market volatility.

Credit ratings

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

In April 2025 Fitch upgraded our corporate rating to B (previously B-). 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 2025 and March 2025 respectively. 

Outlook

Seplat Energy's 2025 production, capex and unit operating cost guidance is maintained. Production operations performed well in the first quarter, with the benefit of ANOH gas and the impacts of the onshore drilling programme and offshore maintenance & capex activities yet to be realised. Costs, both capex and opex tracked below guidance in the first quarter, however we anticipate an increase in run rate costs in 2Q 2025 onwards as drilling activity increases onshore and the jack-up barge commences well restoration work offshore.

Production guidance

Seplat Energy's production operations were ahead of the mid-point of guidance in 1Q 2025 and was supported by strong performance in particular from the onshore assets which benefited from the performance of 2024 new wells, high uptime on Oben gas plant and contribution from Sapele IGP.

2025 production guidance reiterated 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's second MRU and the completion of the Abiala EPF. We also see growth on OML 53 oil given the resumption of 24-hour operations on the 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 guidance is reiterated in the range of $260 million - $320 million.

Capex in 1Q 2025 of $40.2 million was limited to a number of smaller projects including final payments for 2024 wells and Sapele IGP construction costs. Run rate will increase in 2Q 2025 with the drilling of 4 wells and EAP IGE costs.  

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

•    Programme 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 million-$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 programme

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 and asset integrity work required due to long term lack of investments. Our expectation continues to be that unit opex will moderate post 2025/2026 as production grows and as investment pivots towards capital projects. In 2025 the major cost items are: 

•   Two jack-up barges to operate across the offshore license area from early 2Q 2025, one targeting integrity works and the other working on the idle well restoration programme.

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, which commenced in March 2025 and will continue at certain points during the year.