Seplat Energy PLC

National Storage Mechanism | Additional information

RNS Number : 0933T

Seplat Energy PLC

30 July 2025

Please see the Full Financial Results in attached PDF

http://www.rns-pdf.londonstockexchange.com/rns/0933T_1-2025-7-29.pdf

Unaudited results for the six months ended 30 June 2025

30 July 2025

Lagos and London, 30 July 2025: Seplat Energy Plc ("Seplat Energy" or "the Company"), a leading Nigerian independent energy company listed on both the Nigerian Exchange Group and the London Stock Exchange, announces its unaudited results for the six months ended 30 June 2025.

Summary

Strong production firmly underpins FY2025 guidance. Generated $766 million cash flow from operations in 6M 2025, enabling further reduction in net debt and improvement in net leverage to c.0.5x Net debt/EBITDA. $4.6c/shr dividend declared for 2Q 2025, inline with 1Q 2025.

Operational highlights

• Production averaged 134,492 boepd up 178% from 6M 2024 (48,407 boepd), above the midpoint of 2025 guidance (120 - 140 kboepd), and approximately 10% higher than pro-forma production in 6M 2024. Working interest oil production reached 100,327 bopd in 6M 2025.

• Onshore production contribution of 54,831 boepd, was 13% higher than 6M 2024. Liquids +7% and gas +24% vs 6M 2024

• Offshore production contribution was strong in the first half of the year at 79,660 boepd, which was made up of 86% crude and condensate, 5% NGL and 9% gas. 2Q 2025 production increased 11% QoQ, aided by improved uptime.

• Offshore, the idle well restoration programme added c.25.9 kbopd gross production capacity from the first 29 wells restored to production.

• Carbon emissions intensity for Seplat onshore assets: 26.7 kg CO2/boe (revised 6M 2024: 31.4 kg CO2/boe). End of routine flaring for onshore assets on track for end 2025 completion.

• Achieved more than 15.3 million man hours without Lost Time Injury ('LTI') on our operated assets

• In July, ANOH gas plant received dry gas to commence live hydrocarbon commissioning.

Financial highlights

• Revenue $1,398 million up c.231% on prior year (6M 2024: $422 million).

• Unit production operating cost of $12.5/boe (6M 2024: $9.7/boe), below guidance of $14-$15/boe, due to timing of planned maintenance.

• Adjusted EBITDA of $735 million, up 175% on prior year (6M 2024: $267.3 million).

• Cash generated from operations of $766.2 million, up 239% on prior year (6M 2024: $226.0 million).

• Cash capital expenditure of $96.5 million (6M 2024: $102.4 million).

• Balance sheet remains strong, end-June cash at bank $419.4 million (3M 2025: $334.6 million), excluding $133.0 million restricted cash.

• Net Debt at end-June of $676 million down 9.5% on prior quarter (1Q 2025: $747 million). Pro-forma ND/EBITDA improves to 0.53x.

• Credit ratings upgrades: April 2025 Fitch upgraded to B, June 2025: Moody's upgraded to B2 (stable)

• Post period end, repaid the outstanding $100 million on our RCF. At end July 2025 the $350 million RCF is undrawn and fully available.

Dividend

• 2Q 2025 declared dividend of US$ 4.6c/share, inline with the prior quarter dividend. The Company plans to set out a revised capital allocation policy in the Capital Markets Day scheduled for 18 September 2025.

2025 Outlook

• 2025 guidance is maintained:

• Production guidance of 120-140 kboepd (Seplat Onshore 48-56 kboepd, Seplat Offshore 72-84 kboepd).

• Capex guidance $260-320 million. (Seplat Onshore $180-220 million, Seplat Offshore $80-100 million).

• Unit operating costs for the group are expected to be $14.0-15.0/boe.

• Capital Markets Day 18 September 2025 to detail our medium to long term growth ambitions.

Roger Brown, Chief Executive Officer, said:

"Seplat has continued its positive trajectory in Q2 to deliver a strong performance for the first half of 2025. Our focus on integrity, reliability and production improvement activities are bearing fruit as evidenced by strong production in 2Q 2025, with onshore in the upper end of guidance, and offshore production growing 11% quarter on quarter. The Company delivered first half production over 10% higher than the pro-forma output in same period last year, delivering on both our ambitions and supporting Nigeria's goals of oil and gas production growth.

We are well placed to weather the recent increase in macro volatility. Strong revenues and a focus on costs delivered significant positive cash flows, enabling us to further reduce net leverage, continue our strong quarterly dividend track record and in the past week, pay down an additional $100 million of debt.

We have hit the ground running in 2025 building a strong foundation with which deliver on our 2025 performance targets. Integration of the enlarged group continues at pace and we look forward to sharing our exciting plans for the Company when we set out the future of our business at the upcoming Capital Markets Day in September."

Summary of performance


	$ million			₦ billion
6M 2025*	6M 2024	% change	6M 2025*	6M 2024
Revenue **	1,397.7	421.6	231%	2,166.7	575.1
Gross profit	484.6	181.5	167%	751.2	247.5
EBITDA ***	735.0	267.3	175%	1,139.4	364.5
Operating profit	387.8	209.1	85%	601.2	285.2
Profit before tax	292.9	178.9	64%	454.1	244.0
Profit after tax	27.4	49.9	(45)%	42.5	68.1
Cash generated from operations	766.2	226.0	239%	1,187.7	308.2
Working interest production (boepd)	134,492	48,407	178%
Volumes lifted (MMbbls)	17.8	4.2	323%
Average realised oil price ($/bbl)	72.58	85.55	(15)%
Average realised gas price ($/Mscf)	2.97	2.95	1%
LTIF	-	-
CO2 emissions intensity from operated onshore assets, kg/boe	26.7	31.4	(15)%

*Throughout results 6M 2025 reported figures consolidate offshore assets contribution, while 6M 2024 information relates solely to Seplat's Onshore assets

** 6M 2025 reported revenue excludes an underlift of $42.6 million, 6M 2024 excludes an underlift of $55.8 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

Important notice

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

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

Investor call

At 1:00pm BST/WAT on Wednesday 30 July 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/ .


Event title:	Seplat Energy Plc: Half Year 2025 Financial Results
Event date	1:00pm BST/WAT (London / Lagos) Wednesday 30 July 2025
Webcast Live Event Link	Webcast link
Conference call and pre-register Link:	Registration Link

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:


Seplat Energy Plc
Eleanor Adaralegbe, Chief Financial Officer	+23412770400
James Thompson, Head of Investor Relations	[email protected]
Ayorinde Akinloye, Investor Relations
Chioma Afe, Director, External Affairs & Social Performance
FTI Consulting
Ben Brewerton / Christopher Laing	+44 203 727 1000 [email protected]
Citigroup Global Markets Limited
Peter Brown / Peter Catterall	+44 207 986 4000

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://seplatenergy.com/

Operating review

Group Production

Working interest production for the six months ended 30 June 2025


Asset	Seplat WI	Half year ended 30 June 2025				Half year ended 30 June 2024
Crude & Condensate	Gas	NGLs	Total	Crude & Condensate	Gas	NGLs	Total
%	bopd	MMscfd	bpd	boepd	bopd	MMscfd	bpd	boepd
OMLs 4, 38, 41	45 %	16,962	134.5	-	40,145	15,286	108.7	-	34,023
OML 40	45 %	10,309	-	-	10,309	11,532	-	-	11,532
OML 53	40 %	2,864	-	-	2,864	1,222	-	-	1,222
OPL 283	40 %	1,513	-	-	1,513	1,630	-	-	1,630
Seplat Onshore		31,648	134.5	-	54,831	29,670	108.7	-	48,407
OMLs 67, 68, 70, 104	40 %	67,911	28.7	3,772	76,638	-	-	-	-
OML 99 (A/K Field)	9.6 %	768	13.1	-	3,022	-	-	-	-
Seplat Offshore		68,679	41.8	3,772	79,660	-	-	-	-
Total		100,327	176.3	3,772	134,492	29,670	108.7	-	48,407

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.

A/K Field refers to Amenam-Kpono field

In 6M 2025, average daily working interest production for the group was 134,492 boepd (6M 2024: 48,407 boepd), above the midpoint of our production guidance of 120,000 - 140,000 boepd. Total crude & condensate production increased by 236% to 18.2 MMbbls, compared to the 5.4 MMbbls produced in 6M 2024. Total gas produced during the period rose 61% to 31.9 Bscf (6M 2024: 19.8 Bscf), and we also produced 683 kbbls of NGLs in 6M 2025. As such, aggregate production for the period rose 176% to 24.3 MMboe (6M 2024: 8.8 MMboe), reflecting the transformational impact of the offshore assets consolidation and strong performance on our onshore assets. .

Production performance in our onshore assets was strong, up 13% from the equivalent period in 2024 (6M 2025: 54,831 boepd; 6M 2024: 48,407 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 the first module (30MMscf MRU) of the 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').

Production deferment in the period was 23% onshore (6M 2024: 24%) and 20% offshore. Onshore deferments were broadly in-line with 6M 2024 but the period benefited from improved export route availability, particularly for our Eastern assets. However this was largely offset by downtime on OML 40 (more details under Elcrest sub-section).

Working interest production for the three months ended 30 June 2025


Asset	Seplat WI	Q2 2025				Q1 2025
Crude & Condensate	Gas	NGLs	Total	Crude & Condensate	Gas	NGLs	Total
%	bopd	MMscfd	bpd	boepd	bopd	MMscfd	bpd	boepd
OMLs 4, 38, 41	45 %	17,626	136.9	-	41,228	16,291	132.0	-	39,050
OML 40	45 %	7,969	-	-	7,969	12,676	-	-	12,676
OML 53	40 %	2,793	-	-	2,793	2,935	-	-	2,935
OPL 283	40 %	1,420	-	-	1,420	1,535	-	-	1,535
Seplat Onshore		29,808	136.9	-	53,410	33,437	132.0	-	56,196
OMLs 67, 68, 70, 104	40 %	70,409	37.2	4,164	80,990	65,385	20.2	3,376	72,239
OML 99 (A/K Field)	9.6 %	720	12.1	-	2,807	816	14.1	-	3,239
Seplat Offshore		71,129	49.3	4,164	83,797	66,201	34.3	3,376	75,478
Total		100,937	186.2	4,164	137,207	99,638	166.3	3,376	131,674

On a quarter-on-quarter (QoQ) basis, group production rose 4%. The increase was driven by our offshore operations which grew 11% QoQ, as the impact of our idle well restoration program continued to produce strong results. This was further supported by Western Asset which increased 6% QoQ benefiting from high uptime, and continued strong gas production. Onshore production fell 5% QoQ, driven by downtime on OML40.

Seplat Offshore

Production across the offshore assets continued to remain strong during the period. Working interest production in 2Q 2025 rose 11% quarter-on-quarter to 83,797 boepd (1Q 2025: 75,478 boepd). As such, daily average working interest production during 6M 2025 was 79,660 boepd. The improvement in production performance during 2Q 2025 was driven by several factors; improved production optimisation and efficiency, impacts of maintenance and integrity work and the idle well restoration programme.

Across product lines, production was 86% crude and condensates, 5% NGL, and 9% gas. The Amenam-Kpono field ('AK') contributed 3.0 kboepd to average daily production of which 25% was crude oil and the balance gas.

The programme to resume production from idle wells continued at pace during 2Q 2025. A further 19 idle wells were worked on during the quarter taking the total well count to 29 in 2025. Of the 29 wells, 22 have been successfully restored to production. The 2Q 2025 idle well programme restored an additional 14.9 kbopd gross production capacity. The idle well programme continues to be a strong value-adding activity, with year to date additions to gross production capacity up to 25.9 kbopd from 22 productive wells. We remain on track to meet our previously upgraded target of 50 well work-overs from the idle well inventory during 2025.

In addition to the above, production optimisation activities across several assets, including; Ubit, Edop, Enang, Abang and Idoho delivered incremental JV volumes of c.7 kboepd in 2Q 2025 in support of the plan. Other planned maintenance and integrity activities during the period included delivering of over 12,000m2 new surface coatings and mobilizing of two additional vessels doubling our capacity to execute the planned JV programme.

The East Area Project ('EAP') Inlet Gas Exchanger (IGE) replacement project is the main capital project offshore in 2025 and is designed to increase gross JV NGL production at EAP by 8 to 10 kboepd when operational. During 2Q 2025 the original IGE unit was removed from the facility and site preparation works continued for the installation of the replacement IGE. Two shutdowns will be required to install the new unit, both of which are scheduled to occur during 3Q 2025. Production contribution from the replacement IGE will commence during 4Q 2025.

Seplat Onshore

Western Assets

In OMLs 4, 38, & 41, working interest liquids production rose by 11% to 16,962 bopd (6M 2024: 15,286 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 period with the two export routes, Amukpe-Escravos pipeline ('AEP') and Trans Forcados pipeline ('TFP') both achieving c.90% uptime during the period. While overall asset performance was strong, it was partially offset by unscheduled leak repairs on TFP and the minor loading restrictions at the Escravos Oil Terminal ('EOT'). As such, total deferments on the asset in 6M 2025 rose modestly to 16% (6M 2024: 14%).

OML 40

Production at OML 40 declined in 6M 2025, falling by 11% to 10,309 bopd (6M 2024: 11,532 bopd). The decline in production was predominantly due to a planned 21 day shut down for maintenance by the line operator on the Trans Escravos Pipeline ('TEP') which transports our crude to the Forcados Oil Terminal ('FOT'), with minor additional unplanned downtime. Total deferments on OML 40 rose during the period to 34% (6M 2024: 14%). In our 1Q 2025 results, we communicated that the Abiala field was shut-in in April to commence operations to switch production from the extended well test ('EWT') facility to an early production facility ('EPF'). Daily average entitlement production of 930 bopd (95% net to Seplat) in 6M 2025 was impacted by the extended shutdown in 2Q 2025. We continue to optimise the current evacuation configuration with a view to ramping up production to the Abiala full well potential in 2H 2025.

Eastern Assets

In OML 53, overall performance was strong, with average daily working interest production increasing by 134% to 2,864 bopd in 6M 2025, from 1,222 bopd in 6M 2024, due to continuous availability of the evacuation routes for the asset, principally the Trans Niger Pipeline ('TNP'). Total pipeline availability for the TNP-BOT evacuation route for our Ohaji operations in 6M 2025 was 82% (6M 2024: 1%). We also continued to supply the Waltersmith refinery during the quarter. We note that there is a planned 10 days shutdown on the TNP in 3Q 2025, during which time production offtake will be constrained to Waltersmith refinery. Production from our Jisike field continued to improve as the reliability of the Antan-Ebocha-Brass terminal route was sustained in 6M 2025. Uptime on the route improved to 79% (6M 2024: 29%).

In OPL 283, liquids production declined by 8% to 1,513 bopd in 6M 2025 (6M 2024: 1,630 bopd).

Onshore drilling activities

Our 2025 drilling programme set out to deliver 13 wells, all of which are onshore (Western Assets - 8 wells; Eastern Assets - 2 wells; Elcrest - 3 wells). The drilling plan was set out to sustain our strategy of arresting production decline and supporting growth across our assets.

On our Western Assets, we delivered two wells in 6M 2025 which were Orogho-10 and Okporhuru-10. The completed wells are now onstream and producing at a combined gross rate of 2,500 bopd and 20 MMscfd. Post reporting period, a further two wells (Orogho-11 and Sapele-39) were completed and are scheduled to be onstream during 3Q 2025. The remaining four wells will be completed in 4Q 2025.

We continue engagements to enable us to commence implementation of the 2025 drilling programme for our Eastern Assets and Elcrest operations. For the Eastern Assets, the land rig mobilisation to the drilling location is currently ongoing. We expect to commence the drilling program in August and deliver the two-well program before year end. For our Elcrest operations, the rig move occurred during July and drilling program will commence shortly.

We remain confident that our drilling program will be delivered on time and within budget, enabling production to remain robust heading into 2026.

Midstream Gas business performance

During the period, the Company produced 31.9 Bcf of gas, representing a 61% increase on 19.8 Bcf reported in 6M 2024. The average daily working interest gas production volumes increased by 62% to 176.3 MMscfd, from 108.7 MMscfd in 6M 2024. Consolidation of offshore gas production added 41.8 MMscfd to the group's average daily working interest gas production during the period. On our onshore assets, average daily working interest gas production increased by 24% to 134.5 MMscfd (6M 2024: 108.7 MMscfd). The increase was supported by commencement of production at the Sapele gas plant, new gas wells coming onstream, and improved efficiency at the Oben gas plant following the 2024 turnaround maintenance activities.

We also note that gas production from our offshore assets rose 85% quarter-on-quarter to 37.2 MMscfd (1Q 2025: 20.2 MMscfd), benefiting from improved export pipeline availability and improvements in production efficiency.

Sapele Gas Plant

In 1Q 2025, we completed the 90-day reliability test for the 30 MMscfd train 1 Mechanical Refrigeration Unit ('MRU') and received the license to operate ('LTO') from the Nigerian Midstream and Downstream Petroleum Regulatory Authority ('NMDPRA'). The plant has continued to operate efficiently with gas sales progressing well. In addition, commissioning of the plant has resulted in a notable reduction in Scope 1 emissions on our Western Assets (more details in End of Routine Flaring section).

In line with the guidance in our 1Q 2025 financial results, we are pleased to report that the second MRU ('train 2'), a 60 MMscfd facility, is now operational. We received approval from NMDPRA to introduce hydrocarbons into train 2 in May, which we subsequently commenced, with the 90-day reliability test currently ongoing. Gas sales from train 2 are on track to commence during 3Q 2025.

ANOH Gas

AGPC continued its strong safety performance achieving a cumulative total of 16.4 million man-hours LTI free by the end of 2Q 2025.

Operations during 2Q 2025 focused on completion of modification works in support of alternative commissioning gas and export routes, considering ongoing OB3 pipeline project delays. This involved certain modifications at the Ob-Ob gas plant to enable transport of third party gas to the ANOH gas plant for live hydrocarbon commissioning. We are pleased to announce that in July the ANOH gas plant received third party gas to begin live hydrocarbon commissioning. This work precedes the final project milestones which are planned to complete during 3Q 2025 in support of achieving first gas, which is now expected in 4Q 2025.

Alongside the gas plant project execution work, much of the focus in 2Q 2025 has been on concluding commercial negotiations to export ANOH gas through the Nigeria LNG ('NLNG') terminal, as well as with a domestic gas customer who can offtake gas directly from the ANOH gas plant.. Combined, these two customers will provide sufficient contracted demand to enable the ANOH gas plant to operate at design capacity.

Work on the OB3 gas pipeline has been halted while its owner NGIC works with its contractors to review the final stages of the river crossing. We expect pipeline tunneling works to resume in 4Q 2025. In the meantime, as noted above, gas is expected to flow to the new customers in 4Q 2025.

During the quarter, the commercial lenders to AGPC signed a waiver to, among other things, ensure that principal repayment would not commence prior to the earlier of two quarters after completion or 31 March 2026. To ensure the gas plant completion remains on track, Seplat and its partner NGIC each injected an additional $20 million in equity during the period.

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 26.7 kg CO2/boe, lower than the 31.4 kg CO2/boe recorded in 6M 2024. On a quarter-on-quarter basis, carbon emissions intensity for our onshore assets fell by 25% to 23.0 kgCO2/boe in 2Q 2025, from 30.7 kgCO2/boe reported in 1Q 2025.


Emissions Intensity	Unit	Q2 2024	Q3 2024	Q4 2024	Q1 2025	Q2 2025
Onshore Operated Assets	kgCO2/boe	31.79	33.17	32.29	30.65	23.02

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 commenced operations in 1Q 2025 and is now producing, thus converting previously flared gas at the Sapele flow station to revenue. This has resulted in a 23% reduction in CO2 emissions at our Western Assets compared to the same period in 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 our offshore operations and alignment with the group reporting methodology. The intention is to begin reporting offshore emissions data during 2025.

HSE Performance

Across our operated assets we achieved a total of 15.3 million hours without a Lost Time Injury ('LTI') in 6M 2025, which reflects the Company's strong focus on safety and the dedication of its workforce to maintaining a secure work environment.

On our operated onshore assets, we recorded a total of 5.3-million hours without any LTI in 6M 2025 (6M 2024: 4.9-million hours), . The Company has achieved a cumulative 26.8-million hours since last LTI recorded (on 13th October 2022) across our operated onshore assets. On our offshore assets, we recorded 10.1 million hours worked without a LTI during the period. As such, we have now achieved a cumulative 19.4-million-man-hours since its last LTI on our offshore operations.

During the period, on our onshore operations, we recorded three Tier-1 Loss of Primary Containment (LOPC) incidents of which two were related to gas release and one due to an oil spill. Additionally, we recorded two Tier 2 LOPC incidents related to oil spills. Other key HSE performance metrics remain positive with no fatality, LTI, nor TRIR recorded during the quarter. We continue to invest in our processes and people to uphold the highest level of safety in our operations.


LTI-Free hours worked	Q1 2025	Q2 2025	6M 2025
Onshore Operated Assets	2,482,479	2,787,286	5,269,765
Offshore Operated Assets	4,759,567	5,302,475	10,062,042
Total Operated Assets	7,242,046	8,089,761	15,331,807
Elcrest	704,236	773,160	1,477,396
AGPC	909,903	881,542	1,791,445
Total Non-Operated Assets	1,614,139	1,654,702	3,268,841

As we guided in our 1Q 2025 results, we have completed the certification audit to obtain ISO 45001 and are currently awaiting certificate issuance. For ISO 14001, the Stage 1 audit is scheduled for Q3 2025, keeping us on track for certification. Working to achieve these certifications further demonstrates our commitment to top-tier safety and environmental performance.

Petroleum Industry Act (PIA) Implementation Status

In our onshore business, we continued to make good progress on the PIA conversion process in 2Q 2025. Following prior alignment with the Nigerian Upstream Petroleum Regulatory Commission (referred to as 'NUPRC' or 'the Commission') on retention areas and the Minimum Work Program, we concluded the standardisation of asset maps working with the Commission's nominated surveyor and submitted the required documentation. This milestone marks the completion of all technical requirements for PIA conversion. In addition, we received the new Petroleum Mining Lease (PML) and Petroleum Prospecting License (PPL) numbers for license and lease areas for retention.

While technical milestones have been completed, the overall conversion timeline remains subject to the Commission's process. As we move into the second half of the year, we will continue to engage closely with the Commission's legal team to close out relevant title documents for the new licenses and leases ahead of securing approval from the Ministry of Petroleum Resources in the second half of the year.

For our offshore assets, discussions have commenced with the regulator ahead of starting a formal process to convert to the PIA regime.

Financial review

Our 6M 2025 financial results continues to reflect the significant step change in our financial performance following consolidation of our onshore and offshore operations. Despite operating against the backdrop of a lower oil price environment in the second quarter, overall our financial performance remained robust with strong growth in revenue and free cashflow. We recorded an average realised oil price of $72.58/bbl, a $1.99/bbl premium to Brent. Our NGL realised price of $35.3/boe was equivalent to approximately 49% of Brent. Our blended realised gas price averaged $2.97/Mscf, a 1% increase on 6M 2024.

Revenue


Description	Units	Q2 2025	Q1 2025	q/q change	6M 2025	6M 2024	y/y change
Oil volumes lifted	mmbbl	7.9	9.9	(20)%	17.8	4.2	323%
NGLs volumes lifted	kbbl	142.2	138.0	3%	280.2	-	nm
Gas sales volume	Bscf	16.8	14.9	13%	31.7	19.8	60%
Average realised oil price	US$/bbl	67.35	76.42	(12)%	72.58	85.55	(15)%
Average Brent crude oil price	US$/bbl	66.45	74.87	(11)%	70.59	83.36	(15)%
Premium (discount) to Brent	US$/bbl	0.90	1.55	(42)%	1.99	2.19	(9)%
Average realised NGL price	US$/bbl	34.77	35.88	(3)%	35.3	-	nm
Average realised gas price	US$/mscf	2.98	3.01	(1)%	2.97	2.95	1%
Crude oil revenue	US$m	533.4	759.8	(30)%	1,293.2	360.4	259%
Gas revenue	US$m	50.1	44.5	13%	94.6	61.2	54%
NGLs revenue	US$m	4.9	5.0	(2)%	9.9	-	nm
Total revenue	US$m	588.4	809.3	(27)%	1,397.7	421.6	231%
(Overlift)/underlift *	kbbls	1,122	(595)	nm	921	841	10%
(Overlift)/underlift *	US$m	96.1	(53.5)	nm	42.6	55.8	(24)%
Total revenue adjusted for (overlift)/underlift	US$m	684.5	755.8	(9)%	1,440.3	477.4	202%
Crude oil revenue adjusted for (overlift)/underlift	US$m	629.5	706.3	(11)%	1,335.8	416.2	221%

*Overlift/Underlift balance in 6M 2025 comprised 527 kbbl crude oil overlift (valued at $25.8 million) and 394 kbbl NGL underlift (valued at $16.8 million).

Total revenue from oil and gas sales for 6M 2025 rose 231% to $1,397.7 million from $421.6 million in 6M 2024. The substantial increase was predominantly driven by the addition of the offshore assets to the group, partially offset by lower realised pricing. Of note, crude oil revenue contributed 93% of revenues in 6M 2025 compared to 85% in 6M 2024.

In 2Q 2025, reported revenue fell 27% QoQ to $588.4 million. The decline was driven by lower crude oil liftings, down 20% QoQ at 7.9 MMbbl, and lower price realisation as realised crude oil price fell 11% QoQ to $66.5/bbl. On the other hand, Gas revenue rose 13% QoQ to $50.1 miilion, aided by higher gas sales (+13% QoQ). Crude oil revenue represented approximately 91% of total revenue in the period. Adjusting for underlift, total revenue fell 9% QoQ to $684.5 million. Total contribution from Natural Gas Liquids ('NGL') sales remains muted pending replacement of the Inlet gas exchanger ('IGE') at EAP.

Cost of Sales


Description	Units	Q2 2025	Q1 2025	q/q change	6M 2025	6M 2024	y/y change
Non-Production Cost:		300.7	307.2	(2)%	607.9	154.6	293%
Royalties	US$'m	121.8	130.2	(6)%	252.0	71.0	255%
Depletion, Depreciation, & Amortisation	US$'m	168.8	164.1	3%	332.9	79.2	320%
Regulatory fees/levies*	US$'m	10.1	12.9	(22)%	23.0	4.5	417%
Production Cost:		156.1	149.1	5%	305.2	85.6	257%
Crude Handling Fees	US$'m	19.7	18.8	5%	38.6	31.8	21%
Barging & Trucking	US$'m	7.8	5.7	37%	13.5	8.0	68%
Operational & Maintenance Expenses	US$'m	128.6	124.6	3%	253.1	45.7	453%
Production Opex per boe	US$/boe	12.5	12.6	(1)%	12.5	9.7	29%
Cost of Sales	US$'m	456.8	456.3	- %	913.1	240.2	280%

*Regulatory fees & levies include NDDC and NESS levies

Direct operating costs, which encompass expenses related to crude-handling charges (CHC), barging/trucking, operations & maintenance, amounted to $305.2 million in 6M 2025 (6M 2024: $85.5 million). On our onshore operations, total production costs were $100.1 million (6M 2024: $85.5 million), reflecting the impact of higher production on our onshore assets. For our offshore assets, the equivalent costs were $205.1 million, reflecting the operating cost incurred in carrying out repairs and maintenance to improve asset integrity and reliability, laying the foundation for future growth. On a sequential basis production, costs of $156.1 million were up 5% QoQ, reflecting higher production. 2Q 2025 unit operating costs were broadly flat QoQ.

Non-production costs increased by 292% to $607.9 million, made up of $252.0 million in royalties (6M 2024: $71.0 million), $332.9 million in depreciation, depletion, and amortisation (6M 2024: $79.2 million), and regulatory fees/levies of $23.0 million (6M 2024: $4.5 million). Across asset categories, non-production costs on our onshore assets increased to $183.1 million (6M 2024: $154.7 million) due to higher DD&A charge for the quarter arising from higher production volumes. On our offshore assets, total non-production costs were $424.8 million. On a sequential basis non-production costs fell 2% driven by lower royalty payments.

Considering the cost per barrel equivalent basis, our onshore assets, production opex per boe was $10.1/boe while for our offshore assets, it was $14.2/boe. Our consolidated production opex per boe of $12.5/boe remains below our 2025 guidance ($14.0/boe - $15.0/boe) largely due to strong production and the timing of maintenance and workover well activities which are expected to be higher in 2H 2025.

Operating profit and Adjusted EBITDA


Description	Units	Q2 2025	Q1 2025	q/q change	6M 2025	6M 2024	y/y change
Gross Profit	US$'m	131.6	353.0	(63)%	484.6	181.5	167%
Other Income	US$'m	95.4	(44.4)	nm	51.0	88.4	(42)%
General and Administrative Expenses	US$'m	(70.2)	(64.9)	8%	(135.1)	(56.6)	139%
Impairment Loss	US$'m	(2.5)	(0.5)	400%	(3.0)	(1.2)	162%
Fair Value Loss	US$'m	(4.6)	(5.1)	(10)%	(9.7)	(3.0)	219%
Operating Profit	US$'m	149.6	238.2	(37)%	387.8	209.1	85%
Adjusted EBITDA	US$'m	334.4	400.6	(17)%	735.0	267.3	175%

In 6M 2025, gross profit rose 167% to $484.6 million, from $181.5 million in 6M 2024, reflecting the impact of bigger operations. Gross profit margins of 35% in 6M 2025, are lower than the 43% reported in 6M 2024, but in-line with management expectations. reflecting higher weighting to crude oil production, higher unit DD&A charge on our enlarged asset base and higher planned operating cost per barrel. On a sequential basis, gross profit fell 63% QoQ to $131.5 million, primarily due to lower crude oil liftings in the period.

General and Administrative ('G&A') expenses amounted to $135.1 million, versus $56.6 million in 6M 2024. G&A cost per boe for the group was lower at $5.6/boe (6M 2024: $6.4/boe) as one-off professional and acquisition costs exited the books. 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 underlift of $42.6 million, comprised of an overlift in 1Q 2025 more than offset by a large underlift in 2Q 2025, as noted above under "other income". We also recorded foreign exchange gain of $1.7 million (6M 2024: $30.3 million), largely reflecting exchange rate stability during the period.

Overall, we reported operating profit of $387.8 million in 6M 2025 (28% margin), from $209.1 million in 6M 2024 (50% margin). On a quarter on quarter basis operating profit fell 37% to $149.6 million, the change principally due to lower realised oil price.

After adjusting for non-cash items such as impairment, fair value, and exchange gains or losses, the adjusted EBITDA for the period was $735.0million (6M 2024: $267.3 million), resulting in a margin of 53%.

Net result


Description	Units	Q2 2025	Q1 2025	q/q change	6M 2025	6M 2024	y/y change
Profit before Tax	US$'m	85.5	207.4	(59)%	292.9	178.9	64%
Total Income tax expense:		81.4	184.1	(56)%	265.5	129.0	106 %
Net Income	US$'m	4.1	23.3	(82)%	27.4	49.9	(45)%
Profit Attributable to Holders of Equity	US$'m	3.4	20.2	(83)%	23.6	40.8	(42)%
Earnings per Share	US$c'shr	0.01	0.03	(67)%	0.04	0.07	(43)%

Profit before tax rose 64%, amounting to $292.9 million, compared to $178.9 million in 6M 2024. Profit after tax for the period was $27.4 million (6M 2024: $49.9 million). The Profits after tax this period have been impacted significantly by taxes and we have explained this in more detail below in the taxation section.

The profit attributable to equity holders of the parent Company, representing shareholders, was $23.6 million in 6M 2025, which resulted in basic earnings per share of $0.04 for the period (6M 2024: $0.07/share).

Taxation

The Company reported an income tax expense of $265.5 million (6M 2024: $129.0 million), representing an interim effective tax rate (ETR) of 91% (6M 2024: 72%). This ETR has been determined in accordance with IAS 34 Interim Financial Reporting, which requires the income tax expense recognised in the interim income statement to reflect the estimated full-year effective tax rate, applied to year-to-date profits. The high ETR reflects the front-loaded tax burden typically observed in our fiscal profile and the current estimate of full-year taxable profit.

Looking ahead to the second half of the year, we expect a lower tax burden driven by:

1. Increased capital allowances in our offshore business arising from planned capital investments in 2H 2025

2. The outcome of an updated Competent Persons Report (CPR), which is expected to support a potential reduction in the unit-of-production (UOP) depreciation rate, thereby lowering our DD&A expense

3. Progress on the Petroleum Industry Act (PIA) conversion for our onshore assets, which could shift our tax regime from the legacy 85% Petroleum Profits Tax (PPT) framework to a more favourable combined 60% rate (30% Hydrocarbon Tax + 30% Corporate Income Tax).

While these initiatives are still in progress, our current projection is that the full-year 2025 effective tax rate is expected to range between 70% and 80%, subject to the finalisation of the above matters.

Cash flows from operating activities


Description	Units	Q2 2025	Q1 2025	q/q change	6M 2025	6M 2024	y/y change
Profit before tax	US$'m	85.5	207.4	(59)%	292.9	178.9	64%
Non Cash Adjustments	US$'m	262.9	213.3	23%	476.2	93.9	407
Working Capital Changes	US$'m	111.2	(114.2)	(197)%	(3.0)	(46.8)	(94)%
Pre-tax Cashflow from Operating Activities	US$'m	459.6	306.5	50%	766.2	226.0	239%
Cash Taxes	US$'m	(177.3)	(36.2)	390%	(213.5)	(48.8)	337%
Others*	US$'m	(12.1)	(53.7)	(77)%	(65.8)	(4.8)	1281%
Post-tax Cashflow from Operating Activities	US$'m	270.3	216.6	25%	486.9	172.4	182%

*Others include hedge premium and contribution to plan assets

The strong growth in operating cashflow was underpinned by the enhanced production base and improved settlement of trade receivables by customers, partially offset by weaker oil prices.

Net cash flow from operating activities amounted of $486.9 million in 6M 2025, compared to $172.4 million in 6M 2024 and includes cash tax payments made year to date of $213.5 million, hedging premiums of $13.0 million and for the offshore business, a $52 million contribution for the defined benefit scheme paid during the current period, while in the previous year, cash tax payments were $48.8 million, and the hedging premium paid was $2.8 million.

Overall, the cash taxes paid represents 28% of operating cashflow, an increase from 12% recorded in 1Q 2025 as cash tax payments continued to reflect the tax paying position of the enlarged group. A similar amount of cash taxes paid in 1H, 2025 are expected to be paid in 2H 2025, however, the final full year 2025 cash taxes will depend on timing of capital spend in the year and finalisation of the deferred tax position.

With respect to working capital, onshore cash call collections remained robust. On the OMLs 4, 38 & 41 and OML 40 JVs, we received $142.7 million in cash calls from our JV partner, bringing the receivables balance to $61.4 million (FY2024: $41.4 million). On OML 53, cash call obligations are fully paid up. In our offshore business, we received $394.5 million for cash call settlements out of $459.0 million receivables reported in the period, as such the balance on the JV receivables at 30 June 2025 was $384.0 million, an improvement on the $419.0 million reported balance at end Q1 2025. The current receivables are being processed in line with schedule. We have made significant progress on legacy offshore receivables, having obtained approvals of approximately 70% of the outstanding balance. We anticipate cash recoveries on this portion within 2025 while engagements concerning the remaining balances are ongoing and continue to advance constructively.

Cash flows from investing activities


Description	Units	Q2 2025	Q1 2025	q/q change	6M 2025	6M 2024	y/y change
Post-tax Cashflow from Operating Activities	US$'m	270.3	216.6	25%	486.9	172.4	182 %
Capital Expenditure	US$'m	(56.3)	(40.2)	40%	(96.5)	(102.4)	(6)%
Free Cashflow	US$'m	214.0	176.4	21%	390.4	70.0	458%
Additional Investment in Joint Venture	US$'m	(10.0)	(10.0)	- %	(20.0)	-	nm
Others*	US$'m	(0.2)	6.9	(103)%	6.7	20.8	(68)%
Net cash outflows used in investing activities	US$'m	(66.5)	(43.3)	54 %	(109.7)	(81.6)	34%

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

In 6M 2025 the total net cash outflow from investing activities was $109.7 million, an increase on the $81.6 million reported in 6M 2024.

The cash capital expenditure on oil & gas assets during the period was $95.7 million (6M 2024: $101.1 million), down from the prior year given limited drilling activity onshore and the expectation that major capex items for the group will occur in 2H 2025. Total capex (including other fixed assets) was $96.5 million (6M 2024: $102.4 million).

As a result of the strong operating performance in 6M 2025, and expected bias of cash capital expenditure to 2H 2025, the business generated $390.4 million of free cashflow, a material increase compared to the $70 million generated in 6M 2024.

During the period the Company provided $20.0 million in equity funding to the AGPC IJV ($10.0 million in Q1 2025 and $10 million Q2 2025 respectively), in order to support delivery of the final project completion elements ahead of first gas.

Cash flows from financing activities


Description	Units	Q2 2025	Q1 2025	q/q change	6M 2025	6M 2024	y/y change
Repayments of Loans and Borrowings	US$'m	-	(919.3)	nm	(919.3)	(19.3)	4673%
Proceeds from Loans and Borrowings	US$'m	-	650.0	nm	650.0	-	nm
Interest paid on Loans and Borrowings	US$'m	(13.1)	(36.4)	(64)%	(49.5)	(32.5)	52%
Other Finance Costs	US$'m	(35.4)	(5.1)	594%	(40.5)	(9.4)	331%
Dividends paid	US$'m	(67.7)	-	nm	(67.7)	(53.0)	28%
Shares purchased for employees	US$'m	-	-	nm	-	(15.5)	nm
Net cash outflows used in financing activities	US$'m	(116.2)	(310.8)	(63)%	(426.9)	(129.6)	229%

Net cash outflow from financing activities was $426.9 million, compared to an outflow of $129.6 million in 6M 2024. The principal driver for the outflow was debt movements among the Company's principal borrowing facilities as we communicated in our 1Q 2025 results.

The increase in interest expense reflects increased drawn debt facilities (associated with the offshore assets acquisition) and higher interest rates on the newly issued Eurobond. The increase in Other finance costs relates to transaction costs on issuance of the $650 million Eurobond, and as such are not expected to repeat in 2H 2025.

During the period, we paid $67.7 million in dividends to our shareholders, representing a 28% increase on 6M 2024's $53.0 million. No shares were purchased for the obligations under the long-term incentive plan (6M 2024: $15.5 million).

Debt Movements

No principal debt facilities were raised or repaid during 2Q 2025. However, and in July, the Company repaid the outstanding $100.0 million balance on the RCF. As of this report date, our $350 million RCF is undrawn and fully available.

Liquidity

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


		Reported*	Reported*	Reported*
Description	Units	6M 2025	6M 2024	FY2024
Senior loan notes	US$'m	650.0	655.8	657.6
Westport Reserve Based Lending (RBL) facility	US$'m	31.4	71.3	51.1
Revolving credit facility	US$'m	100.4	0.0	351.5
Offtake facilities	US$'m	10.5	10.3	10.3
Advance payment facility	US$'m	303.4	0.0	297.0
Total borrowings	US$'m	1,095.7	737.4	1,367.6
Cash and cash equivalents (exclusive of restricted cash)	US$'m	419.4	371.8	469.9
Net Debt	US$'m	676.3	365.7	897.8
Adjusted Pro-Forma EBITDA **	US$'m	1,272.7	479.4	1,353.5
Net Debt-to-Trailing Twelve Months EBITDA	X	0.53	0.76	0.66

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

** Adjusted EBITDA 2024 represents the FY2024 pro-forma adjusted EBITDA for onshore and offshore combined, 6M 2025 adjusted EBITDA includes pro-forma adjusted EBITDA from onshore and offshore between 2H 2024 plus 6M 2025 adjusted EBITDA as reported.

Seplat Energy ended the period with gross debt of $1,095.7 million (YE 2024: $1,376.6 million) and cash at bank of $419.4 million (YE 2024: $469.9 million), resulting in net debt of $676.3 million (YE 2024: $897.8 million). Net debt declined by 25% due to a combination of debt repayments and free cash generation in 6M 2025. On a quarter-on-quarter basis net debt fell by 9.5% (1Q 2025: $747 million)

We continue to monitor the Net Debt-to-EBITDA ratio of the Company with a corporate policy of maintaining our net leverage ratio below 2.0x (Debt covenant - 3.0x). At the end of June 2025, proforma Net Debt-to-EBITDA ratio improved to 0.53x, from 0.66x at the end of 2024.

Dividend

The Board has approved a dividend of US$ 4.6 cents per share for the second quarter 2025 (subject to appropriate WHT), retaining the dividend increase implemented in 1Q 2025. This is a 28% increase on 4Q 2024 core dividend, and a 53% increase on the equivalent core dividend in 2Q 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 plan to update our capital allocation policy in our capital markets day, scheduled for 18 September this year.


Reporting Period	Proposed Dividend (US$ cents per share)	Announcement Date	Qualification Date (LSE)	Qualification Date (NGX)	Payment Date
Q1 2025	4.6	28. April 2025	23. May 2025	23. May 2025	6. June 2025
Q2 2025	4.6	30. July 2025	12. August 2025	12. August 2025	28. August 2025
Total 2025 YTD	9.2

Hedging

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

We completed our 2025 hedging program during 2Q 2025, hedging a total of 21.0 MMbbls for the year. Hedges have been placed at a weighted average premium of $0.91/bbl and a weighted average strike price of $53.75/bbl. During the second quarter of 2025 the oil market experienced increased volatility. Despite the increased geopolitical premium in short dated Brent, the market retained a conservative medium term oil price outlook. As such, we commenced hedging 2026 volumes for 1Q and added our first tranche of 2.0 MMbbls upfront premium puts hedged at strike price of $50.0/bbl, at a cost of $1.26/bbl. We note that due to increased production, we plan to hedge higher volumes than the 5.25 MMbbl per quarter hedged volumes executed in 2025. Our simple put option hedge strategy is unchanged.


2025 Oil Hedges (Brent Put Options)	Unit	Q1 2025	Q2 2025	Q3 2025	Q4 2025	Q1 2026
Volumes hedged	MMbbls	5.25	5.25	5.25	5.25	2.00
Price hedged	US$/bbl	55	55	55	50	50
Puts cost	US$/bbl	0.44	0.97	0.87	1.34	1.26

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 B2 (stable); (ii) S&P B (stable); (iii) Fitch B (stable).

In April 2025 Fitch upgraded our corporate rating to B (previously B-). Similarly, in June 2025, Moody's upgraded our credit rating to B2 (stable), from Caa1 (positive). This was linked to an upgraded outlook for the Nigerian sovereign long term rating and the agencies' view of a stronger business profile post the completion of the MPNU acquisition. We note that our Corporate rating with Moody's (B2) is a higher rating than the Nigerian sovereign rating of B3. Our rating with S&P was reaffirmed in April 2025.

Outlook

Seplat Energy's 2025 production, capex and unit operating cost guidance is maintained. Production operations strengthened in the second quarter, with the benefit of improved production efficiency and idle well restoration offshore and strong production contribution from Western Assets onshore. Costs, both capex and opex continued to track below guidance in the first half of the year, however we anticipate an increase in run rate costs in 2H 2025 given increased drilling activity, the ordering of long lead items and installation of the replacement IGE offshore.

Production guidance

Seplat Energy's production operations were ahead of the mid-point of guidance in 6M 2025, supported by continued strong performance onshore and in particular from improvements in well capacity offshore. In 3Q 2025 some downtime is planned offshore for installation of the replacement IGE at EAP and onshore in the East due to planned maintenance on TNP.

2025 production guidance maintained at 120-140 kboepd. This includes:

• Seplat Onshore: 48-56 kboepd. In 2H 2025 production focused operations include; remaining new well delivery from the 2025 plan, first gas at ANOH and stable operations at Sapele gas plant.

• Seplat Offshore: 72-84 kboepd. In 2H 2025 production focused operations include: continued work-overs on idle well stock, completion of the replacement IGE at EAP, and continued investment in production optimisation activities.

Capex guidance

Working interest capital expenditure guidance is maintained in the range of $260 million - $320 million.

Cash capex in 6M 2025 of $96.5 million was limited to a number of smaller projects including final payments for 2024 wells, the delivery of the first set of 2025 wells and Sapele IGP construction costs. Run rate is expected to increase in 2H 2025, due to the items outlined below.

• Seplat Onshore: $180 million-$220 million. Key focus of the investment programme remains new well stock to offset natural decline

• Programme includes drilling the remaining 11 wells in the 2025 programme: OMLs 4, 38 & 41: Six (two completed in 1H 2025), OML 53: Two, OML 40: Three.

• Completion of the second MRU at the Sapele IGP

• Delivery of remaining end of routine flaring projects

• Seplat Offshore: $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 guidance maintained in the range of $14.0-15.0/boe.

Other information

Free Float

With a free float of 28.0% as at 30 June 2025, Seplat Energy PLC is compliant with the Nigerian Exchange's free float requirements for companies listed on the Premium Board.

Share Dealing Policy

We confirm that to the best of our knowledge that there has been compliance with the Company's Share Dealing Policy during the period.

Directors' Interest in Shares

In accordance with Section 301 of the Companies and Allied Matters Act, 2020, the interests of the Directors (and of persons connected with them) in the share capital of the Company (all of which are beneficial unless otherwise stated) are as follows:


	31 December 2023	31 December 2024		30 June 2025
	No. of Ordinary Shares	No. of Ordinary Shares	As a percentage of Ordinary Shares in issue	No. of Ordinary Shares	As a percentage of Ordinary Shares in issue
Udoma Udo Udoma	0	55,071	0.01%	55,071	0.01%
Roger Brown	4,831,379	4,006,169	0.68%	4,673,2011	0.79%
Samson Ezugworie	257,288	547,9832	0.09%	547,983	0.09%
Eleanor Adaralegbe	n/a	234,209	0.04%	659,6913	0.11%
Bashirat Odunewu	0	0	- %	0	- %
Nathalie Delapalme	0	0	- %	0	- %
Oliver De Langavant	0	0	- %	0	- %
Emma FitzGerald	0	0	- %	0	- %
Ernest Ebi	50,000	50,000	0.01%	50,000	0.01%
Kazeem Raimi	0	6,577	- %	6,577	- %
Koosum Kalyan	0	0	- %	0	- %
Christopher Okeke	0	0	- %	0	- %
Bello Rabiu4	20,000	20,000	- %	n/a	n/a
Babs Omotowa4	n/a	20,000	- %	n/a	n/a
Total	5,158,667	4,940,009	0.84%	5,992,523	1.02%

1) Additional shares transferred as LTIP vested shares at nil cost, and shares purchased on market

2) 290,695 shares acquired at nil-cost through vesting of sign-on share award and Executive Deferred Bonus (EDB) Award.

3) Additional shares transferred as LTIP vested shares at nil cost,

4) Mr Bello Rabiu and Mr Babs Omotowa stepped down from the Board in April 2025 following their appointments to the Board of NNPC Ltd

Substantial Interest in Shares

At 30 June 2025, the following shareholders held more than 5.0% of the issued share capital of the Company:


Shareholder	Number of holdings	%
Maurel & Prom Group	120,402,000	20.46
Petrolin Group	81,015,319	13.77
Sustainable Capital	59,736,749	10.15
Professional support	50,019,178	8.50
Allan Gray Investment Management	31,784,393	5.40

Principal risks and uncertainties

The Board of Directors is responsible for defining the Company's overall risk management strategy and setting its risk appetite, including determining the level of risk that Seplat Energy is willing to accept. Details of the critical risks and uncertainties facing Seplat Energy as of year-end are outlined in the Risk Management section of the 2024 Annual Report and Accounts. Our risk categories have remained largely consistent and aligned with industry benchmarks. These categories are:

1 Operational and Safety

2 Strategic and Commercial

3 Conduct, Culture & Integrity

4 Political and Security

5 Climate Change and Energy Transition

Responsibility Statement

For the six months ended 30 June 2025

The directors confirm to the best of their knowledge that::

1) The condensed set of financial statements have been prepared in accordance with lAS 34 'Interim Financial Report';

2) The interim management report includes a fair review of the information required by UK DTR 4.2.7R (indication of important events during the first six months and description of principal risks and uncertainties for the remaining six months of the year); and

3) The interim management report includes a fair review of the information required by UK DTR 4.2.8R disclosure of related parties' transactions and changes therein.

A list of current Directors is included on the company website: www.seplatenergy.com.

By order of the Board,


U.U. Udoma Chairman FRC/2013/NBA/00000001796 30 Jul 2025	R.T. Brown Chief Executive Officer FRC/2014/PRO/DIR/003/00000017939 30 Jul 2025	E. Adaralegbe Chief Financial Officer FRC/2017/ICAN/00000017591 30 Jul 2025

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