REG - Seplat Energy PLC - Unaudited Results for Six Months to 30 June 2025
30/07/2025 07:02
For best results when printing this announcement, please click on link below:
https://newsfile.refinitiv.com/getnewsfile/v1/story?guid=urn:newsml:reuters.com:20250730:nRSd0933Ta&default-theme=true
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
(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
(https://sparklive.lseg.com/SEPLATENERGY/events/2c5ed548-9ad8-4e74-8c18-d60c12615bc0/seplat-energy-plc-half-year-results-2025)
Conference call and pre-register Link: Registration Link (https://registrations.events/direct/LON592233)
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 ir@seplatenergy.com
Ayorinde Akinloye, Investor Relations
Chioma Afe, Director, External Affairs & Social Performance
FTI Consulting
Ben Brewerton / Christopher Laing +44 203 727 1000
seplatenergy@fticonsulting.com
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 Half year
ended ended
30 June 2025 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 12,000m(2) 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 CO(2)/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 kgCO(2)/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 CO(2) 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% 4,673,201(1) 0.79%
Samson Ezugworie 257,288 547,983(2) 0.09% 547,983 0.09%
Eleanor Adaralegbe n/a 234,209 0.04% 659,691(3) 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 Rabiu(4) 20,000 20,000 - % n/a n/a
Babs Omotowa(4) 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 R.T. Brown E. Adaralegbe
Chairman Chief Executive Officer Chief Financial Officer
FRC/2013/NBA/00000001796 FRC/2014/PRO/DIR/003/00000017939 FRC/2017/ICAN/00000017591
30 Jul 2025 30 Jul 2025 30 Jul 2025
This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact
rns@lseg.com (mailto:rns@lseg.com)
or visit
www.rns.com (http://www.rns.com/)
.
RNS may use your IP address to confirm compliance with the terms and conditions, to analyse how you engage with the information contained in this communication, and to share such analysis on an anonymised basis with others as part of our commercial services. For further information about how RNS and the London Stock Exchange use the personal data you provide us, please see our
Privacy Policy (https://www.lseg.com/privacy-and-cookie-policy)
. END IR DXGDRSGDDGUCRecent news on Seplat Energy
See all newsREG - Seplat Energy PLC - Notification of Major Holdings
AnnouncementREG - Seplat Energy PLC - CURRENCY EXCHANGE RATE FOR Q2 2025
AnnouncementREG - Seplat Energy PLC - Further Issue and Admission of Ordinary Shares
AnnouncementREG - Seplat Energy PLC - CORPORATE ANNOUNCEMENT
AnnouncementREG - Seplat Energy PLC - Unaudited Results for Six Months to 30 June 2025
Announcement