REG - Seplat Energy PLC - Unaudited Q1 Results: 31 March 2025
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RNS Number : 3520G Seplat Energy PLC 28 April 2025
Please see the Full Audited Results in attached PDF
http://www.rns-pdf.londonstockexchange.com/rns/3520G_1-2025-4-27.pdf
(http://www.rns-pdf.londonstockexchange.com/rns/3520G_1-2025-4-27.pdf)
Unaudited results for the three months ended 31 March 2025
28 April 2025
Overview
Lagos and London, 28 Apr 2025: Seplat Energy PLC ("Seplat Energy" or "the
Company"), a leading Nigerian independent energy Company listed on both the
Nigerian Exchange and the London Stock Exchange, announces its audited results
for the three months ended 31 March 2025.
Summary
Delivered robust production and cost performance during 1Q 2025, at a new
scale, and firmly on track to deliver FY 2025 guidance. Strong cash position
supports early repayment of $250 million reducing the RCF to $100 million, and
an increase in our quarterly dividend to US$ 4.6c/share.
Operational highlights
· Production averaged 131,561 boepd up 167% from 1Q 2024 (49,258 boepd), above
the midpoint of 2025 guidance (120 - 140 kboepd).
· Onshore production contribution of 56,196 boepd, was 14% higher than 1Q
2024, and above 2025 guidance. Within this, liquids +10% and gas +21% vs 1Q
2024, following strong performance at Oben Gas Plant and first contribution
from Sapele Gas Plant.
· SEPNU production contribution of 75,365 boepd, within guidance, of which
88% crude and condensate, 4% NGL and 8% gas.
· SEPNU idle well restoration programme added c.11 kbopd gross JV production
from the first 10 wells restored to production.
· Sapele Integrated Gas Plant ('SIGP') was commissioned and achieved first
commercial gas sales in February 2025. Plant is delivering high quality
processed gas, and condensate yields of c.2 kbopd.
· Carbon emissions intensity for Seplat onshore assets: 30.6 kg CO2/boe (revised
1Q 2024: 31.1 kg CO2/boe), reduction driven by lower emissions at Sapele post
start-up of SIGP. End of routine flaring for onshore assets on track for H2
2025.
· Achieved more than 7.3 million man hours without Lost Time Injury (LTI), of
which 2.5 million was Seplat onshore-operated assets (1Q 2024: 2.3 million man
hours) and 4.8 million hours without LTI for SEPNU.
Financial highlights
· Revenue $809 million up c.350% on prior year (1Q 2024: $180 million).
· Unit production operating cost of $12.6/boe (1Q 2024: $9.5/boe), better than
guidance of $14-$15/boe, due to timing of planned maintenance activities.
· Adjusted EBITDA of $401 million, up 226% on prior year (1Q 2024: $123
million).
· Cash generated from operations of $306.5 million, up materially from $16.8
million in 1Q 2024.
· Cash capital expenditure of $40.2 million (1Q 2024: $47 million). Onshore
drilling activity to ramp up from 2Q 2025.
· Completed refinancing of $650 million senior notes, with newly issued notes
having a 2030 maturity and priced with a coupon of 9.125%. Seplat notes were
priced inside the Nigerian sovereign for the first time, reflective of
established reputation in credit markets.
· Reduced gross debt by ~21% following early repayment of $250 million of RCF
and $19.3 million repayment of Eland RBL.
· Balance sheet remains robust, end-March cash at bank $334.6 million (YE 2024:
$469.9 million), excluding $128.9 million restricted cash.
· Net Debt at end-March of $747 million down 17% on prior quarter (YE 2024: $898
million). Pro-forma ND/EBITDA improves to 0.56x.
Dividend & Board
· 1Q 2025 declared dividend of US$ 4.6c/share, an increase on the prior quarter
dividend (US$ 3.6c/share), reflecting the strength of our financial position
and confidence in our outlook. The company plans to set out a revised capital
allocation policy in the Capital Markets Day scheduled for September 2025.
· Mr. Bello Rabiu, Senior Independent Non-Executive Director and Mr. Babs
Omotowa, Independent Non-Executive Director resigned from the Board following
their appointment to the NNPC Ltd board. The Board has unanimously appointed
Mrs. Bashirat Odunewu as Senior Independent Non-Executive Director.
2025 Outlook
· 2025 guidance unchanged.
· Production guidance of 120-140 kboepd (Seplat Onshore 48-56 kboepd, SEPNU
72-84 kboepd).
· Capex guidance $260-320 million. (Seplat Onshore $180-220 million, SEPNU
$80-100 million).
· Unit operating costs for the group are expected to be $14.0-15.0/boe.
· Capital Markets Day in September 2025 to detail our medium to long term growth
ambitions.
Roger Brown, Chief Executive Officer, said:
"2025 has started positively for Seplat. As we deliver the business at a
significantly enhanced scale, our focus is on the successful integration of
the combined companies, and I am pleased to report that we are making good
progress. It is clear that we can benefit greatly from the combined expertise
of our onshore and offshore workforce.
Production has been strong, showing the benefit of the continuous drilling
programme, investment in asset integrity and the availability of multiple
evacuation routes. Financial performance was also strong, allowing us to be
pro-active in materially reducing gross debt, maintaining low balance sheet
leverage, and further strengthening our company as the near term global
economic outlook becomes less predictable.
We remain conservative in our approach, but our confidence in the future
trajectory for our business, combined with our strong financial position,
means that we are delighted to increase our quarterly dividend to $
4.6c/share, an 28% increase in our quarterly dividend versus 4Q 2024. Our
assets are high quality, and while we will remain agile to the prevailing oil
price environment, our business plan is designed to be robust at lower oil
prices and our gas revenues, which are largely delinked to oil prices, provide
long-term stability for the business. We are committed to our plan of growth
and maximising value for our stakeholders."
Summary of performance
$ million ₦ billion
Q1 2025* Q1 2024 % change Q1 2025* Q1 2024
Revenue ** 809.3 179.8 350.0% 1,227.5 268.6
Gross profit 353.0 42.7 726.4% 535.4 63.8
EBITDA *** 400.6 123.3 224.9% 607.6 184.2
Operating profit (loss) 238.2 81.9 190.7% 361.3 122.4
Profit (loss) before tax 207.4 69.3 199.4% 314.6 103.5
Profit (loss) after tax 23.3 (1.9) nm 35.4 (2.9)
Cash generated from operations 306.5 16.8 1721.0% 464.9 25.2
Working interest production (boepd) 131,561 49,258 167.1%
Volumes lifted (MMbbls) 9.9 1.8 450.0%
Average realised oil price ($/bbl) 76.42 86.17 (11.3)%
Average realised gas price ($/Mscf) 3.01 3.11 (3.2)%
LTIF - -
CO2 emissions intensity from operated onshore assets, kg/boe 30.6 31.1 (1.5)%
*Throughout results 1Q 2025 reported figures consolidate SEPNU contribution,
while 1Q 2024 information relates solely to Seplat's Onshore assets
** 1Q 2025 reported revenue includes an overlift of $53.5 million, 1Q 2024
excludes an underlift of $56.4 million
*** Adjusted for non-cash items
Responsibility for publication
This announcement has been authorised for publication on behalf of Seplat
Energy by Eleanor Adaralegbe, Chief Financial Officer, Seplat Energy PLC.
Signed:
Eleanor Adaralegbe
Chief Financial Officer
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.
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
Investec Bank plc
Chris Sim +44 207 597 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://www.seplatenergy.com/ (https://www.seplatenergy.com/)
Operating review
Group Production
Working interest production for the three months ended 31 March 2025
Asset Seplat WI Q1 2025 Q1 2024
Crude & Condensate Gas NGLs Total Crude & Condensate Gas NGLs Total
% bopd MMscfd bpd kboepd bopd MMscfd bpd kboepd
OMLs 4, 38, 41 45% 16,291 132.0 - 39,050 15,089 109.5 - 33,961
OML 40 45% 12,676 - - 12,676 12,470 - - 12,470
OML 53 40% 2,935 - - 2,935 1,263 - - 1,263
OPL 283 40% 1,535 - - 1,535 1,564 - - 1,564
Seplat Onshore 33,437 132.0 - 56,196 30,386 109.5 - 49,258
OMLs 67, 68, 70, 104 40% 65,385 20.2 3,376 72,238 - - - -
OML 99 (A/K Field) 9.6% 816 13.4 - 3,127 - - - -
SEPNU 66,201 33.6 3,376 75,365 - - - -
Total 99,638 165.6 3,376 131,561 30,386 109.5 - 49,258
Liquid production volumes as measured at the LACT (Lease Automatic Custody
Transfer) unit for OMLs 4, 38 and 41; OML 40 and OPL 283 flow station.
Gas conversion factor of 5.8 boe per scf.
Volumes stated are subject to reconciliation and may differ from sales volumes
within the period.
In 1Q 2025, total crude & condensate production increased by 224% to 9.0
MMbbls, compared to the 2.8 MMbbls produced in 1Q 2024. Total gas produced
during the quarter also rose 50% to 14.9 Bscf (1Q 2024: 10.0 Bscf), and we
also produced 304 kbbls of NGLs in 1Q 2025. As such, aggregate production for
the quarter rose 164% to 11.8 MMboe (1Q 2024: 4.5 MMboe). This reflects the
transformational impact of the SEPNU consolidation and strong performance on
our onshore assets. We provide more details on drivers of this performance in
subsequent sections.
Average daily working interest production for the group was 131,561 boepd (1Q
2024: 49,258 boepd), slightly above the midpoint of our production guidance of
120,000 - 140,000 boepd.
Production performance in our onshore assets was strong, up 14% from the
equivalent period in 2024 (1Q 2025: 56,196 boepd; 1Q 2024: 49,258 boepd),
aided by a confluence of several positive catalysts including good performance
of the new wells in the 2024 drilling campaign, commencement of gas production
from Sapele Integrated Gas Plant (SIGP), improved gas production from Oben
following turnaround maintenance, and continuation of 24-hour operations at
the Trans Niger Pipeline (TNP).
Seplat Energy Producing Nigeria Unlimited (SEPNU)
Production across the offshore assets started the year in-line with
expectations with daily average working interest production during 1Q 2025 of
75,365 boepd. January and February benefited from high uptime, while in March
we commenced a number of planned shutdown operations to improve long term
asset performance.
Across product lines, production was 88% crude and condensates, 4% NGL, and 8%
gas. The Amenam-Kpono field (A/K) contributed 3.1 kboepd to average daily
production of which 26% was crude and condensate and the balance gas.
During 1Q 2025 we commenced the 2025 work programme, and we are pleased to
report that, after period end, we achieved 2025 budget planning sign-off with
our JV partners
The programme to resume production from idle wells across the license
commenced during the period. At period end, approximately 11 kboepd gross
production capacity has been reinstated from the idle well restoration
programme. This has been achieved from 10 idle wells, that could be accessed
directly from certain existing platforms. The jack-up barge has now moved to
well work activities and commenced well interventions after the period end.
Combining both platform and well work barge activities, we are now targeting
production restoration work on over 50 of the idle well inventory in 2025.
The East Area Project ('EAP') Inlet Gas Exchanger (IGE) replacement project
will increase gross JV NGL production at EAP by 8 to 10 kboepd when
operational. Fabrication of the IGE unit was completed in the OEM facility
(Germany) and transported in-country. Construction works, including onshore
interconnect piping fabrication and offshore installation campaign have
commenced and installation is expected to complete during 3Q 2025.
Other planned maintenance activities increased during March, included a nested
shutdown across three major platforms to address full function testing of
critical safety devices and replacement of multiple valves, rises and piping.
These activities impacted production across Crude, NGL and gas in the period.
Gas sales were also impacted by a leak on third party infrastructure.
Seplat Onshore Operations Update
Western Assets
In OMLs 4, 38, & 41, working interest liquids production rose by 8% to
16,291 bopd (1Q 2024: 15,089 bopd). The growth was aided by the successful
2024 drilling campaign which helped to arrest decline on the assets and
support growth. In addition, export route availability remained strong during
the quarter with only two days overlapping downtime between the
Amukpe-Escravos pipeline ('AEP') and Trans Forcados pipeline ('TFP') routes.
While overall asset performance was strong, it was partially offset by some
operational challenges on the TFP and at the Escravos Oil Terminal ('EOT'). As
such, total deferments on the asset in 1Q 2025 rose to 17% (1Q 2024: 13%).
Elcrest
Production at OML 40 recorded marginal improvement, rising by 1.7% to 12,676
bopd (1Q 2024: 12,470 bopd). Well performance at OML 40 continues to remain
strong while export route availability has also been a positive for
production. Total deferments on OML 40 during the quarter were 22%. Elcrest
recorded 0.7 million LTI free man hours in 1Q 2025.
Sibiri oil field
As communicated in our FY 2024 results, following persistent strong well
performance at Sibiri, we plan to drill three wells (Sibiri-C, Sibiri-D, &
Sibiri-E) at the Sibiri field in the 2025 drilling plan. Drilling of the wells
will commence in 2H 2025.
Abiala oil field
In our FY 2024 results, we reported receipt of field development approval
(FDP) from the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) on
14th February, 2025. In the period since, we have ramped up production from
all four producing strings, reaching approximately 3,500 bopd gross. By March
2025, Abiala's total production reached approximately 130,000 barrels, with
the first crude export of 30,000 barrels on March 21, 2025.
In April 2025, the field was shut in as we commenced operations to switch
production from the extended well test facility ('EWT') to an early production
facility ('EPF'). Production is expected to resume during 2Q 2025 following
installation, integration, and commissioning of the Abiala EPF. We are pleased
to report that following positive initial observations, gross production
potential from the two development wells is now estimated at 8,000 bopd, up
from our previous estimate of 5,000 bopd. We also secured an additional
storage vessel to support optimised production and evacuation from the Abiala
field.
Eastern Assets
In OML 53, average daily working interest production increased by 132% to
2,935 bopd in 1Q 2025, from 1,263 bopd in 1Q 2024, due to continuous
availability of the evacuation routes for the asset, principally the Trans
Niger Pipeline ('TNP'). During the quarter a section of the TNP, near the
Bodo-Bonny road, was impacted by attempted sabotage, however the episode
caused minimal disruption to our Ohaji operations, with normal production
restored within days. Total uptime for the TNP-BOT evacuation route in 1Q 2025
was 88% (1Q 2024: 0%). We also continued to supply the Waltersmith refinery
during the quarter.
Production from our Jisike field continued to improve as the reliability of
the Antan-Ebocha-Brass terminal route was sustained in 1Q 2025. Uptime on the
route improved to 73% (1Q 2024: 29%).
In OPL 283, production was stable at 1,535 bopd (1Q 2024: 1,564 bopd).
Drilling activities
As communicated in our FY 2024 results, our 2025 drilling programme involves
delivery of 13 new wells on our onshore assets (Western Assets - 7 wells;
Eastern Assets - 2 wells; Elcrest - 4 wells). No wells from the 2025 plan were
completed during 1Q 2025, while four are expected to complete during 2Q 2025.
The 2025 well programme is expected to arrest production decline and support
organic growth ambitions.
In 1Q 2025, we spudded two wells (Orogho KZGF-02 and Okporhuru-10) on OMLs 4,
38, & 41, both of which are set to be completed in May 2025. A third well
is also planned on our Western asset in 2Q 2025, together, the three wells are
estimated to add 3,100 bopd and 45 MMscfd gross JV production volumes.
At OML 40, implementation of the drilling programme will commence in 2Q 2025
once the rig arrives at location. Rig maintenance work is ongoing while all
regulatory permits needed to commence drilling are being finalised. We plan to
deliver one well in 2Q 2025.
On our Eastern assets, we are in the process of securing a land rig and
obtaining the necessary regulatory permits required to commence drilling.
Drilling activities are expected to start during 3Q 2025.
Offshore activity related to drilling is currently focused on planning for
future drilling campaigns, including identification of potential drilling
contractors and long lead items.
Midstream Gas business performance
During the quarter, the Company delivered 14.9 Bcf of gas, representing a 50%
increase on 1Q 2024's 10.0 Bcf . The average daily working interest gas
production volumes increased by 51% to 165.6 MMscfd, from 109.5 MMscfd in 1Q
2024. Consolidation of SEPNU's gas production added 33.6 MMscfd to the group's
average daily working interest gas production during the quarter. On our
onshore assets, average daily working interest gas production increased by 21%
to 132.0 MMscfd (1Q 2024: 109.5 MMscfd). The increase was supported by
commencement of production at the Sapele gas plant, gas wells coming onstream,
and improved efficiency at the Oben gas plant following the 2024 turnaround
maintenance activities.
2025 Domestic Gas Price Update
On 1st April, the Nigerian Midstream and Downstream Petroleum Regulatory
Authority (NMDPRA) announced a downward review of gas price for Domestic Gas
Delivery Obligation (DGDO) contracts for a year from April 2025, to
$2.13/MMbtu, from $2.42/MMbtu previously. We continue to work with industry
members to engage with the regulator to review the decision.
Sapele Gas Plant
The Sapele Gas Plant is a 90 MMscfd plant, capable of processing both
Non-Associated Gas (NAG) and Associated Gas (AG) which meets export
specifications and an LPG processing module which will supply LPG to the
domestic market. The project will also contribute significantly to Seplat's
target to end routine flaring by the end of 2025.
As previously reported the initial 30 MMscfd Mechanical Refrigeration Unit
('MRU') was completed in Q4 2024, in line with expectations. The start of
commercial operations began in February 2025. Throughput has been very strong,
averaging c.28 Mmscf/d high quality gas, with strong condensate recovery of
c.2 kbopd gross volumes. We have seen high demand for the gas due to its
specification, which augurs well for the start up on the second 60 MMscf MRU.
The second MRU, which will lift total production capacity to 90 MMscfd, is on
track for completion during 2Q 2025 with sales commencing in the third
quarter. The upgraded facility will produce gas that meets export
specifications, and the LPG processing module will enhance the economics of
the plant and eliminate routine gas flaring. During 1Q 2025 associated gas
commercialisation through Sapele gas plant resulted in approximately a 30%
reduction in emissions intensity at the Sapele flow station, illustrating the
potential of the programme.
We note that in early 2025, Oben and Sapele gas plants combined operations
has regularly exceeded 300 MMscfd on a gross JV basis, peaking at 333 MMscfd
(c. 150 MMScfd net working interest) during the quarter.
ANOH Gas
AGPC continued its strong safety performance achieving a cumulative total of
15.4 million man-hours LTI free by the end of 1Q 2025. We are pleased to
announce that the ANOH Gas plant construction project achieved commissioning
(dry) gas Ready for Start-Up ('RFSU') milestone during the quarter, and will
shortly introduce dry gas for commissioning.
Beyond the gas plant execution work, much of the focus in 1Q 2025 has been on
securing alternative evacuation options, given continued delays to completion
of the OB3 pipeline. During the period AGPC agreed preliminary heads of terms
for delivery of gas into the export market through the Nigeria LNG ('NLNG')
terminal. This will act as an interim outlet for gas monetization and work is
currently ongoing to make the necessary pipeline modifications to enable gas
sales to commence in 3Q 2025.
During the quarter the Incorporated Joint Venture ('IJV') partners agreed to
an additional equity investment of $20 million (Seplat share; $10 million) to
support final project execution costs in advance of revenue generation from
production.
Ending routine flaring
Reducing the carbon intensity of our operations is a key strategic focus.
Seplat has implemented its end of routine flaring ('EORF') roadmap, which
includes investments across our production facilities to minimise Scope 1
& 2 greenhouse gas emissions and improve overall energy efficiency.
The carbon emissions intensity recorded on Seplat's onshore operations for the
period was 30.6 kg CO2/boe, lower than the 31.1 kg CO(2)/boe recorded in 1Q
2024. On a quarter-on-quarter basis, carbon emissions intensity onshore fell
by 5% from 32.3 kgCO(2)/boe reported in 4Q 2024. The improvement in carbon
emissions intensity was driven by the completion and commencement of
operations from the 30 MMscfd MRU at the Sapele gas plant. As stated above,
the first module of SIGP has commenced operations and is now producing.
Partial commercialisation of the associated gas flares was achieved, which
resulted in a reduction of c.30% in CO(2) emissions at the Sapele flow
station, versus 4Q 2024. Further reductions are expected as full injection of
associated gas into Sapele gas plant is achieved later in 2025.
Other ongoing key flare-out projects include, the Western Asset Flares Out
(installation of vapour recovery unit compressors), Sapele LPG Storage &
Offloading Facility, Oben LPG Project and Ohaji Flares Out Project. The
Company is on track to end routine flaring of gas across its onshore assets in
2H 2025.
We continue to assess the emissions and flaring regime within SEPNU and
alignment with Seplat reporting methodology. The intention is to begin
reporting SEPNU emissions data during 2025.
HSE Performance
The Company achieved a total of 2.5-million hours without any Lost Time Injury
(LTI) on its operated onshore assets in 1Q 2025 (1Q 2024: 2.3-million hours),
which reflects the Company's strong focus on safety and the dedication of its
workforce to maintaining a secure work environment. The Company has achieved a
cumulative 23.0-million-man hours since last LTI recorded (on 13th October
2022) across our operated onshore assets. In the period we recorded two
Process Safety Tier 1 incidents of which one was related to an oil spill and
one due to a gas release, and one further oil spill related Tier 2 loss of
primary containment incident. Other key HSE performance metrics remain
positive with no fatality, LTI, nor TRIR recorded during the quarter.
As we disclosed in our FY 2024 results, we remain on the path towards
achieving ISO 45001 and 14001 standards certifications. In 1Q 2025, we
progressed the stage 2 audit for ISO 45001 and expect to complete it in time
to receive the certification in Q2 2025. We also completed the stage 2
regulatory audit for ISO 14001 and remain on track to achieve completion in Q2
2025. Working to achieve these certifications further demonstrates our
commitment top-tier safety and environmental performance.
SEPNU recorded 4.8 million hours worked without a LTI during the period, as
such SEPNU has now achieved a cumulative 14.1-million-man-hours since its last
LTI.
Petroleum Industry Act (PIA) Implementation Status
In our onshore business, we have progressed the process towards securing
approval to convert our onshore assets to the PIA regime. In our FY 2024
release, we communicated that delineation had been made based on principles
established in section 93 of the PIA, 2021 and that the Commission has
requested documentation from Seplat that would facilitate the preparation of
legal transfer documents on the retained PMLs and PPLs.
We are pleased to report that post the FY 2024 results release, we have
submitted to NUPRC, all relevant technical data on areas to be relinquished.
We have also commenced work with the commission's recommended surveyor to
standardise vertices and coordinates of the retention areas, in line with
statutory requirements for boundary maps and conversion documentation.
Completing this process will facilitate the preparation of legal transfer
documents on the retained PMLs and PPLs.
For SEPNU, conversations are ongoing with the regulators to resume the process
of conversion of the offshore assets to PIA.
Board Changes
Following their recent appointments to the Board of NNPC Limited by the
President of the Federal Republic of Nigeria, Mr. Bello Rabiu, Senior
Independent Non-Executive Director ('SINED') and Mr. Babs Omotowa, Independent
Non-Executive Director ('INED') notified the Board of their resignations. The
Board has subsequently appointed Mrs. Bashirat Odunewu as our new SINED.
Financial review
Our 1Q 2025 results represent the first complete quarter as an enlarged
business, resulting in a significant step change in financial performance,
with reported revenues 350% higher than in 1Q 2024. This was partially offset
by weakness in Brent oil price versus the prior year, a factor which has
continued after the period end. We recorded an average realised oil price of
$76.42/bbl, a $1.55/bbl premium to Brent, but down 12% on prior year. Our NGL
realised price of $44.8/boe was equivalent to approximately 60% of Brent. Our
blended realised gas price averaged $3.01/Mscf, a 3% decrease on 1Q 2024.
Revenue
Reported Reported
Description Units Q1-2025 Q1-2024 y/y change
Oil volumes lifted mmbbl 9.9 1.8 450%
NGLs volumes lifted kbbl 138.0 - nm
Gas sales volume Bscf 14.9 10.0 49%
Average realised oil price US$/bbl 76.42 86.17 (11)%
Average Brent crude oil price US$/bbl 74.87 81.67 (8)%
Premium (discount) to Brent US$/bbl 1.55 4.50 (66)%
Average realised NGL price US$/bbl 44.8 - nm
Average realised gas price US$/mscf 3.01 3.11 (3)%
Crude oil revenue US$m 759.8 150.8 404%
Gas revenue US$m 44.5 29.0 53%
NGLs revenue US$m 5.0 - nm
Total revenue US$m 809.3 179.8 350%
(Overlift)/underlift * kbbls (595) 849 nm
(Overlift)/underlift * US$m (53.5) 56.4 nm
Total revenue adjusted for (overlift)/underlift US$m 755.8 236.2 220%
Crude oil revenue adjusted for (overlift)/underlift US$m 704.9 207.2 240%
*Overlift/Underlift balance in the quarter comprised 672 kbbl crude oil
overlift (valued at $54.9 million) and 77 kbbl NGL underlift (valued at $1.4
million).
Total revenue from oil and gas sales for 1Q 2025, rose 350% to $809.3 million
from $179.8 million in 1Q 2024. Adjusting reported revenue for 1Q 2025
overlifts and 1Q 2024 underlifts, total oil and gas sales were $755.8 million
($53.5 million overlift), 220% higher than 1Q 2024's equivalent revenue figure
of $236.2 million ($56.4 million underlift).
Reported crude oil revenue, rose 404% to $759.8 million in 1Q 2025 from $150.8
million in 1Q 2024. The increase in crude oil revenue reflects the full impact
of the acquired SEPNU business as total crude oil volume lifted for the period
rose 450% to 9.9 MMbbls in 1Q 2025, from the 1.8 MMbbls lifted in 1Q 2024. As
such, despite an 11% decline in average realised oil price to $76.42/bbl in 1Q
2025 (1Q 2024: $86.17/bbl), the strong increase in volumes lifted supported
crude oil revenue growth. The impact of a liquids-heavy acquired business is
now reflected in the fact that crude oil revenue contributed 94% of revenues
in 1Q 2025 compared to 84% in 1Q 2024.
Reported gas revenue rose by 53% to $44.5 million in 1Q 2025, compared to
$29.0 million in 1Q 2024. Gas sales represented 5% of total reported revenue
in 1Q 2025 (1Q 2024: 16%). The increase in gas revenue is due to higher gas
sales volume of 14.9 Bscf (1Q 2024: 10.0 Bscf) which offset the impact of
lower realised gas price of $3.01/Mscf (1Q 2024: $3.11/Mscf). Higher gas sales
for the period reflects the impact of strong gas production growth at the Oben
gas plant, beginning of commercial operations at the Sapele gas plant, and gas
production from SEPNU. The lower realised gas price reflects the impact of
adding SEPNU's gas sales into the portfolio. The average realised gas price
for SEPNU gas was $2.42/Mscf while for our onshore assets, it was $3.18/Mscf.
The business recorded $5.0 million revenue from Natural Gas Liquids (NGLs)
sales in 1Q 2025. Total NGL production volume was 304 kbbls while total NGLs
lifted during the period was 138 kbbls. Average realised price was $44.79/bbl
(59% of realised crude price).
Production deferment in the period was 19% onshore (1Q 2024: 22%) and 23%
offshore. Onshore deferments were ahead of plan given reduced third party
related downtime, while offshore was in line with plan. The group's average
reconciliation loss factor for the onshore assets remained both stable and low
at 3.2% in 1Q 2025, attributed to continued focus on security measures and
asset integrity management.
Gross profit
Reported Reported
Description Units Q1-2025 Q1-2024 y/y change
Non-Production Cost:
Royalties US$'m 130.2 50.8 156%
Depletion, Depreciation, & Amortisation US$'m 164.0 41.4 296%
Others US$'m 12.9 2.0 545%
Production Cost:
Crude Handling Fees US$'m 18.8 18.9 (1)%
Barging & Trucking US$'m 5.7 3.7 54%
Operational & Maintenance Expenses US$'m 124.6 20.2 517%
Production Opex per boe US$/boe 12.6 9.6 31%
Cost of Sales US$'m 456.2 137.0 233%
Gross Profit US$'m 353.0 42.7 727%
In 1Q 2025, gross profit rose 727% to $353.0 million, from $42.7 million in 1Q
2024, reflecting the impact of bigger operations.
Direct operating costs, which encompass expenses related to crude-handling
charges (CHC), barging/trucking, operations & maintenance, amounted to
$149.1 million in 1Q 2025 (1Q 2024: $42.8 million) due to consolidation of
SEPNU's production costs. On our onshore operations, total direct operating
costs was $53.3 million (1Q 2024: $42.7 million), reflecting the impact of
higher production on our onshore assets. For our offshore assets, total direct
operating costs was $95.8 million.
Non-production costs increased by 226% to $307.2 million, made up of $130.2
million in royalties (1Q 2024: $50.8 million), $164.0 million in depreciation,
depletion, and amortisation (1Q 2024: $41.4 million), and regulatory
fees/levies of $12.9 million (1Q 2024: $2.0 million). The increase in group
non-production costs reflect consolidation of SEPNU's costs. Across asset
categories, non-production costs on our onshore assets increased to $98.3
million (1Q 2024: $94.3 million) due to higher DD&A charge for the quarter
arising due to higher production volumes. On our offshore assets, total
non-production costs were $208.9 million.
Considering the cost per barrel equivalent basis, our onshore assets,
production opex per boe was $10.5/boe while for SEPNU, it was $14.6/boe. Our
consolidated production opex per boe of $12.6/boe is lower than our 2025
guidance ($14.0/boe - $15.0/boe) largely due to timing of maintenance and
workover well activities scheduled to commence later in the year.
Operating profit and Adjusted EBITDA
Reported Reported
Description Units Q1-2025 Q1-2024 y/y change
Other Income/(Loss) US$'m (44.4) 65.0 nm
General and Administrative Expenses US$'m (64.9) (24.1) 169.3%
Impairment (Loss)/Reversal on Financial Assets US$'m (0.5) 0.7 (171.4)%
Fair Value Loss US$'m (5.0) (2.4) 108.3%
Operating Profit US$'m 238.2 81.9 190.8%
Adjusted EBITDA US$'m 400.6 123.3 224.9%
General and Administrative ('G&A') expenses amounted to $64.9 million,
versus $24.1 million in 1Q 2024 further reflecting the consolidation of SEPNU.
G&A cost per boe for the group was $5.5/boe. We continue to invest efforts
in improving administrative efficiency in order to bring costs lower while we
also limit the impact of non-recurring costs.
During the period, we recorded overlift of $53.5 million, translating to 672
kbbls, compared to underlift of $56.4 million (translating to 849 kbbls) which
was adjusted for in the Other income line item in the Income statement. We
also recorded foreign exchange gain of $5.9 million (1Q 2024: $6.0 million)
due to optimized cash working capital management and a more stable naira
this period.
Overall, we reported operating profit of $238.2 million in 1Q 2025 (29.4%
margin), from $81.9 million in 1Q 2024 (45.6% margin). The increase in
reported operating profit also reflects the increased scale of the business.
After adjusting for non-cash items such as impairment, fair value, and
exchange gains or losses, the adjusted EBITDA for the quarter was $400.6
million (1Q 2024: $123.3 million), resulting in a margin of 49.5%.
Taxation
The income tax expense of $184.1 million (1Q 2024: $71.2 million) includes a
current tax charge of $215.0 million (1Q 2024: $13.9 million) and a deferred
tax credit of $30.9 million (1Q 2024: $57.3 million charge). The higher tax
charge in the income statement reflects the current tax due in SEPNU. For the
offshore assets, we expect the current tax charge to moderate overtime as the
pool of available capital allowances increases as we increase our investments
across the asset base.
Net result
Profit before Tax US$'m 207.4 69.3 199%
Total Income tax expense: 184.1 71.2 159%
Current Tax US$'m 215.0 13.9 1447%
Deferred Tax US$'m (30.9) 57.3 (154)%
Net Income/(Loss) US$'m 23.3 (1.9) nm
Profit Attributable to Holders of Equity US$'m 20.2 1.0 1920%
Earnings per Share US$c'shr 3.1 - nm
Profit before tax rose 199%, amounting to $207.4 million, compared to $69.3
million in 1Q 2024. Profit after tax for the quarter was $23.3 million,
compared to a $1.9 million loss in 1Q 2024.
The profit attributable to equity holders of the parent Company, representing
shareholders, was $20.2 million in 1Q 2025, which resulted in basic earnings
per share of $0.03 for the period (1Q 2024: $0.002/share).
Cash flows from operating activities
Reported Reported
Description Units Q1-2025 Q1-2024 y/y change
Profit before tax US$'m 207.4 69.3 199%
Non Cash Adjustments US$'m 213.3 61.0 250%
Working Capital Changes US$'m (114.2) (113.4) 1%
Pre-tax Cashflow from Operating Activities US$'m 306.5 16.9 1714%
Cash Taxes US$'m (36.2) (0.5) 7140%
Others US$'m (53.7) (1.4) 3736%
Post-tax Cashflow from Operating Activities US$'m 216.6 14.9 1354%
In 1Q 2025, the Company generated pre-tax cashflow from operating activities
of $306.5 million (1Q 2024: $16.9 million). The substantial improvement
reflects the impact of the significantly enhanced production base, alongside
relatively lower costs, partially offset by a working capital build of $114.2
million.
Net cash flow from operating activities amounted to $216.6 million in 1Q 2025,
compared to $14.9 million in 1Q 2024. This figure includes cash tax payments
of $36.2 million and a hedging premium of $1.7 million paid during the current
period, while in the previous year, cash tax payments were $0.5 million, and
the hedging premium paid was $1.4 million. Overall, the cash taxes paid
represents 12% of operating cashflow. We anticipate the effective cash tax
rate to increase in subsequent quarters during 2025 due to the addition of the
offshore assets. Longer term, our planned investments in SEPNU via capital
projects such as the East Area Project IGE will help build-up a capital
allowance balance in SEPNU which will be deductible against future assessable
profits.
Our onshore business continues to record strong cash call collection in 1Q
2025. During the quarter, on the NEPL/Seplat JV for OMLs 4, 38 & 41 and
OML 40, we received $119.4 million in cash calls from our JV partner, bringing
the receivables balance on the JV to $28.4 million (FY 2024: $41.4 million).
On our NUIMS/Seplat JV for OML 53, we received $9.0 million in cash call
settlement in 1Q 2025 with cash call obligations fully paid up.
For our SEPNU/NNPC JV, though we received $153.0 million for cash call
settlements out of $253.0 million due for the period, the balance on the JV
receivables rose to $419.0 million (FY 2024: $318.0 million). We note that we
received the balance of the 2025 cash call payments post the reporting period.
On the legacy cash call receivable balance, which represents approximately 75%
of the total balance, we have had positive interactions with our partner to
reconcile these cash calls and progress to settlement. We anticipate that we
will begin to recover these balances from 4Q 2025.
Cash flows from investing activities
Reported Reported
Description Units Q1-2025 Q1-2024 y/y change
Post-tax Cashflow from Operating Activities US$'m 216.6 14.9 1353.7%
Capital Expenditure US$'m (40.2) (47.1) (14.6)%
Free Cashflow US$'m 176.4 (32.2) nm
Additional Investment in Joint Venture US$'m (10.0) - nm
Restricted Cash US$'m 3.3 (3.0) nm
Others* US$'m 3.6 17.6 (79.5)%
Net cash outflows used in investing activities US$'m (43.3) (32.5) 33.2%
*Others include Interest received, and deposit for asset held for sale.
In 1Q 2025 the total net cash outflow from investing activities was $43.3
million, an increase on the $32.5 million reported in 1Q 2024.
The cash capital expenditure on oil & gas assets during the period was
$39.9 million (1Q 2024: $46.4 million), down from the prior year given limited
drilling activity in the quarter. Total capex (including other fixed assets)
was $40.2 million (1Q 2024: $47.1 million).
As a result of the strong operating performance in 1Q 2025, the business
generated $176.4 million of free cashflow, compared to the negative free
cashflow of $32.2 million generated in 1Q 2024.
During the period the Company provided an additional $10 million in equity
funding to the AGPC IJV,
Cash flows from financing activities
Reported Reported
Description Units Q1-2025 Q1-2024 y/y change
Repayments of Loans and Borrowings US$'m (919.3) (19.3) 4663.2%
Proceeds from Loans and Borrowings US$'m 650.0 - nm
Interest paid on Loans and Borrowings US$'m (36.4) (32.2) 13.0%
Other Finance Costs US$'m (5.1) (7.4) (31.1)%
Shares purchased for employees US$'m - (8.5) nm
Net cash outflows used in financing activities US$'m (310.8) (67.4) 361.1%
Net cash outflow from financing activities was $310.8 million, compared to an
outflow of $67.4 million in 1Q 2024. The principal driver for the outflow was
debt movements among the Company's principal borrowing facilities, described
below. Interest charges increased 13% on the prior period due to an increase
in drawn debt facilities. Other finance charges predominantly relates to
repayment of leases and interest on leases. No shares were purchased for the
obligations under the long-term incentive plan (1Q 2024: $8.5 million).
Debt Movements
On 21 March 2025 the Company successfully refinanced its $650 million 7.75%
144A/Reg S bond, which was set to mature in March 2026, with a new $650
million 9.125% 144A/Reg S bond maturing in April 2030. The offering was
strongly over-subscribed, despite challenging market conditions. We are
pleased to note that the offering, our third since 2018, priced inside the
Nigerian sovereign for the first time, testament to our strong reputation in
public credit markets.
Subsequent to our bond refinancing, the Company's $350 million revolving
credit facility ('RCF') maturity was automatically extended to 31 December
2026. In late March, the Company took the opportunity, due to its strong cash
position, to pay down $250 million of its previously fully drawn facility. As
such, at 31 March 2025, $100 million was drawn under the $350 million
revolving credit facility.
The $110 million Westport RBL Facility (RBL Facility) commenced amortising on
31 March 2023. The reduction in facility commitments occurs on a semi-annual
basis in March and September of each year until final maturity in 2026. In
March 2025, Seplat's wholly owned subsidiary, Westport (and the borrower of
record under the RBL facility) paid $19.25 million in principal repayments
under the RBL Facility. As at 31 March 2025, $30.25 million is now outstanding
under the RBL Facility. The next reduction in commitments will be on 30
September 2025 for an amount of $19.25 million.
In total, the Company repaid approximately 21% of its outstanding gross debt
during the period. There were no changes in the principal amount outstanding
under the Seplat group's other facilities (including, the $300m advanced
payment facility with ExxonMobil, which is fully drawn, or the $50 million
Westport off-take loan, of which $11 million is outstanding). See note 22.2
for further details on debt movements during the period.
Liquidity
The balance sheet continues to remain healthy with a solid liquidity position.
Principal amount Reported* Reported*
Description Units Q1-2025 Q1-2025 FY-2024
Senior loan notes US$'m 650.0 634.7 657.6
Westport Reserve Based Lending (RBL) facility US$'m 30.3 30.4 51.1
Revolving credit facility US$'m 100.0 102.2 351.5
Offtake facilities US$'m 11.0 9.9 10.3
Advance payment facility US$'m 300.0 304.5 297.0
Total borrowings US$'m 1,091.3 1,081.7 1,367.5
Cash and cash equivalents (exclusive of restricted cash) US$'m 334.6 469.9
Net Debt US$'m 747.1 897.6
Adjusted Pro-Forma EBITDA ** US$'m 1,345.2 1,353.5
Net Debt-to-TTM EBITDA x 0.56 0.66
* Including amortised interest and accrual for the RCF (undrawn)
commitment fee
** Adjusted EBITDA 2024 represents the FY 2024 pro-forma adjusted EBITDA for
Seplat and SEPNU combined, 1Q 2025 adjusted EBITDA includes pro-forma adjusted
EBITDA from Seplat and SEPNU between 2Q-4Q 2024 plus 1Q 2025 adjusted EBITDA
as reported.
Seplat Energy ended the period with gross debt of $1,081.6 million (YE 2024:
$1,376.6 million) and cash at bank of $334.6 million (YE 2024: $469.9
million), leaving net debt at $747 million (YE 2024: $898 million). Net debt
declined by 17% due to a combination of debt repayments and free cash
generation during the quarter.
We continue to monitor the Net Debt-to-EBITDA ratio of the Company with a
focus to keep it under 2.0x (Debt covenant - 3.0x). At the end of March 2025,
proforma Net Debt-to-EBITDA ratio improved to 0.56x, from 0.66x at end 2024.
Dividend
The Board has approved a quarterly dividend of US$ 4.6 cents per share for the
first quarter 2025 (subject to appropriate WHT). This is a 28% increase on
4Q 2024 core dividend, and a 53% increase on the equivalent core dividend in
1Q 2024. On the basis of maintaining this level through 2025 it will result in
a total dividend of $18.4 cents per share, an 11% increase in the total
dividend declared for 2024 ($16.5 cents per share). We expect to set out an
updated capital allocation policy in our capital markets day scheduled for
September this year.
Reporting Period Proposed Dividend (US$ cents per share) Announcement Date Qualification Date (LSE) Qualification Date (NGX) Payment Date
Q1 2024 3.0 14. June 2024
Q2 2024 3.0 28. August 2024
Q3 2024 3.6 27. November 2024
Q4 2024 3.6 4. March 2025 9. May 2025 12. May 2025 23. May 2025
Special 2024 3.3 4. March 2025 9. May 2025 12. May 2025 23. May 2025
Total 2024 16.5
Q1 2025 4.6 28. April 2025 23. May 2025 23. May 2025 6. June 2025
Hedging
Seplat Energy's hedging policy aims to guarantee appropriate levels of cash
flow assurance in times of oil price weakness and volatility.
Year to date 15.75 MMbbls have been hedged for 1Q-3Q 2025 at a weighted
average premium of $0.76/bbl and a weighted average strike price of $55.0/bbl.
Additional barrels are expected to be hedged for 4Q 2025 later in the year in
line with our policy and as soon as the right opportunity presents especially
in view of market volatility.
2025 Oil Hedges (Brent Deferred Premium Put Options) Unit Q1 2025 Q2 2025 Q3 2025 Q4 2025
Volumes hedged MMbbls 5.25 5.25 5.25
Price hedged US$/bbl 55 55 55
Puts cost US$/bbl 0.44 0.97 0.87
Credit ratings
Seplat maintains corporate credit ratings with Moody's Investor Services
(Moody's), Standard & Poor's Rating Services (S&P) and Fitch Ratings
(Fitch). The current corporate ratings are as follows: (i) Moody's Caa1
(positive); (ii) S&P B (stable); (iii) Fitch B (stable).
In April 2025 Fitch upgraded our corporate rating to B (previously B-). This
was linked to an upgraded outlook for the Nigerian sovereign long term rating
and the agency's view of a stronger business profile post the completion of
the MPNU acquisition. Our ratings with S&P and Moody's were reaffirmed in
April 2025 and March 2025 respectively.
Outlook
Seplat Energy's 2025 production, capex and unit operating cost guidance is
maintained. Production operations performed well in the first quarter, with
the benefit of ANOH gas and the impacts of the onshore drilling programme and
offshore maintenance & capex activities yet to be realised. Costs, both
capex and opex tracked below guidance in the first quarter, however we
anticipate an increase in run rate costs in 2Q 2025 onwards as drilling
activity increases onshore and the jack-up barge commences well restoration
work offshore.
Production guidance
Seplat Energy's production operations were ahead of the mid-point of guidance
in 1Q 2025 and was supported by strong performance in particular from the
onshore assets which benefited from the performance of 2024 new wells, high
uptime on Oben gas plant and contribution from Sapele IGP.
2025 production guidance reiterated at 120-140 kboepd. This includes:
• Seplat Onshore: 48-56 kboepd. mid-point delivers 7% growth on 2024.
Production in 2025 is set to benefit from well stock delivered in 2024, plus
contribution from ANOH from 2H25, Sapele Gas Plant's second MRU and the
completion of the Abiala EPF. We also see growth on OML 53 oil given the
resumption of 24-hour operations on the TNP.
• SEPNU: 72-84 kboepd. mid-point delivers 12% growth on 2024. We are
targeting growth from restoration of idle wells, investment in improving
reliability of the NGL facilities and other activities which will improve
uptime and provide the basis for longer term growth plans.
Capex guidance
Working interest capital expenditure guidance is reiterated in the range of
$260 million - $320 million.
Capex in 1Q 2025 of $40.2 million was limited to a number of smaller projects
including final payments for 2024 wells and Sapele IGP construction costs. Run
rate will increase in 2Q 2025 with the drilling of 4 wells and EAP IGE
costs.
• Seplat Onshore: $180 million-$220 million. Key focus is new well stock
to offset natural decline
• Programme includes drilling 13 new wells: OMLs 4, 38 & 41:
Seven, OML 53: Two, OML 40: Four. Of these, 9 are oil wells and 4 are gas
wells
• Completion of the second MRU at the Sapele IGP
• Delivery of Oben, Amukpe, Sapele & Ohaji flares out projects
• SEPNU: $80 million-$100 million. Key focus on capital projects and
long term planning to improve reliability, uptime and safety
• Installation of the Inlet Gas Exchanger on the East Area Project
(EAP) NGL facility
• Long lead items for 2026+ drilling programme
Opex guidance
Unit operating costs for the Company are expected be in the range of
$14.0-15.0/boe. This increase in unit operating costs versus prior years
reflects increased investment in O&M activities across our offshore
assets, mainly re-opening previously shut-in wells and asset integrity work
required due to long term lack of investments. Our expectation continues to be
that unit opex will moderate post 2025/2026 as production grows and as
investment pivots towards capital projects. In 2025 the major cost items
are:
• Two jack-up barges to operate across the offshore license area from
early 2Q 2025, one targeting integrity works and the other working on the idle
well restoration programme.
The primary goal of the 2025 opex plan is to increase reliability and
integrity offshore which will set a solid foundation from which to grow
production over time. Due to the nature of the installed infrastructure
offshore, the 2025 plan necessitates partial asset shut-downs, which commenced
in March 2025 and will continue at certain points during the year.
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. END QRFPKOBQOBKDAQBRecent news on Seplat Energy
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