REG - Serica Energy PLC - Results for the six months ended 30 June 2025
Yesterday 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:20250805:nRSE9288Ta&default-theme=true
RNS Number : 9288T Serica Energy PLC 05 August 2025
Serica Energy plc
('Serica' or 'the Company')
Results for the six months ended 30 June 2025
London, 5 August 2025 - Serica Energy plc (AIM: SQZ), a British independent
upstream oil and gas company with operations in the UK North Sea, today
announces its unaudited financial results for the six months ended 30 June
2025. The results are included below and copies are available at
www.serica-energy.com (http://www.serica-energy.com) and www.sedar.com
(http://www.sedar.com) .
Chris Cox, Serica's CEO, stated:
"Serica has felt like a coiled spring in the first half of 2025. The
resilience of our gas production from the Bruce Hub and strong Q1 gas prices,
coupled with a robust contribution from our other producing assets, helped
deliver a creditable financial performance despite the downtime at the Triton
FPSO. With the ramp up from Triton progressing, we should soon return to
production levels of around 50,000 boepd, with more to come as new wells at
Guillemot and Evelyn come onstream. Optimisation work by the Serica team at
the Bruce Hub is also beginning to deliver results, and will boost production
in the second half of the year.
We continue to make progress on advancing future production opportunities.
Subsea tie-in work on Belinda is progressing well, and this new field will
come onstream at the start of 2026. As we plan future drilling programmes
across our wider asset base, we will look to replicate the success of the five
well drilling campaign at Triton. This achieved tremendous subsurface results
that are of material size to Serica, and was delivered ahead of schedule and
under budget. Our future drilling plans have the potential to offset natural
field declines into the next decade.
The expected increase in production compared to the last 12 months is set to
provide material cash generation, funding organic growth and sustained
dividends while we continue to seek to create shareholder value through
disciplined M&A."
Results summary ($ million unless stated)
H1 2025 H1 2024 FY 2024
Average realised Brent oil price ($/bbl) 70 78 75
Average realised gas price (pence per therm) 96 67 76
Production (boepd) 24,700 43,700 34,600
Revenue 305 462 727
Operating costs 156 151 330
EBITDAX 118 279 379
Cash Tax (received)/paid (71) 72 153
CFFO less Current Tax 102 193 403
Capital expenditure 138 116 260
Free cash flow 14 98 (1)
(Loss)/profit after tax (43) 82 92
Cash 174 362 148
Total debt (231) (231) (231)
(Adjusted net debt)/adjusted net cash (57) 131 (83)
Interim dividend declared (pence per share) 6 9 N/A
( )
Highlights
Positive subsurface performance set to boost production
· Production of 24,700 boepd net to Serica in H1 2025 (H1 2024:
43,700 boepd), impacted materially by the shut-in of the Triton FPSO from 28
January to the end of the period
· Work to increase production from the Bruce Hub is starting to
deliver results, with well optimisation work and the resumption of production
at Keith leading to an increase in production post-period end, which averaged
21,600 boepd in July compared to 16,700 boepd in H1 2025
· The completion of the BE01 well on the Belinda field (Serica
100%), which delivered rates of 7,500 boepd on test, brought to an end the
highly successful five well drilling programme at Triton
- All five wells delivered positive results which met or exceeded
pre-drill estimates
- The programme was delivered 25 days ahead of schedule and c.$31
million net to Serica under budget
Cash position remains robust, providing optionality over capital allocation
· Cash of $174 million (31 December 2024: $148 million), an
increase since year end 2024 despite the ongoing capital expenditure programme
and no production from Triton since January
- Cash was boosted by the receipt of the $71 million cash tax refund
in June 2025, the result of Group relief in 2024 leading to an overpayment of
cash tax in 2024 under the Instalment Payment Regulations
- Capital expenditure on a cash basis of $138 million in H1, as work
continued on the Triton drilling campaign
· Net debt reduced by $26 million in the period to $57 million
· Strong financial capacity maintained with the redetermination of
Reserves Based Lending facility ('RBL') completed in June, with the Borrowing
Base set at $490 million, of which $231 million is drawn down
- Liquidity of $433 million as at 1 July 2025
· Interim dividend of 6p declared today (2024 interim dividend:
9p), in line with the previously announced rebalancing of the final dividend
- The interim dividend is payable on 20 November 2025 to shareholders
registered on 24 October 2025, with an ex-dividend date of 23 October 2025
Organic growth potential, actively exploring value-accretive M&A
· Serica's low net debt and robust liquidity position underpins the
Company's continued ability to make targeted organic growth investments and to
remain both competitive and opportunistic in M&A
· Serica continues to progress plans to convert material 2C
resources into reserves, should the appropriate fiscal and regulatory
environment allow
- Following the identification of over 20 potential infill targets
around the Bruce Hub, considerable further work and planning has been
undertaken with a high-graded list of optimal targets being matured for a
possible future drilling campaign
- The Company continues to aim for FID of the Kyle redevelopment
(Serica 100%) in H1 2026 Front-end design work tenders have been issued and
the procurement of long lead items is underway
- A Request for Information has been sent out for a semi-submersible
rig to carry out a potential drilling campaign across Bruce and Kyle
· Serica continues to analyse multiple M&A opportunities,
largely focused on the UK North Sea
Outlook and guidance - material cash generation expected
· Production in the second half of 2025 is expected to be
materially higher than H1, due to significantly increased Triton FPSO uptime,
contribution from new wells at Triton, and the continuation of the production
increase following the reinstatement of low-pressure wells at the Bruce Hub
· Production guidance for FY 2025 of 33,000-35,000 boepd
· Capital expenditure expected to be around the top end of the
$220-250 million range given the relative strength of Sterling against the US
Dollar, and work to progress Belinda towards production at the start of 2026
moving forward at pace, accelerating spend from 2026 into 2025
· Opex guidance unchanged at c.$330 million
· Work is progressing well regarding the move from the AIM to the
Main Market of the London Stock Exchange early in Q4 2025
Regulatory
This announcement is inside information for the purposes of Article 7 of
Regulation 596/2014.
The technical information contained in the announcement has been reviewed and
approved by Fergus Jenkins, VP Technical at Serica Energy plc. Mr. Jenkins
(MEng in Petroleum Engineering from Heriot-Watt University, Edinburgh) is a
Chartered Engineer with over 25 years of experience in oil & gas
exploration, development and production and is a member of the Institute of
Materials, Minerals and Mining (IOM3) and the Society of Petroleum Engineers
(SPE).
Enquiries:
Serica Energy plc +44 (0)20 7487 7300
Martin Copeland (CFO) / Andrew Benbow (Group Investor Relations Manager)
Peel Hunt (Nomad & Joint Broker) +44 (0)20 7418 8900
Richard Crichton / David McKeown / Emily Bhasin
Jefferies (Joint Broker) +44 (0)20 7029 8000
Sam Barnett
Vigo Consulting (PR Advisor) +44 (0)20 7390 0230
Patrick d'Ancona / Finlay Thomson serica@vigoconsulting.com
Serica will host a live presentation on the Investor Meet Company platform
today at 0900 BST. The presentation is open to all existing and potential
shareholders. Questions can be submitted at any time during the live
presentation. Investors can sign up to Investor Meet Company for free and add
to meet Serica Energy plc via
https://www.investormeetcompany.com/serica-energy-plc/register-investor
(https://www.investormeetcompany.com/serica-energy-plc/register-investor) .
CHIEF EXECUTIVE OFFICER'S REVIEW
Having now been at Serica for just over a year, there remains a lot of hard
work ahead to position the Company where I want it to be, but work done in the
first half of the year will help the business to start delivering at its true
potential.
I have said a number of times since joining that there were two things that
surprised me, the first being the quality of our subsurface opportunities and
the team to exploit them, and the second being the potential upside available
from running our operations more efficiently. Both areas have been highlighted
by events during the first half of 2025.
Our run of exceptional subsurface results continued to the end of the
five-well drilling campaign on the fields around the Triton FPSO. This has
been a tremendous success, both in terms of the operational delivery - almost
a month ahead of schedule and $31 million under budget - and in the subsurface
results. Credit is due to both the Serica team and our key contractors engaged
in this activity. All five wells are set to add to production. Two, at Bittern
and Gannet E, have already done so at a combined rate of over 10,000 boepd net
to Serica prior to the FPSO going offline, and wells on Guillemot and Evelyn
will be brought online shortly. The final well drilled, on Belinda, flowed
c.7,500 boepd on a constrained test, and will be on stream at the start of
2026.
Of course, for Serica to truly benefit from these wells, the Triton FPSO has
to deliver a far better performance. It has not been good enough. The lack of
adequate historical maintenance led to a backlog of work that resulted in the
necessity for five months of downtime, with only 27 days of production in the
first half of the year. The good news is that the lengthy outage has allowed
work to be done that should enhance uptime going forward.
There is still hard work ahead though. The Triton FPSO is now in a state of
repair consistent with an FPSO of its age, and requires ongoing maintenance
with better planning and delivery. The good news is that this is something
recognised by the operator, Dana, who has made significant changes to its
personnel and processes at Triton. We will continue to work closely with Dana
to identify ways of improving operational performance at Triton so that the
subsurface potential is translated into production and cash.
A fully functioning Triton FPSO will deliver material production and
significant, largely tax-sheltered, cash generation for Serica. The resumption
of Triton operations is expected to return us to aggregate production of over
50,000 boepd once all fields are returned to production, with more to come as
new wells are brought onstream.
The Bruce Hub produces very reliably, but it can produce more. The first steps
to do this have taken place with the resumption of bull-heading work, taking
production back up to over 21,000 boepd in July. This level can be maintained
through future well work, ahead of resuming drilling around the asset. Plans
for this are progressing well - the Triton drilling campaign is the clear
blueprint, and we are in the process of whittling down the 20 potential
prospects to a handful of drill ready opportunities.
To help achieve our production objectives, we are being proactive in
strengthening our organisation. I am delighted, therefore, to have recently
appointed a Chief People Officer and shortly to be adding a new Chief
Technical Officer as well as other key roles having been filled recently in
production optimisation and IT. There is plenty for us to aim at.
The opportunities described above together with the potential, very
attractive, redevelopment of the Kyle field as a new tie-back to Triton, can
support annual production at around 40,000 boepd into the next decade. While
we are taking steps to ensure that we deliver our organic growth opportunities
as quickly as possible, they cannot proceed without the right external
environment.
All credible forecasts show the UK consuming substantially more oil and gas
than it produces over the foreseeable future. To support UK jobs, communities
and public finances, the country is better off producing its own oil and gas
than importing it. Whether in relation to tax, licensing or regulation, UK
government policies should be designed with that objective at the forefront.
The retention of capital allowances in last year's Autumn Budget helped
preserve the viability of relatively small, short-cycle return investments,
but taking fuller advantage of the UK's domestic oil and gas resources
requires a change in government policy towards pragmatic and realistic fiscal
and regulatory policies.
The results of the first of three consultations launched by the government
were finally released on 19 June. This confirmed the details of the new
requirement to include end use (Scope 3) emissions in field development
submissions. Including this information is in itself not difficult to do, and
we are in fact already publishing these data at Company level, but we hope
that when the government takes decisions on new fields, they properly reflect
that, quite apart from the obvious economic, jobs and tax arguments, UK
developments (especially for gas) have total emissions very materially below
those of imported hydrocarbons.
The industry is still waiting for an outcome to the consultations relating to
future licensing and the successor to the Energy Profits Levy ('EPL'). Clarity
on these issues is urgently required. In order for companies to sanction the
large ticket long-term investments in the UK North Sea that will benefit the
UK, a more appropriate tax regime that reflects reality is required. For
example, due to the anomalous design of the Energy Security Investment
Mechanism linking oil and gas prices, oil production continues to be taxed at
78% despite the average Brent price in the first half of the year at $71.9/bbl
being below the threshold price of $74.2/bbl for termination of the EPL. As
has been stated consistently by the industry over many months, we are not in
windfall conditions.
Notwithstanding the current circumstances of an excessive tax rate combined
with fiscal and regulatory uncertainty, we are confident that Serica can make
smart investment decisions. This includes proactively seeking value-accretive
acquisitions in the UK North Sea that will grow the business and deliver
synergy potential.
As we have demonstrated previously, having a strong balance sheet and a robust
financial outlook allows us to invest in our assets and maintain meaningful
cash distributions to shareholders, while also being able to take advantage of
M&A opportunities.
Serica expects to generate material free cash flow in the coming years, cash
flow that we would like to reinvest in projects that promise rapid payback and
support material shareholder returns. We have today announced an interim
dividend of 6p per share, at a level in line with the rebasing of the dividend
that we announced with our full-year results. We see this rebased level of
dividend as being sustainable in the medium-term, delivering a competitive
level of shareholder returns as well as allowing us to invest in the exciting
growth opportunities we see in our portfolio and in the M&A market, all
while maintaining a resilient financial frame.
Production is set to resume the 50,000 boepd achieved earlier in the year,
with more to come - on which we look forward to updating you in due course.
With our organic portfolio set to deliver, and hard work ongoing to add to our
asset base, I am confident that Serica is well positioned heading into the
second half of 2025.
REVIEW OF OPERATIONS
Serica's assets contain 118.5 mmboe of 2P reserves net to the Company as of 31
December 2024, evenly split between oil and gas. The current producing
portfolio has the capacity for daily production exceeding 50,000 boepd, with
the subsurface potential to convert a material portion of the 88.7 mmboe of 2C
resources into producing reserves. This can then maintain annualised
production of over 40,000 boepd into the next decade, given the right fiscal
and regulatory environment.
Production (boepd)
H1 2025 H1 2024 FY 2024
Bruce Hub 16,700 23,400 19,800
Triton Hub 2,500 14,200 9,000
Other Producing Assets 5,500 6,100 5,800
Total 24,700 43,700 34,600
( )
Bruce Hub
Bruce Field - Blocks 9/8a, 9/9b and 9/9c, Serica 98% and operator
Rhum Field - Blocks 3/29a, Serica 50% and operator
Keith Field - Block 9/8a, Serica 100%
Production from the Bruce Hub averaged 16,700 boepd (H1 2024: 23,400 boepd)
net to the Company in the first half of the year. This figure was impacted by
the previously noted operational work required on the productive R3 well,
which reduced production in January from Rhum, and unscheduled downtime of the
facility in May due to required maintenance work taking place on the export
pipeline.
Production was also constrained due to the main oil line ('MOL') booster pump
being offline for the majority of the period. This impacted the volume
throughput at BKR, resulting in production being slightly below the potential
of the fields. Following the replacement of the MOL booster pump in June, the
restoration of capacity on the export line allowed bull-heading operations (in
which gas is pumped into a well to reduce back pressure and enhance
production) to resume. With three wells now successfully bull-headed at Bruce,
production at the hub has recently increased markedly, averaging 21,600 boepd
net to Serica in July.
Following the work done at Bruce, the K1 well at Keith was also brought back
onto production towards the end of July for the first time since 2021.
Serica has recently hired a production optimisation manager to coordinate the
overall focus on delivering further resilience and efficiency improvements,
aimed at optimising production from the Bruce Hub going forward. The annual
maintenance outage for 2025 will align with the scheduled Forties pipeline
downtime, and is set to begin on 16 August for around 12 days.
As well as improving production through boosting the operational efficiency of
the Bruce platform, Serica continues to work towards the first drilling on the
Bruce field since 2012. Subsurface work has identified over 20 possible
opportunities around BKR, and the process is ongoing to high-grade these and
define the optimal future drilling programme. Work is expected to proceed in
two phases, the first focused in the vicinity of the Western Area Development,
allowing rapid tie back to existing infrastructure, and phase two targeting
opportunities to the North East of the Bruce platform, where subsurface
studies suggest large untapped potential.
As Serica prepares for a drilling campaign on BKR and the Kyle redevelopment,
a Request for Information has been issued relating to a semi-submersible rig
to undertake a two-year campaign starting around the end of 2026/early 2027.
Triton Hub
Bittern - 64.63%, Evelyn - 100%, Gannet E - 100%, Guillemot West & North
West - 10%, Belinda - 100%
Due to necessary maintenance work that took place on the Triton FPSO from the
end of January 2025 until July, the Triton Hub produced severely reduced rates
of 2,500 boepd net (H1 2024: 14,200 boepd) in the first half of 2025.
Extensive remediation work and modifications have been carried out. Repairs to
the inert gas marine system were completed, with over 100 components on the
system either replaced or refurbished. Topside modifications were made in
readiness to accept the start of production from the Belinda field,
significant safety critical work was also undertaken on the firewater system,
and valves and sections of pipework across the FPSO were replaced.
In order to reduce overall downtime this year, following discussions with
Dana, the scheduled summer maintenance programme was carried out concurrently.
This was completed at the end of June, with work to then resume production
ongoing.
Following the initial resumption of production from the Bittern field, a
problem with the gas lift system prevented other Triton fields being
restarted. Additionally, other minor work was identified, which required a
short cessation of production to repair. This remedial work now being
complete, the restart of the Triton fields is progressing.
Production from the Bittern field (Serica 64.6%) will be followed by the
Evelyn (Serica 100%) and Gannet E (Serica 100%) fields. Once existing wells
resume production, the new wells drilled on the Guillemot North West (Serica:
10%) and Evelyn (Serica: 100%) fields will be brought onstream for the first
time, promising an increase to the 25,000 boepd the Triton FPSO was producing
net to Serica in January.
The BE01 well on the Belinda field (Serica 100%), which flow tested at
constrained rates of 7,500 boepd, is now expected to enter production at the
start of 2026 following work to tie the well into the Triton FPSO. This is the
key focus of our capital expenditure in H2, with spend expected in 2026
brought forward into 2025.
Other Production Assets
Production from our Other Producing Assets averaged 5,500 boepd in the first
half of the year, and generated $35 million in operational free cash flow.
Erskine Field - Blocks 23/26a (Area B) and 23/26b (Area B), Serica 18%
The Erskine field continues to produce consistently, delivering a rate of over
2,100 boepd net to Serica in H1 2025 (H1 2024: 500 boepd). A late life
compression project to extend the life of the field is planned to be carried
out this year.
Columbus Field - Blocks 23/16f and 23/21a (part), Serica 75% (operator)
Production at Columbus has been steady in the first half of 2025, averaging
1,500 boepd (H1 2024: 1,800 boepd) net to Serica. Annual maintenance on the
host Shearwater platform began on 12 July 2025 and is scheduled to take 45
days.
Orlando Field - Block 3/3b, Serica 100%
Average Orlando field production in H1 2025 was 1,900 boepd (H1 2024: 3,800
boepd) net to Serica, due to a scheduled shut-in of 28 days for annual
maintenance taking place during the period, aligned with maintenance on the
Ninian platform. An issue with the Ninian export system also prevented
production from the end of April through the majority of May.
Development
Kyle Redevelopment - (P2616) Serica 100% and operator
The Kyle Redevelopment, located in Block 29/2c, is a previously producing
oilfield, 20 km southeast of Triton, shut-in in 2020 solely due to the
decommissioning of the Banff FPSO host facility. With the appropriate fiscal
and licensing environment, there is the potential for first oil in 2028 on a
project that carries over 11 mmboe of 2C resources, via a single horizontal
well tied-back to Triton via Bittern, similar to other Triton tie-backs.
Subsurface work has matured and front-end design work tenders have been
issued. The procurement of long lead items, such as the subsea wellhead
system, is also underway, as Serica works towards a potential FID in H1 2026.
Greater Buchan Area - Blocks 20/5a, 205d, 21/1d & 21/1a, Serica 30%
Buchan Horst is one of the largest remaining undeveloped fields on the UKCS,
with an estimated 22.7 mmboe of 2C resources net to Serica, and the potential
for 10,000 boepd peak net production. The development project would support an
estimated 1,000 jobs in the UK and includes the possibility of powering the
facilities from offshore wind to achieve UKCS leading low carbon emissions.
The viability of the project continues to depend in large part on the future
UKCS fiscal and regulatory regimes, which are currently subject to government
consultations. Serica continues to work closely with the joint venture
partners to retain optionality over future development scenarios.
Mansell - (P2448) Serica 100% and operator
The Mansell discovery is located in licence P.2448 in UKCS Block 3/8g south
and east of the Ninian and Columba fields. Production from the field commenced
in 1992 and ceased in 1995. Serica undertook work to determine the feasibility
and timing of a redevelopment, however it has not been possible to identify a
viable host facility in this area of the Northern North Sea and hence Serica
expects to relinquish this licence by the end of Q3 2025. The Mansell field
comprises 8.3 mmboe of Serica's stated 2C resources.
Exploration
Skerryvore - Blocks 30/12c (part), 30/13c (split), 30/17h, 30/18c and 30/19c
(part), Serica: 70% working interest
The P2400 Licence is located in the Central North Sea, 60 km south of the
Erskine field. The commitment work programme included drilling an exploration
well on the Skerryvore prospect by the end of September 2025. Given the lack
of clarity regarding the future fiscal and licensing regime, the joint venture
applied for an extension to the period, and the NSTA has agreed to extend the
P2400 licence to 31 March 2027.
Fynn Beauly - (P2634) Serica 50%
A 50% interest in P2634 licence, containing the Fynn Beauly heavy oil
discovery, was acquired when completing the acquisition of Parkmead (E&P)
Limited in April 2025. The current licence commitment is limited to technical
studies to assess potential development options.
FINANCIAL REVIEW
Financial results in the first half of 2025 were unavoidably impacted by the
prolonged outage of the Triton FPSO. However, considering the material
reduction in production and revenues that resulted from this outage, our
financial performance - continuing to deliver a pre-tax profit and with cash
increasing from the year-end - was creditable. Production is expected to
increase materially in H2, with commensurate increases in H2 revenues, albeit
we anticipate lower gas prices than seen in H1.
The key difference is expected from our Triton Hub, where profits continue to
be shielded from Corporation Tax and Supplementary Corporation Tax by our
carried forward loss position, and benefit from the application of capital
allowances against EPL from our Triton investment programme. However, the
impact on H2 net cash generation will also factor in (as normal) that both the
final and interim dividends are payable in the period, and that we project the
resumption of cash tax payments, as well as some working capital effects.
Our robust financial position, and the expectation of material free cash flows
in 2026 and beyond, gives us continued confidence in our capital allocation
policy. We are keen to carry on investing in our portfolio, with Kyle and
infill drilling around the Bruce Hub having the opportunity to deliver rapid
payback, while also being very tax efficient. Should the result of the
outstanding consultations on licensing and the EPL successor regime provide an
appropriate investment environment, spend on these projects could be
sanctioned in early 2026, but with material expenditure unlikely before 2027.
We see the aggregate rebased dividend level, consistent with the 6p per share
interim announced today and the 10p announced with our full-year results, as
being sustainable in the medium-term. We believe this will deliver a
competitive level of shareholder returns at the same time as allowing us to
invest in the exciting growth opportunities we see in our portfolio and from
M&A, all while maintaining a resilient financial frame.
Summary of H1 2025 unaudited financial results
An analysis of the summary metrics provided in the Summary Financial
Information table below is detailed in the following pages of this Financial
Review.
Summary Financial Information Units H1 2025 H1 2024
Production and sales realised prices
Production kboepd 24.7 43.7
Sales volumes mmboe 4.6 7.9
Natural Gas (net of NTS system charges) p/th 96 67
Crude Oil $/Bbl 70 78
NGLs $/MT 490 432
Income Statement
Revenue $ million 305 462
EBITDAX((1)) $ million 118 279
Profit before taxation $ million 101 188
(Loss)/profit after taxation $ million (43) 82
Basic (loss)/earnings per share cents (11) 21
Other key financial figures
Capital expenditure((1)) $ million 138 124
Operating cashflow $ million 102 301
CFFO less current tax((1)) $ million 102 193
Share buyback $ million - 19
(1) See Reconciliation of non-IFRS measures for further detail.
Production for H1 2025 was 24.7 kboepd, compared to 43.7 kboepd for H1 2024
with the sharply reduced level impacted largely by the loss of production from
Triton from late January, but also some unscheduled downtime at BKR. Realised
sales prices for gas for the period were materially higher than for H1 2024
with NBP gas prices (net of NTS system charges) averaging 96p/th (H1 2024:
67p/th) as more typical winter pricing patterns prevailed, while Brent crude
pricing was volatile and averaged slightly lower compared to H1 2024, at
$70/bbl (H1 2024: $78/bbl). The combination of these volume and price impacts
saw revenues of $305 million (H1 2024: $462 million), down by approximately a
third year-on-year despite production volumes down by 43%.
With a largely fixed operating costs base, the revenue impacts were amplified
at the profit level, with EBITDAX of $118.5 million compared to $279.2 million
for H1 2024 and a profit before taxation of $100.8 million for H1 2025
compared to $188.5 million for H1 2024. After book tax of $143.9 million (H1
2024: $106.0 million) which included a one off non-cash deferred tax expense
of $65.2 million as a result of the extension of the EPL to 31 March 2030
being substantively enacted on 3 March 2025, the after tax position resulted
in a loss for the period of $43.1million compared to a profit after tax of
$82.5 million for H1 2024.
Sales revenues
Revenue Units H1 2025 H1 2024
Total revenue $ million 305 462
Gas Sales $ million 207 195
Crude Oil $ million 87 252
NGLs $ million 11 15
Total H1 2025 revenue was $304.9 million, compared to H1 2024 revenue of
$461.6 million. The reduction in revenue is largely driven by the impact of
the Triton unplanned outage for the majority of H1 2025. The revenue fall was
partially offset by slightly higher gas revenue during the period, driven by
higher gas prices.
Sales comprised gas revenue of $207.4 million (H1 2024: $194.5 million), oil
revenue of $86.4 million (H1 2024: $251.7 million) and NGL revenue of $11.1
million (H1 2024: $15.4 million). The increase in gas revenue was driven by
higher realised whilst the oil revenue in the period was significantly lower
than H1 2024, reflecting approximately 2 million bbls lower lifted volumes due
to the Triton outage as well as slightly lower realised oil prices in the
period ($70 per barrel as compared to $78 per barrel H1 2024). Like for like
NGL revenues were also lower as a result of the Triton shutdown, with the
lower sales volumes partially offset by higher realised prices for NGLs ($490
per metric tonne as compared to H1 2024: $432 per metric tonne).
Total product sales volumes for the period comprised approximately 167 million
therms of gas (H1 2024: 229 million therms), 1.2 million lifted barrels of oil
(H1 2024: 3.2 million barrels) and 22,600 metric tonnes of NGLs (H1 2024:
35,600 metric tonnes). This amounted to product sales in the period of 4.6
million boe (H1 2024: 7.9 million boe).
Gross profit
The gross profit for H1 2025 was $76.4 million compared to $206.8 million for
H1 2024. Overall cost of sales of $228.5 million compared to $254.7 million
for H1 2024. This comprised essentially unchanged field operating and lifting
costs of $158.5 million (H1 2024: $156.4 million), movements in oil
over/underlift charge of $15.0 million (H1 2024: charge of $11.2 million), and
$54.9 million of non-cash depletion charges (H1 2024: $87.1 million).
Cost of sales Units H1 2025 H1 2024
Total operating costs $ million 229 255
Field operating costs $ million 156 151
Lifting costs $ million 3 6
Movement in over / underlift $ million 15 11
DD&A $ million 55 87
The largely unchanged field operating costs, despite markedly reduced
production volumes, reflects that a significant proportion of such costs are
fixed in nature, particularly in the Triton Area. The reported level of costs
was also impacted by the weaker USD to GBP exchange rate on the Group's
operating costs which are predominantly in GBP. Operating costs as reported
per boe were approximately $34 per boe, increased from $19 per boe for H1
2024, with the increased unit rate mainly due to the reduced production from
the unplanned Triton outage during H1 2025.
The reduced H1 2025 production volumes did however directly impact non-cash
depletion charges calculated on a unit of production basis, which fell by
$32.2 million from the comparative period.
EBITDAX, operating profit before net finance costs and tax
EBITDAX for H1 2025 was $118 million, less than half the $279 million for H1
2024.
Operating profit to EBITDAX((1)) Units H1 2025 H1 2024
Operating profit $ million 118 202
Add back DD&A and depreciation $ million 55 88
Add back E&E costs $ million 1 2
(Deduct)/add back unrealised hedging $ million (53) 15
Deduct contract revenue - other $ million (6) (29)
Add back share-based payments $ million 2 2
Add back/(deduct) FX effects/remeasurements $ million 1 (1)
EBITDAX((1)) $ million 118 279
(1) See Reconciliation of non-IFRS measures for further detail.
The operating profit for H1 2025 was $118.1 million compared to $201.8 million
for H1 2024.
Net hedging income of $51.8 million (H1 2024: net expense of $18.4 million)
reflected a strong performance of the Group's hedge book, delivering
unrealised hedging gains of $53.1 million (H1 2024: $14.9 million) and only
very modest realised hedging losses of $1.4 million (H1 2024: $3.5 million
losses). Unrealised hedging gains arose from the movement in valuation of
Serica's H1 2025 period-end commodity hedge positions, primarily following a
decrease in the Group's gas derivatives valuation prices (compared to hedged
prices) from 31 December 2024 to 30 June 2025 resulting in a net mark to
market asset of $15.7 million in H1 2025 compared to a net mark to market
liability of $37.2 million in H1 2024. Realised hedging expense in both
periods related to oil and gas commodity derivatives settling during the
period.
Contract revenue of $5.4 million (H1 2024: $28.6 million) arose from the
partial unwind of an underlying revenue offtake contract that was fair valued
in connection with the Tailwind acquisition in 2023. An original liability of
$66.7 million was recognised which has been progressively released to the
Income Statement across 2023, 2024 and H1 2025 as the underlying contract
unwound, with the final unwind impact of $5.4 million included in H1 2025.
Administrative expenses for H1 2025 of $12.0 million was largely in line with
H1 2024 expense of $11.7 million.
Profit before taxation and loss after taxation for the period
Profit before taxation for H1 2025 of $100.8 million (H1 2024: $188.5 million)
included a $3.6 million charge arising from an increase in the fair value of
financial liabilities (H1 2024: $2.9 million charge), $2.5 million of finance
revenue (H1 2024: $6.9 million) and $16.2 million of finance costs (H1 2024:
$17.3 million).
Finance revenue of $2.5 million (H1 2024: $6.9 million) primarily represented
interest income earned on cash deposits and decreased as a result of lower
cash balances held and lower interest rates achievable in the period compared
to H1 2024. Finance costs of $16.9 million (H1 2024: $17.3 million) included
interest payable and other charges on the RBL facility, the discount unwind on
decommissioning provisions and other minor finance costs.
The H1 2025 taxation charge of $143.9 million (H1 2024: $106.0 million)
comprised current tax charges of nil (H1 2024: $72.7 million) and a sharply
increased deferred tax charge of $143.9 million (H1 2024: $33.3 million). The
current tax charge for the Group was nil as a result of the application of
group relief from tax losses which arose following the Triton field shutdown
and ongoing significant capital expenditure on the Belinda and Evelyn fields
during H1 2025. The deferred tax charge was significantly higher in H1 2025
due to deferred tax charges arising from capital expenditure on the Triton
fields and a material one off deferred tax charge of $65.2 million in respect
of the extension of the EPL from 31 March 2028 to 31 March 2030. The EPL
extension was substantively enacted on 3 March 2025 and hence recognised for
accounting purposes for the first time in H1 2025.
Reported and Effective tax rate Units H1 2025 H1 2024
Profit before tax $ million 101 188
Current tax $ million - 73
Deferred tax charge $ million 144 33
Tax charge for the period $ million 144 106
Book tax rate % 143% 56%
Applicable ring-fence aggregate tax rate % 78% 75%
The combined effect of the lost production largely from the Triton Area in the
period and the one-off non-cash tax charge, meant that the Group generated a
loss after taxation for H1 2025 of $43.1 million compared to a profit after
taxation of $82.5 million for H1 2024. This corresponded to a loss per share
of 11 cents (H1 2024: earnings per share of 21 cents) after taking into
account the weighted average number of ordinary shares in issue.
GROUP BALANCE SHEET
Serica retains a strong balance sheet with a conservative adjusted net debt to
LTM EBITDAX ratio of 0.3x as at 30 June 2025 notwithstanding an LTM period
reflecting the very significant impact of Triton outages. The continued
position of balance sheet strength and ample liquidity gives the group
flexibility in capital allocation including the ability to fund its ongoing
and planned capital investment programmes while continuing to support
distributions to shareholders despite a period of material production
interruption.
Assets 30 June 2025 31 December 2024
$ million $ million
E&E 34 20
PP&E 1,100 992
Deferred tax asset - 55
Inventory 16 15
Trade and other receivables 161 159
Corporate tax receivable 2 71
Derivative financial assets 18 5
Cash & cash equivalents 174 148
Total Assets 1,505 1,465
Equity and liabilities 30 June 2025 31 December 2024
$ million $ million
Equity 722 797
RBL borrowings, drawn amounts 231 231
RBL unamortised fees (11) (12)
Deferred tax liability 101 -
Provisions 152 146
Financial liabilities 90 82
Derivative financial liabilities 2 42
Contract liabilities - 5
Trade and other payables, lease liabilities 164 174
Dividend payable 54 -
Total Equity and Liabilities 1,505 1,465
Total property, plant and equipment increased from $991.6 million at year end
2024 to $1,100.2 million at 30 June 2025.
PP&E additions comprised book capital expenditure including accruals
during H1 2025 of $142.5 million, with the vast majority in the Triton Area
($130.8 million) reflecting the impact of our drilling programme and a smaller
amount at BKR ($11.7 million). The Triton Area expenditure included $72.7
million on the Belinda well and development, $46.2 million on the Evelyn EV02
well, and other life extension work on the Triton FPSO. The overall increase
also included a $21.7 million currency translation adjustment, and these were
partly offset by depletion charges for H1 2025 of $54.9 million.
The UK corporation tax receivable of $71.0 million at 31 December 2024
reflected a recovery of overpayments of corporation tax, supplementary charge,
and EPL in respect of 2024, resulting primarily from the application of group
relief. This balance was substantially received in June 2025.
The net deferred tax liability of $101.1 million at 30 June 2025 compares to a
net deferred tax asset of $55.1 million at year end 2024. This comprised
deferred tax liabilities arising on PP&E balances partially offset by the
recognition of deferred tax assets in relation to tax losses and future relief
available on decommissioning. The change from a net deferred tax asset
position at 31 December 2024 to a net deferred tax liability at the end of H1
2025 is largely a result of additional deferred tax liabilities of $76.2
million created from the significant capital expenditure incurred in the
period, and an increased deferred tax liability of $65.2 million arising
following the enactment during H1 2025 of the extension of the EPL from 31
March 2028 to 31 March 2030. Deferred tax liabilities arising upon the Group's
PP&E balances will be released in future periods as those balances are
depleted.
The net derivative financial asset of $15.7 million at 30 June 2025 represents
the mark to market valuation of gas ($5.4 million) and oil ($10.3 million)
commodity swap and collar products in place at the period end. The 31 December
2024 net liability of $37.2 million comprised a derivative liability of $42.4
million arising from valuation of gas collars and swaps in place at the
year-end based on higher mark to market gas prices as at that date, offset by
$5.2 million of derivative asset from the valuation of oil collars and swaps.
The change from the net derivative liability position in 2024 to a net
derivative asset position in H1 2025 is primarily due to a decrease in the
mark to market gas prices in H1 2025.
The increase in cash balances from $148.5 million at 31 December 2024 to
$174.4 million at 30 June 2025 reflected net cash inflow from operating
activities of $172.4 million (including tax recovery receipts of $70.6
million) mainly offset by capital expenditures paid of $137.8 million.
Current trade and other payables decreased to $159.8 million at 30 June 2025
from $168.3 million at the end of 2024.
The dividend payable of $53.8 million at 30 June 2025 (31 December 2024: $nil)
represents the final cash dividend in respect of FY2024 of 10 pence (13 cents)
per share approved at the annual general meeting on 22 May 2025 and paid after
the period end in July 2025.
Non-current financial liabilities of $90.3 million (31 December 2024:
$81.9million) comprise remaining deferred consideration projected to be paid
under the BKR acquisition agreements of $56.7 million (31 December 2024: $49.7
million) and royalty liabilities of $33.6 million (31 December 2024: $32.2
million) for amounts payable to third parties under the terms of Triton asset
acquisitions previously made by Tailwind. The increase in the non-current
financial liabilities is due to unwinding of discount and the impact of higher
currency translation adjustments.
Provisions of $152.4 million (31 December 2024: $146.0 million) predominantly
relate to future decommissioning obligations. The increase from the prior year
balance of $146.0 million was mainly due to unwinding of the discount applied
as well as currency translation effects.
Interest bearing loans of $220.2 million at 30 June 2025 represent drawn
amounts of $231.0 million net of unamortised facility fees of $10.8 million
under the Group's $525 million RBL facility (31 December 2024: $219.1
million).
CASH BALANCES AND FUTURE COMMITMENTS
Current cash position and price hedging
At 30 June 2025 the Group held adjusted net debt of $57 million as compared to
adjusted net debt of $83 million at 31 December 2024.
Adjusted Net Debt 30 June 2025 31 December 2024
$ million $ million
Interest bearing loans (220) (219)
Add back unamortised fees (11) (12)
Cash & cash equivalents 174 148
Adjusted Net Debt (57) (83)
Hedging
Serica carries out hedging activity to manage commodity price risk, to meet
its contracted arrangements under its RBL facility and to ensure there is
sufficient funding for future investments. Serica held the following
instruments as at 31 July 2025:
Oil hedges
2025 2026 2027
Weighted Average Units Q3 Q4 Q1 Q2 Q3 Q4 Q1
Put Net $/bbl - - - - - - -
Swap price $/bbl 75 75 75 - - - -
Collar floor net $/bbl 68 68 69 61 60 61 60
Total weighted average $/bbl 69 69 70 61 60 61 60
Collar ceiling $/bbl 88 86 86 77 76 76 76
Hedged Volumes Kboe/d 6 5 4 7 5 2 1
Gas hedges
2025 2026 2027
Weighted Average Units Q3 Q4 Q1 Q2 Q3 Q4 Q1
Put Net p/therm - - - - - - -
Swap price p/therm 86 90 94 - - - -
Collar floor net p/therm 70 82 83 66 64 71 71
Total weighted average p/therm 81 85 85 66 64 71 71
Collar ceiling p/therm 121 135 138 101 99 121 121
Hedged Volumes Kboe/d 5 7 8 7 5 8 8
Field and other capital commitments
Following the completion of its 2024-25 drilling campaign in the Triton Area,
Serica's remaining 2025 investment programme includes continued work on the
Belinda development, and further capital work on the Bruce facilities
including resilience upgrades as well as the early stages of a flare gas
recovery project being implemented during the planned turnaround in August.
At 30 June 2025, the Group had commitments for future capital expenditure
relating to its oil and gas properties which relate primarily to the ongoing
Belinda development, Triton area work (including Bittern and FPSO life
extension work), and certain other capital works on Bruce.
The Group's only significant exploration commitment work programme includes
drilling an exploration well on Licence P2400 (Skerryvore prospect). Given the
lack of clarity regarding the future fiscal and licensing regime, the joint
venture applied for an extension to the period, and the NSTA has agreed to
extend the P2400 licence to 31 March 2027.
Cash projections are run periodically to examine the potential impact of
extended low oil and gas prices as well as possible production interruptions.
Serica currently has substantial net cash resources and relatively low
operating costs per boe which means that the Company is well placed to
withstand such risks and its capital commitments can be funded from existing
cashflow in most scenarios.
Additional Information
Additional information relating to Serica, can be found on the Company's
website at www.serica-energy.com and on SEDAR at www.sedar.com
(http://www.sedar.com) .
Approved on behalf of the Board
Chris Cox
Chief Executive Officer
4 August 2025
Forward Looking Statements
This disclosure contains certain forward looking statements that involve
substantial known and unknown risks and uncertainties, some of which are
beyond Serica Energy plc's control, including: the impact of general economic
conditions where Serica Energy plc operates, industry conditions, changes in
laws and regulations including the adoption of new environmental laws and
regulations and changes in how they are interpreted and enforced, increased
competition, the lack of availability of qualified personnel or management,
fluctuations in foreign exchange or interest rates, stock market volatility
and market valuations of companies with respect to announced transactions and
the final valuations thereof, and obtaining required approvals of regulatory
authorities. Serica Energy plc's actual results, performance or achievement
could differ materially from those expressed in, or implied by, these forward
looking statements and, accordingly, no assurances can be given that any of
the events anticipated by the forward looking statements will transpire or
occur, or if any of them do so, what benefits, including the amount of
proceeds, that Serica Energy plc will derive therefrom.
Serica Energy plc
Condensed Consolidated Income Statement
Six Six
months months Year
ended ended ended
30 June 30 June 31 December
Notes 2025 2024 2024
Continuing operations $000 $000 $000
Sales revenue 4 304,896 461,559 727,178
Cost of sales 5 (228,523) (254,725) (503,981)
Gross profit 76,373 206,834 223,197
Other income/(expense) 6 51,786 (18,449) (43,474)
Contract revenue - other 5,408 28,576 31,292
Exploration expense (1,100) (1,476) (1,595)
E&E asset write-offs (96) (532) (851)
Administrative expenses (11,976) (11,725) (21,601)
Foreign exchange (loss)/gain (635) 639 3,234
Share-based payments (1,673) (2,114) (3,735)
Operating profit 118,087 201,753 186,467
Change in fair value of financial liabilities (3,587) (2,944) (2,538)
Finance revenue 2,473 6,947 13,927
Finance costs 7 (16,198) (17,258) (37,358)
Profit before taxation 100,775 188,498 160,498
Taxation charge for the period 12 (143,869) (106,023) (68,069)
(Loss)/profit after taxation and
(loss)/profit for the period (43,094) 82,475 92,429
(Loss)/earnings per ordinary share
Basic EPS on (loss)/profit for the period ($) (0.11) 0.21 0.24
Diluted EPS on (loss)/profit for the period ($) (0.10) 0.20 0.23
Serica Energy plc
Condensed Consolidated Statement of Comprehensive Income
Six Six
months months Year
ended ended ended
30 June 30 June 31 December
2025 2024 2024
$000 $000 $000
(Loss)/profit for the period (43,094) 82,475 92,429
Other comprehensive profit/(loss)
Exchange differences on translation 20,774 (2,685) (5,217)
Other comprehensive profit/(loss) for the period (2,685) (5,217)
20,774
Total comprehensive (loss)/profit for the period (22,320) 79,790 87,212
Total comprehensive (loss)/profit attributable to:
Equity owners of the Company (22,320) 79,790 87,212
Serica Energy plc
Condensed Consolidated Balance Sheet
30 June 31 December
2025 2024
$000 $000
Notes
Non-current assets
Exploration & evaluation assets 9 34,341 20,367
Property, plant and equipment 10 1,100,273 991,588
Deferred tax asset 12 - 55,139
1,134,614 1,067,094
Current assets
Inventories 16,199 14,884
Trade and other receivables 161,390 158,117
Corporate tax receivable 2,188 71,013
Derivative financial asset 17,968 5,185
Cash and cash equivalents 174,395 148,460
372,140 397,659
TOTAL ASSETS 1,506,754 1,464,753
Current liabilities
Trade and other payables 159,785 168,287
Derivative financial liability 1,183 31,185
Contract liabilities - 5,408
Lease liabilities 1,459 1,418
Dividends payable 8 53,892 -
Non-current liabilities
Derivative financial liabilities 1,057 11,201
Financial liabilities 90,307 81,923
Deferred tax liability 12 101,100 -
Lease liabilities 3,230 3,769
Provisions 152,441 145,974
Interest bearing loans 11 220,203 219,130
TOTAL LIABILITIES 784,657 668,295
NET ASSETS 722,097 796,458
Share capital 13 245,715 245,537
Merger reserve 13 286,590 286,590
Other reserves 39,213 37,540
Treasury/own shares (1,579) (8,931)
Currency translation reserve 6,662 (14,112)
Accumulated funds 145,496 249,834
TOTAL EQUITY 722,097 796,458
Serica Energy plc
Condensed Consolidated Statement of Changes in Equity
Share capital Merger reserve Other reserves Treasury/own shares Currency translation reserve Accumulated funds Total
$000 $000 $000 $000 $000 $000 $000
At 1 January 2024 245,257 283,367 37,650 - (8,895) 276,789 834,168
Profit for the year - - - - - 92,429 92,429
Other comprehensive income - - - - (5,217) - (5,217)
Total comprehensive income - - - - (5,217) 92,429 87,212
Issue of shares 280 3,223 - - - - 3,503
Share-based payments - - 3,735 - - - 3,735
Treasury/own shares - - - (18,775) - - (18,775)
Release of shares - - - 9,844 - (9,844) -
Share payments - - (3,845) - - 3,845 -
Dividend payable - - - - - (113,385) (113,385)
At 31 December 2024 245,537 286,590 37,540 (8,931) (14,112) 249,834 796,458
Loss for the period - - - - - (43,094) (43,094)
Other comprehensive income - - - - 20,774 - 20,774
Total comprehensive income/(loss) - - - - 20,774 (43,094) (22,320)
Issue of shares 178 - - - - - 178
Share-based payments - - 1,673 - - - 1,673
Release of shares - - - 7,352 - (7,352) -
Dividend payable - - - - - (53,892) (53,892)
At 30 June 2025 245,715 286,590 39,213 (1,579) 6,662 145,496 722,097
Serica Energy plc
Condensed Consolidated Cash Flow Statement
Six Six
months months Year
ended ended ended
30 June 30 June 31 December
2025 2024 2024
$000 $000 $000
Note
Cash inflow from operations 14 101,954 301,137 452,222
Taxation received/(paid) 70,554 (72,414) (152,517)
Decommissioning spend (104) (4,514) (18,142)
Net cash inflow from operating activities 14 172,404 224,209 281,563
Investing activities:
Interest received 2,473 6,947 13,927
Purchase of E&E assets (1,179) (5,001) (11,123)
Purchase of property, plant & equipment (136,527) (106,664) (249,050)
Acquisition of subsidiary (10,416) (7,665) (7,665)
Net cash outflow from investing activities (145,649) (112,383) (253,911)
Financing activities:
Issue of ordinary shares 178 350 280
Repayment of borrowings - (323,700) (323,700)
Proceeds from borrowings - 283,500 283,500
Payments of lease liabilities (979) (415) (2,697)
Dividends paid - - (113,385)
Share buyback - (18,972) (18,775)
Finance costs paid (11,620) (25,917) (38,501)
Net cash outflow from financing activities (12,421) (85,154) (213,278)
Cash and cash equivalents
Net increase/(decrease) in period 14,334 26,672 (185,626)
Effect of exchange rates on cash and cash equivalents 11,601 98 (1,347)
Amount at start of period 148,460 335,433 335,433
Amount at end of period 174,395 362,203 148,460
Serica Energy
plc
Notes to the Condensed Consolidated Financial Statements
1. Corporate information
The interim condensed consolidated financial statements of the Group for the
six months ended 30 June 2025 were authorised for issue in accordance with a
resolution of the directors on 4 August 2025.
Serica Energy plc ('the Company') is a public limited company incorporated and
domiciled in England & Wales. The Company's ordinary shares are traded on
the AIM in London. The principal activity of the Company is to identify,
acquire and exploit oil and gas reserves.
2. Basis of preparation and accounting policies
Basis of preparation
The interim condensed consolidated financial statements for the six months
ended 30 June 2025 have been prepared in accordance with International
Accounting Standard 34 "Interim Financial Reporting".
These unaudited financial statements of the Group have been prepared following
the same accounting policies and methods of computation as the consolidated
financial statements for the year ended 31 December 2024. These financial
statements do not include all the information and footnotes required by
generally accepted accounting principles for annual financial statements and
therefore should be read in conjunction with the consolidated financial
statements and the notes thereto in the Serica Energy plc annual report for
the year ended 31 December 2024.
The financial information contained in this announcement does not constitute
statutory financial statements within the meaning of section 435 of the
Companies Act 2006.
Going concern
The Directors are required to consider the availability of resources to meet
the Group's liabilities for the period ending 30 September 2026, the 'going
concern period'.
As at 30 June 2025 the Group held cash and term deposits of $174.4 million.
Separate RBL liquidity headroom of $259 million existed at 30 June 2025 ($231
million drawn versus $490 million available). See note 11 for further details
of the current RBL facility.
The Group has a balance in product mix between gas and oil, and two main
operating hubs which reduces the potential impact of production interruptions.
The Group regularly monitors its cash, funding and liquidity position,
including available facilities and compliance with facility covenants.
Near-term cash projections are revised and underlying assumptions reviewed,
generally monthly, and longer-term projections are also updated regularly.
Downside price and other risking scenarios are considered. In addition to
commodity sales prices the Group is exposed to potential production
interruptions and these are also considered under such scenarios. In recent
years, management has given priority to building a strong cash reserve which
can respond to different types of risk.
For the purposes of the Group's going concern assessment we have reviewed two
cash projections for the going concern period. These projections cover a base
case forecast and an extreme stress test scenario for the operations of the
Group. RBL repayments have been assumed based on the current redetermination
and no covenant compliance matters noted.
The base case assumptions for the going concern period included commodity
pricing of 80 pence/therm for gas and US$70/bbl for oil for the whole period.
Production, opex, capex and tax assumptions are those currently included in
standard management forecasting. The forward-looking price assumptions are
considered as reasonable in light of recent commodity forward pricing and a
consensus of published forecasts from the industry, brokers and other
analysts.
The stress test assumptions assume a full six month period shut-in of Triton
hub production for Q4 2025 and Q1 2026 and 25% reduced production volumes from
the base case across the full portfolio of producing assets for Q2 and Q3
2026. Base case commodity pricing is retained for 2025 and Q1 2026 but lower
commodity pricing of 50 pence/therm gas and US$60/bbl oil are assumed for the
Q2 2026 and Q3 2026 periods in this scenario which are significantly below the
range of current market expectations for the going concern period. Under this
scenario, which would result in lower cash inflows and any repayments of the
RBL facility as redetermined, the Group was able to maintain sufficient cash
to meet its obligations and maintain covenant compliance. A number of
mitigating factors and mitigating actions that are under management control
are available to management in the stress test event. These would mitigate the
reduced operating cash outflows experienced and are not included in the
projection.
After making enquiries and having taken into consideration these factors, the
Directors considered it appropriate that the Group has adequate resources to
continue in operational existence for the going concern period. Accordingly,
they continue to adopt the going concern basis in preparing the financial
statements.
Significant accounting policies
A number of new standards, amendments to existing standards and
interpretations were applicable from 1 January 2025. The adoption of these
amendments did not have a material impact on the Group's interim condensed
consolidated financial statements for the period ended 30 June 2025.
The accounting policies adopted in the preparation of the interim condensed
consolidated financial statements are consistent with those followed in the
preparation of the Group's annual financial statements for the year ended 31
December 2024. The impact of seasonality or cyclicality on operations is not
considered significant on the interim consolidated financial statements.
The Group financial statements are presented in $ and all values are rounded
to the nearest thousand except when otherwise indicated.
Basis of consolidation
The consolidated financial statements include the accounts of the Company and
its wholly-owned subsidiaries Serica Holdings UK Limited, Serica Energy
Holdings BV, Serica Energy Corporation, Petroleum Development Associates
(Asia) Limited, Serica Energy (UK) Limited, Serica Energy Norte Limited,
Serica GBA Limited, Serica Energy Investments Limited, Serica Energy Meltemi
Limited, Serica Energy Mistral Limited, Serica Energy Sirocco Limited and
Serica Energy Chinook Limited. Together, these comprise the 'Group'.
The results and financial position of all of the Group entities that have a
functional currency different from the presentation currency are translated
into the presentation currency as follows:
· Assets and liabilities for each balance sheet presented are
translated at the closing rate at the date of that balance sheet;
· Income and expenses for each income statement are translated at
average exchange rates (unless this average is not a reasonable approximation
of the rates prevailing on the transaction dates, in which case income and
expenses are translated at the rate on the dates of each transaction);
· The exchange differences arising on translation for consolidation are
recognised in other comprehensive income; and
· Any fair value adjustments to the carrying amounts of assets and
liabilities arising on the acquisition are treated as assets and liabilities
of the acquired entity and are translated at the spot rate of exchange at the
reporting date.
All inter-company balances and transactions have been eliminated upon
consolidation.
3. Segmental information
For the purposes of segmental reporting, the Group currently operates a single
class of business being oil and gas exploration, development and production
and related activities in a single geographical area, being presently the UK
North Sea.
4. Sales revenue
Six months Six months Year
ended ended ended
30 June 30 June 31 December
2025 2024 2024
$000 $000 $000
Gas sales 207,410 194,507 374,719
Oil sales 86,403 251,661 317,478
NGL sales 11,083 15,391 34,981
Total revenue 304,896 461,559 727,178
5. Cost of sales
Six months Six months Year
ended ended ended
30 June 30 June 31 December
2025 2024 2024
$000 $000 $000
Operating costs 156,069 150,975 329,820
Lifting costs 2,499 5,408 6,874
Change in decommissioning estimates expensed - - 601
Movement in liquids overlift / underlift 15,023 11,195 (20,564)
Depletion (note 10) 54,932 87,147 187,250
228,523 254,725 503,981
6. Group operating profit
Six months Six months Year
ended ended ended
30 June 30 June 31 December
2025 2024 2024
$000 $000 $000
Unrealised hedging gains/(losses) 53,136 (14,918) (31,814)
Realised hedging losses (1,350) (3,531) (11,660)
Other income/(expense) 51,786 (18,449) (43,474)
Derivative financial instruments
The Group enters into derivative financial instruments with various
counterparties. Commodity and foreign currency derivative contracts are
designated as at fair value through profit and loss (FVTPL), and gains and
losses on these contracts are recognised in the income statement. Derivative
financial instruments held at 30 June 2025 and 31 December 2024 comprised
swaps and collars for both oil and gas volumes. These were valued by
counterparties, with the valuations reviewed internally and corroborated with
readily available market data of forward pricing (level 2). Details of the
Group's derivative financial instruments currently held are provided in the
financial review above.
The mark-to-market of the Group's open contracts as at 30 June 2025 was a net
asset of $15.7 million (31 December 2024: net liability of $37.2 million).
7. Finance costs
Six months Six months Year
ended ended ended
30 June 30 June 31 December
2025 2024 2024
$000 $000 $000
Loan interest payable 9,556 11,448 22,917
Loan commitment fees 2,377 2,590 6,144
Other charges and interest payable 1,006 459 2,733
Unwinding of discount on provisions 3,259 2,761 5,564
Total finance costs 16,198 17,258 37,358
8. Dividends payable
A final cash dividend for 2024 of 10.0 pence per share was proposed in April
2025 and approved at the annual general meeting on 22 May 2025. Following the
approval in the H1 2025 period, the dividend payable of £39.3 million ($53.9
million) is recognised as a liability in the Balance Sheet at 30 June 2025.
The dividend was paid in July 2025.
Dividends on ordinary shares paid in 2024
A final cash dividend for 2023 of 14.0 pence per share was proposed in April
2024 and approved at the annual general meeting on 27 June 2024. Following the
approval in the H1 2024 period, the dividend payable of £54.4 million ($68.8
million) was recognised as a liability in the Balance Sheet at 30 June 2024.
The dividend was paid in July 2024.
An interim cash dividend for 2024 of 9.0 pence per share was announced in
September 2024 and £35.0 million ($44.6 million) was paid in November 2024.
9. Exploration and evaluation assets
Total
$000
Cost:
At 1 January 2024 2,457
Acquisitions 7,665
Additions 11,123
Asset write-offs (851)
Currency translation adjustment (27)
At 31 December 2024 20,367
Acquisitions 10,416
Additions 1,179
Asset write-offs (96)
Currency translation adjustment 2,475
At 30 June 2025 34,341
Net Book Amount:
30 June 2025 34,341
31 December 2024 20,367
1 January 2024 2,457
10. Property, plant and equipment
Fixtures and fittings
Oil and gas properties Right-of-use assets
Total
$000 $000 $000 $000
Cost:
At 1 January 2024 1,312,468 270 5,342 1,318,080
Acquisitions
Additions 264,000 - 5,069 269,069
Decommissioning asset revisions 9,711 - - 9,711
Currency translation adjustment (10,576) (4) (114) (10,694)
31 December 2024 1,575,603 266 10,297 1,586,166
Additions 142,458 - - 142,458
Currency translation adjustment 54,464 25 558 55,047
At 30 June 2025 1,772,525 291 10,855 1,783,671
Depreciation and depletion:
At 1 January 2024 410,229 270 1,821 412,320
Charge for the year (note 5) 186,206 - 1,044 187,250
Charge for the year - other - - 1,070 1,070
Currency translation adjustment (6,021) (4) (37) (6,062)
At 31 December 2024 590,414 266 3,898 594,578
Charge for the period (note 5) 54,412 - 520 54,932
Charge for the period - other - - 515 515
Currency translation adjustment 33,134 25 214 33,373
At 30 June 2025 677,960 291 5,147 683,398
Net book amount:
At 30 June 2025 1,094,565 - 5,708 1,100,273
At 31 December 2024 985,189 - 6,399 991,588
At 1 January 2024 902,239 - 3,521 905,760
Depreciation and depletion
Depletion charges on oil and gas properties are calculated on a unit of
production method based on commercial proved and probable reserves and are
classified within 'cost of sales'. Depreciation on other elements of property,
plant and equipment is provided on a straight-line-basis and taken through
general and administration expenses.
11. Interest bearing loans
The Group's loan is carried at amortised cost as follows:
30 June 31 December
2025 2024
$000 $000
Reserve based lending - principal 231,000 231,000
Loan commitment fees (10,797) (11,870)
Reserve based lending - net of fees 220,203 219,130
Due within one year - -
Due after more than one year 220,203 219,130
219,130
220,203
The Group has a Reserve Based Lending (RBL) facility of $525 million which is
a revolving credit facility available in multiple currencies, and which
provides significant liquidity to support future acquisitions and investments.
The RBL has a maturity date of 31 December 2029 with amortisation commencing
on 31 December 2026. The interest rate for loan drawings is SOFR plus a margin
of 3.90% per annum and the Borrowing Base Assets comprise all of Serica's
interests in producing fields except Serica's largest single producing field
the Rhum field, and the available amount under the facility is subject to
semi-annual redeterminations. The facility also includes a separate $100
million sub limit which can be utilised to issue Letters of Credit without the
need for cash security.
The facility agreement also has an uncommitted accordion feature which
provides an option for an additional financing of up to $525 million,
amounting to facilities of up to $1,050 million. The accordion facility can be
exercised within thirty-six months of the facility signing date, subject to
certain conditions.
The RBL includes a financial covenant to maintain net debt/EBITDAX cover ratio
below 3.5x and other terms and conditions are consistent with Loan Market
Association terms for comparable syndicated RBL financings. As at 30 June
2025, Serica is fully compliant with the financial covenant and all other
terms of the facility.
In June 2025, Serica completed the semi-annual redetermination under its RBL
facility, with the Borrowing Base under the facility set at $490 million,
effective from 1 July 2025, of which $231 million is drawn down and $259
million is available for future draw down.
12. Taxation
The major components of income tax charged in the consolidated income
statement are:
Six months Six months Year
ended ended ended
30 June 30 June 31 December
2025 2024 2024
$000 $000 $000
Current income tax charge - 72,728 13,876
Deferred income tax charge 143,869 33,295 54,193
Total taxation charge for the period 143,869 106,023 68,069
The deferred tax included in the Balance Sheet is as follows:
30 June 31 December 2024
2025
$000 $000
Deferred tax assets 636,545 576,575
Deferred tax liabilities (737,645) (521,436)
Total deferred tax (liability)/asset (101,100) 55,139
Reconciliation of net deferred tax (liability)/asset $000
At 1 January 2025 55,139
Tax charge for the period recognised in loss (143,869)
Currency translation adjustment (12,370)
At 30 June 2025 (101,100)
Tax losses
The Group's Balance Sheet has a deferred tax asset amount of $636.5 million as
at 30 June 2025 (31 December 2024: $576.6 million) arising from ring-fence
losses, decommissioning liabilities and other temporary differences. These
deferred tax assets are expected to be recovered through utilisation against
deferred tax liabilities, primarily related to temporary differences on fixed
assets ($737.6 million) and through future taxable profits.
The Group's deferred tax assets at 31 December 2024 and 30 June 2025 are
recognised to the extent that taxable profits are expected to arise in the
future against which tax losses and allowances in the UK can be utilised. In
accordance with IAS 12 Income Taxes, the Group assessed the recoverability of
its deferred tax assets at 30 June 2025 with respect to ring fence losses and
allowances.
Changes to UK corporation tax legislation
In October 2024, the UK government announced changes (effective from 1
November 2024) to the Energy Profits Levy including a 3% increase in the rate
taking the headline rate of tax on North Sea profits to 78%, an extension to
the period of application of the Levy to 31 March 2030 and the removal of the
Levy's main investment allowance. The changes to the rate and to the
investment allowance were substantively enacted in November 2024 and have been
applied in accounting for current tax and deferred tax in the period. The
government confirmed in the announcement that the Energy Security Investment
Mechanism ('ESIM') would remain unchanged and that there were no planned
changes to the way tax relief for capital expenditure is applied in the
permanent ring fence regime.
The extension of the EPL to 31 March 2030 was substantively enacted on 3 March
2025 and has therefore been reflected in the financial statements as at 30
June 2025. The impact of the extension is an additional deferred tax expense
of $65.2 million that has been recognised in the current financial statements.
13. Equity share capital
As at 30 June 2025, the share capital of the Company comprised one "A" share
of £50,000 and 393,568,407 ordinary shares of $0.10 each. The "A" share has
no special rights.
The balance classified as total share capital includes the total net proceeds
(both nominal value and share premium) on issue of the Group and Company's
equity share capital, comprising $0.10 ordinary shares and one 'A' share.
Allotted, issued and fully paid: Share Share Total share Merger
Number capital premium capital reserve
Group '000 $000 $000 $000 $000
At 1 January 2024 391,321 39,132 206,125 245,257 283,367
Shares issued 2,147 215 65 280 3,223
At 31 December 2024 393,468 39,347 206,190 245,537 286,590
Shares issued 100 10 168 178 -
At 30 June 2025 393,568 39,357 206,358 245,715 286,590
During H1 2025, 100,000 ordinary shares were issued to satisfy awards under
the Company's share-based incentive schemes.
As at 1 August 2025, the issued voting share capital of the Company was
393,568,407 ordinary shares and one A share.
14. Additional cash flow information
Net cash flows from operating activities consist of:
Six Six
months months Year
ended ended ended
30 June 30 June 31 December
2025 2024 2024
$000 $000 $000
Operating activities:
(Loss)/profit for the period (43,094) 82,475 92,429
Adjustments to reconcile (loss)/profit for the
period to net cash flow from operating activities:
Taxation charge 143,869 106,023 68,069
Change in fair value of financial liabilities 3,587 2,944 2,538
Change in provisions - - 601
Net finance costs 13,725 10,311 23,431
Depletion and depreciation 55,447 87,649 188,320
Oil and NGL over/underlift movement 15,023 11,195 (20,564)
E&E asset write-offs 96 532 851
Unrealised hedging (gains)/losses (53,136) 14,918 31,814
Contract revenue - other (5,408) (28,576) (31,292)
Share-based payments 1,673 2,114 3,735
Other non-cash movements 1,437 (831) (81)
Decrease in DSA advances - 35,055 35,055
(Increase)/decrease in receivables (9,616) (15,305) 36,170
(Increase) in inventories (605) (712) (1,140)
(Decrease)/increase in payables (21,044) (6,655) 22,286
Cash inflow from operations 101,954 301,137 452,222
Taxation received/(paid) 70,554 (72,414) (152,517)
Decommissioning spend (104) (4,514) (18,142)
Net cash inflow from operating activities 172,404 224,209 281,563
15. Post balance sheet events
There have been no events since the balance sheet date that require
disclosure.
16. Publication of Non-Statutory Accounts
The financial information contained in this interim statement does not
constitute statutory accounts as defined in the Companies Act 2006. The
financial information for the full preceding year is based on the statutory
accounts for the financial year ended 31 December 2024, which are available at
the Company's registered office at 72 Welbeck Street, London W1G 0AY and on
its website at www.serica-energy.com (http://www.serica-energy.com) and on
SEDAR at www.sedar.com (http://www.sedar.com) .
This interim statement will be made available at the Company's registered
office at 72 Welbeck Street, London W1G 0AY and on its website at
www.serica-energy.com (http://www.serica-energy.com) and on SEDAR at
www.sedar.com (http://www.sedar.com) .
Reconciliation of non-IFRS measures
Serica uses certain measures of performance that are not specifically defined
under IFRS or other generally accepted accounting principles ("GAAP"). These
non-IFRS measures, which are presented within the financial review, are
defined below:
EBITDAX: Earnings before interest, tax, depreciation and amortisation,
impairments, transaction costs, unrealised hedging expenses, FX translation
effects, asset revaluation effects, other noncash gains or expenses and
exploration expenditure. This is a useful indicator of underlying business
performance and the definition adopted by Serica is consistent with that
stipulated in the Group's reserve based lending ("RBL") facility. A
reconciliation from Operating Profit to EBITDAX is provided below:
$ 000 H1 2025 H1 2024
Operating Profit 118,087 201,753
Add back DD&A 54,932 87,147
Add back depreciation in G&A 515 502
Add back E&E expenses and licence costs 1,196 2,008
Deduct contract revenue - other (5,408) (28,576)
(Deduct) / add back unrealised hedging (53,136) 14,918
Add back / deduct FX effects/remeasurements 635 (639)
Add back share based payments 1,673 2,114
EBITDAX 118,494 279,227
Capital Expenditure (capex and abex): Comprises the cash spend (prior to tax
allowances) on the acquisition of PP&E assets, the purchase of exploration
and appraisal assets and decommissioning spend. Depicts how much the Group has
spent, on a cash basis, on purchasing fixed assets in order to further its
business goals and objectives. It is a useful indicator of the Group's organic
expenditure on oil and gas assets, and exploration and appraisal assets,
incurred during a period on a pre-tax basis.
$ 000 H1 2025 H1 2024
Purchase of PP&E assets 136,527 106,664
Purchase of E&E assets 1,179 5,001
Decommissioning spend 104 4,514
Capital Expenditure 137,810 116,179
CFFO less current tax: comprises cash inflow from operations adjusted by the
current tax charge for the period as reflected in Note 12 and also excludes
cash movement arising from the return or posting of security deposits for
decommissioning and hedging. Serica considers that this is a useful measure of
the cash generation of the business prior to the decisions made by the Group
in relation to capital allocation.
$ 000 H1 2025 H1 2024
Cash inflow from operations 101,954 301,137
Less current tax - (72,727)
Changes in DSA advances - (35,055)
Adjusted CFFO less tax 101,954 193,355
Free cash flow: net cash flow from operating activities less cash used in
investing activities (excluding acquisition costs) and financing activities.
This measure is considered a useful indicator of the Group's ability to
invest, repay the Group's debt and meet other payment obligations. Group free
cash flow reconciles to net cash flow from operating activities as follows
$ 000 H1 2025 H1 2024
Net cash flow from operating activities 172,404 224,209
Net cash flow from investing activities (145,649) (112,383)
Net cash flow from financing activities (12,421) (85,154)
Adjusted by:
Repayment of loans and borrowings - 52,545
Payments for share buyback - 18,972
Proceeds from issue of shares (178) (350)
Free cash flow 14,156 97,839
Adjusted net cash / (debt): Total cash and cash equivalents plus the level of
interest bearing loans net of the carrying value of unamortised fees. This is
an indicator of the Group's indebtedness and contribution to capital
structure.
$ 000 30 June 2025 31 December 2024
Interest bearing loans (220,203) (219,130)
Add back unamortised fees (10,797) (11,870)
Cash and cash equivalents 174,395 148,460
Adjusted Net Debt (82,540)
(56,605)
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 PKQBPCBKDOFKRecent news on Serica Energy
See all newsREG - Serica Energy PLC - Results for the six months ended 30 June 2025
AnnouncementREG - Serica Energy PLC - Update on production at Triton FPSO
AnnouncementREG - Serica Energy PLC - PDMR Dealings
AnnouncementREG - Serica Energy PLC - Resumption of production operations at Triton FPSO
AnnouncementREG - Serica Energy PLC - Block Listing Six Monthly Return
Announcement