REG - Savannah Energy Plc - 2025 Half-Year Results & Trading Update
22/10/2025 16:45
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RNS Number : 4463E Savannah Energy Plc 22 October 2025
22 October 2025
Savannah Energy PLC
("Savannah" or "the Company")
Publication of 2025 Half-Year Results and Restoration to Trading
Profit Before Tax more than doubles to US$101.5 million
Savannah Energy PLC, the British independent energy company focused around the
delivery of Projects that Matter, is pleased to announce the publication of
its unaudited half-year results for the six months ended 30 June 2025. The
results will shortly be available on the Company's website.
Following the publication of the 2024 Annual Report earlier today, and these
2025 Half-Year Results, trading in the Company's ordinary shares on the AIM
market is expected to be restored on the AIM market at 7.30 a.m. on Thursday
23 October 2025.
H1 2025 Highlights
· Completion of the SIPEC Acquisition in March 2025, increasing our
reserve and resource base by approximately 47 MMboe (29%) from 160 MMboe to
207 MMboe(1). Following completion of the SIPEC Acquisition, we commenced an
up to 18-month expansion programme designed to increase Stubb Creek production
from the 2.7 Kbopd average 2024 level to as much as 4.7 Kbopd;
· SIPEC Acquisition delivered over US$8 million of free cashflow in
the c. 16 week period post-completion;
· 29% increase in Stubb Creek Gross 2P Reserves and 21% increase in
Uquo Gross 2P Reserves(2);
· Average gross daily production of 21.6 Kboepd (FY 2024: 23.1
Kboepd)(3);
· Progressed investment in capital projects:
o Safely achieved completion and full commissioning of the compression
project at the Uquo Central Processing Facility ("CPF"), approximately 10%
below the original US$45 million budget, post-period end; and
o Advanced preparations for a planned up to two-well drilling campaign on
the Uquo Field in 2026 with long-lead items procurement process progressed in
the period.
· Stable financial performance reported in the period:
o Total Revenues(4) of US$127.1million, up 2.8% (H1 2024: US$123.6 million);
o Cash collections of US$147.2 million, in line with the prior year period
(H1 2024: US$148.6 million);
o Profit before tax of US$101.5 million, up 54% (H1 2024: US$47.2 million);
o Adjusted EBITDA(5) of US$72.9 million (H1 2024:US$91.6 million);
o Leverage(6) ratio reduced to 3.1x (31 December 2024: 3.5x); and
o Trade Receivables balance reduced by 2.1% to US$527.7 million (31 December
2024: US$538.9 million).
· As at 30 June 2025, cash balances were over 50% higher than
year-end at US$50.4 million (31 December 2024: US$32.6 million) and net debt
was lower at US$628.7 million (31 December 2024: US$636.9 million). The debt
associated with the SIPEC Acquisition was drawn in the period and, for
comparison purposes if excluded, underlying net debt as at 30 June 2025 was
over 7% lower at US$590.9 million. Only 6% of outstanding debt as at 30 June
2025 was recourse to the Company, with the balance sitting with subsidiary
companies on a non-recourse basis;
· Completion of an equity issuance in March 2025, raising in
aggregate, gross proceeds of approximately £30.6 million and the signing of a
US$200 million acquisition debt facility providing access to potential funding
for future hydrocarbon asset acquisitions;
· Final documentation was agreed in respect of an increase in the
Accugas Naira-denominated debt facility from NGN340 billion (approximately
US$222 million) to up to approximately NGN772 billion (approximately US$500
million) (the "Transitional Facility"). Agreements were signed post-period
end, with the expectation that the upsized facility will be utilised to enable
the remaining outstanding balance of the Accugas US$ Facility to be repaid by
end 2025;
· Subject to a satisfactory agreement being reached with the
Government of Niger, a subsidiary is considering commencing a four-well
testing programme and/or a return to exploration activity in the R1234 PSC
contract area in 2026/27; and
· Continued to progress our portfolio of large-scale wind, solar
and hydroelectric projects, together with the announcement of plans to
reposition our Power Division business model, expanding its remit to include
potential thermal as well as potential renewable energy projects.
For further information, please refer to the Company's website
www.savannah-energy.com or contact:
Savannah
Energy
+44 (0) 20 3817 9844
Andrew Knott, CEO
Nick Beattie, CFO
Sally Marshak, Head of IR & Communications
Strand Hanson Limited (Nominated
Adviser) +44 (0) 20 7409 3494
James Spinney
Ritchie Balmer
Rob Patrick
Cavendish Capital Markets Ltd (Joint
Broker) +44 (0) 20 7220 0500
Derrick Lee
Tim Redfern
Panmure Liberum Limited (Joint
Broker) +44 (0) 20
3100 2000
Scott Mathieson
James Sinclair-Ford
Camarco
+44 (0) 20 3757 4983
Billy Clegg
Owen Roberts
Violet Wilson
This announcement contains inside information for the purposes of Article 7 of
the Market Abuse Regulation (EU) 596/2014 as it forms part of UK domestic law
by virtue of the European Union (Withdrawal) Act 2018, as amended.
About Savannah:
Savannah Energy PLC is a British independent energy company focused around the
delivery of Projects that Matter in Africa.
Operational Review
Hydrocarbons Division
Average gross daily production was 21.6 Kboepd for H1 2025 (FY 2024: 23.1
Kboepd), of which 86% was gas (FY 2024: 88%)(3). As previously announced, we
expect gas volumes to be lower in 2025 than prior year, given the significant
ongoing operation work during 2025 (including completion of compression, site
and logistical preparations for upcoming material drilling activity and other
ongoing field activities), together with anticipated levels of customer
demand. Production in the first half was in line with expectations.
On 10 March 2025, we announced the completion of the SIPEC Acquisition.
Following completion, we commenced a planned production expansion programme
that has already increased current Stubb Creek gross daily production to 3.3
Kbopd, approximately 24% above the 2024 average. The full programme, expected
to take up to 18 months, is anticipated to raise gross production to as much
as 4.7 Kbopd. In parallel, we are evaluating an alternative, lower capex
option that could deliver a faster production ramp up, with plateau production
sustained for a longer period at a slightly lower rate than under the original
expansion programme.
As announced on 19 May 2025, the Company appointed McDaniel & Associates
Consultants Ltd ("McDaniel") to prepare an updated CPR for the oil and gas
assets of the Group which confirmed a 29% increase in Stubb Creek Gross 2P
Reserves and a 21% increase in Uquo Gross 2P Reserves as set out in the table
below. The reduced range between the 1P and 3P Reserves demonstrates the
increased certainty in the Reserves estimates and is a reflection of the
maturity of an asset that has now been on production for over 10 years:
Summary Comparison of Nigeria Gross Reserves
Uquo Field Summary of Gross Gas Reserves (Bscf)
1P 2P 3P
CPR, March 2024* 233.5 400.5 493.6
McDaniel, March 2025 320.2 484.9 544.8
Changes (%) 37% 21% 10%
*Prepared by CGG Services (UK) Ltd
Stubb Creek Field Summary of Gross Oil Reserves (MMstb)
1P 2P 3P
CPR, March 2024* 3.3 10.7 20.4
McDaniel, March 2025 9.7 13.8 18.1
Changes (%) 194% 29% -11%
* Prepared by CGG Services (UK) Ltd
Nigeria Gross 2P Reserves and 2C Resources
CGG, 2024* McDaniel, 2025 Changes (%)
Uquo 2P Gas Bscf 400.5 484.9 21%
Uquo 2P Condensate MMstb 0.6 0.7 21%
Uquo 2C Gas Bscf 82.8 55.1 -33%
Stubb Creek 2P Oil MMstb 10.7 13.8 29%
Stubb Creek 2C Gas Bscf 515.3 513.1 0%
Nigeria 2P+2C MMboe 177.7 190.0 7%
*Prepared by CGG Services (UK) Ltd
During the first half of the year, we continued to progress the compression
project at the Uquo CPF (with completion and full commissioning achieved early
in H2 2025). The project was completed safely and approximately 10% below the
original US$45 million budget and it is expected that the project will allow
us to maximise the production from our existing and future gas wells.
During the period, we advanced preparations for a two-well drilling campaign
on the Uquo Field, commencing the procurement process of long lead equipment
in Nigeria. The Uquo NE development well ("Uquo NE"), due to commence drilling
in January 2026, is forecast to provide gas volumes of up to 80 MMscfpd, while
an additional exploration well in the Uquo Field ("Uquo South") is expected to
be drilled back-to-back with the Uquo NE well. Uquo South is targeting an
Unrisked Gross gas initially in place of 131 Bscf of incremental gas
resources.
During the period, we also continued to seek to progress the 35 MMstb (Gross
2C Resources) R3 East oil development in South-East Niger, subject to
satisfactory stakeholder agreements being entered into.
Power Division
During the first half of 2025, we continued to progress our portfolio of
large-scale wind, solar and hydroelectric development projects, with our
principal focus projects being on the up to 250 MW Parc Eolien de la Tarka
wind farm project in Niger and the up to 95 MW Bini a Warak hybrid
hydroelectric and solar project in Cameroon.
Our Parc Eolien de la Tarka project made significant progress, with the
Minister of Energy confirming that the project is on the Government's list of
priority projects. We continued to progress the additional Environmental and
Social Impact Assessment ("ESIA") field work studies required for the full
ESIA, which we expect to complete and submit to the relevant authorities in
early 2026. The Company is negotiating outline terms in relation to the
project's proposed power purchase agreement and continues to work on the
project in close collaboration with the International Finance Corporation
(World Bank) and the US International Development Finance Corporation.
Negotiations with the Government of Cameroon continued regarding a Joint
Development Agreement for the up to 95 MW Bini a Warak project. This is
expected to replace the Memorandum of Agreement signed in April 2023 and
secure the terms under which Savannah will collaborate with the Government of
Cameroon to further develop the project.
As previously announced, we continued to work on repositioning our Power
business model, including the expansion of the Power Division to include both
renewable as well as potential thermal energy projects.
Financial Review
The table below provides an overview of results for H1 2025 with a comparison
for H1 2024:
Key Financial Highlights
Six months ended Six months ended
30 June 2025 30 June 2024
Total Revenues(4), US$ million US$127.1 million US$123.6 million
Profit before tax, US$ million US$101.5 million US$47.2 million
Adjusted EBITDA(5), US$ million US$72.9 million US$91.6 million
Cash collections US$147.2 million US$148.6 million
Total Revenues(4) were higher in the period at US$127.1 million (H1 2024:
US$123.6 million). As anticipated, Other operating income was materially lower
in the period at US$5.9 million (H1 2024: US$109.9 million) - this relates
principally to the re-billing of foreign exchange losses incurred by Accugas
and given the relative exchange rate stability seen in Nigeria in the period,
combined with the greater proportion of debt now denominated in Naira, there
was only minimal level of losses seen which were rebilled to customers.
Profit before tax was materially higher at US$101.5m (H1 2024: US$47.2
million) which reflects the impact of the SIPEC Acquisition in the period.
Adjusted EBITDA(5) was US$72.9 million (H1 2024: US$91.6 million), with this
decrease largely due to an increase in cost of sales due to certain
non-recurring items as discussed below. Excluding these one-off costs would
show a comparable Adjusted EBITDA(5) of US$84.2 million.
Cash collections were stable compared to the prior year at US$147.2 million
(H1 2024: US$148.6 million) and increasing the rate of cash collections
remains a focus for the Company this year.
SIPEC Acquisition
The impact of the completion of the SIPEC Acquisition mid-way through the
period is reflected in the financial statements. The positive effects of the
transaction are already being seen with over US$8 million of free cashflow
generated between acquisition date and 30 June 2025 and . The outstanding debt
under the reserve-based lending ("RBL") facility has also reduced from US$60
million on acquisition to US$40 million as at 30 June 2025. The RBL remains
fully available with current borrowing base capacity exceeding the US$60
million facility limit.
The acquisition has been accounted for using the acquisition method and the
Group applied the requirements for a business combination achieved in stages
by remeasuring its previously held interest in the joint operation through
Universal Energy Resources Limited. This has resulted in the Group recognising
a provisional gain on acquisition of a subsidiary of US$127.4m and a gain on
remeasurement of a previously held interest of US$23.3m in the period. Further
details are provided in Note 19.
Revenue
Revenue during the period of US$126.0 million (H1 2024: US$114.8 million) was
10% higher than 2024. This was driven by additional revenue earned from the
Stubb Creek oil field following the SIPEC Acquisition and an increase in
liquids production, partially offset by a reduction in gas production.
As previously highlighted, it is important to note the impact of take-or-pay
accounting rules under IFRS 15 on our Income Statement as regards to revenue
recognition for our gas sales agreements. The Revenue shown in the Condensed
Consolidated Statement of Comprehensive Income includes only the gas, oil and
condensate that has been delivered. Total Revenues(4) of US$127.1 million (H1
2024: US$123.6 million) include the volume of gas that customers are committed
to pay for under the take-or-pay terms of certain gas sales agreements, which
includes gas that has been delivered plus gas invoiced but yet to be
delivered, plus oil and condensate revenues. The foreign exchange true-up
invoices are also not reflected within Revenue or Total Revenues(4).
Cost of Sales, Administrative and Other Operating Expenses
Cost of sales increased in the six months to US$58.3 million (H1 2024: US$34.6
million). The increase includes two non-recurring items - firstly there have
been various accounting entries required post-acquisition of SIPEC to
transition to Savannah accounting policies which resulted in a one-off charge
of US$3.8 million related to recording of inventory balances. The other
one-off expenditure related to costs incurred in pipeline maintenance and
tariff fees associated with rerouting of produced gas, totalling approximately
US$7.5million. (This continued into the early part of the current quarter with
total costs related to this of US$13.5 million anticipated for the full year).
Excluding these one-off costs, the cost of sales would have been US$47.0
million. The remaining increase in cost of sales is largely due to the SIPEC
Acquisition, including depletion related to the fair value uplift (as
discussed below), increased royalties from higher oil production and costs
related to SIPEC operations - in total these are approximately US$10.0
million. For comparison, excluding the SIPEC Acquisition and non-recurring
costs, the cost of sales would have been broadly unchanged in the period
(approximately $36 million vs $34.6 million in H1 2024).
Administrative and other operating expenses for the period were well contained
despite the high inflationary environment in Nigeria at US$18.4 million (H1
2024: US$17.3 million, excluding a one-off rebate in that period), with the
majority of the increase resulting from costs associated with the newly
acquired SIPEC subsidiary.
Transaction and other related expenses of US$21.4 million (H1 2024: US$8.9
million) primarily relate to legal expenses with respect to the ongoing
arbitration processes, SIPEC Acquisition related transaction costs and
activity associated with other potential acquisitions.
Finance Costs
In H1 2024, there was a one-off release of a legacy non-cash related finance
cost of US$9.6 million. Excluding this non-recurring amount, on a comparable
basis the finance costs increased from US$48.8 million to US$69.5 million.
This increase is a result of greater utilisation of the Transitional Facility
which carries a higher average interest rate than the Accugas US$ Facility.
The average interest rate has increased in the period from 14.3% to 18.4%.
Foreign Exchange Loss
Foreign exchange losses were materially lower in the period at US$4.9 million
(H1 2024: US$67.6 million). This is a result of the broadly stable exchange
rate between Naira and US$ throughout the period.
Of the total, US$3.7 million (H1 2024: US$49.9 million) are unrealised losses,
mainly due to movements in Naira monetary assets and liabilities, specifically
Naira cash balances. Realised losses accounted for remainder at US$1.2 million
(H1 2024: US$17.7 million). Certain foreign exchange losses are recoverable
through the true up mechanism included in the GSA with our principal gas
customer. These amounts, when invoiced, are reported under Other operating
income - as noted above, in H1 2025 these amounted to US$5.6 million (H1 2024:
US$109.9 million).
Cash Flow
Net cashflow from operating activities increased by 10% to US$82.2 million (H1
2024: US$74.5 million).
Capital and exploration expenditure for the period amounted to US$8.6 million
(H1 2024: US$13.9 million), the majority of which related to the Uquo
compression project. The other principal use of cash in period was towards
debt repayments and finance costs amounting to a combined US$99.5 million (H1
2024: US$106.8 million).
Cash balances at 30 June 2025 were US$50.4 million (31 December 2024: US$32.6
million).
Debt
Net debt at 30 June 2025 was US$628.7 million, a decrease of 1.3% from the
year-end position (31 December 2024: US$636.9 million). Gross debt rose by
US$9.0 million to US$679.1 million (31 December 2024: US$669.5 million). The
increase in gross debt was a result of the SIPEC Acquisition completing during
the period and the utilisation of the acquisition related debt facility. On a
like-for-like basis (without taking into account the SIPEC Acquisition related
debt), gross debt fell by 4.2% compared to year-end position.
Leverage (which takes into account a pro-forma 12-month EBITDA for SIPEC) has
reduced in the period to 3.1x (31 December 2024: 3.5x).
It is worth noting the treatment of the debt facility entered into to finance
the acquisition of the Chad and Cameroon Assets. Despite the Nationalisation
there remains an outstanding balance of US$142.4 million (31 December 2024:
US$134.6 million) which accounts for over 20% of the total debt within the
Group - of this amount only up to a maximum of US$37.0 million is recourse to
the Company with the remainder being fully non-recourse. The only other debt
within the Group which is resource to the Company totals approximately US$4.3
million, with all other borrowings on a non-recourse basis.
In H1 2025, Accugas entered into the Transitional Facility. This facility was
fully utilised earlier this year with the resulting funds converted to US$,
which, along with cash held, was used to partially prepay the existing Accugas
US$ Facility. There was a remaining principal balance under the US$ Facility
as at 30 June 2025 of approximately US$199.9 million. An increase in the
Transitional Facility was signed in Q3 2025, increasing total commitments to
up to NGN772 billion. This increased facility will enable the remaining
outstanding US$ balance to be converted into Naira, with the expectation this
will allow the remainder of the Accugas US$ Facility to be fully repaid by end
2025. This process, when complete, will align Accugas' debt facility with the
currency in which gas revenues are received.
The Company has in place a rolling hedging programme for Stubb Creek oil with
480,000 barrels hedged for the next 12 months at an average floor price of
$58.75/bbl.
Going Concern
The results have been presented on a going concern basis. Details of the
Group's assessment of going concern for the period can be found in Note 2.
Condensed consolidated statement of comprehensive income
for the six months ended 30 June 2025
Six months ended Six months ended
30 June 30 June
2025 2024
US$'000 US$'000
Note Unaudited Unaudited
Revenue 4a 126,024 114,788
Cost of sales 5 (58,278) (34,639)
Gross profit 67,746 80,149
Other operating income 4b 5,887 109,930
Administrative and other operating expenses (18,406) (15,960)
Transaction and other related expenses 6 (21,368) (8,914)
Expected credit loss and other related adjustments 12 (11,525) (12,944)
Operating profit 6 22,334 152,261
Gain on acquisition of a subsidiary 19 127,422 -
Gain on remeasurement of a previously held interest 19 23,264 -
Finance income 3,636 1,815
Finance costs 7 (69,524) (39,271)
Fair value through profit or loss (731) -
Foreign exchange loss 8 (4,894) (67,592)
Profit before tax 101,507 47,213
Current tax expense 9 (10,462) (15,198)
Deferred tax credit/(expense) 9 9,907 (11,662)
Total tax expense 9 (556) (26,860)
Profit after tax 100,951 20,353
Profit after tax and Total comprehensive income 100,951 20,353
Total comprehensive profit/(loss) attributable to:
Owners of the Company 102,472 16,268
Non-controlling interests (1,521) 4,085
100,951 20,353
US cents US cents
Earnings per share
Basic 10 7.12 1.31
Diluted 10 6.87 1.25
Condensed consolidated statement of financial position
as at 30 June 2025
30 June 31 December
2025 2024
US$'000 US$'000
Note Unaudited Audited
Assets
Non-current assets
Property, plant and equipment 11 606,842 457,453
Intangible assets 177,136 176,427
Financial investment 139,459 139,459
Deferred tax assets 299,812 271,737
Right-of-use assets 2,869 3,418
Restricted cash 3,026 29
Other non-current receivables 14,442 17,334
Total non-current assets 1,243,586 1,065,857
Current assets
Inventory 7,886 5,078
Trade and other receivables 12 466,325 470,047
Cash at bank 13 50,388 32,585
Total current assets 524,599 507,710
Total assets 1,768,185 1,573,567
Equity and liabilities
Capital and reserves
Share capital 2,212 1,836
Share premium 152,510 126,824
Treasury shares (91) (97)
Other reserves 525 531
Share-based payment reserve 18,245 17,261
Retained earnings 244,072 141,600
Equity attributable to owners of the Company 417,473 287,955
Non-controlling interests 26,543 28,064
Total equity 444,016 316,019
Non-current liabilities
Other payables 14 2,844 1,671
Borrowings 15 406,728 370,229
Lease liabilities 2,884 2,213
Provisions 53,473 49,384
Contract liabilities 16 389,503 382,640
Total non-current liabilities 855,432 806,137
Current liabilities
Trade and other payables 14 117,011 80,147
Borrowings 15 272,371 299,299
Interest payable 17 26,391 27,248
Tax liabilities 35,289 24,276
Lease liabilities 1,433 1,777
Contract liabilities 16 16,241 18,664
Total current liabilities 468,737 451,411
Total liabilities 1,324,169 1,257,548
Total equity and liabilities 1,768,185 1,573,567
Condensed consolidated statement of cash flows
for the six months ended 30 June 2025
Six months ended Six months ended
30 June 2025 30 June 2024
US$'000 US$'000
Note Unaudited Unaudited
Cash flows from operating activities:
Profit before tax 101,507 47,213
Adjustments for:
Depreciation 1,780 1,474
Depletion 19,393 16,126
Gain on acquisition of a subsidiary (127,422) -
Gain on remeasurement of a previously held interest (23,264) -
Finance income (3,606) (1,598)
Finance costs 7 69,425 39,271
Fair value through profit or loss 731 -
Unrealised foreign exchange loss 8 3,702 49,875
Share-based payments 984 1,015
Current service cost 107 -
Other expenses (56) -
Expected credit loss and other related adjustments 12 11,525 12,944
Operating cash flows before movements in working capital 54,806 166,320
Increase in inventory 3,649 (5)
Decrease/(increase) in trade and other receivables 7,259 (94,597)
Increase/(decrease) in trade and other payables 20,806 (1,604)
Increase in contract liabilities 1,115 8,780
Benefits paid (121) -
Income tax paid (5,270) (4,401)
Net cash generated from operating activities 82,244 74,493
Cash flows from investing activities:
Interest received 692 134
Payments for property, plant and equipment (8,381) (9,729)
Payments for exploration and evaluation assets (239) (4,179)
Return of deposit related to proposed acquisition - 10,000
Cash acquired on acquisition of subsidiary 16,844 -
Cash paid for acquisition of subsidiary (35,384) -
Loans and advances - receipts 3,370 782
Loans and advances - payments (1,709) (7,351)
Cash transferred from debt service accounts 5,033 57,180
Cash transferred to restricted cash accounts (2,998) -
Lessor receipts - 223
Net cash (used in)/generated from investing activities (22,772) 47,060
Cash flows from financing activities:
Finance costs (57,794) (59,576)
Borrowing proceeds 17 65,193 39,018
Borrowing repayments 17 (41,705) (47,236)
Lease payments 17 (332) (467)
Net cash used in from financing activities (34,638) (68,261)
Net increase in cash and cash equivalents 24,834 53,292
Effect of exchange rate changes on cash and cash equivalents (2,033) (60,172)
Cash and cash equivalents at beginning of period 26,323 48,134
Cash and cash equivalents at end of period 13 49,124 41,254
Amounts held for debt service at end of period 13 1,264 1,627
Cash at bank at end of period 13 50,388 42,881
Condensed consolidated statement of changes in equity
for the six months ended 30 June 2025
Share capital Share premium Treasury shares Other reserves Share-based payment reserve Retained earnings Equity attributable to the owners of the Company Non-controlling interest Total equity
US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 US$'000
Balance at 1 January 2025 (audited) 1,836 126,824 (97) 531 17,261 141,600 287,955 28,064 316,019
Profit/(loss) after tax and Total comprehensive income - - - - - 102,472 102,472 (1,521) 100,951
Total comprehensive income - - - - - 102,472 102,472 (1,521) 100,951
Transactions with shareholders:
Issued shares, net of costs 376 25,686 6 (6) - - 26,062 - 26,062
Equity-settled share-based payments - - - - 984 - 984 - 984
Balance at 30 June 2025 (unaudited) 2,212 152,510 (91) 525 18,245 244,072 417,473 26,543 444,016
Share capital Share premium Treasury shares Other reserves Share-based payment reserve Retained earnings Equity attributable to the owners of the Company Non-controlling interest Total equity
US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 US$'000
Balance at 1 January 2024 (audited) 1,836 126,824 (136) 531 14,717 110,726 254,498 9,259 263,757
Profit after tax and Total comprehensive income - - - - - 16,268 16,268 4,085 20,353
Total comprehensive income - - - - - 16,268 16,268 4,085 20,353
Equity-settled share-based payments - - - - 1,015 - 1,015 - 1,015
Balance at 30 June 2024 (unaudited) 1,836 126,824 (136) 531 15,732 126,994 271,781 13,344 285,125
Notes to the condensed consolidated interim financial statements
1. General information
Savannah Energy PLC ("Savannah" or "the Company") was incorporated in England
and Wales on 3 July 2014. The condensed consolidated financial statements of
Savannah and its subsidiaries (together the "Group") for the six months ended
30 June 2025 were approved and authorised for issuance by the board of
directors on
22 October 2025.
The Group's principal activities are the exploration, development and
production of natural gas and crude oil and development of other energy
related projects in Africa.
The Company is domiciled in England for tax purposes and its shares were
listed on the Alternative Investment Market ("AIM") of the London Stock
Exchange on 1 August 2014. The Company's registered address is 40 Bank
Street, London, E14 5NR.
2. Accounting policies
Basis of Preparation
The condensed consolidated interim financial statements included within this
Interim Report have been prepared in a form consistent with that which will be
adopted in the Company's annual accounts having regard to the accounting
standards applicable to such annual accounts, and in accordance with the
London Stock Exchange AIM Rules for Companies. The provisions of IAS 34:
Interim Financial Reporting have not been applied.
The condensed consolidated interim financial statements do not include all
disclosures that would otherwise be required in a complete set of financial
statements and should be read in conjunction with the Group's 2024 Annual
Report and Accounts, for the year ended 31 December 2024 ("the Group's 2024
Annual Report"). The financial information for the six months ended 30 June
2025 does not constitute statutory accounts within the meaning of Section
434(3) of the Companies Act 2006 and is unaudited.
The annual financial statements of Savannah for the year ended 31 December
2024 were prepared in accordance with UK-adopted international accounting
standards in conformity with the requirements of the Companies Act 2006. The
Independent Auditors' Report on the Group's 2024 Annual Report contained a
disclaimer of opinion, and as such contained a statement under 498(2) or
498(3) of the Companies Act 2006. The Group's statutory financial statements
for the year ended 31 December 2024 will be filed with the Registrar of UK
Companies.
All the Company's subsidiaries' functional currency is US Dollars ("US$"), and
the consolidated financial statements are presented in US Dollars and all
values are rounded to the nearest thousand (US$'000), except when otherwise
stated.
The financial information presented herein has been prepared in accordance
with the accounting policies used in preparing the Group's 2024 Annual Report.
There are no other new or amended standards or interpretations adopted from 1
January 2025 that have a significant impact on the interim financial
information.
As disclosed in the Group's 2024 Annual Report, the Republic of Chad
nationalised the Group's interests in its Chad subsidiaries Savannah Chad Inc
("SCI") and Savannah Midstream Investment Limited ("SMIL"), (the "Chad
Assets") by way of a law passed on 31 March 2023 (the "Nationalisation"). As a
result of the Nationalisation, the Group was unable to fully access all the
underlying financial information, nor have access to the relevant Chad-based
employees of the affected entities SCI and SMIL in order to prepare the
financial information: (i) for audit purposes to be consolidated into the
Group's financial statements for the year ended 31 December 2024; and (ii) for
the unaudited condensed consolidated interim financial statements for the six
months ended 30 June 2025.
Therefore, as at 31 March 2023 the activities of the Chad Assets were
considered as a discontinued operation, in accordance with IFRS 5: Non-current
Assets for Sale and Discontinued Operations; and the net statement of
financial position associated with the Chad Assets was fully impaired such
that no balances remained in the consolidated statement of position at
subsequent reporting dates. For both the six months ended 30 June 2025 and 30
June 2024, no transactions were recorded with this discontinued operation and
Note 20 sets out the position of any potential contingent liabilities
associated with the Chad Assets.
With respect to the Group's valuation of its financial investment in Cameroon
Oil Transportation Company (COTCo), no further adjustment has been made as at
30 June 2025 - more details of this financial investment are set out in the
Group's 2024 Annual Report.
Going concern
The Directors have considered the factors relevant to support a statement of
going concern; in assessing the going concern assumption the Directors have
reviewed the Group's forecasted cash flows as well as the funding requirements
of the Group from the date of the approval of these financial statements to 31
October 2026. As in previous periods, this forecast was prepared on a
"bottom-up" basis, at each major asset and corporate level, and it reflects
the Group's best estimate of costs and revenues for the going concern period.
The capital expenditure and operating costs used in this forecast are based on
the Group's corporate budget which includes operating budgets for each of the
operating subsidiaries and an estimate of the corporate general and
administrative costs for the going concern period.
The base case model assumes that Cash Collections from the Group's gas
customers in Nigeria are received on a regular basis along with an unwind of
historic receivables in line with both key long-term supply contracts with
committed volumes and short-term supply contracts and only assumes that
current customers are supplied. Forecast cash inflows generated from liquids
production at the Stubb Creek and Uquo fields are based on in-house production
forecasts in line with the Competent Person Report.
As part of its analysis in making the going concern assumption, the Directors
have considered the range of risks facing the business on an ongoing basis, as
set out in the Risk management section of this Annual Report. In addition, the
other principal assumptions made in relation to our base case going concern
assessment relate to the regular payments of gas invoices by customers, the
forecast commodity price environment and continued access to FX markets
(specifically in relation to the financing of US Dollar denominated costs and
the refinancing of the remaining balance of the Accugas US$ Facility).
Notwithstanding the risks across the Group, both the base case forecasts and
sensitised scenarios confirm that the Directors believe that the Group and
each subsidiary company has sufficient liquidity to continue as a going
concern for at least a 12-month period from the date of the approval of this
report.
Looking at a selection of the principal risks:
Payment of invoices from a concentrated customer base
The Group continues to have a relatively concentrated customer base which
results in an inherent reliance risk on a small number of customers. As
previously outlined, the Group continues to focus on diversifying the customer
base to reduce this concentration. The risk associated with Nigerian-based gas
customers is mitigated through the external credit support covering the off
take contracts at Accugas where we have a Partial Risk Guarantee in place via
the World Bank to provide credit support for Accugas' principal customer for
up to approximately US$112 million of invoices and for other customers,
letters of credit are normally required.
The Group continues to seek to diversify its revenue stream and following the
acquisition of the additional interest in the Stubb Creek, this continues to
further enhance the US Dollar cash revenue generating capacity of the Group.
Commodity price/foreign exchange environment
The Group operates in the energy sector and is therefore exposed to
fluctuations in commodity prices. Brent oil prices traded at an average of
US$82.0/bbl in 2023, US$81.0/bbl in 2024 and US$69.7/bbl between January 2025
and September 2025. Due to the market volatility experienced in 2025 year to
date, Management has adopted an oil price of US$65.0/bbl for the going concern
period. The Group's gas sales contracts are at fixed prices without any
correlation to crude, with long-term supply contracts subject to inflation
price adjustments.
Commodities remain volatile and can fluctuate based on a wide range of
factors. Following the increase in the Group's interest in the Stubb Creek
field a rolling, options-based hedging programme has commenced to provide
protection against oil price fluctuations.
Following the proactive actions of the Nigerian Government, Nigerian Naira
("NGN") devalued significantly at the start of 2024, from an exchange rate
against the US$ of NGN859 to approximately NGN1,544 at year end (with an
average of NGN1,478 during the year). The Naira is now more aligned to a
market driven rate and overall, this has had a positive impact on the Group's
cash flows. The Group continues to invoice its customers in US Dollars and,
while they have the option to pay in either US Dollars or NGN, any NGN
payments are at prevailing market rates ensuring US Dollar equivalent receipts
remain consistent. NGN denominated costs are more favourable on a US Dollar
equivalent basis, providing cash flow benefits to the Group throughout the
going concern period.
Debt financing
Accugas has in place a Naira denominated loan facility with a consortium of
Nigerian lenders (the "Transitional Facility"), which has been utilised to
partially refinance the Accugas US$ Facility. The Transitional Facility was
increased in September 2025 to up to NGN773 billion, and this increased
facility will allow Accugas to convert and repay the remainder of the Accugas
US$ Facility prior to its maturity date at the end of 2025.
The limit of the increased Transitional Facility was calculated based on an
exchange rate of greater than 30% above the current market rates. Accugas is
confident therefore that the Transitional Facility will be sufficient to fully
repay the Accugas US$ Facility, However, repayment of the Accugas US$ Facility
and utilisation of the Transitional Facility continue to require access to
appropriately priced US Dollars. If the expanded Transitional Facility is not
sufficient to fully repay the Accugas US$ Facility, an amount would remain
outstanding which is required to be repaid by the final maturity date of the
Accugas US$ Facility (31 December 2025). The base case model shows that
sufficient cash flows are available to service any remaining balance under the
Accugas US$ Facility. The Group also has other maturing debt facilities during
H2 2025 and the base case model shows that sufficient cash flows are available
to service these maturing obligations. In Nigeria, the Group continues to
access US Dollars as required to pay its non-Naira denominated expenditures.
The Directors remain confident that this will continue and that the Group will
be able to access US Dollars and other currencies as required to maintain its
operational funding needs.
The maturity date of the term loan facility entered into to fund the
acquisition of the Chad and Cameroon Assets has been amended on several
occasions following the Nationalisation. Most recently, in October 2025 it has
been amended to provide Savannah with the option, at its sole discretion, to
extend the final maturity date until January 2027 which is beyond the going
concern review period.
Equity issue
In March 2025, the Company undertook an equity issuance to raise in total
approximately US$41 million. Approximately US$21 million of the new money
raised was used to acquire certain debt which was maturing in 2025. There is a
second tranche of new shares expected to be issued in October 2025 once the
Company's shares have resumed trading.
Sensitivity analysis
The Group has undertaken sensitivity analysis on the respective cash flow
forecasts and considered the material risk areas for the business which could
impact upon the going concern assumption. These risks included: (i) timely
payment of receipts from gas customers; (ii) commodity pricing; and (iii)
reduction of customer collections. In this respect, a number of sensitivities
were prepared, as follows:
(i) gas customer receipts - extended the collection receipt
time;
(ii) commodity price - reduced the forecast average oil price
to US$60/bbl;
(iii) exclude certain customer collections; and
(iv) a combination of all the above sensitivities.
Mitigating actions were considered which could be taken by the Group to
prevent a shortfall arising under any scenario and these could include:
(i) deferring or reducing costs - given its high equity
ownership levels and operatorship of key assets, the Group has significant
levels of control over capital and operating spend and can directly manage
costs where necessary with only minimal committed capital spend;
(ii) enforcing its rights to claim payment under the credit
support arrangements in place; and
(iii) raising of additional debt or equity if required - the
leverage on the Nigerian assets is low and given the long-term gas sales
contracts and long-life nature of the assets, the Group believes further
funding could be accessed if the need arose.
Under sensitivity analysis, the operating cash flows and funding available to
the Group remain sufficient at all times during the forecast period to meet
obligations as required whilst still maintaining headroom.
The Directors are confident in the Group's forecast and have a reasonable
expectation that the Group will continue in operational existence for the
going concern assessment period and believe it is appropriate to continue to
adopt the going concern basis in preparing these interim condensed financial
statements.
3. Segmental reporting
For the purposes of resource allocation and assessment of segment performance,
the operations of the Group are divided into four segments: three geographical
locations and an Unallocated segment. The current geographical segments are
Nigeria, Cameroon and Niger. All these geographical segments' principal
activities are exploration, development and extraction of oil and gas. The
Unallocated segment's principal activities are the governance and financing of
the Group, as well as undertaking business development opportunities. Items
not included within Operating profit/(loss) are reviewed at a Group level and
therefore there is no segmental analysis for this information.
The following is an analysis of the Group's continuing operations results by
reportable segment for the six months ended 30 June 2025:
Nigeria Niger Unallocated Total
US$'000 US$'000 US$'000 US$'000
Unaudited Unaudited Unaudited Unaudited
Revenue 126,024 - - 126,024
Cost of sales(1) (58,278) - - (58,278)
Gross profit 67,746 - - 67,746
Other operating income 5,617 - 270 5,887
Administrative and other operating expenses (4,830) (300) (13,276) (18,406)
Transaction and other related expenses - - (21,368) (21,368)
Expected credit loss and other related adjustments (11,525) - - (11,525)
Operating profit/(loss) 54,608 (300) (34,374) 22,334
Gain on acquisition of a subsidiary 127,422
Gain on remeasurement of a previously held interest 23,264
Finance income 3,636
Finance costs (69,524)
Fair value through the profit or loss (731)
Foreign exchange loss (4,894)
Profit before tax 101,507
Segment depreciation, depletion and amortisation (20,742) (90) (341) (21,173)
Segment non-current assets additions(2) 3,510 1,665 6 5,181
1. Refer to Note 5 for items included within Cost of Sales.
2. Includes Property, plant and equipment and Exploration and
evaluation assets.
The following is an analysis of the Group's results by reportable segment for
the six months ended 30 June 2024:
Nigeria Niger Unallocated Total
US$'000 US$'000 US$'000 US$'000
Unaudited Unaudited Unaudited Unaudited
Revenue 114,788 - - 114,788
Cost of sales(1) (34,639) - - (34,639)
Gross profit 80,149 - - 80,149
Other operating income 109,930 - - 109,930
Administrative and other operating expenses (2,532) (518) (12,910) (15,960)
Transaction and other related expenses (1,075) - (7,839) (8,914)
Expected credit loss and other related adjustments (12,944) - - (12,944)
Operating profit/(loss) 173,528 (518) (20,749) 152,261
Finance income 1,815
Finance costs (39,271)
Fair value through the profit or loss -
Foreign exchange loss (67,592)
Profit before tax 47,213
Segment depreciation, depletion and amortisation 16,128 114 1,358 17,600
Segment non-current assets additions(2) 6,191 2,615 114 8,920
1. Refer to Note 5 for items included within Cost of Sales.
2. Includes Third party investments, Property, plant and equipment,
Exploration and evaluation assets and Right-of-use assets.
4. Revenue
(a) Revenue from contracts with customers
Set out below is the disaggregation of the Group's revenue from contracts with
customers:
2025 2024
US$'000 US$'000
Six months ended 30 June Unaudited Unaudited
Gas sales 94,798 101,759
Oil, condensate and processing sales 31,226 13,029
Revenue from contracts with customers 126,024 114,788
Gas sales represent gas deliveries made to the Group's customers under gas
sale agreements. The Group sells oil and condensate at prevailing market
prices.
(b) Other operating income
Other operating income consists of US$5.6 million (2024: US$109.9 million)
relating to the invoicing of foreign exchange losses incurred on certain
customer trade receivables that are settled in a currency other than the
invoiced currency and are permitted to be invoiced to the relevant customer,
and income from grants amounting to US$0.2 million (2024: US$nil) with respect
to renewable development projects.
5. Cost of sales
2025 2024
US$'000 US$'000
Six months ended 30 June Unaudited Unaudited
Depletion - oil and gas, and infrastructure assets (Note 11) 19,386 16,126
Facility operation and maintenance costs 33,795 15,919
Royalties 5,097 2,594
58,278 34,639
6. Operating profit
Operating profit has been arrived at after charging:
2025 2024
US$'000 US$'000
Six months ended 30 June Unaudited Unaudited
Staff costs 13,517 13,130
Depreciation - other assets (Note 11) 257 276
Depreciation - right-of-use assets 574 485
Amortisation of intangibles 956 713
Transaction and other related expenses(1) 21,368 8,914
1. Transaction and other related expenses primarily relate to the
Group's legal and other costs in relation to the Chad and Cameroon arbitration
processes, and acquisition related expenses relating to the acquisition of
assets in Nigeria and the proposed acquisition of assets in South Sudan (in
2024).
7. Finance costs
2025 2024
US$'000 US$'000
Six months ended 30 June Unaudited Unaudited
Interest on bank borrowings and loan notes 62,551 42,061
Amortisation of balances measured at amortised cost(1) 3,157 3,316
Unwinding of decommissioning discount 1,244 542
Interest expense on lease liabilities 401 85
Hedging related costs(2) 97 -
Bank charges and other finance costs 2,074 2,860
Reversal of prior period finance costs - (9,593)
69,524 39,271
1. Includes amounts due to unwinding of a discount on a long-term payable, contract liabilities (Note 16) and amortisation of debt fees.
2. Hedging related costs relate to oil hedge premiums paid and net mark-to-market (MTM) movements.
8. Foreign exchange loss
2025 2024
US$'000 US$'000
Six months ended 30 June Unaudited Unaudited
Realised loss 1,192 17,717
Unrealised loss 3,702 49,875
4,894 67,592
Realised foreign translation loss mainly relates to the translation of Naira
denominated transactions into US Dollars.
9. Taxation
The tax expense/(credit) for the Group is:
2025 2024
US$'000 US$'000
Six months ended 30 June Unaudited Unaudited
Current tax
Adjustments in respect of prior years - -
Current year 10,462 15,198
10,462 15,198
Deferred tax
Adjustments in respect of prior years 1,035 1,118
Write down and reversal of previous write downs of deferred tax assets - -
Origination and reversal of temporary differences 10,942 10,544
(9,907) 11,662
Total tax expense for the period 556 26,860
Income tax expense is recognised based on the actual results for the period and principally arises on Nigerian profits.
The Nigeria Tax Act 2025 ("the Act") was enacted after the balance sheet date and is effective 1 January 2026.
Under this legislation, Nigerian entities with a turnover in excess of 50 billion Naira will be liable to pay a minimum effective corporate tax rate of 15% based on profits before tax, as reported in their audited financial statements, subject to certain adjustments. This will result in a supplementary tax payable should the aggregate corporate income taxes payable or paid by the company be less than 15% of the profits before tax. It is expected that further details will be issued by the Nigerian Revenue Service via Regulations. It should be noted that the Act permits such Regulations to prescribe a higher turnover threshold for this minimum effective tax rate to apply. Due to the complexities of implementation and pending the Regulations, the Group is in the process of assessing the impact of this change on its Nigerian subsidiaries.
10. Earnings per share
Basic earnings per share amounts are calculated by dividing the profit or loss
for the period attributable to owners of the Company by the weighted average
number of ordinary shares outstanding during the period.
Diluted earnings per share amounts are calculated by dividing the profit or
loss for the periods attributable to owners of the Company by the weighted
average number of ordinary shares outstanding during the period, plus the
weighted average number of shares that would be issued on the conversion of
dilutive potential ordinary shares into ordinary shares.
As there is a profit attributable to the owners of the Company for the six
months ended 30 June 2025 and 30 June 2024, the diluted weighted average
number of shares has been calculated. In the comparative period, the basic
average number of shares was used to calculate the diluted loss per share
given there is a loss attributable to the owners of the Company, meaning the
diluted weighted average number of shares reduces the loss per share.
Therefore, the basic weighted average number of shares was used to calculate
the diluted loss per share.
The weighted average number of shares outstanding excludes treasury shares of
68,964,585 (30 June 2024: 68,964,585).
2025 2024
Unaudited Unaudited
Six months ended 30 June US$'000 US$'000
Profit after tax 100,951 20,353
Profit after tax attributable to owners of the Company(1) 102,472 16,268
(Loss)/profit after tax attributable to non-controlling interests (1,521) 4,085
(1. ) The earnings per share calculation only
takes into account profit/(loss) attributed to owners of the Company.
Number Number
of shares of shares
Basic weighted average number of shares 1,438,846,934 1,243,229,960
Add: employee share options 52,626,132 56,344,675
Diluted weighted average number of shares 1,491,473,066 1,299,574,635
US cents US cents
Earnings per share
Basic profit per share 7.12 1.31
Diluted profit per share 6.87 1.25
23,450,849 options granted under employee share option schemes and 101,113,992
warrants issued are not included in the calculation of diluted earnings per
share because they are anti-dilutive for the six months ended 30 June 2025 (30
June 2024: 23,853,457 and 101,113,992 warrants). These options could
potentially dilute basic earnings per share in the future. The basic weighted
average number of shares used in 2024 has been recalculated and has decreased
the previously reported EPS.
11. Property, plant and equipment
Oil and gas assets Infrastructure assets Other assets
Total
US$'000 US$'000 US$'000 US$'000
Cost
Balance at 1 January 2024 (audited) 193,625 430,166 5,218 629,009
Additions 13 14,368 808 15,189
Disposals - - (743) (743)
Decommissioning remeasurement adjustment 1,910 (3,228) - (1,318)
Balance at 31 December 2024 (audited) 195,548 441,306 5,283 642,137
Assets recognised on acquisition of a subsidiary (Note 19) 165,363 - 112 165,475
Additions 1,083 2,444 30 3,516
Disposals - - - -
Balance at 30 June 2025 (unaudited) 361,994 443,750 5,425 811,169
Accumulated depreciation
Balance at 1 January 2024 (audited) (77,726) (71,840) (3,299) (152,865)
Depletion and depreciation charge (18,002) (13,901) (570) (32,473)
Disposals - - 654 654
Balance at 31 December 2024 (audited) (95,728) (85,741) (3,215) (184,684)
Depletion and depreciation charge (12,421) (6,965) (257) (19,643)
Disposals - - - -
Balance at 30 June 2025 (unaudited) (108,149) (92,706) (3,472) (204,327)
Net book value
1 January 2024 (audited) 115,899 358,326 1,919 476,144
31 December 2024 (audited) 99,820 355,565 2,068 457,453
30 June 2025 (unaudited) 253,845 351,044 1,953 606,842
Upstream assets principally comprise the well and field development costs
relating to the Uquo and Stubb Creek oil and gas fields in Nigeria. Oil and
gas assets recognised through acquisition of Savannah Energy Stubb Creek
Limited relates to 49% interest in the Stubb Creek Field. In line with the
acquisition, the previously held oil gas assets were revalued in line with
step-up acquisition reporting standard under IFRS 3. See Note 19 Business
Combination for further details.
Infrastructure assets principally comprise the Nigerian midstream assets
associated with the Group's network of gas transportation pipelines, oil and
gas processing facilities and gas receiving facilities. Other assets include
vehicles, office equipment and building improvements. Decommissioning
remeasurement adjustments reflect updated cost estimates for the
period/year.
Each year, management performs a review of each CGU to identify potential
impairment triggers. During the six months ended 30 June 2025 and the year
ended 31 December 2024, no such triggers were identified.
12. Trade and other receivables
30 June 31 December
2025 2024
US$'000 US$'000
Unaudited Audited
Trade receivables 527,727 538,894
Receivables from a joint arrangement - 4,509
Other financial assets 16,646 12,657
544,373 556,060
Expected credit loss (110,586) (98,102)
434,787 457,958
Loans and advances 2,709 1,442
VAT receivable 1,733 2,242
Prepayments and other receivables 26,882 8,405
Derivative asset (oil hedge) 1,214 -
466,325 470,047
The following has been recognised in the condensed statement of comprehensive
income relating to expected credit losses for the period:
2025 2024
US$'000 US$'000
Six months ended 30 June Unaudited Unaudited
Provision for expected credit losses 11,525 12,944
Expected credit loss and other related adjustments 11,525 12,944
13. Cash at bank
30 June 31 December
2025 2024
US$'000 US$'000
Unaudited Audited
Cash and cash equivalents 49,124 26,322
Amounts held for debt service 1,264 6,263
50,388 32,585
Amounts held for debt service represents Naira denominated cash balances which
are held for debt service, and this has been separately disclosed from Cash
and cash equivalents.
14. Trade and other payables
30 June 31 December 2024
2025
US$'000 US$'000
Unaudited Audited
Trade payables 18,974 18,584
Accruals 51,482 27,671
VAT and WHT payable 21,060 19,226
Royalty and levies 7,554 5,510
Employee benefits 280 17
Financial liability 2,081 1,350
Other payables 15,580 7,789
Trade and other payables 117,011 80,147
Other payables - non-current
Employee benefits 1,844 1,671
Other payables 1,000 -
2,844 1,671
119,855 81,818
The Directors consider that the carrying amount of trade and other payables
approximates to their fair value.
15. Borrowings
30 June 31 December 2024
2025
US$'000 US$'000
Unaudited Audited
Revolving credit facility 2,361 2,327
Bank loans 457,406 426,873
Senior Secured Notes 59,579 88,428
Other loan notes 159,753 151,900
679,099 669,528
30 June 31 December 2024
2025
US$'000 US$'000
Unaudited Audited
Current borrowings 272,371 299,299
Non-current borrowings 406,728 370,229
679,099 669,528
16. Contract liabilities
Contract liabilities represent the value of gas supply commitment to the
Group's customers for gas not taken but invoiced under the terms of the
contracts. The amount has been analysed between current and non-current, based
on the customers' expected future usage gas delivery profile. This expected
usage is updated periodically with the customers.
30 June 31 December 2024
2025
US$'000 US$'000
Unaudited Audited
Amount due for delivery within 12 months 16,241 18,664
Amount due for delivery after 12 months 389,503 382,640
405,744 401,304
30 June 31 December 2024
2025
US$'000 US$'000
Unaudited Audited
As at 1 January 401,304 364,144
Additional contract liabilities 10,377 46,605
Contract liabilities utilised (9,262) (14,735)
Unwinding of discount on contract liabilities 3,325 5,290
As at end of period 405,744 401,304
The unwinding of the discount on contract liabilities relates to the fair
value adjustments made under IFRS 3: Business Combinations following the
acquisition of the Nigerian assets and entities in 2019. The fair value
adjustment was calculated as the discounted, expected cost of the future
deliveries of gas volumes under the terms of customer take-or-pay contracts.
This discounted amount unwinds relative to an apportioned amount of the
contract liabilities volumes at the date of acquisition that have subsequently
been utilised.
17. Cash flow reconciliations
The changes in the Group's liabilities arising from financing activities can be classified as follows:
Borrowings Interest payable Lease liabilities Total
US$'000 US$'000 US$'000 US$'000
At 1 January 2025 (audited) 669,528 27,248 3,990 700,766
Cash flows
Proceeds 65,193 - - 65,193
Repayment (41,705) (54,224) (265) (96,194)
Realised FX - (2) - (2)
23,488 (54,226) (265) (31,003)
Non-cash adjustments
Payment in kind adjustment/accretion of interest 8,907 53,645 400 62,952
Net debt fees (2,447) - - (2,447)
Settlement (20,845) (454) - (21,299)
Re-estimation of lease liability - - 56 56
Foreign translation 466 178 136 780
Balance at 30 June 2025 (unaudited) 679,097 26,391 4,317 709,805
Borrowings Interest payable Lease liabilities Total
US$'000 US$'000 US$'000 US$'000
At 1 January 2024 (audited) 580,668 136,091 4,796 721,555
Cash flows
Proceeds 39,018 - - 39,018
Repayment (47,236) (56,644) (467) (104,347)
(8,218) (56,644) (467) (65,329)
Non-cash adjustments
Payment in kind adjustment/accretion of interest 9,563 21,578 61 31,202
Net debt fees (760) - - (760)
Re-estimation of lease liability - - (773) (773)
Foreign translation (5,210) (99) 36 (5,273)
Balance at 30 June 2024 (unaudited) 576,043 100,926 3,653 680,622
18. Capital commitments
At 30 June 2025, capital commitments amounted to US$9.5 million (30 June 2024:
US$0.5 million).
19. Business combination
On 19 March 2024, the Company announced that a wholly subsidiary had signed
Share Purchase Agreements to acquire SIPEC, the Group's joint venture partner
in the Stubb Creek Field. On 10 March 2025 the SIPEC Acquisition completed and
the entity was renamed as Savannah Energy Stubb Creek Limited ("SESCL"). The
entity owns a 49% non-operated interest and completion of the SIPEC
Acquisition now gives the Group a combined effective ownership of 100% in the
Stubb Creek Field. The Group is proceeding with its plans to increase oil
production.
The SIPEC Acquisition has been accounted for using the acquisition method and
the Group has applied the requirements for a business combination achieved in
stages by remeasuring its previously held interest in the joint operation
through Universal Energy Resources Limited ("UERL"). The interim consolidated
financial statements include the results of SESCL from the acquisition date
and the six-month results for UERL.
Set out below are the provisional fair values of the separable assets and
liabilities of the combined acquired entities (SESCL and UERL) together with
the fair value of the purchase consideration*.
10 March
2025
US$'000
Property, plant and equipment 190,000
Deferred tax assets 60,700
Inventories 7,557
Trade receivables and other current assets 10,889
Cash and cash equivalents 19,892
Total assets 289,038
Trade and other payables (27,569)
Deferred tax liability (24,900)
Provisions (4,775)
Total liabilities (57,244)
Total identifiable net assets at fair value 231,794
Bargain purchase arising on acquisition (127,422)
Total fair value of consideration transferred 104,372
Consideration satisfied by:
10 March
2025
US$'000
Gross cash paid, includes an amount for an assigned inter-company receivable 35,072
Deferred consideration 1,800
FV of previously held interest 67,500
Total fair value of consideration transferred 104,372
* As at the date of the approval of these financial statements the purchase
price allocation process and the determination of the fair values of the
assets and liabilities of the acquired entity were yet to conclude. Net assets
may therefore be subsequently adjusted, with a corresponding adjustment to
gain on bargain purchase. This exercise will be completed prior to 10 March
2026 (one year after the completion of the SIPEC Acquisition).
The Group recognised a gain on the previously held interest from remeasurement
in UERL to its fair value on the acquisition date.
10 March
2025
US$'000
FV of previously held interest 67,500
Net book value of UERL (44,236)
Gain on previously held interest 23,264
The acquisition date fair value of the trade receivables amounts to US$1.2
million. The gross amount due under the contract is US$2.2 million of which
US$0.9 million is expected to be uncollectible.
Transaction costs related to the SIPEC Acquisition of US$11.0 million have
been expensed and are reported within Transaction and other related expenses
in the Condensed consolidated statement of comprehensive income, and are
reflected in Cash flows from operating activities in the Condensed
consolidated statements of cash flows.
20. Contingent liabilities
As explained the 2024 Annual Report, the impact of the Nationalisation of the
Chad Assets has resulted in the Group not being able to determine liabilities
within its subsidiary, SCI, as to both type and quantum. The Directors have
sought legal advice which has confirmed that the scope of Law No. 003/PT/2023
promulgated by the President of Chad on 31 March 2023 (Nationalisation Law) is
not specific in relation to SCI's liabilities in Chad. The consequences of
the Nationalisation Law for SCI will be established by an arbitration which
SCI commenced during 2024 against the Republic of Chad and remains going as at
the date of this report. Based upon the legal advice received and the Group's
inability to sufficiently identify and quantify, through any reasonable means,
the liabilities associated with SCI or the Chad Assets, the Directors believe
that these should be considered as contingent liabilities in line with the
requirements of IAS 37: Provisions, Contingent Liabilities and Contingent
Assets.
As reported in the Group's 2024 Annual Report there are conditions remaining
to the completion of the sale of the 10% interest in COTCo to Société
Nationale Des Hydrocarbures (SNH) and if the sale is completed it could result
in a tax liability. Given the uncertainty surrounding the completion, the
impact of the above arbitrations and the shareholder dispute it is not
possible to properly assess if any tax liability will arise.
21. Events after the reporting date
On 19 September 2025, the Company announced that it is expected to sign a
share and purchase agreement to acquire a 50.1% interest in Klinchenberg BV, a
joint venture company which has a number of indirect interests in a portfolio
of hydropower plants in Uganda, Malawi, Burundi, Democratic Republic of the
Congo and Rwanda. The consideration for this transaction is expected to be up
to US$65.4 million and expected to close during 2026.
Footnotes
(1.) On a pro forma basis as at end 2024.
(2.) Based on the March 2025 Competent Persons Report prepared by McDaniel
& Associates Consultants Ltd.
(3.) Note that gas production levels are largely driven by customer nomination
levels, while cash collections are largely driven by contractual maintenance
adjusted take-or-pay provisions of 117 MMscfpd in aggregate.
(4.) Total Revenues are defined as the total amount of invoiced sales during
the period. This number is seen by management as more accurately reflecting
the underlying cash generation capacity of the business as opposed to Revenue
recognised in the Condensed Consolidated Statement of Comprehensive Income.
( )
(5.) Adjusted EBITDA is calculated as profit or loss before finance costs,
investment revenue, foreign exchange gains or losses, expected credit loss and
other related adjustments, fair value adjustments, gain on acquisition, share
based payments, taxes, transaction and other related expenses, depreciation,
depletion and amortisation and adjusted to include deferred revenue and other
invoiced amounts. Management believes that the alternative performance measure
of Adjusted EBITDA more accurately reflects the cash-generating capacity of
the business.
(6.) Leverage is defined as net debt/Adjusted EBITDA(5), with Adjusted
EBITDA(5) being prepared on a rolling 12-month basis and incorporating a
pro-forma 12-month EBITDA in respect of SIPEC.
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