TIDMCEG
RNS Number : 3059E
Challenger Energy Group PLC
29 June 2023
29 June 2023
Challenger Energy Group PLC
("Challenger Energy" or the "Company")
ANNUAL REPORT AND FINANCIAL STATEMENTS FOR THE YEARED 31
DECEMBER 2022
Challenger Energy (AIM: CEG), the Caribbean and Atlantic-margin
focused oil and gas company, with oil production, appraisal,
development and exploration assets across the region, announces its
Annual Report and Financial Statements for the year ended 31
December 2022.
The 2022 Annual Report and Financial Statements will be posted
to shareholders by 30 June 2023. The Company's AGM will be held on
15 August 2023 at 11:00 GMT at The Engine House, Alexandra Road,
Castletown, Isle of Man IM9 1TG. Notice of the AGM will also be
posted to shareholders in due course.
The 2022 Annual Report and Financial Statements are set out in
full below and are also available on the Company's website
https://www.cegplc.com/ .
For further information, please contact:
Challenger Energy Group PLC Tel: +44 (0) 1624 647
Eytan Uliel, Chief Executive Officer 882
WH Ireland - Nomad and Joint Broker Tel: +44 (0) 20 7220
Antonio Bossi / Darshan Patel / Enzo 1666
Aliaj
Zeus - Joint Broker Tel: +44 (0) 20 3829
Simon Johnson 5000
Gneiss Energy Limited - Financial Tel: +44 (0) 20 3983
Adviser 9263
Jon Fitzpatrick / Paul Weidman / Doug
Rycroft
CAMARCO Tel: +44 (0) 20 3757
Billy Clegg / Hugo Liddy / Sam Morris 4980
Notes to Editors
Challenger Energy is a Caribbean and Americas focused oil and
gas company, with a range of oil production, development,
appraisal, and exploration assets in the region. The Company's
primary assets are located in Uruguay, where the Company holds high
impact offshore exploration licences, and in Trinidad and Tobago,
where the Company has a number of producing fields and
earlier-stage exploration / appraisal projects.
Challenger Energy is quoted on the AIM market of the London
Stock Exchange.
https://www.cegplc.com
S
Chairman's Letter to the Shareholders
Dear shareholders,
I am pleased to report to you as chairman of your Company.
In my last report I discussed the transition that the company
was undertaking on several fronts: moving on from legacy issues,
refocusing the Trinidad business, and pivoting longer term
exploration towards Uruguay. Over the last year, we have delivered
on each of these.
In relation to legacy issues, nal settlements of historic
liabilities were agreed at the start of 2022, which, in tandem with
a capital raising in March of 2022, allowed the company to clear
its balance sheet and refocus its resources. The Company remains in
discussions with the Bahamian government regarding the status of
its licences there, and our rights to bene t from the substantial
work undertaken and cost incurred. However, this project no longer
forms part of our immediate business focus.
In Trinidad, we made substantial changes to our business,
resetting the basic operating philosophy away from "maximising
production" to "efficiency and pro t". We strategically prioritised
our main assets in south-east Trinidad, streamlined operations
around those main assets, and began a process of divesting and
monetising non-core assets. These measures have resulted in a more
efficient and sustainable Trinidadian business.
In Uruguay, the Company has bene tted from renewed global focus
on energy security and exploration, following the Ukrainian
invasion and loss of access to Russian production and reserves in
Western energy markets. These developments, when coupled with
recent exploration success in Namibia - the "other side" of the
Atlantic conjugate margin on which our Uruguay assets sit - have
seen Uruguay become a new hot zone in global exploration, as
evidenced by the heavy presence of global majors in the country's
recent licencing rounds.
Our AREA OFF-1 acreage has thus become more important for our
Company. As Eytan describes more fully in his CEO report, in the
past year we have rapidly advanced our AREA OFF-1 technical work
program, to enhance the value we hope to realise when we farm-out
the asset. The story has been further enhanced by the award of the
OFF-3 licence to the Company, which grows our business in Uruguay
even further.
In my last report, I noted my belief that oil will remain an
important part of the energy mix for many years to come. The events
of the last year, and the impact this has had on energy prices and
the global energy industry, make these observations as relevant as
ever. As the Western world searches for new and more secure sources
of energy, we are well positioned to bene t.
I would like to thank all our staff for their efforts over the
course of the past year, the Board for their support in managing
and guiding this process, and nally our shareholders for their
continued support.
Iain McKendrick Chairman
28 June 2023
Chief Executive Officer's Report to the
Shareholders
Dear fellow Shareholders,
I am pleased to provide the following commentary on our business
and operations during the period under review.
The 2022 nancial year (that is, from January to December 2022)
was a time of considerable change and progress for our Company. In
early 2022 we completed a comprehensive nancial and operational
restructuring, along with a recapitalisation. Then, with the bene t
of legacy issues behind us, we were able to devote full attention
to core operations: our production business in Trinidad and Tobago
and developing a deeper insight as to the value of our exploration
acreage in Uruguay. And, as the fundamentals and realities of our
business and our assets shifted, we reshaped our strategies and
priorities to match. The result is that both pillars of our
business advanced such that we are now, in 2023, seeing results
from the solid foundations laid in 2022.
Exploration Acreage in Uruguay
One of the key drivers of value for any junior E&P company
is the ability to adapt rapidly to changes in circumstances.
Nowhere was this more evident than in relation to Challenger
Energy's Uruguayan business during 2022.
We were awarded the AREA OFF-1 licence block offshore Uruguay in
2020, but as at the start of 2022, Uruguay was not yet on the
global industry's radar, and Challenger Energy was Uruguay's sole
licence holder. Starting in early 2022, however, everything changed
quite dramatically, and very quickly.
The catalyst for this was when two energy majors (TotalEnergies
and Shell) each announced in February 2022 that they had made
massive discoveries from independent wells drilled offshore
Namibia. Those successful Namibian wells served to greatly de-risk
the presence of a high-quality, oil-prone source rock and charge,
not just in Namibia but on the other side of the South Atlantic
conjugate margin - in particular Uruguay, which represents a
geological "mirror" of the area where the new Namibian discoveries
were made. And whilst in February 2022 the profound signi cance of
the Namibian discoveries for Uruguay may not have been immediately
obvious to casual market observers, the industry knew exactly what
it meant.
As a result, almost overnight we witnessed Uruguay become a
global exploration "hotspot." Thus, in the rst Uruguayan bidding
round after the Namibian discoveries (May 2022), three licences
were bid on and awarded to majors Shell and APA (formerly Apache).
Then, in November 2022, a further two licences were bid on and
awarded, one to a consortium of Shell and APA, and the other to
YPF, the Argentinian national oil company. Tellingly, the new
entrants offered signi cant work program to secure their licences
(as compared to the very modest work program we had bid to secure
AREA OFF-1), and a number of other energy majors also registered to
bid in the two Uruguayan open rounds held in 2022, but were
unsuccessful.
This step change in industry interest validated our rst-mover,
low-cost entry into Uruguay, and con rmed that we had secured
highly prospective frontier acreage with potential for considerable
near-term value uplift. And once we saw industry interest escalate,
we rapidly shifted our strategy to match, prioritising our Uruguay
business around three clear workstreams:
-- First, we elected to accelerate our work program on the AREA
OFF-1 block, with a view to generating proprietary intellectual
property and upgrading technical knowledge of the area in light of
the new conjugate margin discoveries, and in this way seek to
increase the value of the AREA OFF-1 asset. The program of work
undertaken included reprocessing of legacy 2D seismic data,
advanced attribute variation with offset (AVO) analysis, seabed
geochemical and satellite seep studies, full reinterpretation and
remapping of all data, and an initial volumetric assessment. The
result of this work, announced in early 2023, was the identi cation
of three technically robust primary prospects on AREA OFF-1, that
in aggregate represent a prospect inventory of approximately 2
billion barrels (Pmean) and up to 5 billion barrels (P10) -
establishing that AREA OFF-1 is a world-class asset of scale
-- Second, we began preparing for a farm-out process. This is
because taking AREA OFF-1 forward to 3D seismic acquisition and
ultimately exploration well drilling, especially on an expedited
basis, will be a technically demanding and costly undertaking, for
which we ideally wish to have an industry and funding partner.
Consequently, a formal farm-out process was launched in Q2 2023.
The next step is to deliver a farm-out, which we are working
diligently on.
-- And third, we sought to expand our presence in Uruguay, given
our developing knowledge base and energy understanding, the
excellent working relationship established with ANCAP, and the
attractive conditions in that country for hydrocarbon industry
activity. The rst tangible result of this work came in June 2023,
when Challenger Energy was awarded the AREA OFF-3 block - the last
available offshore acreage in Uruguay - on attractive terms,
subject to licence signing. Once this licence has been signed, our
Company will be the 2nd largest acreage holder in Uruguay, with a
signi cant prospect inventory, and two high- quality assets in what
has fast become a global exploration focus area.
In summary, therefore, through the course of 2022 our early
entry into Uruguay was transformed from apparently being little
more than "option value" to being a near-term opportunity for
substantial value-creation. We are con dent that eventually the
equity market will pay attention and reward the value we are
creating.
Production Operations in Trinidad and Tobago
It was not only in relation to Uruguay that pragmatic adaptation
was required during 2022 - our business in Trinidad demanded a
similar strategic reassessment during 2022.
At the start of 2022 our Trinidad and Tobago business was
focused on a drive for material organic growth in production from
our existing elds. Our goal was to achieve production growth from
applying efficient mature oil eld management practices, eld
improvements, Enhanced Oil Recovery (EOR) initiatives, and targeted
production enhancement activities. Yet despite doing all this,
production growth proved elusive. The undeniable reality is that
our oil elds are mature, and having produced oil for many decades
they have depressurised reservoirs, where the rate at which the
remaining resource is produced cannot easily be increased. That
noted, no matter what we did the production from our existing elds
was remarkably constant and predictable. That is, the same eld
maturity that mitigates against organic production increase also
mitigates against unreliable production performance. And based on
this simple observation, we undertook a reassessment of our
Trinidad operations in mid-2022, which resulted in the following
revised business objectives:
-- One - prioritise those areas where Challenger Energy has a competitive advantage.
In practical terms, this meant dividing our Trinidad portfolio
into two parts: "core" - consisting of the Goudron and
Inniss-Trinity assets in south-east Trinidad, and "non-core" - our
assets in central and south-west Trinidad. The rationale for this
division was simple: (i) our two assets in south-east Trinidad
represent about 85% of our current production; (ii) almost all of
our operations, staff and equipment are devoted to these two assets
and we are one of the larger operators in that area of Trinidad;
and (iii) operating conditions in south-east Trinidad are peculiar
and difficult (remote locations, jungle, poor infrastructure,
etc.), so we have unique local operational knowledge and
capabilities that can be leveraged.
-- Two - for core business operations, focus on keeping
production constant, drive efficiencies, and match the operational
footprint and cost to the production we know can be achieved.
Once core assets had been prioritised, we were better able to
schedule equipment movements and workovers in support of those
assets alone, and we were able to reshape our staff base,
operations, and other costs to better " t" the needs of those speci
c assets. We also switched many of the smaller producing wells over
to continuous swabbing - an operational approach that meant we
would no longer be chasing increased production from those smaller
wells, but at the same time also meant we could run those wells at
a fraction of the cost of continually working the wells over. In
terms of outcomes, this new focus saw production through 2022
holding constant, total operating expenses and G&A reduced, and
positive net operating cash ow across 2022 (which represents a
substantial improvement on 2021, where the Trinidad business had
incurred a net operating cash de cit).
-- Three - exit or monetise non-core operations.
We made substantial progress in relation to this objective, and
in the later part of 2022 succeeded in selling (i) the non-
producing Cory Moruga asset, with the buyer committing to a
substantial future work program, including EOR and new well
drilling (completion of that sale remains pending regulatory
approval in Trinidad), and (ii) the South Erin asset, with that
sale fully completed in early 2023, resulting in not only an
up-front cash payment, but the assumption by the buyer of our
obligation to drill three new wells. In both cases, we have
retained future back-in rights, such that if the work undertaken by
the new owners (at their sole cost and risk) proves successful, we
retain the option to "re-acquire" part of the asset. We continue to
work on similar exit options for the remaining non-core assets we
hold.
-- Four - generate increased production from "new oil".
We continue to believe that the opportunity exists to create a
pro table and growing production business in Trinidad. But, as
described previously, the key learning for us in 2022 was that
growth in production will not come from our existing well stock.
Rather, the path to growing production in Trinidad will be via
accessing "new oil" - that is, either nding places within our
existing elds that have not been drained effectively and drilling
new wells, or by getting new licences. As such, we have been
working diligently in the background to identify suitable "new oil"
options, whether within our existing core operations, or in our
broader geographic area of focus.
The rst tangible expression of this work become evident only
recently, when in June 2023 we were nominated as the party invited
to negotiate for the Guayaguayare block, located onshore in
south-east Trinidad and thus strategically and operationally
synergistic with our existing core assets (our bid was submitted in
late 2022, following extensive due diligence and bid preparation
through 2022). Guayaguayare is one of the largest onshore blocks in
Trinidad, and amongst the largest remaining underexplored /
undrained contiguous onshore areas, offering excellent upside.
Additionally, the block contains over 60 historic wells, a few of
which are active, but most of which are currently shut-in /
suspended / abandoned, which can be cheaply reactivated and
serviced from existing operations, thus offering the possibility of
near-term production uplift.
In summary, insofar as our business in Trinidad is concerned,
2022 was a year where not everything worked out as we had initially
hoped, but we learned from experience, re ned our strategy
accordingly, and built from there. As a result, we are now seeing
positive outcomes - continuing improvements in nancial performance,
wins on the business development front, and in overall context,
progress toward our goal of building a pro table and growing
Trinidadian production business.
Corporate Restructuring & Recapitalisation
As I noted at the start of this report, at the beginning of 2022
we completed a comprehensive nancial and operational restructuring,
along with a recapitalisation. This process had begun in mid-2021,
and so I had opportunity to comment at length on it in the 2021
Annual Report. I will thus not repeat the details again here, other
than to note that the successful conclusion of this process
resulted in a signi cantly reduced overhead cost, streamlined
operations, a refreshed board and executive, and a cleaned up
balance sheet that put the Company into a position where it was
free of nancial debts and able to fund planned activities during
2022. Many people worked tirelessly in difficult circumstances to
achieve this outcome, and on behalf of all shareholders I wish to
express my gratitude.
Legacy Assets
Insofar as our "legacy" asset portfolio is concerned, through
2022 we continued to manage those with a view to retaining title in
good order, ensuring minimal cost, and seeking means of ultimately
monetising the assets. In relation to the Company's licences in The
Bahamas we maintained ongoing dialogue with the Government of The
Bahamas on two parallel options: (i) the renewal of the licences
into a third exploration period, given that we still see
considerable long-term exploration potential in those licences, or
(ii) a joint initiative seeking to monetise those assets via an
alternative approach based around carbon credits. Meanwhile in
Suriname there was no eld activity during 2022 in relation to the
WNZ block, but we were granted an initial 6-month extension of the
licence, so that we could undertake a further review of the
project, focussing on well design options and the long-term
commerciality of the eld. This work has recently been completed,
and we are now in discussion with the Surinamese regulator as to
the future direction for this asset. I hope to be able to advise of
progress in relation to both of these legacy assets in the
not-too-distant future.
ESG
Finally, I would like to make a few comments in relation to the
broad category of activities referred to nowadays generally as
Environment, Social and Governance, or ESG. The fact that these
comments come at the end of my report should not in any way be seen
as diminishing the importance of this area, because it is
absolutely central to everything we do. Not a day goes by at
Challenger Energy where we do not devote a portion of our time to
discussing, planning, and implementing a variety of programs and
actions in support of a simple goal: to make sure that achieving
our commercial objectives never comes at the expense of harm to
people or the environment.
I am pleased to report that in 2022, our exemplary record in
this all-important area was maintained. Across all our operations
there were no incidents of note - whether personal injury, property
damage or environmental, and all operations throughout 2022 took
place without the occurrence of any Lost Time Incidents. Throughout
the year we continued to invest in Company-wide training programs
and ESG awareness activities, we continued to maintain productive
and positive relationships with all relevant Governments and
regulatory bodies, and we continued to make targeted social and
welfare contributions in the communities where we operate.
Overall, shareholders should be pleased with the Company's ESG
performance and track record in 2022, and we will continue to do
our utmost to ensure this continues.
2023 Strategic Direction
Looking ahead, the 2023 focus for our business in Uruguay is
unambiguously on securing a farm-out partner for the AREA OFF-1
block, such that we can expedite future technical work program on
the block and in particular a 3D seismic acquisition - we see this
as the path to signi cant near-term value creation for
shareholders. In Trinidad the 2023 focus will be to continue the
work of the last two years: maintain current production, drive
improved nancial performance, dispose of remaining non-core assets,
and seek to strategically access "new oil" opportunities so as to
expand the production base.
I would like to take this opportunity to thank our staff, whose
hard work and dedication is at the heart of everything we do. And
collectively, all of us who work at Challenger Energy wish to
express our deep appreciation for the support we receive from our
Board, stakeholders, regulators, suppliers, contractors and
especially our shareholders. In 2023 and beyond, we will do
everything we can to reward your con dence in us.
Eytan Uliel
Chief Executive Officer
28 June 2023
Challenger Energy Overview
Challenger Energy is a Caribbean and Americas focused oil and
gas company, with a range of onshore and offshore oil and gas
assets in the region. The Company's primary focus is on its Uruguay
exploration acreage and its Trinidad production business.
Uruguay
Challenger Energy is the holder of two offshore exploration
licences in Uruguay - the AREA OFF-1 and AREA OFF-3 blocks.
Together the two blocks represent a total of approximately 28,000
km 2 - the second largest offshore acreage holding in Uruguay.
OFFSHORE LICENCE HOLDERS - URUGUAY (JUNE 2023)
Source: ANCAP
Uruguay is located in South America, bordering Brazil and
Argentina, and with a broad Atlantic Ocean coastline. The country
has a relatively high income per-capita in the region, and
represents an advantaged operating regime, frequently ranking rst
in Latin America in measures such as democracy, anti-corruption,
and ease of doing business.
Since 2022, and following on from successful exploration
drilling in the conjugate margin offshore southwest Africa, the
region has seen a signi cant increase in licencing and operational
activity, and has become an emerging industry "hot spot". All
blocks offshore Uruguay have been licenced in the last 24 months,
and with the exception of the two licences awarded to Challenger
Energy, all have been awarded to international oil and gas majors.
The collective work program of other Uruguay licence holders is
estimated to be in excess of $230 million over the next four years.
Licence holders in adjacent northern Argentina are also undertaking
or expected to be undertaking technical work over the coming two
years, including 3D seismic acquisition and deepwater drilling.
AREA OFF-1
The Group has a 100% working interest in and is the operator of,
the 14,557 km 2 AREA-OFF 1 block, offshore Uruguay.
AREA OFF-1 was awarded in June 2020, and formally signed on 25
May 2022. The licence has a 30-year tenure with the rst four- year
exploration period having commenced on 25 August 2022. The Group's
initial four-year exploration period work commitment (ending
September 2026) is to licence and reprocess 2,000 kms of legacy 2D
seismic, and undertake two G&G studies. Given the strong
emerging interest in Uruguay, and to facilitate a farm-out, this
work program has been expanded and accelerated, with the work
largely complete as at the date of this report, and with the full
program on schedule to be completed in Q3 2023.
As a result of this technical work program, three prospects have
been identi ed from a range of play types. Prospects are
seismically-derived, supported / further de-risked by AVO analysis,
and their robustness corroborated by geochemical seabed sampling
and satellite seep analysis. These are summarized as follows:
PROSPECT DEPOSITIONAL STRATIGRAPHIC AREAL EXTENT WATER DEPTH RESERVOIR ESTIMATED
ENVIRONMENT AGE DEPTH EUR
(mmboe)
P10/Pmean/P50/P90
========== =================== ================= =============== ============= ========= ==================
Onlap slope
turbidite
to shelf
margin wave Mid to Upper
delta AVO Creataceous
supported Albian to 360/210/106 3,925
TERU TERU - Class II Campanian km(2) 800m m 1,647/740/547/158
========== =================== ================= =============== ============= ========= ==================
Outer shelf
margin stacked
sands AVO
supported Upper Cretaceous 304/214/101 3,400
ANAPERO - Class III Campanian km(2) 750m m 1,627/670/445/88
========== =================== ================= =============== ============= ========= ==================
Lacustrine
alluvial
syn-rift
fan sealed
by regional Lower Cretaceous 248/85/14 4,500
LENTEJA uncomformity Neocomian km(2) 85m m 1,666/576/198/17
========== =================== ================= =============== ============= ========= ==================
The overall AREA OFF-1 prospect inventory of approximately 2
billion barrels recoverable resource (Pmean, unrisked), and
over
4.9 billion barrels in an upside case (P10, unrisked), is
summarized as follows:
ESTIMATED OIL-IN-PLACE, AREA OFF-1, URUGUAY (MAY 2023)
PROSPECT P10 Pmean P50 P90
========== ======= ===== ===== =====
TERU TERU 5116 2334 1777 527
========== ======= ===== ===== =====
ANAPERO 5267 2190 1493 304
========== ======= ===== ===== =====
LENTEJA 5730 1969 690 59
========== ======= ===== ===== =====
TOTAL 16113 6493 3960 890
========== ======= ===== ===== =====
ESTIMATED ULTIMATE RECOVERABLE (EUR), AREA OFF-1, URUGUAY (MAY
2023)
PROSPECT P10 Pmean P50 P90
========== ====== ====== ====== =====
TERU TERU 1647 740 547 158
========== ====== ====== ====== =====
ANAPERO 1627 670 445 88
========== ====== ====== ====== =====
LENTEJA 1666 576 198 17
========== ====== ====== ====== =====
TOTAL 4940 1986 1190 263
========== ====== ====== ====== =====
The Group's forward strategy for AREA OFF-1 is (i) to complete
the low-cost minimum work obligations by the end of 2023, (ii) to
introduce a partner by the end of 2023 - a formal adviser-led
farm-out process initiated, and (iii) proceed to a 3D acquisition
on the licence, expedited into the rst licence exploration period.
The Company considers that conjugate margin exploration success,
competitive recent licensing rounds in Uruguay, and technical
uplift from CEG's 2023 work will drive a successful farm-out
process.
AREA OFF-3
The Group was awarded the AREA OFF-3 licence, offshore Uruguay,
in June 2023. The award of the licence is pending formal signing of
the licence agreement (anticipated within 2023).
Once signed, the licence will provide for a 30-year tenure with
the rst four-year exploration period commencing on signing. The
Group's initial four-year exploration period work commitment will
be to licence and reprocess 1,000 kms of legacy 2D seismic, and
undertake two G&G studies. CEG will hold a 100% working
interest in and will be the operator of the 13,252 km 2 block.
There has been considerable prior seismic activity and interest
on and adjacent to the OFF-3 block, comprising 4,000 kms legacy 2D
(various vintages) and 7,000 kms legacy 3D (2012 proprietary
acquisition). The block was previously held by BP, but was
relinquished in 2016. There are no prior wells on the block.
Based on prior technical work, two material-sized prospects have
previously been identi ed and mapped on AREA OFF-3, as follows:
-- Amalia: resource estimate (EUR mmbbl, gross): P10/50/90
(ANCAP) 2,189 / 980 / 392 - the Amalia prospect straddles the
boundary with Shell's AREA OFF-2, with an estimated 25% of Amalia
contained within AREA OFF-3; and
-- Morpheus: resource Estimate (EUR TCF, gross): P10/50/90
(ANCAP) - 8.96 / 2.69 / 0.84 - the Morpheus prospect is entirely
contained with AREA OFF-3.
During the initial 4-year exploration period, CEG's technical
focus will be on the re-evaluation of the existing 2D and 3D
seismic data on the block, given the renewed interest in the types
of plays present in Uruguay occasioned by the recent conjugate
margin discoveries offshore south-west Africa. In particular, the
data and enhanced technical understanding provided from recent
activities in Namibia provides greater con dence that the regional
petroleum system charging Venus and Graff (offshore Namibia) is
likely to be present offshore Uruguay. As a result, traps that
exhibit effective sealing mechanisms, and which may previously have
been overlooked or not considered viable, are now potential
exploration targets.
Moreover, AREA OFF-3 has the advantage of having the majority of
the block covered by relatively recent 3D (2012 vintage) that could
be reassessed and subjected to advanced analysis techniques, both
in terms of reviewing existing known prospects / plays and
identifying potential new prospects / plays. In addition, with the
Amalia prospect straddling the border with AREA OFF-2, it
potentially facilitates a joint exploration assessment with Shell
(since May 2022 the licence AREA OFF-2 licence holder).
Trinidad and Tobago
The Republic of Trinidad and Tobago is a Caribbean nation
consisting of the two islands of Trinidad and Tobago, offshore from
Venezuela. The nation has a long history of oil and gas activity,
both onshore on the island of Trinidad, and offshore, with some of
the world's oldest hydrocarbon producing elds located in the
country.
The Group has four producing elds, all onshore Trinidad. Across
these elds there are a total of approximately 250 wells, of which
approximately 75 are in production at any given time. The Group
also has a large exploration licence position in the South-West
Peninsula of Trinidad (SWP).
The Company's strategy in Trinidad is to focus on its core
operations, being the Goudron and Inniss-Trinity elds in the
south-east of Trinidad, from which most of the Company's production
is derived and where almost all equipment / resources are
deployed.
Various options to expand activity in this core area are being
considered, including new licence applications, M&A, and joint
programs with neighbouring operators. In line with this strategy,
in late 2022 the Company had submitted a bid for the Guayaguayare
block under the Trinidadian 2022 Onshore Nearshore Competitive Bid
Round. Guayaguayare is a large block covering a 306km 2 area in the
south-east of Trinidad and the Company's Goudron eld lies within
the Guayaguayare block (see map further below). In June 2023 the
Company was nominated as the party with whom the Trinidadian
Ministry of Energy and Energy Industries ("MEEI") should negotiate
the award of Guayaguayare, a precursor step to formal award of the
licence.
In parallel, the Company is seeking to monetise non-core assets,
so as to maximise cash and offset risk and work program
commitments, but at the same time retain upside exposure. In line
with this approach on 20 December 2022 the Company announced the
conditional disposal of the Cory Moruga licence (presently pending
MEEI consent), and, subsequent to the year- end, on 14 February
2023 completed the disposal of the South Erin licence (in both
cases, with back-in rights retained). The disposal of these
non-core assets represented less than 10% of then current
production.
Trinidad Asset Map
Production assets
Goudron
The Group owns and operates 100% of the Goudron eld by way of an
enhanced production service contract ("EPSC") with Heritage
Petroleum Company Limited ("Heritage"), the Trinidadian state-owned
oil and gas company. The current term of the EPSC runs until 30
June 2030. Within the eld, regular well workover operations are
undertaken on the existing production well stock, including well
stimulation operations, reperforations, and repairs to shut-in
wells, as and when appropriate. The Group has identi ed certain
well recompletion opportunities (perforating potential oil-bearing
zones previously not produced) and is undertaking a comprehensive
well optimisation and swabbing programme with the objective of
achieving production stability, growth and longevity, as well as
reducing overall eld operating costs. The Group is awaiting
approvals for a planned water injection enhanced oil recovery pilot
project focused on repressuring reservoir units.
Inniss-Trinity
The Group owns and operates 100% of the Inniss-Trinity eld by
way of an incremental production service contract ("IPSC") with
Heritage. The IPSC has been extended to 30 June 2023 on an interim
basis to allow for ministerial consent required for execution of a
fresh EPSC effective 1 January 2022 and expiring on 30 September
2031. Within the eld, regular well workover operations are
undertaken on the existing production well stock, including well
stimulation operations, reperforations, and repairs to shut-in
wells, as and when appropriate. As with the Goudron eld, the Group
continues to undertake a comprehensive well optimisation and
swabbing programme with the objective of achieving production
stability, growth and longevity, and reduced eld operating
costs.
Exploration assets
Guayaguayare
The Group, via its wholly owned subsidiary, CEG Goudron Trinidad
Limited ("CGTL"), had submitted a bid for the Guayaguayare block
onshore Trinidad under the 2022 Onshore and Nearshore Competitive
Bid Round. On 12 June 2023, the Group was advised by MEEI that the
Government of Trinidad has authorised MEEI to enter into
negotiations with CGTL for the grant of an Exploration and
Production (Public Petroleum Licence) for the Guayaguayare block
(the "Licence"), following a successful bid for that Licence by
CGTL. Formal grant of the Licence presently remains subject to
negotiations and nalisation of Licence terms with MEEI.
The Guayaguayare block is located in South-East Trinidad. It is
one of the largest onshore exploration and production blocks in
Trinidad (approximately 306 km 2 ), and is strategically and
operationally synergistic with the Group's core Trinidadian
production business, in that the Licence wholly encloses the
Company's Goudron licence area, and is adjacent to the Company's
Inniss-Trinity licence area.
The Group considers the Guayaguayare block to be highly
prospective, being amongst the largest remaining underexplored /
undrained contiguous onshore areas in Trinidad. Additionally, the
block contains over 60 historic wells (1970s vintage and earlier),
most of which are currently shut-in/suspended/abandoned, and some
of which the Company believes can be reactivated and serviced from
its existing operations, offering the opportunity for near-term
production uplift at minimal incremental cost.
"Option" and non-core assets
Cory Moruga
The Group owns 83.8% of the Cory Moruga licence and is the
operator, alongside its partner Touchstone Exploration Inc. which
holds a 16.2% non-operated interest. The Cory Moruga eld is
presently not in production. The Cory Moruga licence includes the
Snowcap oil discovery, with oil having previously been produced on
test from the Snowcap-1 and Snowcap-2ST wells (but rapidly declined
when the wells were put on production).
On 20 December 2022, the Company announced entering into binding
heads of terms in relation to the sale of T-Rex Resources Trinidad
Limited ("T-Rex"), a subsidiary that holds the Group's interest in
the Cory Moruga licence, to Predator Oil & Gas Holdings Limited
("Predator") for a cash consideration of US$2 million (US$1 million
payable upfront and US$1 million in six months from completion) and
a further US$1 million contingent consideration payable once 100
barrels per day production is achieved from the Cory Moruga eld.
Further, the Company has the option to buy back 25% of Predator's
share in T-Rex (and thus representing a 20.95% interest in the
underlying Cory Moruga asset).
Subsequently, in March 2023, The Company and Predator completed
fully termed legal documentation and jointly submitted a written
request to MEEI to seek consent on the basis of a committed forward
work programme and restructuring certain licence terms including
the settlement of past dues and rebasing annual licence fees to an
appropriate level. Discussions with MEEI are ongoing and the
completion of sale of Cory Moruga presently remains subject to MEEI
consent.
South Erin
The Group owned and operated 100% of the South Erin eld by way
of a farm-out agreement with Heritage. The farm-out agreement had
been renewed until 31 December 2023 and is extendable up to 30
September 2031 subject to completion of a work programme comprising
drilling of 3 new wells by 31 December 2023. On 14 February 2023,
the Group announced the sale of Caribbean Rex Limited, a subsidiary
that held interest in the South Erin licence through interposed
subsidiaries, for a consideration of US$1.5 million comprising
US$1.2 million cash consideration (fully received by the Company)
and US$0.3 million in the form of assumption of third-party
liabilities. The Company has retained a back-in option, granting
the Company the right to repurchase a 49% non-operating interest in
the South Erin eld exercisable at the Company's election, at any
time in 18 months from the transaction date for a xed cash amount
of US$1 million, plus 49% of all amounts spent by the buyer on
South Erin eld activities and new well drilling.
SWP
The SWP contains the Bonasse and Icacos producing oil elds, in
which the Group holds a 100% operated interest via a number of
private leases covering the Bonasse, Cedros and Icacos licence
areas. Similar to other elds, regular well operations are
undertaken on the existing production well stock and repairs to
shut-in wells, as and when appropriate. The Saffron-1 and Saffron-2
wells were drilled in the Bonasse licence area during 2020 and
2021, respectively. Both wells primarily targeted the Lower Cruse
reservoir horizons and while production could not be sustained from
these Lower Cruse horizons, both wells yielded valuable data on the
commercial viability of production from the shallower Upper Cruse
and Middle Cruse horizons. Accordingly, the Group is presently
evaluating the potential for a shallow eld development plan. In
parallel, the Group is seeking to monetise SWP by way of either a
sale or joint venture / farm-in with a view to retaining upside
exposure as with the sale of the Cory Moruga and South Erin
licences.
Legacy Assets
The Bahamas
The Group is the 100% holder of four conjoined exploration
licences offshore The Bahamas. The Perseverance-1 exploration well
was drilled in the licence area in early 2021, and did not result
in a commercial discovery at the drill location. However, a number
of other structures and drill targets remain prospective across the
licence areas, and the technical ndings from Perseverance-1
indicate the potential of deeper Jurassic horizons. In March 2021,
the Group noti ed the Government of The Bahamas of its intent to
renew the licences into a third 3-year exploration period - this
renewal remains pending, and the Group is engaging with the
Government on the renewal process. At the same time, the Group is
engaging with the Government and various third-party consultants on
a joint initiative seeking to monetise the asset via an alternative
approach based around carbon credits.
Suriname
During 2022, the Group held a 100% interest in a Production
Sharing Contract ("PSC") with Staatsolie Maatschappij Suriname N.V,
the Suriname state-owned petroleum company ("Staatsolie"), for an
onshore appraisal / development project contained in the Weg naar
Zee Block ("WNZ"). During 2022 the Group was granted an initial
6-month extension of the licence, during which time the group
undertook a review of the project, focussing on well design options
and the long-term commerciality of the eld. This work has recently
been completed, and the Group is in discussion with the Surinamese
regulator as to the future direction for this asset.
People and Operations
The Group's registered office is in the Isle of Man. In
addition, the Group maintains three operational offices, in London
(United Kingdom), Montevideo (Uruguay) and San Fernando (Trinidad).
Across its operations the business has a total staff of
approximately 75 employees, the majority being operating staff
in Trinidad. In support of its active eld operations in Trinidad,
the Group owns and operates two workover rigs, one swabbing rig,
and assorted heavy eld equipment.
The Company's Board, management team and staff base have a broad
range of skills as well as deep technical and industry experience.
Company takes great pride in its exemplary HSE&S track record,
and constantly aims to be an employer and partner of choice, making
a valued contribution to the communities and nations in which it
operates.
Governance
Set out below are details of Challenger Energy's approach to
Environmental, Social and Corporate Governance ("ESG") ESG related
activities and areas.
ESG Philosophy and Management
At Challenger Energy, we believe that pursuit of our commercial
objectives should never be at the expense of harm to people,
community, or the environment.
We believe that we have a responsibility for, and owe a duty of
care to, the people who work for us, the contractors and suppliers
that work alongside us in our operations, and the broader
communities in which we live and work. We take all steps possible
to safeguard the health, wellbeing and personal safety of all
involved with us as we deliver our operational projects. Our
objective is for zero lost time injuries or incidents.
At all times Challenger Energy seeks to conduct its business
with integrity and high ethical standards, and foster a working
environment of respect for all employees. We wish to see the
personal and professional development of our people in the roles
that they perform for us. We recognise the importance of diversity
to our business, which may relate to gender, nationality, faith,
personal background and other factors. We value how diversity bene
ts our business and how the individual experiences of our people
contribute to a positive environment in the Group.
Challenger Energy operates in a number of international
locations, and we both depend on and impact the people and
institutions in those places. Our business does not exist in a
vacuum, and we are part of the societies we operate in. Our
commitment is to be a responsible business and good corporate
citizen, making a meaningful contribution to the places in which we
live and work.
We are very conscious of the natural environment that we operate
in, and we work hard to minimise our impact on that environment.
The Group is always committed to the responsible stewardship of the
environment and we seek to operate safely and responsibly. Our
objective is for zero environmental incidents and zero spills or
leaks.
Recognising ESG as a core business priority, the Group maintains
a structured Health, Safety, Environment & Security (HSES)
Management System. This comprises a documented set of policies,
procedures and practices, which were substantially revised and
updated in 2021, with Company-wide application, designed to promote
and foster excellence in all relevant areas of HSES.
Corporate Governance
Challenger Energy operates in the energy sector, which is
regulated by strict laws and rules imposed by host Governments and
international regulators, as well as being subject to intense
public scrutiny. Additionally, the Group's shares are traded on the
AIM Market of the London Stock Exchange, and the Group is thus
subject to various additional rules and regulations associated with
being a publicly traded entity.
Accordingly, the Board is committed to maintaining the highest
standards of corporate governance at all times.
QCA Code
Pursuant to applicable rules of the AIM Market of the London
Stock Exchange, the Group is required to apply a recognised
corporate governance code, and demonstrate how the Group complies
with such corporate governance code and where it departs from it.
Given that the Group is not subject to the requirements of the UK
Corporate Governance Code, the Directors of the Group have decided
to apply the QCA Corporate Governance Code (the "QCA Code") as the
standard against which the Group chooses to measure itself.
Further information on the Group's application of the QCA Code
is available on the Group website at www.cegplc.com.
The Board and its Committees
The Board of Directors
The Board meets regularly to discuss and consider all aspects of
the Group's activities. A Charter of the Board has been approved
and adopted which sets out the membership, roles and
responsibilities of the Board. The Board is primarily responsible
for formulating, reviewing and approving the Group's strategy,
budgets, major items of capital expenditure and acquisitions and
divestments. The Board currently consists of the Chairman (Iain
McKendrick), the Chief Executive Officer (Eytan Uliel), and two
Non-executive Directors (Stephen Bizzell and Simon Potter). Iain
McKendrick (Chairman) was independent on appointment to the Board.
All Directors have access to the Company Secretary and the Group's
professional advisers.
Iain McKendrick has over 30 years of industry experience,
holding Board positions across several listed companies. He was
previously with NEO Energy, was Chief Executive Officer of Ithaca
Energy, was Executive Chairman of Iona Energy, and spent several
years with Total, including acting as Commercial Manager of
Colombia. Iain is the Chairman of the Company's Remuneration and
Nomination Committee and a member of the Company's Audit
Committee.
Eytan Uliel assumed the position as Chief Executive Officer from
27 May 2021, having previously served as the Company's Commercial
Director since 2014. Eytan is a nance executive with signi cant oil
and gas industry experience. He has signi cant experience in
mergers and acquisitions, capital raisings, general corporate
advisory work, oil and gas industry-speci c experience in public
market takeovers and transactions, private treaty acquisitions and
farm-in / farm-out transactions. He has held executive roles in
various ASX and SGX listed companies. Prior to working with
Challenger Energy, from 2009 - 2014 Eytan was Chief Financial
Officer and Chief Commercial Officer of Dart Energy Limited, an ASX
listed company that had unconventional gas assets (coal bed methane
and shale gas) in Australia, Asia and Europe, and Chief Commercial
Officer of its predecessor company, Arrow International Ltd, a
Singapore based company that had unconventional gas asset primarily
in Asia and Australia. He holds a Bachelor of Arts (Political
Science) and Bachelor of Laws (LLB) degree from the University of
New South Wales, and was admitted as a solicitor in the Supreme
Court of New South Wales in 1997. Eytan is a member of the
Company's Remuneration Committee, Nomination Committee and the
Health, Safety, Environmental and Security Committee
Stephen Bizzell has over 25 years' corporate nance and public
company management experience in the resources sector in Australia
and Canada with various public companies. He is the Chairman of
boutique corporate advisory and funds management group Bizzell
Capital Partners Pty Ltd., a rm which over the last 15 years has
raised more than A$1.5 billion in equity capital for its associated
entities. He is also the Chairman of ASX listed MAAS Group Holdings
Ltd and Laneway Resources and a Non-executive Director of ASX
listed Armour Energy Ltd, Renascor Resources Limited and Chairman
of Strike Energy Ltd. He was an Executive Director of ASX listed
Arrow Energy Ltd from 1999 until its acquisition in 2010 by Shell
and PetroChina for A$3.5 billion. Stephen quali ed as a Chartered
Accountant and early in his career was employed in the Corporate
Finance division of Ernst & Young and the Corporate Tax
division of Coopers & Lybrand. He has had considerable
experience and success in the elds of corporate restructuring, debt
and equity nancing, and mergers and acquisitions. Stephen is also
the Chairman of Challenger Energy Audit Committee.
Simon Potter was previously the Chief Executive Officer of the
Company for nearly 10 years and oversaw the safe drilling of the
Perseverance-1 well in the Bahamas. Simon assumed the role of a
Non-Executive Director in May 2021. Simon quali ed as a geologist
with an M.Sc. in Management Science, has over 30 years oil and gas
industry and mining sector experience. From the Zambian Copperbelt
to a 20-year career with BP he has held executive roles in
companies managing oil and gas exploration, development and
production; gas processing, sales and transport; LNG manufacture,
marketing and contracting in Europe, Russia, America, Africa and
Australasia. On leaving BP, having helped create TNK-BP, he took up
the role of CEO at Hardman Resources where he oversaw growth of the
AIM and ASX listed Company into an oil producer and considerable
exploration success ahead of executing a corporate sale to Tullow
Oil. Simon is a member of the Company's Remuneration Committee,
Nomination Committee and the Health, Safety, Environmental and
Security Committee.
Records of the board meetings
There were 7 meetings of the board of the parent entity in the
period 1 January 2022 to 31 December 2022.
Audit Committee
The Audit Committee of the Board comprises Stephen Bizzell
(Chair) and Iain McKendrick with input as required from the Chief
Financial Officer. The Audit Committee is primarily responsible for
ensuring that the nancial performance of the Group is properly
reported on and monitored, for reviewing the scope and results of
the audit, its cost effectiveness and the independence and
objectivity of the auditor. The Audit Committee has oversight
responsibility for public reporting and the internal controls of
the Group. A Charter of the Audit Committee has been approved and
adopted which formally sets out the membership, roles and
responsibilities of the Audit Committee. All members of the Audit
Committee have access to the Company Secretary and the Group's
professional advisers, including direct access to the Group's
auditor. The Audit Committee meets on a regular basis, and in 2022
met on two occasions, with all members being present for all
meetings.
Remuneration & Nomination Committee
The Remuneration & Nomination Committee comprises Simon
Potter (Chair), Iain McKendrick and Eytan Uliel. The Remuneration
& Nomination Committee is responsible for making
recommendations to the Board of Directors regarding executive
remuneration packages, including bonus awards and share options,
and assisting the Board in ful lling its responsibilities in the
search for and evaluation of potential new Directors and ensuring
that the size, composition and performance of the Board is
appropriate for the scope of the Group's and Company's activities.
It is recognised that shareholders of the Group have the ultimate
responsibility for determining who should represent them on the
Board. The Remuneration & Nomination Committee meets on an
as-required basis, and in 2022 met on one occasion, with all
members being present for that meeting.
Health, Safety, Environmental and Security Committee
The Board has a Health, Safety, Environmental and Security
(HSES) Committee which currently comprises Iain McKendrick (Chair),
Simon Potter and Eytan Uliel. The Committee's purpose is to assist
the Directors in establishing ESG strategy and reviewing, reporting
and managing the Group's performance, to assess compliance with
applicable regulations, internal policies and goals and to
contribute to the Group's risk management processes. The HSES
Working Group reports to the HSES Committee, which meets on a
regular basis. In 2022 the HSES Committee met on four occasions,
with all members being present for all meetings.
Company Secretary
All Directors have access to the Company Secretary for advice
and services. The appointment and removal of the Company Secretary
is a decision for the Board as a whole. Directors also have access
to independent professional advice at the Company's expense and
receive appropriate training where necessary.
Internal Control
The Directors acknowledge their responsibility for the Group's
system of internal control and for reviewing its effectiveness. The
system of internal control is designed to manage the risk of
failure to achieve the Group's strategic objectives. It cannot
totally eliminate the risk of failure but will provide reasonable,
although not absolute, assurance against material misstatement or
loss.
Going Concern
These nancial statements have been prepared on a going concern
basis, which assumes that the Group will continue in operation for
the foreseeable future.
The Group had incurred an operating loss of $4.2 million for the
nancial year ended 31 December 2022 and the Group's current
liabilities exceeded current assets by approximately $2.0 million
as of 31 December 2022. At 31 December 2022, the Group had
approximately $2.5 million in unrestricted cash funding and at the
date of authorisation of these nancial statements, the Group had
approximately $1.3 million in unrestricted cash funding. In
addition, the Group had approximately $0.5m in restricted cash
holdings in support of minimum work obligations in Uruguay, for
which the work has been substantially completed as at the date of
this report. In addition, the Group has several high-probability
sources of cash in ows expected over the next 12 months to enable
the Group to continue as a going concern for the foreseeable
future. These include:
1. Contracted proceeds from sale of Cory Moruga licence in Trinidad.
In December 2022, the Group announced the sale of Cory Moruga
licence onshore Trinidad and Tobago for a consideration of up to
US$3 million of which US$1 million is payable upon completion, US$1
million in six months from completion and a further US$1 million
contingent upon Cory Moruga eld achieving 100 barrels of oil per
day production. Cory Moruga licence is presently a dormant licence
with previously discovered and tested oil resource. The sale is
fully documented and not subject to any conditions to completion
other than consent from the Trinidadian Ministry of Energy and
Energy Industries ("MEEI"), which remains outstanding. The Group,
in conjunction with the acquirer, have been in discussions with
MEEI and anticipates consent being obtained and completion of the
sale transaction within 3Q 2023. A successful completion would
result in the Group receiving US$2 million in cash consideration
within six months from completion.
2. Potential in ows from successful farm-out of the AREA OFF-1 licence in Uruguay.
The Group had been in discussions with various industry
participants in relation to potential farm-out / partnership
options for the AREA OFF-1 licence in Uruguay. In June 2023, a
formal adviser-led process was commenced with the objective of
securing an industry partner to farm-out the AREA OFF-1 licence by
the end of 2023. In the event of a successful farm-out, the Group
expects signi cant upfront cash consideration, consistent with
typical transactions of this nature in the international oil and
gas industry. The Group is con dent that a farm-out transaction can
be successfully achieved in this timeframe, because (i) multiple
high-quality energy majors are presently engaged in the farm-out
process, undertaking due diligence as at the date of this report;
(ii) the Group's technical work to-date has resulted in identi
cation and de nition of three prospects with an estimated
recoverable resource of approximately 2 billion barrels (Pmean) and
up to 5 billion barrels in an upside case (P10) establishing that
AREA OFF-1 is a high-quality asset of scale, material to any player
in the global industry, and (iii) the Directors consider successful
completion of the farm-out process to be highly probable in light
of the recent industry developments - namely signi cant offshore
discoveries in Namibia (Uruguay is considered to be geological
mirror of the offshore Namibia basins), and substantial industry
interest in offshore Uruguay acreage in the past 12 months,
evidenced by licencing activity in the recent Uruguayan licencing
rounds that has resulted in all available acreage now having been
awarded to industry majors (Shell, APA Corporation and YPF) along
with several other interested global oil majors not securing any
acreage.
3. Sale of other non-core assets
The Group is also in discussions in relation to the potential
sale of other non-core assets in its portfolio. A successful
completion of any transaction of this nature would result in the
Group receiving cash consideration, thus increasing its available
cash reserves.
In addition to the above, the Directors note that the Company is
a publicly listed company on a recognised stock exchange, thus
affording the Company the ability to raise capital equity, debt
and/or hybrid nancing alternatives as and when the need arises. The
Company has a robust track record in this regard, having raised in
excess of US$100 million in equity and alternative nancing in the
past ve years. Based on the Company's attractive asset portfolio
and history of capital raising, the Directors are of the view that
if required (i.e., in the event sources of cash in ows discussed
above do not materialise as and when expected) the Company will be
able to source fresh capital on short notice. As such, the
Directors have prepared the nancial statements on a going concern
basis and consider it to be reasonable.
Anti-bribery and corruption ("ABC")
Challenger Energy applies a zero-tolerance policy for bribery,
corruption or unethical conduct in our business. Our policies
require compliance across our businesses with applicable ABC laws,
in particular the UK Bribery Act 2010, and all applicable laws in
other jurisdictions in which we operate. We have a system of
documented ABC policies and procedures in place that provide a
consistent policy framework across the Group to ensure awareness of
potential threats among our employees and help to ensure
appropriate governance of ABC matters. In 2022, all employees
across the Group were required to attend mandatory ABC training,
with a focus on the areas of legislation most relevant to the
Group.
Anti-Money Laundering ("AML")
Challenger is conscious of the risks arising out of money
laundering and terrorist nancing. These criminal activities
threaten society, as well as the Group, its partners, shareholders,
and staff. The Group exercises the utmost vigilance wherever its
operations are taking place in order to ght these threats. This
vigilance extends to third party associates who are at any time
active in the Group. Annual AML training is compulsory for Group
staff, and during 2022, money laundering training courses were
taken by various employees and contractors.
Taxation
Depending on the jurisdiction of operation, the Group is subject
to a range of taxes, including corporate income tax, supplemental
petroleum taxes, royalties, other scal deductions, VAT and payroll
taxes, amongst others. We are a responsible operator and corporate
citizen and the Group is committed to adhering to all relevant tax
laws in all jurisdictions of operation: compliance with tax laws
and regulations is fundamental to our licence to operate, and is an
obligation that we take seriously.
Risk Management
Understanding our principal risks and ensuring that Challenger
Energy has the appropriate controls in place to manage those risks
is critical to our business operations. Managing business risks and
opportunities is a key consideration in determining and then
delivering against the Group's strategy. The Group's approach to
risk management is not intended to eliminate risk entirely, but
provides the means to identify, prioritise and manage risks and
opportunities. This, in turn, enables the Group to effectively
deliver on its strategic objectives in line with its appetite for
risk.
The Board's Responsibility for Risk Management
The board has overall responsibility for ensuring the Group's
risk management and internal control frameworks are appropriate and
are embedded at all levels throughout the organisation. Principal
risks are reviewed by the board and are speci cally discussed in
relation to setting the Group strategy, developing the business
plan to deliver that strategy and agreeing annual work programmes
and budgets. See "Principal Risks and Uncertainties" section below
and the mitigation steps taken to minimise these risks.
Principal risks and uncertainties
The principal risks facing the Group together with a description
of the potential impacts, mitigation measures and the appetite for
the risk are presented below. The analysis includes an assessment
of the potential likelihood of the risks occurring and their
potential impact. Identi ed risks are segregated between those that
we can in uence and those which are outside our control. Where we
can in uence risks, we have more control over outcomes. Where risks
are external to the business, we focus on how we control the
consequences of those risks materialising.
RISKS THAT WE CAN INFLUENCE
1. Health, safety and environment (HSE)
Oil and gas exploration, development and production activities
can be complex and are physical in nature. HSE risks cover many
areas including major accidents, personal health and safety,
compliance with regulations and potential environmental harm.
Potential impact: High Probability: Low
Risk Appetite
The Group has a very low appetite for risks associated with HSE
and strives to achieve a zero-incident rate.
Mitigation
The Group strives to ensure the safety of its employees,
contractors and visitors. We are very conscious of the natural
environment that we operate in and seek to minimise our
environmental impact and footprint.
2. Exploration, development and production
The ultimate success of the Group is based on its ability to
maintain and grow production from existing assets and to create
value through exploration activity across the existing portfolio
together with selective acquisition activity to grow the asset
portfolio.
Potential impact: High Probability: Moderate
Risk appetite
The Group's current production is derived from later-life
production assets that are in the latter portion of the production
decline curve. The development of later life assets can be complex
and technically challenging. This can expose the Group to higher
levels of risk, particularly in stimulating existing wells through
workover or enhanced oil recovery techniques which may, due to
their nature, not be successful or may compromise existing
production. Identifying locations for optimal locations new in ll
wells that do not interfere with existing production can be
challenging.
The Group has some tolerance for this risk and acknowledges the
need to have effective controls in place in this area.
Mitigation
The production team responsible for operating the Group's assets
is very experienced in the industry and in the management, workover
and enhancement of the Group's assets. In addition, the Group has
built a trusted network of service providers who are similarly
familiar with the assets and who support production enhancing
activity including targeted recompletions and other well
interventions to further extend the productive life of the Group's
well stock.
3. Reserves and resources
The estimation of oil and gas reserves and resources involves a
high level of subjective judgment based on available geological,
technical and economic information.
Potential impact: Medium Probability: Low
Risk appetite
The Group has a strong focus on subsurface analysis. We employ
industry technical specialists and quali ed reservoir engineers and
geologists who work closely with our operational teams who are
responsible for delivering asset performance.
The Group tolerates some risk related to the estimation of
reserves and resources.
Mitigation
Reserve and resource volumes are assessed periodically using the
Petroleum Resource Management System (PRMS) developed by the
Society of Petroleum Engineers. An external assessment of reserve
volumes may also be undertaken periodically by an independent
petroleum engineering rm. CEG has staff and consultants who are
quali ed reservoir engineer with signi cant international
experience.
4. Portfolio concentration
The Group's producing assets are concentrated in Trinidad and
are principally characterised as later-life assets. This
concentrates production risk in a single jurisdiction and in an
asset group with a particular age and production pro le
Potential impact: Medium Probability: High
Risk appetite
The principal location of the Group's producing assets and their
age pro le places emphasis on the Group's ability to successfully
maintain existing production in Trinidad. The Group has a moderate
appetite for this risk.
Mitigation
The Group is continuously seeking to selectively add new
development or production onshore Trinidad or elsewhere in the
Atlantic margin through new licence applications, M&A activity
or partnering arrangements with service providers.
Progressing exploration and eventual development of Uruguay, if
successful, will similarly mitigate this risk over time.
5. Financing
Oil and gas exploration, development and production activity are
capital intensive. The Group currently generates modest levels of
cash from operations and relies on investment capital to enhance
the asset base and, in turn, production and consequential cash
generation.
Potential impact: High Probability: Moderate
Risk appetite
The Group has a low appetite for nancing risk. The inability to
fund nancial commitments, including licence obligations, could
signi cantly delay the development of the Group's assets and
consequent value creation. Financial or operational commitments are
often a pre-condition to the grant of a licence. The Group's
inability to satisfy these could result in nancial penalty and/or
termination of licences.
Mitigation
The Group has a strong track record over many years of
successfully raising nance to fund its activities as and when
required.
6. Bribery and corruption
There is a risk that third parties or staff could be encouraged
to become involved in corrupt or questionable practices.
Transparency International's rankings (out of 180 countries) and
respective scores (out of a maximum of 100 points) on their 2022
Corruption Perceptions Index for the jurisdictions where the Group
has presence are as below:
Jurisdiction 2022 (2021) 2023 (2021) score
Rank
====================== =========== =================
Uruguay 14 (18) 74 (73)
====================== =========== =================
Trinidad and Tobago 77 (82) 42 (41)
====================== =========== =================
The Bahamas -30 (30) 64 (64)
====================== =========== =================
Suriname 85 (87) 40 (39)
====================== =========== =================
United Kingdom 18 (11) 73 (78)
====================== =========== =================
Potential impact: High Probability: Moderate
Risk appetite
The Group has a zero-tolerance policy regarding bribery and
corruption.
Mitigation
The Group, its board and management have an established
anti-bribery and corruption (ABC) policy that requires all new
hires to con rm that they have read and understood the contents and
personal requirements of the policy. The Group ensures that our
third- party contractors and advisers follow our procedures and
policies related to ABC. Annual ABC training and brie ngs are
carried out.
RISKS BEYOND OUR INFLUENCE
7. Commodity prices
The Group is exposed to commodity price risk in relation to
sales of crude oil.
Potential impact: High Probability: Moderate
Risk appetite
The Group has a moderate appetite for commodity price risk. A
material decline in oil prices could adversely affect the Group's
pro tability, cash ow, nancial position, and ability to invest.
Mitigation
All the Group's production in Trinidad is sold to Heritage under
the terms of the respective production licences and the Group is
fully exposed to adverse commodity price uctuation (and also
conversely bene ts from favourable commodity price movement).
The Group does not currently use hedging instruments to mitigate
oil price risk as the volumes are relatively small and signi cant
volatility observed in crude prices in the recent years coupled
with oil futures curve backwardation make it difficult to assess
effectiveness of a hedge. The Group monitors the oil and gas
benchmark prices, principally WTI and Brent Crude, and may consider
enter hedging arrangements if market conditions and nancial and
risk analysis suggest that price risk is lowered by doing so.
8. Demand/ limited sales routes
All the Group's current production is derived from its Trinidad
assets and sold to a single customer, Heritage Petroleum Company
Limited, the state-owned oil and gas company.
Potential impact: High Probability: Low
Risk appetite
Demand can be negatively affected by economic conditions in
Trinidad and globally. The Group accepts demand risk related to its
crude oil production.
Mitigation
All the Group's production is sold to Heritage as required under
the terms of the licence agreements with Heritage. There is no
history of Heritage refusing delivery of crude produced by the
Group. The Group accepts this potential risk.
9. Fiscal and political
The Group's operations are located in Trinidad and Tobago and
Uruguay, with legacy assets in The Bahamas and Suriname, and the
Group is therefore exposed to both in-country scal and political
risk.
Potential impact: High Probability: Moderate
Appetite
The Group accepts a modest amount of scal risk. The Group is
exposed to currency risk resulting from uctuations between
currencies in various jurisdictions of operation, and in particular
between the US Dollar (in which most expenses are denominated) and
the Pound Sterling (as a signi cant amount of the Group's cash
holdings are denominated in Pound Sterling). Currency hedging
instruments are not used.
Mitigation
The Group closely monitors scal and political situation in the
jurisdictions it operates in with a view to identifying and
minimising the downside risk presented by changes in scal and
political circumstances. While the Group has not hedged its
currency exposure in the past, the Group closely monitors currency
uctuations with a view to assessing potential downside risk
vis-à-vis foreign currency requirements (and the timing thereof) so
as to determine the efficacy of a potential hedge. The Group
monitors political risk and political developments of the countries
of its operations and considers the structure and operation of the
respective governments in each of the jurisdictions of its
operations to present low risk to the Group. Further, the Group
interacts with relevant Governments, Government Ministries and
Agencies, and the state-owned oil and gas companies in the
jurisdictions in which it operates. The Group has no exposure to
Russian oil production, and recently enacted sanctions have had no
impact on the Group's business or operations.
Directors' Report
The Company's Directors present their report and audited nancial
statements of the Company and the consolidated group consisting of
Challenger Energy Group PLC ("Challenger Energy" or "the Company")
and the entities it controlled (the "Group") at the end of, or
during, the nancial year ended 31 December 2022.
Directors
The following persons were Directors of the Company during the
nancial year under review:
Iain McKendrick (appointed 5 March 2022) Stephen Bizzell
Simon Potter Eytan Uliel
Timothy Eastmond (appointed 5 March 2022, resigned 15 July
2022)
William Schrader (resigned 5 March 2022)
James Smith (resigned 5 March 2022)
Principal Activity
The principal activity of the Group and the Company consists of
oil & gas production, development, appraisal and exploration in
Uruguay, Trinidad and Tobago, Suriname, and The Bahamas.
Results and dividends
The results of the Group for the year are set out on page 26 and
show a pro t for the year ended 31 December 2022 of $4,382,000
(2021: loss of $23,697,000). The total comprehensive loss for the
year of $1,360,000 (2021: loss of $23,845,000) has been transferred
to the retained de cit.
The Directors do not recommend payment of a dividend (2021:
nil).
Signi cant Shareholders
The following tables represent shareholdings of 3% or more noti
ed to the Company at 31 December 2022:
Top shareholders (by parent
company)
Shareholder 31-Dec-22 %
============================= ============= =====
Hargreaves Lansdown Asset
Management 935,028,940 9.72
============================= ============= =====
Bizzell Capital Partners 914,633,600 9.51
============================= ============= =====
Choice Investments (Dubbo)
Pty Ltd 837,000,000 8.7
============================= ============= =====
Jarvis Investment Management 562,454,613 5.85
============================= ============= =====
Mr Mark Carnegie 560,000,000 5.82
============================= ============= =====
Mr Eytan M Uliel 545,373,962 5.67
============================= ============= =====
Rookharp Capital Pty Ltd 528,000,000 5.49
============================= ============= =====
Merseyside Pension Fund 417,350,000 4.34
============================= ============= =====
GP (Jersey) Ltd 390,000,000 4.05
============================= ============= =====
RAB Capital 365,900,000 3.8
============================= ============= =====
Interactive Investor 318,545,525 3.31
============================= ============= =====
Maybank Kim Eng Securities 300,000,000 3.12
============================= ============= =====
TOTAL 6,674,286,640 69.38
============================= ============= =====
Directors' Shareholding and Options
The interests in the Company at balance sheet date of all
Directors who hold or held office on the Board of the Company at
the year-end and subsequent to year end are stated below.
Statement of Directors' Responsibilities in respect of the
nancial statements
The Directors are responsible for preparing the Annual Report
and the Financial Statements in accordance with applicable Isle of
Man law and regulation.
Company law requires the Directors to prepare nancial statements
for each nancial year. The Directors have elected to prepare the
Group and Company nancial statements in accordance with
International Financial Reporting Standards ("IFRSs"). The nancial
statements are required by law to give a true and fair view of the
state of affairs of the Group and the Company and of the pro t or
loss of the Group for that period.
In preparing the nancial statements, the Directors are required
to:
-- select suitable accounting policies and then apply them consistently;
-- state whether IFRSs have been followed, subject to any
material departures disclosed and explained in the nancial
statements;
-- make judgements and accounting estimates that are reasonable and prudent; and
-- prepare the nancial statements on the going concern basis
unless it is inappropriate to presume that the Group and the
Company will continue in business.
The Directors are responsible for keeping proper accounting
records that are sufficient to show and explain the Group and
Company's transactions and disclose with reasonable accuracy at any
time the nancial position of the Group and the Company and to
enable them to ensure that the nancial statements comply with the
Isle of Man Companies Acts 1931 to 2004. They are also responsible
for safeguarding the assets of the Group and the Company and hence
for taking reasonable steps for the prevention and detection of
fraud and other irregularities. The Directors are responsible for
the maintenance and integrity of the Company's website. Legislation
in the Isle of Man governing the preparation and dissemination of
nancial statements may differ from legislation in other
jurisdictions.
On behalf of the Board
Eytan Uliel Director
28 June 2023
Independent auditor's report to the members
of Challenger Energy Group PLC
Opinion
We have audited the nancial statements of Challenger Energy
Group PLC (the "Company") and its subsidiaries (the "Group"), which
comprise the Consolidated Statement of Comprehensive Income,
Consolidated and Company Statements of Financial Position,
Consolidated and Company Statements of Cash Flows and Statement of
Changes in Equity for the year ended 31 December 2022, and the
related notes to the nancial statements, including a summary of
signi cant accounting policies.
The nancial reporting framework that has been applied in the
preparation of the nancial statements is applicable law and
International Financial Reporting Standards (IFRS).
In our opinion, Challenger Energy Group PLC's consolidated and
company nancial statements:
-- give a true and fair view in accordance with IFRS of the
nancial position of the Group and Company as at 31 December 2022,
and of the Group's nancial performance and the Group and Company
cash ows for the year then ended; and
-- have been properly prepared in accordance with the
requirements of the Isle of Man Companies Acts of 1931 to 2004.
Basis for opinion
We conducted our audit in accordance with International
Standards on Auditing (UK) ('ISAs (UK)') and applicable law. Our
responsibilities under those standards are further described in the
'Responsibilities of the auditor for the audit of the nancial
statements' section of our report. We are independent of the Group
and Company in accordance with the ethical requirements that are
relevant to our audit of the nancial statements in the Isle of Man,
including the FRC's Ethical Standard and the ethical pronouncements
established by Chartered Accountants Ireland, applied as determined
to be appropriate in the circumstances for the entity. We have ful
lled our other ethical responsibilities in accordance with these
requirements. We believe that the audit evidence we have obtained
is sufficient and appropriate to provide a basis for our
opinion.
Conclusions relating to going concern
In auditing the nancial statements, we have concluded that the
directors' use of going concern basis of accounting in the
preparation of the nancial statements is appropriate. Our
evaluation of the validity of the directors' assessment of the
Group and Company's ability to continue to adopt the going concern
basis of accounting included:
-- verifying the mathematical accuracy of management's cash ow
forecast and agreeing the opening cash position;
-- assessing management's underlying cash ow projections for the
Group for the period to December 2024 and evaluating the
assumptions including production, prices, operating expenditure and
capital expenditure. In doing so we compared production forecasts
to historical trends and considered the price assumptions against
consensus market prices and historical prices. We compared forecast
costs with historical expenditure and to other external and
internal sources, including the impairment assessments, where
appropriate;
-- assessing and validating the impact of post year end cash in
ow sources and commitments, including contractual proceeds from
sale of Cory Moruga licence in Trinidad and Tobago and potential in
ows from farm-out of Area OFF-1 license in Uruguay;
-- assessing management's ability to take mitigating actions, if required; and
-- assessing the completeness and appropriateness of
management's going concern disclosures in the nancial
statements.
Based on the work we have performed, we have not identi ed any
material uncertainties relating to events or conditions that,
individually or collectively, may cast signi cant doubt on the
Group's and Company's ability to continue as a going concern for a
period of at least twelve months from the date when the nancial
statements are authorised for issue.
We have nothing material to add or draw attention to in relation
to the directors' statement in the nancial statements about whether
the directors considered it appropriate to adopt the going concern
basis of accounting in preparing the nancial statements.
Our responsibilities and the responsibilities of the directors
with respect to going concern are described in the relevant
sections of this report.
Other matter
The nancial statements of Challenger Energy Group PLC and its
subsidiaries for the year ended 31 December 2021, were audited by
PwC who expressed an unmodi ed opinion on those nancial statements
on 29 September 2022.
Key audit matters
Key audit matters are those matters that, in our professional
judgement, were of most signi cance in our audit of the nancial
statements of the current nancial period and include the most signi
cant assessed risks of material misstatement (whether or not due to
fraud) we identi ed, including those which had the greatest effect
on: the overall audit strategy, the allocation of resources in the
audit, and the directing of efforts of the engagement team. These
matters were addressed in the context of our audit of the nancial
statements as a whole, and in forming our opinion thereon, and
therefore we do not provide a separate opinion on these
matters.
Overall audit strategy
We designed our audit by determining materiality and assessing
the risks of material misstatement in the nancial statements. In
particular, we looked at where the directors made subjective
judgements, for example, in respect of signi cant accounting
estimates that involved making assumptions and considering future
events that are inherently uncertain. We also addressed the risk of
management override of internal controls, including evaluating
whether there was any evidence of potential bias that could result
in a risk of material misstatement due to fraud.
Based on our considerations as set out below, our areas of focus
included:
-- Going concern;
-- Valuation of the Group's intangible exploration and evaluation assets; and
-- Valuation of the Group's tangible oil and gas assets.
How we tailored the audit scope
Challenger Energy Group Plc is the holders of several oil &
gas exploration and production licences located in Uruguay,
Trinidad & Tobago, Suriname and The Bahamas.
Our Group audit was scoped by obtaining an understanding of the
Group and its environment, including the Group's system of internal
control and assessing the risks of material misstatement in the
nancial statements. We also addressed the risk of management
override of internal controls, including assessing whether there
was evidence of bias by the directors that may have represented a
risk of material misstatement.
We performed an audit of the complete nancial information of ve
components, audit of one or more classes of transactions of two
components and performed audit procedures on speci c balances for a
further four components. The remaining components of the Group were
considered non-signi cant and these components were subject to
analytical review procedures.
Components represent business units across the Group considered
for audit scoping purposes.
Materiality and audit approach
The scope of our audit is in uenced by our application of
materiality. We set certain quantitative thresholds for
materiality. These, together with qualitative considerations, such
as our understanding of the entity and its environment, the history
of misstatements, the complexity of the Group and the reliability
of the control environment, helped us to determine the scope of our
audit and the nature, timing and extent of our audit procedures and
to evaluate the effect of misstatements, both individually and on
the nancial statements as a whole.
Based on our professional judgement, we determined materiality
for the Group and Company at 0.75% of total assets at 31 December
2022. We have applied this benchmark because the main objective of
the Group is to utilise its existing oil and gas assets and
exploration and evaluation assets to provide investors with returns
on their investments.
We have set performance materiality for the Group and Company at
65% of materiality, having considered business risks and fraud
risks associated with the entity and its control environment. This
is to reduce to an appropriately low level the probability that the
aggregate of uncorrected and undetected misstatements in the
nancial statements exceeds materiality for the nancial statements
as a whole.
We agreed with the audit committee and directors that we would
report to them misstatements identi ed during our audit above 2.5%
of group materiality and 3% of Company materiality, as well as
misstatements below that amount that, in our view, warranted
reporting for qualitative reasons.
Signi cant matters identi ed
The risks of material misstatement that had the greatest effect
on our audit, including the allocation of our resources and effort,
are set out below as signi cant matters together with an
explanation of how we tailored our audit to address these speci c
areas in order to provide an opinion on the nancial statements as a
whole. This is not a complete list of all risks identi ed by our
audit.
Other information
Other information comprises information included in the annual
report, other than the nancial statements and our auditor's report
thereon. The directors are responsible for the other information.
Our opinion on the nancial statements does not cover the other
information and, except to the extent otherwise explicitly stated
in our report, we do not express any form of assurance conclusion
thereon.
In connection with our audit of the nancial statements, our
responsibility is to read the other information and, in doing so,
consider whether the other information is materially inconsistent
with the nancial statements or our knowledge obtained in the audit,
or otherwise appears to be materially misstated. If we identify
such material inconsistencies in the nancial statements, we are
required to determine whether there is a material misstatement in
the nancial statements or a material misstatement of the other
information. If, based on the work we have performed, we conclude
that there is a material misstatement of this other information, we
are required to report that fact.
We have nothing to report in this regard.
Responsibilities of management and those charged with governance
for the nancial statements
As explained more fully in the Statement of Directors'
Responsibilities, management is responsible for the preparation of
the
nancial statements which give a true and fair view in accordance
with IFRS, and for such internal control as directors determine
necessary to enable the preparation of nancial statements are free
from material misstatement, whether due to fraud or error.
In preparing the nancial statements, management is responsible
for assessing the Group and Company's ability to continue as a
going concern, disclosing, as applicable, matters related to going
concern and using the going concern basis of accounting unless
management either intends to liquidate the Group or Company or to
cease operations, or has no realistic alternative but to do so.
Those charged with governance are responsible for overseeing the
Group and Company's nancial reporting process.
Responsibilities of the auditor for the audit of the nancial
statements
The objectives of an auditor are to obtain reasonable assurance
about whether the nancial statements as a whole are free from
material misstatement, whether due to fraud or error, and to issue
an auditor's report that includes their opinion. Reasonable
assurance is a high level of assurance, but is not a guarantee that
an audit conducted in accordance with ISAs (UK) will always detect
a material misstatement when it exists. Misstatements can arise
from fraud or error and are considered material if, individually or
in the aggregate, they could reasonably be expected to in uence the
economic decisions of users taken on the basis of these nancial
statements.
A further description of an auditor's responsibilities for the
audit of the nancial statements is located on the Financial
Reporting Council's website at:
www.frc.org.uk/auditorsresponsibilities. This description forms
part of our auditor's report.
Explanation as to what extent the audit was considered capable
of detecting irregularities, including fraud
Irregularities, including fraud, are instances of non-compliance
with laws and regulations. We design procedures in line with our
responsibilities, outlined above, to detect material misstatements
in respect of irregularities, including fraud. Owing to the
inherent limitations of an audit, there is an unavoidable risk that
material misstatement in the nancial statements may not be
detected, even though the audit is properly planned and performed
in accordance with the ISAs (UK). The extent to which our
procedures are capable of detecting irregularities, including fraud
is detailed below.
Based on our understanding of the Group and industry, we identi
ed that the principal risks of non-compliance with laws and
regulations related to compliance with AIM Listing Rules, Data
Privacy law, Employment Law, Environmental Regulations, Health
& Safety, and we considered the extent to which non-compliance
might have a material effect on the nancial statements. We also
considered those laws and regulations that have a direct impact on
the preparation of the nancial statements such as the local law,
Isle of Man Companies Act 1931 to 2004 and local tax legislations.
The Audit engagement partner considered the experience and
expertise of the engagement team to ensure that the team had
appropriate competence and capabilities to identify or recognise
non-compliance with the laws and regulation. We evaluated
management's incentives and opportunities for fraudulent
manipulation of the nancial statements (including the risk of
override of controls), and determined that the principal risks were
related to posting inappropriate journal entries to manipulate
nancial performance and management bias through judgements and
assumptions in signi cant accounting estimates, in particular in
relation to signi cant one-off or unusual transactions. We apply
professional skepticism through the audit to consider potential
deliberate omission or concealment of signi cant transactions, or
incomplete/inaccurate disclosures in the nancial statements.
The group engagement team shared the risk assessment with the
component auditors so that they could include appropriate audit
procedures in response to such risks in their work.
In response to these principal risks, our audit procedures
included but were not limited to:
-- enquiries of management, board and audit committee on the
policies and procedures in place regarding compliance with laws and
regulations, including consideration of known or suspected
instances of non-compliance and whether they have knowledge of any
actual, suspected or alleged fraud;
-- inspection of the Group and Company's regulatory and legal
correspondence and review of minutes of board and audit committee
meetings during the year to corroborate inquiries made;
-- gaining an understanding of the entity's current activities,
the scope of authorisation and the effectiveness of its control
environment to mitigate risks related to fraud;
-- discussion amongst the engagement team in relation to the
identi ed laws and regulations and regarding the risk of fraud, and
remaining alert to any indications of non-compliance or
opportunities for fraudulent manipulation of nancial statements
throughout the audit;
-- identifying and testing journal entries to address the risk
of inappropriate journals and management override of controls;
-- designing audit procedures to incorporate unpredictability
around the nature, timing or extent of our testing;
-- challenging assumptions and judgements made by management in
their signi cant accounting estimates, including impairment
assessment of intangible exploration and evaluation assets,
tangible oil and gas assets, investment in subsidiaries and amounts
owed by subsidiary undertakings;
-- review of the nancial statement disclosures to underlying
supporting documentation and inquiries of management; and
-- requesting information from component auditors on instances
of non-compliance with laws or regulations that could give rise to
a material misstatement of the group nancial statements.
The primary responsibility for the prevention and detection of
irregularities including fraud rests with those charged with
governance and management. As with any audit, there remains a risk
of non-detection or irregularities, as these may involve collusion,
forgery, intentional omissions, misrepresentations or override of
internal controls.
The purpose of our audit work and to whom we owe our
responsibilities
This report is made solely to the company's members, as a body,
in accordance with the terms of our engagement letter. Our audit
work has been undertaken so that we might state to the company's
members those matters we are required to state to them in an
auditor's report and for no other purpose. To the fullest extent
permitted by law, we do not accept or assume responsibility to
anyone other than the company and the company's members as a body,
for our audit work, for this report, or for the opinions we have
formed.
Cathal Kelly
(Senior Statutory Auditor)
For and on behalf of Grant Thornton
Chartered Accountants & Statutory Auditors 13-18 City
Quay
Dublin 2 Ireland
Notes to the nancial statements for the year ended 31 December
2022
1 Summary of signi cant accounting policies
1.01 General information and authorisation of nancial statements
Challenger Energy Group PLC (the "Company") and its subsidiaries
(together, the "Group") is the holders of several oil & gas
exploration and production licences located in Uruguay, Trinidad
& Tobago, Suriname and The Bahamas.
The Company is a limited liability company incorporated and
domiciled in the Isle of Man. The address of its registered office
is The Engine House, Alexandra Road, Castletown, Isle of Man IM9
1TG. The Company's review of operations and principal activities is
set out in the Directors' Report. See note 14 to the nancial
statements for details of the Company's principal subsidiaries.
The accounting reference date of the Company is 31 December.
1.02 Statement of compliance with IFRS
The Group's nancial statements have been prepared in accordance
with International Financial Reporting Standards (IFRS). The
Company's nancial statements have been prepared in accordance with
IFRS and as applied in accordance with the provisions of the Isle
of Man Companies Acts 1931 to 2004. As permitted by part 1 Section
3(5) of the Isle of Man Companies Act 1982, the Company has elected
not to present its own Statement of Comprehensive Income for the
year. The principal accounting policies adopted by the Group and
Company are set out below.
Some accounting pronouncements which have become effective from
1 January 2022 and have therefore been adopted do not have a signi
cant impact on the Group's nancial results or position.
New and revised standards and interpretations not applied
Certain new accounting standards and interpretations have been
published that are not mandatory for 31 December 2022 reporting
periods and have not been early adopted by the Group and the
Company. These standards are not expected to have a material impact
on the Group and the Company in the current or future reporting
periods and on foreseeable future transactions.
1.03 Basis of preparation
The nancial statements have been prepared on the historical cost
basis, except for the measurement of certain assets and nancial
instruments at fair value as described in the accounting policies
below.
The nancial statements have been prepared on a going concern
basis, refer to note 1.29 for more details.
The nancial statements are presented in United States Dollars
($) and all values are rounded to the nearest thousand dollars
($'000) unless otherwise stated.
1.04 Basis of consolidation
The nancial statements incorporate the results of the Company
and its subsidiaries (collectively, the "Group") using the
acquisition method. Control is achieved where the Company is
exposed to, or has rights to, variable returns from its involvement
with the entity and has the ability to affect those returns through
its power over the entity.
Inter-company transactions and balances between Group companies
are eliminated in full.
Where necessary, adjustments are made to the nancial statements
of subsidiaries to bring the accounting policies used in line with
those used by the Group.
1.05 Business combinations
On the acquisition of a subsidiary, the business combination is
accounted for using the acquisition method. In the consolidated
statement of nancial position, the acquiree's identi able assets
and liabilities are initially recognised at their fair values at
the acquisition date. The cost of an acquisition is measured as the
fair value of aggregated amount of the consideration transferred,
measured at the date of acquisition. The consideration paid is
allocated to the assets acquired and liabilities assumed on the
basis of fair values at the date of acquisition. Acquisition costs
not directly related to the issuance of shares in consideration are
expensed when incurred and included in administrative expenses.
Acquisition costs which are directly related to the issuance of
shares in consideration are deducted from share premium. The
results of acquired operations are included in the consolidated
statement of comprehensive income from the date on which control is
obtained.
If the cost of acquisition exceeds the fair value of the identi
able net assets attributable to the Group, the difference is
considered as purchased goodwill, which is not amortised but
annually reviewed for impairment. In the case that the identi able
net assets attributable to the Group exceed the cost of
acquisition, the difference is recognised in pro t or loss as a
gain on bargain purchase.
If the initial accounting for a business combination cannot be
completed by the end of the reporting period in which the
combination occurs, only provisional amounts are reported, which
can be adjusted during the measurement period of up to 12 months
after acquisition date.
After initial recognition, goodwill is measured at cost less any
accumulated impairment losses.
1.06 Intangible assets - exploration and evaluation assets
Exploration and evaluation expenditure incurred which relates to
more than one area of interest is allocated across the various
areas of interest to which it relates on a proportionate basis.
Exploration and evaluation expenditure incurred by or on behalf of
the Group is accumulated separately for each area of interest. The
area of interest adopted by the Group is de ned as a petroleum
title.
Expenditure in the area of interest comprises direct costs and
an appropriate portion of related overhead expenditure but does not
include general overheads or administrative expenditure not linked
to a particular area of interest.
As permitted under IFRS 6, exploration and evaluation
expenditure for each area of interest, other than that acquired
from the purchase of another entity, is carried forward as an asset
at cost provided that one of the following conditions is met:
-- the costs are expected to be recouped through successful
development and exploitation of the area of interest, or
alternatively by its sale; or
-- exploration and/or evaluation activities in the area of
interest have not, at the reporting date, reached a stage which
permits a reasonable assessment of the existence or otherwise of
economically recoverable reserves, and active and signi cant
operations in, or in relation to, the area of interest are
continuing.
Such costs are initially capitalised as intangible assets and
include payments to acquire the legal right to explore, together
with the directly related costs of technical services and studies,
seismic acquisition, exploratory drilling and testing. Exploration
and evaluation expenditure which fails to meet at least one of the
conditions outlined above is taken to the consolidated statement of
comprehensive income.
Expenditure is not capitalised in respect of any area of
interest unless the Group's right of tenure to that area of
interest is current.
Intangible exploration and evaluation assets in relation to each
area of interest are not amortised until the existence (or
otherwise) of commercial reserves in the area of interest has been
determined.
Exploration and evaluation assets are assessed for impairment
when facts and circumstances suggest that the carrying amount may
exceed its recoverable amount. In accordance with IFRS 6, the Group
reviews and tests for impairment on an ongoing basis and speci
cally if the following occurs:
a) the period for which the Group has a right to explore in the
speci c area has expired during the period or will expire in the
near future, and is not expected to be renewed;
b) substantive expenditure on further exploration for and
evaluation of hydrocarbon resources in the speci c area is neither
budgeted nor planned;
c) exploration for and evaluation of hydrocarbon resources in
the speci c area have not led to the discovery of commercially
viable quantities of mineral resources and the Group has decided to
discontinue such activities in the speci c area; and
d) sufficient data exists to indicate that although a
development in the speci c area is likely to proceed the carrying
amount of the exploration and evaluation asset is unlikely to be
recovered in full from successful development or by sale.
An impairment loss is recognised for the amount by which the
asset's carrying value exceeds its recoverable amount. The
recoverable amount is the higher of an asset's fair value less
costs to sell and value in use. For the purposes of assessing
impairment, assets are grouped at the lowest levels for which there
are separately identi able cash in ows which are largely
independent of the cash in ows from other assets or groups of
assets (cash-generating units).
Net proceeds from any disposal of an exploration asset are
initially credited against the previously capitalised costs. Any
surplus proceeds are credited to the consolidated statement of
comprehensive income.
1.07 Oil and gas development/producing assets and commercial reserves
If the eld is determined to be commercially viable, the
attributable costs are transferred to development/production assets
within tangible assets in single eld cost centres.
Subsequent expenditure is capitalised only where it either
enhances the economic bene ts of the development/producing asset or
replaces part of the existing development/producing asset.
Decreases in the carrying amount are charged to the consolidated
statement of comprehensive income.
Net proceeds from any disposal of development/producing assets
are credited against the previously capitalised cost. A gain or
loss on disposal of a development/producing asset is recognised in
the consolidated statement of comprehensive income to the extent
that the net proceeds exceed or are less than the appropriate
portion of the net capitalised costs of the asset.
Commercial reserves are proven and probable oil and gas
reserves, which are de ned as the estimated quantities of crude
oil, natural gas and natural gas liquids which geological,
geophysical and engineering data demonstrate with a speci ed degree
of certainty to be recoverable in future years from known
reservoirs and which are considered commercially producible. There
should be at least a 50% statistical probability that the actual
quantity of recoverable reserves will be more than the amount
estimated as a proven and probable reserves.
1.08 Depletion and amortisation
All expenditure carried within each eld is amortised from the
commencement of production on a unit of production basis, which is
the ratio of oil and gas production in the period to the estimated
quantities of commercial reserves at the end of the period plus the
production in the period, generally on a eld-by- eld basis. In
certain circumstances, elds within a single development area may be
combined for depletion purposes. Costs used in the unit of
production calculation comprise the net book value of capitalised
costs plus the estimated future eld development costs necessary to
bring the reserves into production. Changes in the estimates of
commercial reserves or future eld development costs are dealt with
prospectively.
1.09 Decommissioning
Where a material liability for the removal of production
facilities and site restoration at the end of the productive life
of a eld exists, a provision for decommissioning is recognised. The
amount recognised is the present value of estimated future
expenditure determined in accordance with local conditions and
requirements. The cost of the relevant tangible xed asset is
increased with an amount equivalent to the provision and
depreciated on a unit of production basis. Changes in estimates are
recognised prospectively, with corresponding adjustments to the
provision and the associated xed asset.
1.10 Property, plant and equipment
Property, plant and equipment is stated in the consolidated
statement of nancial position at cost less accumulated depreciation
and any recognised impairment loss. Depreciation on property, plant
and equipment other than exploration and production assets, is
provided at rates calculated to write off the cost less estimated
residual value of each asset on a straight-line basis over its
expected useful economic life. Depreciation rates applied for each
class of assets are detailed as follows:
-- Furniture, ttings and equipment 1 - 4 years
-- Motor vehicles 5 years
-- Leasehold improvements Over the life of the lease
The assets' residual values and useful lives are reviewed, and
adjusted if appropriate, at each balance sheet date.
An asset's carrying amount is written down immediately to its
recoverable amount if the asset's carrying amount is greater than
its estimated recoverable amount with any impairment charge being
taken to the consolidated statement of comprehensive income.
Gains and losses on disposals are determined by comparing
proceeds with carrying amount and are recognised in the
consolidated statement of comprehensive income.
1.11 Non-current assets and liabilities classi ed as held for
sale and discontinued operations
A discontinued operation is a component of the Group that either
has been disposed of, or is classi ed as held for sale.
A discontinued operation represents a separate major line of the
business. Pro t or loss from discontinued operations comprises the
post-tax pro t or loss of discontinued operations and the post-tax
gain or loss recognised on the measurement to fair value less costs
to sell or on the disposal group(s) constituting the discontinued
operation.
Non-current assets classi ed as held for sale are presented
separately and measured at the lower of their carrying amounts
immediately prior to their classi cation as held for sale and their
fair value less costs to sell. However, some held for sale assets
such as nancial assets or deferred tax assets, continue to be
measured in accordance with the Group's relevant accounting policy
for those assets. Once classi ed as held for sale, the assets are
not subject to depreciation or amortisation.
Any pro t or loss arising from the sale of a discontinued
operation or its remeasurement to fair value less costs to sell is
presented as part of a single line item, pro t or loss from
discontinued operations. See Note 15 for further details.
1.12 Inventories
Inventories are stated at the lower of cost and net realisable
value. Cost is determined by the weighted average cost formula,
where cost is determined from the weighted average of the cost at
the beginning of the period and the cost of purchases during the
period. Net realisable value represents the estimated selling price
less all estimated costs of completion and costs to be incurred in
marketing, selling and distribution.
1.13 Revenue recognition
Revenue from sales of oil and natural gas is recognised at the
transaction price to which the group expects to be entitled,
exclusive of indirect taxes and excise duties. Revenue is
recognised when performance obligations have been met, on delivery
of product or when control of the product is transferred to the
customer.
1.14 Foreign currencies
Transactions in foreign currencies are translated at the
exchange rate ruling at the date of each transaction. Foreign
currency monetary assets and liabilities are retranslated using the
exchange rates at the balance sheet date. Gains and losses arising
from changes in exchange rates after the date of the transaction
are recognised in the consolidated statement of comprehensive
income. This treatment of monetary items extends to the Group's
intercompany loans whereby gains and losses arising from changes in
the exchange rate after the date of transaction are also recognised
in the consolidated statement of comprehensive income. Intercompany
loans are provided to subsidiaries in the Group with the
expectation that these loans will be collected in the foreseeable
future. Non-monetary assets and liabilities that are measured in
terms of historical cost in a foreign currency are translated at
the exchange rate at the date of the original transaction.
In the nancial statements, the net assets of the Group are
translated into its presentation currency at the rate of exchange
at the balance sheet date. Income and expense items are translated
at the average rates for the period. The resulting exchange
differences are recognised in equity and included in the
translation reserve. The consolidated nancial statements and
company nancial statements are presented in United States Dollars
("$"), which is the functional currency of the Company.
Subsidiaries in the Group have a range of functional currencies
including United States Dollars, UK Pound Sterling, Trinidad and
Tobago Dollars and Euros.
1.15 Leases
The Group leases various offices, warehouses, equipment and
vehicles. Rental contracts are typically made for xed periods of 6
months to 3 years, but may have extension options.
Lease terms are negotiated on an individual basis and contain a
wide range of different terms and conditions. The lease agreements
do not impose any covenants other than the security interests in
the leased assets that are held by the lessor. Leased assets may
not be used as security for borrowing purposes.
Where applicable leases are recognised as a right-of-use asset
and a corresponding liability at the date at which the leased asset
is available for use by the Group.
Assets and liabilities arising from a lease are initially
measured on a present value basis. Lease liabilities include the
net present value of the following lease payments:
-- xed payments (including in-substance xed payments), less any
lease incentives receivable;
-- variable lease payment that are based on an index or a rate,
initially measured using the index or rate at the commencement
date;
-- amounts expected to be payable by the Group under residual value guarantees;
-- the exercise price of a purchase option if the Group is
reasonably certain to exercise that option; and
-- payments of penalties for terminating the lease, if the lease
term re ects the Group exercising that option.
Lease payments to be made under reasonably certain extension
options are also included in the measurement of the liability. The
lease payments are discounted using the interest rate implicit in
the lease. If that rate cannot be readily determined, which is
generally the case for leases in the Group, the lessee's
incremental borrowing rate is used, being the rate that the
individual lessee would have to pay to borrow the funds necessary
to obtain an asset of similar value to the right-of-use asset in a
similar economic environment with similar terms, security and
conditions.
To determine the incremental borrowing rate, the Group:
-- where possible, uses recent third-party nancing received by
the individual lessee as a starting point, adjusted to re ect
changes in nancing conditions since third party nancing was
received;
-- uses a build-up approach that starts with a risk-free
interest rate adjusted for credit risk for leases held by the
Group, which does not have recent third-party nancing; and
-- makes adjustments speci c to the lease, for example term,
country, currency and security.
The Group is exposed to potential future increases in variable
lease payments based on an index or rate, which are not included in
the lease liability until they take effect. When adjustments to
lease payments based on an index or rate take effect, the lease
liability is reassessed and adjusted against the right-of-use
asset.
Lease payments are allocated between principal and nance cost.
The nance cost is charged to pro t or loss over the lease period so
as to produce a constant periodic rate of interest on the remaining
balance of the liability for each period.
1.15 Leases continued
Right-of-use assets are measured at cost comprising the
following:
-- the amount of the initial measurement of lease liability;
-- any lease payments made at or before the commencement date
less any lease incentives received;
-- any initial direct costs; and
-- restoration costs.
Right-of-use assets are generally depreciated over the shorter
of the asset's useful life and the lease term on a straight-line
basis. If the Group is reasonably certain to exercise a purchase
option, the right-of-use asset is depreciated over the underlying
asset's useful life.
Payments associated with short-term leases of equipment and
vehicles and all leases of low-value assets are recognised on a
straight-line basis as an expense in pro t or loss. Short-term
leases are leases with a lease term of 12 months or less. Low-value
assets comprise IT equipment and small items of office
furniture.
1.16 Financial instruments Financial assets
The Group classi es its nancial assets as nancial assets held at
amortised cost. Management determines the classi cation of its
nancial assets at initial recognition.
The Group classi es its nancial assets as nancial assets held at
amortised cost only if both of the following criteria are met:
- the asset is held within a business model whose objective is
to collect the contractual cash ows; and
- the contractual terms give rise to cash ows that are solely
payments of principal and interest.
Measurement
Financial assets held at amortised cost are initially recognised
at fair value, and are subsequently stated at amortised cost using
the effective interest method. Financial assets at amortised cost
comprise 'cash and cash equivalents' at variable interest rates,
'restricted cash', 'escrowed and abandonment funds' and 'trade and
other receivables' excluding 'prepayments'.
Impairment of nancial assets
The Group assesses, on a forward-looking basis, the expected
credit losses associated with its nancial assets held at amortised
cost. The impairment methodology applied depends on whether there
has been a signi cant increase in credit risk.
The Group applies the expected credit loss model to nancial
assets at amortised cost. Given the nature of the Group's
receivables, expected credit losses are not material.
Financial liabilities
The Group classi es its nancial liabilities as other nancial
liabilities. Other nancial liabilities are recognised initially at
fair value and are subsequently measured at amortised cost using
the effective interest method. Other nancial liabilities consist of
'trade and other payables' and 'lease liabilities'. Trade and other
payables represent liabilities for goods and services provided to
the Group prior to the end of the nancial period which are unpaid.
The amounts are unsecured and are usually paid within
30 days of recognition.
Fair value measurement
Fair value is the price that would be received when selling an
asset or paid to transfer a liability in an orderly transaction
between market participants in its principal or most advantageous
market at the measurement date. All assets and liabilities for
which fair value is measured or disclosed in the nancial statements
are further categorised using the following three-level hierarchy
that re ects the signi cance of the lowest level of inputs used in
determining fair value.
- Level 1 - Quoted prices are available in active markets for
identical assets or liabilities as of the reporting date. Active
markets are those in which transactions occur in sufficient
frequency and volume to provide pricing information on an ongoing
basis.
- Level 2 - Pricing inputs are other than quoted prices in
active markets used in Level 1. Prices in Level 2 are either
directly or indirectly observable as of the reporting date. Level 2
valuations are based on inputs, included quoted forward price for
commodities, time value and volatility factors, which can be
substantially observed or corroborated in the marketplace.
- Level 3 - Valuations in this level are those with inputs that
are not based on observable market data.
At each reporting date, the Group determines whether transfers
have occurred between levels in the hierarchy by reassessing the
level of classi cation for each nancial asset and nancial liability
measured or disclosed at fair value in the nancial statements based
on the lowest level input that is signi cant to the fair value
measurement as a whole. Assessments of the signi cance of a
particular input to the fair value measurement require judgement
and may affect the placement within the fair value hierarchy.
1.17 Cash and cash equivalents
Cash and cash equivalents include cash on hand and deposits held
at call with nancial institutions with original maturities of three
months or less. For the purposes of the statement of cash ows,
restricted cash is not included within cash and cash
equivalents.
1.18 Share capital
Ordinary shares are classi ed as equity. Incremental costs
directly attributable to the issue of new shares or options are
deducted, net of tax, from the share premium. Net proceeds are
disclosed in the statement of changes in equity.
1.19 Finance costs
Borrowing costs are recognised as an expense when incurred.
1.20 Borrowings
Borrowings are initially recognised at fair value, net of any
applicable transaction costs incurred. Borrowings are subsequently
carried at amortised cost; any difference between the proceeds (net
of transaction costs) and the redemption value is recognised in the
income statement over the period of the borrowings using the
effective interest method (if applicable).
Interest on borrowings is accrued as applicable to that class of
borrowing.
Convertible loans
Loans with certain conversion rights are identi ed as compound
instruments with the liability and equity components separately
recognised. On initial recognition the fair value of the liability
component is calculated by discounting the contractual stream of
future cash ows using the prevailing market interest rate for
similar non-convertible debt. The difference between the fair value
of the liability component and the fair value of the whole
instrument is recorded as equity within the convertible debt option
reserve. Transaction costs are apportioned between the liability
and the equity components of the instrument based on the amounts
initially recognised. The liability component is subsequently
measured at amortised cost using the effective interest rate
method, in line with other nancial liabilities. The equity
component is not remeasured. On conversion of the instrument,
equity is issued and the liability component is derecognised. The
original equity component recognised at inception remains in
equity. No gain or loss is recognised on conversion.
1.21 Provisions
Provisions are recognised when the Group has a present
obligation (legal or constructive) as a result of a past event, it
is probable that an out ow of resources embodying economic bene ts
will be required to settle the obligation and a reliable estimate
can be made of the amount of the obligation.
When the Group expects some or all of a provision to be
reimbursed, for example under an insurance contract, the
reimbursement is recognised as a separate asset but only when the
reimbursement is virtually certain. The expense relating to any
provision is presented in the statement of comprehensive income net
of any reimbursement.
1.22 Dividends
Dividends are reported as a movement in equity in the period in
which they are approved by the shareholders.
1.23 Taxation
The tax expense represents the sum of the tax currently payable
and deferred tax.
Current tax, including overseas tax, is provided at amounts
expected to be paid (or recovered) using the tax rates and laws
that have been enacted or substantially enacted by the balance
sheet date.
Deferred tax is the tax expected to be payable or recoverable on
differences between the carrying amounts of assets and liabilities
in the nancial statements and the corresponding tax bases used in
the computation of taxable pro t, and is accounted for using the
balance sheet liability method. Deferred tax liabilities are
generally recognised for all taxable temporary differences and
deferred tax assets are recognised to the extent that it is
probable that taxable pro ts will be available against which
deductible temporary differences can be utilised. Such assets and
liabilities are not recognised if the temporary difference arises
from goodwill or from the initial recognition (other than in a
business combination) of other assets and liabilities in a
transaction that affects neither the tax pro t nor the accounting
pro t.
Deferred tax liabilities are recognised for taxable temporary
differences arising on investments in subsidiaries and associates,
except where the Group is able to control the reversal of the
temporary difference and it is probable that the temporary
difference will not reverse in the foreseeable future.
The carrying amount of deferred tax assets is reviewed at each
balance sheet date and adjusted to the extent that it is probable
that sufficient taxable pro ts will be available to allow all or
part of the asset to be recovered.
Deferred tax is calculated at the tax rates that are expected to
apply in the period when the liability is settled or the asset is
realised. Deferred tax is charged or credited in the consolidated
statement of comprehensive income, except when it relates to items
charged or credited directly to equity, in which case the deferred
tax is also dealt with in equity.
1.24 Impairment of assets
At each balance sheet date, the Group assesses whether there is
any indication that its tangible and intangible assets have become
impaired. Evaluation, pursuit and exploration assets are also
tested for impairment when reclassi ed to oil and natural gas
assets. If any such indication exists, the recoverable amount of
the asset is estimated in order to determine the extent of the
impairment, if any. If it is not possible to estimate the
recoverable amount of the individual asset, the recoverable amount
of the cash-generating unit to which the asset belongs is
determined.
The recoverable amount of an asset or a cash-generating unit is
the higher of its fair value less costs to sell and its value in
use. The value in use is the present value of the future cash ows
expected to be derived from an asset or cash-generating unit. This
present value is discounted using a pre-tax rate that re ects
current market assessments of the time value of money and of the
risks speci c to the asset, for which future cash ow estimates have
not been adjusted. If the recoverable amount of an asset is less
than its carrying amount, the carrying amount of the asset is
reduced to its recoverable amount. That reduction is recognised as
an impairment loss.
The Group's impairment policy is to recognise a loss relating to
assets carried at cost less any accumulated depreciation or
amortisation immediately in the consolidated statement of
comprehensive income.
Impairment of goodwill
Goodwill acquired in a business combination is, from the
acquisition date, allocated to each of the cash-generating units,
or groups of cash-generating units, that are expected to bene t
from the synergies of the combination. Goodwill is tested for
impairment at least annually, and whenever there is an indication
that the asset may be impaired. An impairment loss is recognised on
cash-generating units, if the recoverable amount of the unit is
less than the carrying amount of the unit. The impairment loss is
allocated to reduce the carrying amount of the assets of the unit
by rst reducing the carrying amount of any goodwill allocated to
the cash-generating unit, and then reducing the other assets of the
unit, pro rata on the basis of the carrying amount of each asset in
the unit.
If an impairment loss subsequently reverses, the carrying amount
of the asset is increased to the revised estimate of its
recoverable amount but limited to the carrying amount that would
have been determined had no impairment loss been recognised in
prior years. A reversal of an impairment loss is recognised in the
statement of comprehensive income. Impairment losses on goodwill
are not subsequently reversed.
1.25 Employee bene ts
Wages and salaries, annual leave and sick leave
Liabilities for wages and salaries, including non-monetary bene
ts, expected to be settled within 12 months of the reporting date
are recognised in other payables in respect of employees' services
up to the reporting date and are measured at the amounts expected
to be paid when the liabilities are settled.
Share-based payments
Where equity settled share-based instruments are awarded to
employees or Directors, the fair value of the instruments at the
date of grant is charged to the consolidated statement of
comprehensive income over the vesting period. Non-market vesting
conditions are taken into account by adjusting the number of equity
instruments expected to vest at each balance sheet date so that,
ultimately, the cumulative amount recognised over the vesting
period is based on the number of instruments that eventually vest.
Market vesting conditions are factored into the fair value of the
instruments granted. As long as all other vesting conditions are
satis ed, a charge is made irrespective of whether the market
vesting conditions are satis ed. The cumulative expense is not
adjusted for failure to achieve a market vesting condition.
Where equity instruments are granted to persons other than
employees or Directors, the consolidated statement of comprehensive
income is charged with the fair value of goods and services
received.
Bonuses
The Group recognises a liability and an expense for bonuses.
Bonuses are approved by the Board and a number of factors are taken
into consideration when determining the amount of any bonus
payable, including the recipient's existing salary, length of
service and merit. The Group recognises a provision where
contractually obliged or where there is a past practice that has
created a constructive obligation.
Pension obligations
For de ned contribution plans, the Group pays contributions to
privately administered pension plans. The Group has no further
payment obligations once the contributions have been paid. The
contributions are recognised as an employee bene t expense when
they are due.
1.25 Employee bene ts continued
Termination bene ts
Termination bene ts are payable when employment is terminated by
the Group before the normal retirement date, or whenever an
employee accepts voluntary redundancy in exchange for these bene
ts. The Group recognises termination bene ts when it is
demonstrably committed to a termination and when the entity has a
detailed formal plan to terminate the employment of current
employees without the possibility of withdrawal. Bene ts falling
due more than 12 months after the end of the reporting period are
discounted to their present value.
1.26 Segmental reporting
Operating segments are reported in a manner consistent with the
internal reporting provided to the chief operating
decision-maker. The chief operating decision-maker, who is
responsible for allocating resources and assessing performance of
the operating segments, has been identi ed as the Board of
Directors that makes strategic decisions. The performance of
operating segments is assessed on the basis of key metrics
applicable, such as barrels of oil produced per day, "netbacks" per
barrel, revenue and operating pro t.
The Board has determined there is a single operating segment:
oil and gas exploration, development and production. However, there
are four geographical segments: Trinidad and Tobago and Suriname,
the Bahamas, Uruguay and the Isle of Man and United Kingdom
(including holding companies in Cyprus, Netherlands, and St Lucia,
and dormant entities in Spain, Uruguay and United States of
America). The Isle of Man and United Kingdom geographic segment is
non-operating.
1.27 Share issue expenses and share premium account
Costs of share issues are written off against the premium
arising on the issues of share capital.
1.28 Share based payments reserve
This reserve is used to record the value of equity bene ts
provided to employees and Directors as part of their remuneration
and provided to consultants and advisors hired by the Group from
time to time as part of the consideration paid.
1.29 Critical accounting estimates, judgements and assumptions
The Group makes estimates and assumptions concerning the future.
The resulting accounting estimates will, by de nition, seldom equal
the related actual results. The estimates and assumptions that have
a risk of causing material adjustment to the carrying amounts of
assets and liabilities within the next nancial year are discussed
below.
(i) Recoverability of oil and gas exploration and production assets
Impairment of Trinidad and Tobago tangible oil and gas assets
and property plant and equipment
The Directors carried out an impairment review of the Group's
tangible assets in Trinidad and Tobago, including goodwill, to
determine whether the carrying value of these assets exceeded their
fair value. This assessment was undertaken by reference to various
market data points and industry valuation standards, including,
where applicable, discounted cash ows. Following this exercise, the
Directors determined that one of the cash generating units ("CGU")
located in Trinidad and Tobago has not met performance expectations
determined at the time of the Columbus Energy Group acquisition in
August 2020. Consequently, an impairment of related tangible assets
of $2,289,000 (2021: $5,347,000) within this CGU has been
recognised at balance sheet date. No impairment has been recognised
to goodwill of $4,610,000 (2021: no impairment) at the balance
sheet date. Refer to note 10 (intangible assets) and note 11
(tangible assets).
For continuing operations, calculation of the value in use is
determined by covering a detailed three-year forecast approved by
management, followed by an extrapolation of expected cash ows for
the remaining useful lives using a declining growth rate determined
by management. The present value of expected cash ow of each cash
generating unit is determined by applying a pre-tax discount rate
of 10% re ecting market assessment of the time value of money and
forward oil price of
$65 per barrel. Applying this methodology an impairment was
identi ed in a CGU as described above primarily due to lower
expected future production and lower expected future oil price
assumed compared to the prior year.
Further sensitivity analysis determined the following:
- A $5 per barrel decrease in the oil prices would increase the
overall impairment charge to $2,700,000;
- A 10% decrease in production would increase the overall
impairment charge to $2,600,000; and
- A 5% increase in the pre-tax discount rate would increase the
overall impairment charge to $5,900,000
1.29 Critical accounting estimates, judgements and assumptions continued
Carrying value of capitalised exploration costs
Costs capitalised as exploration assets are assessed for
impairment when circumstances suggest that the carrying value may
exceed its recoverable value. This assessment involves judgement as
to the likely commerciality of the asset, the future revenues and
costs pertaining and the discount rate to be applied for the
purposes of deriving a recoverable value.
The carrying value of exploration costs at 31 December 2022 is
$93,963,000 (2021: $93,952,000) relating to the cost of exploration
licences, geological and geophysical consultancy, seismic data
acquisition and interpretation and the drilling of exploration
wells in the Bahamian offshore licences. The Group's exploration
activities are subject to a number of signi cant and potential
risks including:
- licence obligations;
- requirement for further funding;
- geological and development risks; and
- political risk.
The recoverability of these assets is dependent on the discovery
and successful development of economic reserves, including the
ability to raise nance to develop future projects or alternatively,
sale of the respective licence areas. The carrying value of the
Group's exploration and evaluation expenditure is reviewed at each
balance sheet date and, if there is any indication that it is
impaired, its recoverable amount is estimated. Estimates of
impairment are limited to an assessment by the Directors of any
events or changes in circumstances that would indicate that the
carrying value of the asset may not be fully recoverable. Any
impairment loss arising is charged to the consolidated statement of
comprehensive income.
Bahamas oil and gas exploration costs
On 21 February 2019, the Group received noti cation from the
Bahamian Government of the extension of the term of its four
southern licences to 31 December 2020, with the requirement that
the Company commence an exploration well before the end of the
extended term. On 23 March 2020 the Group noti ed the Government of
The Bahamas that, due to the impacts of the global response to the
Covid-19 pandemic, a force majeure event had occurred under the
terms of its exploration licences, such that the term of the
licences needed to be extended beyond 31 December 2020 commensurate
with the duration of the force majeure event. In November 2020 the
Group received noti cation per the Government of The Bahamas
agreeing to an extension of these licences to 30 June 2021 as a
result of the force majeure event.
On 20 December 2020, the Group commenced drilling of the
Perseverance-1 exploration well on its offshore licence area in The
Bahamas, with drilling activity ceasing on 7 February 2021. Whilst
the well demonstrated presence of hydrocarbons, commercial volumes
of movable hydrocarbons were not present at this drilling location.
Subsequently the Group undertook an extensive review of the data
gathered from the Perseverance-1 well to determine the extent to
which this data indicates remaining prospectivity in deeper,
untested horizons, as well as horizons of interest at other
locations along the B and C structures. The results of this review
indicate that substantial prospectivity remains in sufficient
potential volumes such that further exploration activity on these
licences is merited. On the basis of the revised prospect volume
inventory for these untested horizons and structures, the Group
undertook an exercise to determine whether the present value of any
future economic bene t which may be derived from hydrocarbon
extraction from these licences is sufficient to support the
carrying value of the capitalised costs at 31 December 2022.
Following this review, the Group has determined that the present
value of these future economic bene ts exceeds the carrying value
of this asset and that consequently no impairment of this asset is
required.
In March 2021, the Group noti ed the then Government of The
Bahamas of its election to renew the four southern licences into a
further three-year exploration period, having discharged the
licence obligation to drill an exploration well before the expiry
of the current licence period on 30 June 2021. A new Government was
elected in The Bahamas in September 2021, and the Group is engaging
with the new administration regarding the renewal of these licences
and the level of licence fees which remain to be paid for the
period that expired up to 30 June 2021 and which would be payable
for the renewed licence period. Once this renewal process is
completed, the key licence obligation for the new three-year period
will be the drilling of a further exploration well within the
licence area before the expiry of the renewed licence term.
The ability of the Group to discharge its obligation to commence
a well prior to the end of a renewed licence period will be
contingent on securing the funding required to execute a second
exploration well. Following the licence renewal, the Group will
continue to engage in discussions with various industry operators
regarding entering into a joint venture partnership or farm-out to
fund any future well, and the Directors consider that the Group
will be able to discharge the licence requirement of a further
exploration well within a renewed term of the licence.
1.29 Critical accounting estimates, judgements and assumptions continued
(ii) Going concern
These nancial statements have been prepared on a going concern
basis, which assumes that the Group will continue in operation for
the foreseeable future.
The Group had incurred an operating loss of $4.2 million for the
nancial year ended 31 December 2022 and the Group's current
liabilities exceeded current assets by approximately $2.0 million
as of 31 December 2022. At 31 December 2022 the Group had
approximately $2.5 million in unrestricted cash funding and at the
date of authorisation of these nancial statements, the Group had
approximately $1.3 million in unrestricted cash funding. In
addition, the Group had approximately
$0.5m in restricted cash holdings in support of minimum work
obligations in Uruguay, for which the work has been substantially
completed as at the date of this report. In addition, The Group has
several high-probability sources of cash in ows expected over the
next 12 months to enable the Group to continue as a going concern
for the foreseeable future. These include:
1. Contracted proceeds from sale of Cory Moruga licence in Trinidad.
In December 2022, the Group announced the sale of Cory Moruga
licence onshore Trinidad and Tobago for a consideration of up to
US$3 million of which US$1 million is payable upon completion, US$1
million in six months from completion and a further US$1 million
contingent upon Cory Moruga eld achieving 100 barrels of oil per
day production. Cory Moruga licence is presently a dormant licence
with previously discovered and tested oil resource. The sale is
fully documented and not subject to any conditions to completion
other than consent from the Trinidadian Ministry of Energy and
Energy Industries ("MEEI"), which remains outstanding. The Group,
in conjunction with the acquirer, have been in discussions with
MEEI and anticipates consent being obtained and completion of the
sale transaction within 3Q 2023. A successful completion would
result in the Group receiving US$2 million in cash consideration
within six months from completion.
2. Potential in ows from successful farm-out of the AREA OFF-1 licence in Uruguay.
The Group had been in discussions with various industry
participants in relation to potential farm-out / partnership
options for the AREA OFF-1 licence in Uruguay. In June 2023, a
formal adviser-led process was commenced with the objective of
securing an industry partner to farm-out the AREA OFF-1 licence by
the end of 2023. In the event of a successful farm-out, the Group
expects signi cant upfront cash consideration, consistent with
typical transactions of this nature in the international oil and
gas industry. The Group is con dent that a farm-out transaction can
be successfully achieved in this timeframe, because (i) multiple
high-quality energy majors are presently engaged in the farm-out
process, undertaking due diligence as at the date of this report;
(ii) the Group's technical work to-date has resulted in identi
cation and de nition of three prospects with an estimated
recoverable resource of approximately
2 billion barrels (Pmean) and up to 5 billion barrels in an
upside case (P10) establishing that AREA OFF-1 is a high-quality
asset of scale, material to any player in the global industry, and
(iii) the Directors consider successful completion of the farm-out
process to be highly probable in light of the recent industry
developments - namely signi cant offshore discoveries in Namibia
(Uruguay is considered to be geological mirror of the offshore
Namibia basins), and substantial industry interest in offshore
Uruguay acreage in the past 12 months, evidenced by licencing
activity in the recent Uruguayan licencing rounds that has resulted
in all available acreage now having been awarded to industry majors
(Shell, APA Corporation and YPF) along with several other
interested global oil majors not securing any acreage.
3. Sale of other non-core assets
The Group is also in discussions in relation to the potential
sale of other non-core assets in its portfolio. A successful
completion of any transaction of this nature would result in the
Group receiving cash consideration, thus increasing its available
cash reserves.
In addition to the above, the Directors note that the Company is
a publicly listed company on a recognised stock exchange, thus
affording the Company the ability to raise capital equity, debt
and/or hybrid nancing alternatives as and when the need arises. The
Company has a robust track record in this regard, having raised in
excess of US$100 million in equity and alternative nancing in the
past ve years. Based on the Company's attractive asset portfolio
and history of capital raising, the Directors are of the view that
if required (i.e., in the event sources of cash in ows discussed
above do not materialise as and when expected) the Company will be
able to source fresh capital on short notice. As such, the
Directors have prepared the nancial statements on a going concern
basis and consider it to be reasonable.
1.29 Critical accounting estimates, judgements and assumptions continued
(iii) Recoverability of investment in subsidiary and amounts
owed by subsidiary undertakings in the Company statement of nancial
position
The investment in the Company's direct subsidiaries and amounts
owed by subsidiary undertakings at 31 December 2022 stood at
$50,940,000 (2021: $50,940,000) and $113,600,000 (2021:
$113,187,000) respectively.
Ultimate recoverability of investments in subsidiaries and
amounts owed by subsidiary undertakings is dependent on successful
development and commercial exploitation, increasing production
through optimisation of existing wells, drilling of new in ll wells
and/or the application of improved oil recovery methods or
alternatively, sale of the respective licence areas. The carrying
value of the Company's investments in subsidiaries is reviewed at
each balance sheet date and, if there is any indication of
impairment, the recoverable amount is estimated. Estimates of
impairments are limited to an assessment by the directors of any
events or changes in circumstances that would indicate that the
carrying values of the assets may not be fully recoverable.
Similarly, the expected credit losses on the amounts owed by
subsidiary undertakings are intrinsically linked to the recoverable
amount of the underlying assets. Any impairment losses arising are
charged to the statement of comprehensive income.
At 31 December 2022 a loss allowance for expected credit losses
of $14,737,000 (2021: $12,984,000) was held in respect of the
recoverability of amounts due from subsidiary undertakings.
1.30 Earnings/(loss) per share
Basic earnings/(loss) per share is calculated as net pro t
attributable to members of the parent company, adjusted to exclude
any costs of servicing equity (other than dividends) and preference
share dividends, divided by the weighted average number of ordinary
shares, adjusted for any bonus element.
Diluted earnings per share is calculated as net pro t
attributable to members of the parent company, adjusted for:
(i) Costs of servicing equity (other than dividends) and preference share dividends;
(ii) The post-tax effect of dividends and interest associated
with dilutive potential ordinary shares that have been recognised
as expenses; and
(iii) Other non-discretionary changes in revenues or expenses
during the period that would result from the dilution of potential
ordinary shares, divided by the weighted average number of ordinary
shares and dilutive potential ordinary shares, adjusted for any
bonus element.
1.31 Investment in subsidiary in the Company statement of nancial position
Investments in subsidiaries are recognised at initial cost of
acquisition, less any impairment to date.
2 Turnover and segmental analysis
Management has determined the operating segments based on the
reports reviewed by the Board of Directors that are used to make
strategic decisions. The Board has determined there is a single
operating segment: oil and gas exploration, development and
production. However, there are four geographical segments: Trinidad
& Tobago & Suriname (including a single operating segment
and a separate disposal group for the year ended 31 December 2022
(refer to note 15)), The Bahamas (operating), Uruguay (operating)
and The Isle of Man, UK, Spain, Saint Lucia, Cyprus, Netherlands
& USA (all non-operating).
The segment including Trinidad & Tobago has been reported as
the Group's direct oil and gas producing and revenue generating
operating segment. The Bahamas segment includes the Bahamian
exploration licences on which drilling activities were conducted in
2020 and 2021. The Uruguay segment includes the exploration
licences and appraisal works which have commenced in 2022. The
non-operating segment including the Isle of Man (the Group's
parent), which provides management service to the Group and
entities in Saint Lucia, Cyprus, Spain, the Netherlands, and the
U.S.A. all of which are non-operating in that they either hold
investments or are dormant. Their results are consolidated and
reported on together as a single segment.
Deferred tax assets arise on recognition of deferred tax
liabilities which arise on taxable temporary differences. As these
temporary differences unwind, release of the deferred tax
liabilities creates a taxable pro t against which deferred tax
assets are utilised. At 31 December 2022, the Group had an
unrecognised deferred tax asset of $49,000,000 (2021: $47,000,000)
calculated at 46.1% (2021: 46.8%) (weighted average across taxable
entities) in respect of an estimated $130,000,000 (2021:
$123,100,000) of accumulated tax losses. The deferred tax asset was
not recognised as there was insufficient evidence to suggest that
it would be recoverable in future periods.
The recognition of movements in deferred tax assets and deferred
tax liabilities in the consolidated statement of comprehensive
income for the year have given rise to a net deferred tax charge of
$27,000 (2021: nil).
15 Discontinued operations
At balance sheet date two asset sales were considered to be
active and highly probable of taking place: the sale of T-Rex
Resources (Trinidad) Limited, an indirectly wholly owned subsidiary
of the Company holding the Group's 83.8% interest in the Cory
Moruga licence onshore Trinidad, and the sale of Caribbean Rex
Limited (CREX), an indirectly wholly owned subsidiary of the
Company holding the Group's 100% interest in the South Erin licence
via interposed subsidiaries. Accordingly, these entities form a
separate disposal group and have been reclassi ed as assets held
for sale at 31 December 2022.
Sale of T-Rex (Cory Moruga asset):
On 20 December 2022 the Company announced that it had entered
into a binding heads of terms with Predator Oil & Gas Holdings
Plc, providing for the conditional sale of the Company's interest
in the non-producing Cory Moruga licence in Trinidad through the
sale of 100% of the share capital in T-Rex Resources (Trinidad)
Limited (TREX), with retention of 25% future back-in right (at the
Company's option) based on the outcomes of future drilling / EOR
activity and associated future production.
Subsequently, on 8 March 2023, the Company announced that the
acquirer had completed its con rmatory due diligence process and
the parties had entered into fully termed long form legal
documentation.
The completion of the Transaction is conditional on consent of
the Trinidadian Ministry of Energy and Energy Industries ("MEEI")
to a revised work programme for the Cory Moruga licence and
restructuring of certain licence terms. The parties have agreed to
work together to secure the required consents and agreements with
MEEI and thus achieve completion of the Transaction as soon as
reasonably practicable with a long stop date of 31 August 2023.
Sale of CREX (South Erin asset):
On 14 February 2023 the Company announced publicly (via RNS) it
had entered into and completed a transaction for the sale of its St
Lucia domiciled subsidiary company, CREX which included its
associated assets and subsidiary entities. This includes (via
interposed subsidiaries) CEG South Erin Trinidad Limited ("CSETL")
a Trinidadian company that is party to a farm-out agreement for,
and is the operator of, the South Erin eld, onshore Trinidad) and
West Indian Energy Group Limited (a Trinidadian service
company).
The results for the combined disposal group are presented
below:
The net cash ows incurred by the combined disposal group are, as
follows:
*Included in the current trade and other payables are
exploration and evaluation payables balances amounting to nil
(2021: $7,916,000).
During the reporting period, the Group and Company completed a
comprehensive restructuring and recapitalisation exercise
("Restructuring and Capital Raising") which resulted in:
i) the Group and Company raising approximately GBP7.3 million
(or approximately $10 million) (before expenses) via the issue of
new shares, to fund certain payments to creditors as part of the
agreed discounted payment plan, as well as to fund a work programme
for 2022;
ii) a substantial reduction in balance sheet payables, debts and
potential liability exposures, that would have reasonably required
settlement in cash, from approximately $23.5 million as of 31
December 2021 to approximately $2.5 million, being the estimated
liabilities amount that would be required for settlement in cash by
the Group in the foreseeable future. The substantial majority of
liability settlements took place during the reporting period;
and
iii) the Company reducing its net current liability position
from approximately $10.1 million at 31 December 2021 to a net
current asset position of approximately $1.9 million at 31 December
2022 as a result of the settlements made during the reporting
period.
Consequently, following the implementation of Restructuring and
Capital Raising, the trade and other payables (including accruals)
include dues, amounting to approximately $2.5 million in aggregate,
that are considered to be of a routine working capital nature, and
that are being settled in the ordinary course of business and / or
under certain agreed payment plans. The remainder of trade and
other payables (including accruals) include:
i) approximately $3.3 million is in respect of taxes owed in
Trinidad and Tobago that the Group expects to settle by way of
offset against tax refunds due to the Group in Trinidad and Tobago
($2.1 million, including under 'Trade and other receivables'). The
balance amount relates to a notional estimate of penalties that
apply in accordance with the tax laws in Trinidad and Tobago - as
at the date of this report these are notional estimates only and
have not been levied or assessed, and the Group does not expect
that they will be levied or assessed and that ultimately no cash
payment will be required as the Group had claimed the bene t of a
tax amnesty during the 2021 tax amnesty period implemented by the
Trinidad and Tobago tax authorities, with the nal resolution of
this matter remaining pending;
ii) approximately $2.3 million is in respect of various dues
comprising, i) $0.5 million is in respect of accruals in relation
to restructuring and recapitalisation costs, which are expected to
be settled in shares without any cash cost to the Company,
ii) $0.5 million is in respect of potential insurance "top-up"
exposure, due to the ultimate cost of the Perseverance-1 well in
The Bahamas exceeding the initial estimated cost - however, as at
the date of this report, the matter remains pending resolution with
the insurers, iii) $0.6 million is in respect of accrued licence
fee which the Group expects to offset against
$0.5 million refundable advances (included in trade and other
receivables) resulting in no material incremental cash exposure to
the Group, iv) $0.4 million in advances towards a work programme
undertaken by a third-party a settlement agreement for which has
been reached (pending completion of the sale of Cory Moruga asset)
resulting in no cash exposure to the Group, and v) $0.3 million in
relation to legacy accruals recognised in the nancial statements
which the Group expects to be written-back following lapse of the
relevant statute of limitation period.
1 On 30 December 2020, the Company drew down GBP1,110,000
(US$1,511,000) of a GBP3,000,000 (US$4,084,000) rst tranche of a
convertible loan previously agreed with Bizzell Capital Partners
Pty Ltd. As part of this initial draw down in 2020, GBP287,000
(US$396,000) was recognised as the equity component. Tranche 1 had
a total fair value, after deduction of all facility costs, of
GBP2,800,000 (US$3,812,000). The term of the loan was 3 years from
the date of draw-down. The holder had the right, at any time prior
to maturity, to elect to convert the Notes (principal plus any
accrued interest) into fully paid ordinary shares in the Company.
Initially, the conversion price was set at a 25% premium to the
price of the Company's next capital raising
(if any) or at 6p per share, whichever was the lower.
Subsequently, in February 2021 the conversion price was amended by
agreement to 0.8p per share. In May 2021 the balance of the
GBP3,000,000 facility was drawn down in full, resulting in a
further GBP370,000 (US$505,000) equity component being recognised.
Thereafter GBP2,500,000 (US$3,496,000) of the facility amount was
converted into ordinary shares resulting in a GBP579,000
(US$787,000) equity conversion, leaving a remaining principal
outstanding of GBP342,000 (US$462,000) and residual equity
component of GBP84,000 (US$114,000) at 31 December 2021. The
remaining balance was converted into ordinary shares as part of the
restructuring completed in March 2022.
2 The loan was issued by RBC Royal Bank Limited in June 2015 in
respect of the Columbus Energy Resources Plc business. Repayments
were over 7 years and the loan is denominated in Trinidad and
Tobago Dollars.
3 The loan was issued by BNP Paribas in 2015 in respect of the
Columbus Energy Resources Plc business. In December 2016, the
outstanding balance of US$2.6m was re nanced and retired, and all
security was removed, leaving a nal unsecured payment of US$0.25m
due on 31 December 2019. In November 2020 this loan balance was re
nanced with the outstanding balance to be repaid over one year
commencing in February 2021. In November 2021 this loan balance was
subject to a
re-settlement resulting in a reduced payment terms with nal
settlement made in February 2022. The loan was denominated in US
Dollars.
4 In July 2019, CEG South Erin Trinidad Limited drew down on a
new working capital loan facility (New Sunchit Loan). Repayments
are over 5 years with the nal payment due in June 2024. The loan is
denominated in Trinidad and Tobago Dollars. This loan has been
reclassi ed as part of Liabilities directly associated with the
assets held for sale, see note 15 for details.
The carrying amounts of all the borrowings approximate to their
fair value.
* The provisions relate to the estimated costs of the removal of
Trinidadian and Spanish production facilities and site restoration
at the end of the production lives of the facilities.
Decommissioning provisions in Trinidad and Tobago have been subject
to a discount rate of 3.8%-4.98% (2021: 5%), expected cost in ation
of 2.06%-3.22% (2021: 1.4%) and assumes an average expected year of
cessation of production of 2032. Decommissioning provisions
relating to facilities in Spain are undiscounted and unin ated as
the eld is no longer operating. The Spanish subsidiary is currently
in the process of being liquidated and management's expectation is
that the provision for decommissioning relating to Spanish assets
will be released on completion of this process.
Other provisions
In one of the Group's Trinidadian subsidiaries, there are
licence fees and commitments relating to an exploration and
production licence that the subsidiary is expecting to settle by
way of negotiation with the Trinidadian Ministry of Energy and
Energy Industries ("MEEI"). A provision has been recognised to re
ect management's best estimate of its obligation at balance sheet
date. However, the Group has formally written to MEEI proposing
rebasing of this licence whereby all claimed past dues would be
cancelled, the annual licence fees rebased to an appropriate level,
and a new future work programme agreed. To the extent a suitable
arrangement of this nature cannot be agreed with MEEI, the Company
intended to surrender the licence, in which case the subsidiary
company holding the licence will be placed into administration, and
all liabilities claimed in respect of this licence will be
eliminated, without recourse to the Company, as con rmed by a legal
opinion. This provision has been reclassi ed as part of liabilities
directly associated with the assets held for sale, see note 15 for
details.
During the year, transaction costs for issued share capital
totalled $598,000 (2021: $754,000) which were offset against the
proceeds received from the issue of shares, with the balance
settled through the issue of share capital, these amounts were
allocated against share premium.
The total authorised number of ordinary shares at 31 December
2022 was 50,000,000,000 (2021: 2,000,000,000) with a par value
of
0.02 pence per share. All issued shares of 0.02 pence are fully
paid.
* The merger reserve arose in 2010 as a result of the Group
undergoing a Scheme of Arrangement which saw the shares in the then
parent company BPC Limited replaced with shares in Challenger
Energy Group PLC.
** In 2008, BPC Jersey Limited acquired Falkland Gold and
Minerals Limited ('FGML') via a reverse acquisition, giving rise to
the reverse acquisition reserve. BPC Jersey Limited was the
acquirer of FGML although FGML became the legal parent of the Group
on the acquisition date. FGML subsequently changed its name to BPC
Limited.
In the Company Financial Statements, the Other Reserve balance
of $29,535,463 (2021: $29,535,463) arises from the issue of shares
in the Company as part of the Scheme of Arrangement undertaken in
2010, which saw the shares in the then parent company BPC Limited
replaced with shares in Bahamas Petroleum Company PLC (then BPC
PLC), which became the new parent company of the Group.
1 Trinidad and Tobago
The Group has certain minimum work commitments under its
licences in Trinidad and Tobago which generally include carrying
out heavy work overs, drilling of exploration and / or development
wells, undertaking enhanced oil recovery projects including water
injection and / or carbon dioxide injection.
As of 31 December 2022, the term of one of the Group's licences
was extended to 31 March 2022 (and, more recently, to 30 June 2023)
to allow for ministerial approval required for the nalisation and
execution of the agreed form documentation in relation to a fresh
enhanced production service contract ("EPSC") with 30 September
2031 expiry. The EPSC will include certain minimum work obligations
comprising CO2 pilot project, heavy workovers and the drilling of
new wells.
2 Suriname
The Group holds an onshore licence for the exploration for and
production of hydrocarbons in Suriname. Under the terms of this
licence, the Group is obliged to undertake an extended well test in
the licence area by October 2022. The Group was granted a
six-month extension till April 2023 by the Surinamese regulator
to undertake further review of the project focusing on well design
options and long-term commerciality of the eld. This work has been
completed, and the Group is presently in discussions with the
Surinamese regulator as to the future direction for this asset. As
of the date of this report, extension of the licence beyond 2023
remains outstanding and uncertain.
3 Uruguay
In June 2020, the Group was noti ed by ANCAP, the Uruguayan
state oil company, of the award of the Area OFF-1 block offshore
Uruguay. At the balance sheet date, formal issuance of the licence
remained outstanding, however, subsequent to the balance sheet
date, the licence was formally signed on 25 May 2022. As a
consequence, the Group will have a commitment to undertake various
technical investigations over the licence block before the expiry
of the four-year exploration period commencing 25 August 2022.
4 The Bahamas
On 21 February 2019, the Group received noti cation from the
Bahamian Government of the extension of the term of its four
southern licences to 31 December 2020, with the requirement that
the Group commence an exploration well before the end of the
extended term. In November 2020 the term of the licence period was
extended to 30 June 2021 following the outbreak of the global
Covid-19 pandemic and the declaration of the Group of force
majeureunder the terms of its licences. On 20 December the Group
commenced the drilling of its licence obligation well in the
Bahamas, Perseverance 1, which was completed on 7 February 2021. As
such, at present, the Group does not have any committed work
obligations in The Bahamas. In March 2021 the Company noti ed the
Government of the Bahamas that it was renewing the four southern
offshore exploration licences for a further
three-year period, having discharged its obligations under the
previous licence term. The Group remains in discussions with the
Government over the terms of the renewal of these licences and,
once renewed, will have the obligation to commence a further
exploration well in the licence area before the expiry of the next
three-year term.
Annual licence rental commitments
The Group is required under its Bahamian exploration licences to
remit annual rentals in advance to the Government in respect of the
licenced areas.
On 27 February 2020, the Company advised that, consequent on the
granting of Environmental Authorisation for the Perseverance-1
well, the Company and the Government of The Bahamas had agreed a
process seeking a nal agreement on the
amount of licence fees payable for the balance of the second
exploration period (including the additional period of time to
which the licence period was extended as a result of force
majeure). At the time, the parties entered into discussions with a
view to nalising this outstanding matter. This discussion has been
delayed owing to the State of Emergency declared and ongoing
business disruption caused by the national response to the Covid-19
outbreak in The Bahamas. However, subject to said con rmation, the
Company expects that an appropriate side-letter agreement will be
nalised in due course.
In March 2021 the Company noti ed the Government of The Bahamas
that it was renewing the four southern offshore exploration
licences for a further three-year period, having discharged its
obligations under the previous licence term. The Group remains in
discussions with the Government over the terms of the renewal of
these licences, which will include agreement on the level of annual
rental fees payable over the renewed term.
The Group does not have any material annual rental payments
payable on its licences in Trinidad and Tobago, and Suriname and
Uruguay.
27 Related party transactions - Group & Company
Transactions between the Company and its subsidiaries, which are
related parties, have been eliminated on consolidation.
Transactions between other related parties are outlined below.
Remuneration of Key Management Personnel
The Directors of the Company are considered to be the Key
Management Personnel. Details of the remuneration of the Directors
of the Company are disclosed below, by each of the categories speci
ed in IAS24 Related Party Disclosures.
* Represents the fair value of shares issued to directors during
the year in settlement of deferred salary and fees, less the total
value of accrued salaries and fees on the date of settlement.
See note 7 for further details of the Directors' remuneration
and note 24 for details of the Directors' share-based payment bene
ts. On 23 July 2021, share options were granted to key management
personnel as follows.
28 Events after the reporting period - Group & Company
On 20 December 2022 the Company announced that it had entered
into a binding heads of terms with Predator Oil & Gas Holdings
Plc, providing for the conditional sale of the Company's interest
in the non-producing Cory Moruga licence in Trinidad through the
sale of 100% of the share capital in T-Rex Resources (Trinidad)
Limited, with retention of 25% future back-in right (at the
Company's option) based on the outcomes of future drilling / EOR
activity and associated future production.
Subsequently, on 8 March 2023, the Company announced that the
acquirer had completed its con rmatory due diligence process and
the parties had entered into fully termed long form legal
documentation.
As at the date of this report the completion of the Transaction
is conditional on consent of the Trinidadian Ministry of Energy and
Energy Industries ("MEEI") to a revised work programme for the Cory
Moruga licence and restructuring of certain licence terms. The
parties have agreed to work together to secure the required
consents and agreements with MEEI and thus achieve completion of
the Transaction as soon as reasonably practicable with a long stop
date of 31 August 2023. Refer to note 15 for further details.
On 14 February 2023 the Company announced that it had entered
into and completed a transaction for the sale of its St Lucia
domiciled subsidiary company, Caribbean Rex Limited which included
its associated assets and subsidiary entities. This includes (via
interposed subsidiaries) CEG South Erin Trinidad Limited, a
Trinidadian company that is party to a farm-out agreement for, and
is the operator of, the South Erin eld, onshore Trinidad) and West
Indian Energy Group Limited (a Trinidadian service company). Refer
to note 15 for further details.
On 5 June 2023, ANCAP announced it has awarded the AREA OFF-3
block, offshore Uruguay, to the Company, subject to licence
signing. The award of AREA OFF-3 will expand the Company's licence
holding in Uruguay to two blocks, in the offshore Punta del Este
and Pelotas sedimentary basins (AREA OFF-1 and AREA OFF-3) and will
position the Company's acreage on either side of Shell's AREA OFF-2
block.
On 14 June 2023 the Company announced that CEG Goudron Trinidad
Limited ("CGTL"), an indirectly wholly owned Trinidadian
subsidiary, has been noti ed by the Trinidad and Tobago Ministry of
Energy and Energy Industries ("MEEI") that the Government of
Trinidad and Tobago has authorised MEEI to enter into negotiations
with CGTL for the grant of an Exploration and Production (Public
Petroleum Rights) Licence for the Guayaguayare block (the
"Licence"), following a successful bid for that Licence by CGTL.
The Guayaguayare block is located onshore in south-east Trinidad.
It is one of the largest onshore exploration and production blocks
in Trinidad (approximately 306 km2), and is strategically and
operationally synergistic with the Company's core Trinidadian
production business, in that the Licence wholly encloses the
Company's Goudron licence area, and is adjacent to the Company's
Inniss-Trinity licence area. At the date of this report, the formal
award of the licence remains subject to negotiations and nalisation
of the Licence terms with MEEI.
29 Comprehensive income/(expense) for the year - Company
The Company's pro t after tax for the year was $1,330,000 (2021:
loss of $15,515,000).
Corporate Directory
Company Number Registered in the Isle of Man with registered
number 123863C
Current Directors Iain McKendrick Simon Potter
Non-Executive Chairman Non-Executive
Stephen Bizzell Eytan Uliel
Non-Executive Chief Executive Officer
Secretary Benjamin Proffitt
Registered Office and The Engine House
Corporate Headquarters Alexandra Road, Castletown
Isle of Man IM9 1TG
Registrar Link Market Services (IOM) Limited
PO Box 227
Peveril Buildings Peveril Square Douglas
Isle of Man IM99 1RZ
Auditor Grant Thornton
13-18 City Quay
Dublin 2 Ireland
Principal Legal Advisors Clyde & Co
St Botolph Building 138 Houndsditch London
EC3A 7AR
United Kingdom
Nominated Advisor WH Ireland plc 24 Martin Lane London
EC4R 0DR
United Kingdom
Brokers Arden Partners plc
WH Ireland plc
125 Old Broad Street 24 Martin Lane
London London
EC2N 1AR EC4R 0DR
United Kingdom United Kingdom
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(END) Dow Jones Newswires
June 29, 2023 02:00 ET (06:00 GMT)
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