REG - Challenger Energy - ANNUAL REPORT FOR YEAR ENDED 31/12/22
29/06/2023 07:00
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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 YEAR ENDED 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/
(https://www.cegplc.com/) .
For further information, please contact:
Challenger Energy Group PLC Tel: +44 (0) 1624 647 882
Eytan Uliel, Chief Executive Officer
WH Ireland - Nomad and Joint Broker Tel: +44 (0) 20 7220 1666
Antonio Bossi / Darshan Patel / Enzo Aliaj
Zeus - Joint Broker Tel: +44 (0) 20 3829 5000
Simon Johnson
Gneiss Energy Limited - Financial Adviser Tel: +44 (0) 20 3983 9263
Jon Fitzpatrick / Paul Weidman / Doug Rycroft
CAMARCO Tel: +44 (0) 20 3757 4980
Billy Clegg / Hugo Liddy / Sam Morris
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 (https://www.cegplc.com/)
ENDS
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, final 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 benefit 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
profit". 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 benefitted 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 benefit.
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 finally 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 financial 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 financial and operational restructuring, along with
a recapitalisation. Then, with the benefit 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 significance 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 first 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
significant 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 first-mover, low-cost
entry into Uruguay, and confirmed 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 identification 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 first 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 significant
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 confident 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 fields. Our goal
was to achieve production growth from applying efficient mature oilfield
management practices, field 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 fields 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 fields was remarkably constant and predictable.
That is, the same field 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
"fit" the needs of those specific 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 cashflow
across 2022 (which represents a substantial improvement on 2021, where the
Trinidad business had incurred a net operating cash deficit).
• 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 profitable 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 finding places within our
existing fields 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 first 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, refined our strategy accordingly, and built from there. As a
result, we are now seeing positive outcomes - continuing improvements in
financial performance, wins on the business development front, and in overall
context, progress toward our goal of building a profitable 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 financial 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 significantly 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 financial 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 field
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 field. 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 significant 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
financial 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 confidence 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 km2 - 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 first 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 significant
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
km2 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 first 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
identified 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 ENVIRONMENT STRATIGRAPHIC AGE AREAL EXTENT WATER DEPTH RESERVOIR DEPTH ESTIMATED EUR
(mmboe) P10/Pmean/P50/P90
TERU TERU Onlap slope turbidite to shelf margin wave delta AVO supported - Class II Mid to Upper Creataceous Albian to Campanian 360/210/106 km² ~ 800m 3,925 m 1,647/740/547/158
ANAPERO Outer shelf margin stacked sands AVO supported - Class III Upper Cretaceous Campanian 304/214/101 km² ~ 750m 3,400 m 1,627/670/445/88
LENTEJA Lacustrine alluvial syn-rift fan sealed by regional uncomformity Lower Cretaceous Neocomian 248/85/14 km² ~ 85m 4,500 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 first 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 first
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 km2
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 identified 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 confidence 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 fields
located in the country.
The Group has four producing fields, all onshore Trinidad. Across these
fields 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 fields 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 306km2 area in the south-east of Trinidad and the Company's Goudron
field 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 field 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 field, 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 identified 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 field 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 field 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 field, 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 field, the Group continues to
undertake a comprehensive well optimisation and swabbing programme with the
objective of achieving production stability, growth and longevity, and reduced
field 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 finalisation 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 km2), 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 field 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 field.
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 field 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 field exercisable at the Company's
election, at any time in 18 months from the transaction date for a fixed cash
amount of US$1 million, plus 49% of all amounts spent by the buyer on South
Erin field activities and new well drilling.
SWP
The SWP contains the Bonasse and Icacos producing oilfields, 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 fields,
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 field 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 findings from
Perseverance-1 indicate the potential of deeper Jurassic horizons. In March
2021, the Group notified 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 field. 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 field operations in Trinidad, the Group owns and
operates two workover rigs, one swabbing rig, and assorted heavy field
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 benefits 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. (http://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 finance executive with significant oil and gas industry
experience. He has significant experience in mergers and acquisitions,
capital raisings, general corporate advisory work, oil and gas
industry-specific 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 finance 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 firm 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 qualified 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 fields of corporate restructuring, debt and
equity financing, 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 qualified 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 financial
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 fulfilling 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 financial 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 financial
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 financial 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 inflows 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 field 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 inflows 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 significant upfront cash consideration, consistent with typical
transactions of this nature in the international oil and gas industry. The
Group is confident 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
identification and definition 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
significant 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 financing 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
financing in the past five 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 inflows 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 financial
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 financing. 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 fight
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 fiscal 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
specifically 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. Identified
risks are segregated between those that we can influence and those which are
outside our control. Where we can influence 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 infill
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 qualified 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 firm. CEG has staff and
consultants who are qualified reservoir engineer with significant
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
profile
Potential impact: Medium Probability: High
Risk appetite
The principal location of the Group's producing assets and their age profile
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 financing risk. The inability to fund
financial commitments, including licence obligations, could significantly
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 financial
penalty and/or termination of licences.
Mitigation
The Group has a strong track record over many years of successfully raising
finance 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) Rank 2023 (2021) score
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 confirm 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 briefings 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 profitability, cash flow,
financial 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 fluctuation (and also conversely benefits 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 significant 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
financial 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 fiscal and political risk.
Potential impact: High Probability: Moderate
Appetite
The Group accepts a modest amount of fiscal risk. The Group is exposed to
currency risk resulting from fluctuations 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 significant
amount of the Group's cash holdings are denominated in Pound Sterling).
Currency hedging instruments are not used.
Mitigation
The Group closely monitors fiscal and political situation in the
jurisdictions it operates in with a view to identifying and minimising the
downside risk presented by changes in fiscal and political circumstances.
While the Group has not hedged its currency exposure in the past, the Group
closely monitors currency fluctuations 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 financial 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 financial year ended
31 December 2022.
Directors
The following persons were Directors of the Company during the financial 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
profit 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 deficit.
The Directors do not recommend payment of a dividend (2021: nil).
Significant Shareholders
The following tables represent shareholdings of 3% or more notified 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 financial 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 financial statements for each
financial year. The Directors have elected to prepare the Group and Company
financial statements in accordance with International Financial Reporting
Standards ("IFRSs"). The financial 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 profit or loss of the Group for that period.
In preparing the financial 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 financial statements;
• make judgements and accounting estimates that are
reasonable and prudent; and
• prepare the financial 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 financial position of the
Group and the Company and to enable them to ensure that the financial
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 financial 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 financial 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 financial statements, including a summary of
significant accounting policies.
The financial reporting framework that has been applied in the preparation of
the financial statements is applicable law and International Financial
Reporting Standards (IFRS).
In our opinion, Challenger Energy Group PLC's consolidated and company
financial statements:
• give a true and fair view in accordance with IFRS of the
financial position of the Group and Company as at 31 December 2022, and of
the Group's financial performance and the Group and Company cash flows 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 financial 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 financial 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
fulfilled 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 financial statements, we have concluded that the directors'
use of going concern basis of accounting in the preparation of the financial
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 flow
forecast and agreeing the opening cash position;
• assessing management's underlying cash flow 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 inflow
sources and commitments, including contractual proceeds from sale of Cory
Moruga licence in Trinidad and Tobago and potential inflows 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 financial statements.
Based on the work we have performed, we have not identified any material
uncertainties relating to events or conditions that, individually or
collectively, may cast significant 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 financial statements are authorised for issue.
We have nothing material to add or draw attention to in relation to the
directors' statement in the financial statements about whether the directors
considered it appropriate to adopt the going concern basis of accounting in
preparing the financial 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 financial statements of Challenger Energy Group PLC and its subsidiaries
for the year ended 31 December 2021, were audited by PwC who expressed an
unmodified opinion on those financial statements on 29 September 2022.
Key audit matters
Key audit matters are those matters that, in our professional judgement, were
of most significance in our audit of the financial statements of the current
financial period and include the most significant assessed risks of material
misstatement (whether or not due to fraud) we identified, 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
financial 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 financial statements. In particular, we looked
at where the directors made subjective judgements, for example, in respect of
significant 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 financial 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 financial information of five
components, audit of one or more classes of transactions of two components and
performed audit procedures on specific balances for a further four
components. The remaining components of the Group were considered
non-significant 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 influenced 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 financial
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 financial statements exceeds materiality for the
financial statements as a whole.
We agreed with the audit committee and directors that we would report to them
misstatements identified 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.
Significant matters identified
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
significant matters together with an explanation of how we tailored our audit
to address these specific areas in order to provide an opinion on the
financial statements as a whole. This is not a complete list of all risks
identified by our audit.
Other information
Other information comprises information included in the annual report, other
than the financial statements and our auditor's report thereon. The directors
are responsible for the other information. Our opinion on the financial
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 financial statements, our responsibility
is to read the other information and, in doing so, consider whether the other
information is materially inconsistent with the financial statements or our
knowledge obtained in the audit, or otherwise appears to be materially
misstated. If we identify such material inconsistencies in the financial
statements, we are required to determine whether there is a material
misstatement in the financial 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 financial statements
As explained more fully in the Statement of Directors' Responsibilities,
management is responsible for the preparation of the
financial 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 financial statements are free from material misstatement,
whether due to fraud or error.
In preparing the financial 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 financial reporting process.
Responsibilities of the auditor for the audit of the financial statements
The objectives of an auditor are to obtain reasonable assurance about whether
the financial 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 influence the economic
decisions of users taken on the basis of these financial statements.
A further description of an auditor's responsibilities for the audit of the
financial statements is located on the Financial Reporting Council's website
at: www.frc.org.uk/auditorsresponsibilities.
(http://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 financial 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 identified 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 financial
statements. We also considered those laws and regulations that have a direct
impact on the preparation of the financial 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 financial statements (including the risk of override of
controls), and determined that the principal risks were related to posting
inappropriate journal entries to manipulate financial performance and
management bias through judgements and assumptions in significant accounting
estimates, in particular in relation to significant one-off or unusual
transactions. We apply professional skepticism through the audit to consider
potential deliberate omission or concealment of significant transactions, or
incomplete/inaccurate disclosures in the financial 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
identified laws and regulations and regarding the risk of fraud, and
remaining alert to any indications of non-compliance or opportunities for
fraudulent manipulation of financial 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 significant 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 financial 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 financial 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 financial statements for the year ended 31 December 2022
1 Summary of significant accounting policies
1.01 General information and authorisation of financial 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 financial 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 financial statements have been prepared in accordance with
International Financial Reporting Standards (IFRS). The Company's financial
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 significant impact on the
Group's financial 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 financial statements have been prepared on the historical cost basis,
except for the measurement of certain assets and financial instruments at
fair value as described in the accounting policies below.
The financial statements have been prepared on a going concern basis, refer
to note 1.29 for more details.
The financial 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 financial 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 financial 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 financial
position, the acquiree's identifiable 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 identifiable 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 identifiable net assets attributable to the Group exceed the
cost of acquisition, the difference is recognised in profit 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 defined 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 significant 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 specifically if the following occurs:
a) the period for which the Group has a right to explore in the
specific 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 specific area is neither budgeted nor
planned;
c) exploration for and evaluation of hydrocarbon resources in the
specific 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 specific area; and
d) sufficient data exists to indicate that although a development in
the specific 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 identifiable cash inflows which are largely independent of
the cash inflows 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 field is determined to be commercially viable, the attributable costs
are transferred to development/production assets within tangible assets in
single field cost centres.
Subsequent expenditure is capitalised only where it either enhances the
economic benefits 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
defined as the estimated quantities of crude oil, natural gas and natural gas
liquids which geological, geophysical and engineering data demonstrate with a
specified 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 field 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
field-by-field basis. In certain circumstances, fields 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 field development costs necessary to bring
the reserves into production. Changes in the estimates of commercial reserves
or future field 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 field 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 fixed 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 fixed asset.
1.10 Property, plant and equipment
Property, plant and equipment is stated in the consolidated statement of
financial 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, fittings 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 classified as held for sale and discontinued operations
A discontinued operation is a component of the Group that either has been
disposed of, or is classified as held for sale.
A discontinued operation represents a separate major line of the business.
Profit or loss from discontinued operations comprises the post-tax profit 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 classified as held for sale are presented separately and
measured at the lower of their carrying amounts immediately prior to their
classification as held for sale and their fair value less costs to sell.
However, some held for sale assets such as financial assets or deferred tax
assets, continue to be measured in accordance with the Group's relevant
accounting policy for those assets. Once classified as held for sale, the
assets are not subject to depreciation or amortisation.
Any profit 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, profit 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 financial 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 financial statements and company
financial 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 fixed 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:
• fixed payments (including in-substance fixed 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 reflects 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 financing
received by the individual lessee as a starting point, adjusted to reflect
changes in financing conditions since third party financing 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 financing; and
• makes adjustments specific 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 finance cost. The finance
cost is charged to profit 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 profit 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 classifies its financial assets as financial assets held at
amortised cost. Management determines the classification of its financial
assets at initial recognition.
The Group classifies its financial assets as financial 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 flows; and
- the contractual terms give rise to cash flows 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 financial assets
The Group assesses, on a forward-looking basis, the expected credit losses
associated with its financial assets held at amortised cost. The impairment
methodology applied depends on whether there has been a significant increase
in credit risk.
The Group applies the expected credit loss model to financial assets at
amortised cost. Given the nature of the Group's receivables, expected credit
losses are not material.
Financial liabilities
The Group classifies its financial liabilities as other financial
liabilities. Other financial liabilities are recognised initially at fair
value and are subsequently measured at amortised cost using the effective
interest method. Other financial 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 financial 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
financial statements are further categorised using the following three-level
hierarchy that reflects the significance 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 classification
for each financial asset and financial liability measured or disclosed at
fair value in the financial statements based on the lowest level input that
is significant to the fair value measurement as a whole. Assessments of the
significance 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
financial institutions with original maturities of three months or less. For
the purposes of the statement of cash flows, restricted cash is not included
within cash and cash equivalents.
1.18 Share capital
Ordinary shares are classified 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 identified 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 flows 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 financial 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 outflow of
resources embodying economic benefits 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 financial
statements and the corresponding tax bases used in the computation of taxable
profit, 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 profits 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 profit nor the
accounting profit.
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
profits 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
reclassified 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 flows expected to be derived from an
asset or cash-generating unit. This present value is discounted using a
pre-tax rate that reflects current market assessments of the time value of
money and of the risks specific to the asset, for which future cash flow
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 benefit 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 first 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 benefits
Wages and salaries, annual leave and sick leave
Liabilities for wages and salaries, including non-monetary benefits, 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 satisfied, a charge is made irrespective of
whether the market vesting conditions are satisfied. 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 defined 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 benefit expense when they are due.
1.25 Employee benefits continued
Termination benefits
Termination benefits 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 benefits. The Group recognises termination
benefits 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. Benefits 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 identified 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 profit.
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 benefits 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 definition, 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
financial 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 cashflows. 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 cashflows for the remaining useful lives using a
declining growth rate determined by management. The present value of expected
cashflow of each cash generating unit is determined by applying a pre-tax
discount rate of 10% reflecting market assessment of the time value of money
and forward oil price of
$65 per barrel. Applying this methodology an impairment was identified 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 significant 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
finance 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 notification 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
notified 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 notification
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
benefit 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 benefits exceeds the carrying value of
this asset and that consequently no impairment of this asset is required.
In March 2021, the Group notified 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 financial 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 financial
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 financial 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 inflows 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 field 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 inflows 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 significant upfront cash consideration, consistent with typical
transactions of this nature in the international oil and gas industry. The
Group is confident 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
identification and definition 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 significant 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 financing 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
financing in the past five 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 inflows 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 financial
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 financial 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 infill 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 profit 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 profit 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 financial 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 profit 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 reclassified 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 confirmatory 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 field, 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 flows 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 £7.3 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 benefit of a tax amnesty during the
2021 tax amnesty period implemented by the Trinidad and Tobago tax
authorities, with the final 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 financial
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 £1,110,000
(US$1,511,000) of a £3,000,000 (US$4,084,000) first tranche of a convertible
loan previously agreed with Bizzell Capital Partners Pty Ltd. As part of this
initial draw down in 2020, £287,000 (US$396,000) was recognised as the equity
component. Tranche 1 had a total fair value, after deduction of all facility
costs, of £2,800,000 (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 £3,000,000 facility was drawn down in full,
resulting in a further £370,000 (US$505,000) equity component being
recognised. Thereafter £2,500,000 (US$3,496,000) of the facility amount was
converted into ordinary shares resulting in a £579,000 (US$787,000) equity
conversion, leaving a remaining principal outstanding of £342,000
(US$462,000) and residual equity component of £84,000 (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 refinanced and retired, and all security was removed,
leaving a final unsecured payment of US$0.25m due on 31 December 2019. In
November 2020 this loan balance was refinanced 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 final 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 final payment due in June 2024. The loan is denominated in Trinidad
and Tobago Dollars. This loan has been reclassified 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 inflation 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 uninflated as the field 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 reflect 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 confirmed by a legal opinion. This provision has
been reclassified 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 finalisation 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 field. 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 notified 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 notification 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
notified 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 final 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 finalising 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 confirmation, the Company
expects that an appropriate side-letter agreement will be finalised in due
course.
In March 2021 the Company notified 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 specified 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 benefits. 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 confirmatory 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 field, 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
notified 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 finalisation of the Licence
terms with MEEI.
29 Comprehensive income/(expense) for the year - Company
The Company's profit 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 FR FFFELREITFIVRecent news on Challenger Energy
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