REG - Challenger Energy - Annual Report for the year ended 31 Dec 21 Part 1
30/09/2022 07:00
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RNS Number : 2568B Challenger Energy Group PLC 30 September 2022
30 September 2022
Challenger Energy Group PLC
("Challenger Energy" or the "Company")
Annual Report and Financial Statements for the year ended 31 December 2021
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 2021.
The 2021 Annual Report and Financial Statements will be posted to shareholders
today. The Company's AGM will be held on 29 November 2021 at 34 North Quay,
Douglas, Isle of Man IM1 4LB. Notice of the AGM will also be posted to
shareholders in due course.
The 2021 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
Strand Hanson Limited - Nomad Tel: +44 (0) 20 7409 3494
Rory Murphy / James Spinney / Rob Patrick
Arden Partners plc - Broker Tel: +44 (0) 20 7614 5900
Simon Johnson
CAMARCO Tel: +44 (0) 20 3757 4980
Billy Clegg / James Crothers / Hugo Liddy
Notes to Editors
Challenger Energy is a Caribbean and Atlantic margin focused oil and gas
company, with a range of exploration, appraisal, development and production
assets and licences, located onshore in Trinidad and Tobago, and Suriname, and
offshore in the waters of Uruguay and The Bahamas. In Trinidad and Tobago,
Challenger Energy has five (5) producing fields, two (2) appraisal /
development projects and a prospective exploration portfolio in the South West
Peninsula. In Suriname, Challenger Energy has on onshore appraisal /
development project. Challenger Energy's exploration licences in Uruguay, the
South West Peninsula of Trinidad, and The Bahamas offer high-impact value
exposure within the overall portfolio value.
Challenger Energy is quoted on the AIM market of the London Stock Exchange.
https://www.cegplc.com (https://www.cegplc.com/)
ENDS
Challenger Energy Overview
Challenger Energy is a Caribbean and Atlantic margin focused energy business
with a range of exploration, appraisal, development and production assets and
licences, located onshore in Trinidad and Tobago and Suriname, and offshore in
Uruguay and The Bahamas.
Trinidad and Tobago
· 7 licences (100%), 1 licence (83.8%) -all onshore
· Low-risk production operations at five fields; considerable
existing well stock (~250 wells of which approximately 80 are in production at
any time); close to sales infrastructure
· 2P Reserves of 1.3MMbbls; 2C Resources of 6.4MMbbls (per 2020
CPR)
Production and cashflow focused strategy
· Production enhancement potential from workovers, recompletions,
reactivations, enhanced oil recovery techniques, and swabbing, and growth
potential from new wells / field developments in 2023 and beyond
· Consolidation and new licence opportunities offer scope to grow
production base further
Suriname
· 1 onshore licence- Weg naar Zee PSC (100%), 900 km2
· 2C Resources of 1.1MMbbls; 3C Resources of 3.5 MMbbls (24 MMbbls
STOIIP) (per 2020 CPR)
· Technical work underway to define and implement production test
well design along with enhanced oil recovery techniques, success would lead to
a development
Uruguay
· 1 offshore licence- OFF-1 (100%) 14,557 km2 with multiple leads
and prospects -resource potential in excess of 1 billion bbls
· Low-cost initial 4-year exploration period commenced 25 August
2022, initial 2D seismic licencing and reprocessing work underway
· Uruguay is an emerging industry "hot spot" given successful
conjugate margin exploration drilling in Namibia in early 2022, as well as
recent Uruguay entry by majors with substantial forward work programme
commitments
The Bahamas
· 4 offshore licences (100%), licence renewals currently pending
· Perseverance-1 well drilled in 2021: encountered hydrocarbons via
logs although commercial volumes were not proven; post well analysis indicates
potential for a deeper Jurassic play and continued prospectivity of other
structures and targets
· People and Assets
· ~75 staff, with the majority in Trinidad and Tobago
· 2 workover rigs and 1 swabbing rig, owned and operated in
Trinidad and Tobago to support routine production and maintenance activities
Chief Executive Officer's Report to the
Shareholders
Dear fellow Shareholders,
This is my second report to you, the owners of the Group, in my capacity as
Chief Executive Officer.
This Annual Report covers the 2021 financial year period (that is, from
January to December 2021). As with last year, however, timing for 2021
reporting was delayed more than usual, owing to residual local impacts of the
Covid-19 pandemic in some of the jurisdictions in which we operate. Hopefully,
as the world rebounds from the pandemic and work gets back to normal in all
jurisdictions, this will not be the case next year when it comes to reporting
for 2022.
As a result of the timing delay for this Annual Report, its release coincides
with the timing for release of the half-year results for the period
January-June 2022, and much of the restructuring activity (which I elaborate
on below), although commenced in the second half of 2021, only saw significant
outcomes for the Group during the first half of 2022. Therefore, even though
strictly speaking this Annual Report relates to the period January to December
2021, I will refer in my report more generally, to the period from the start
of 2021 until the middle of 2022.
2021 in Context
For the majority of the Group's history its business and asset base focused
exclusively on the frontier basin "wildcat" operations associated with its
Bahamian licences - a preserve usually associated with International Majors
and NOCs. Entry into an exploration licence in Uruguay in May 2020 broadened
the portfolio for the first time, by adding another early-stage high-impact
exploration asset. Then, through the acquisition in August 2020 of production,
near term production, appraisal and exploration assets in Trinidad and Tobago
and Suriname, we transformed the Group by extending the asset base across the
region and sector value chain, and diversified the corporate risk profile.
2021 thus marked the Group's first full year of operations with an expanded
asset suite, and we commenced 2021 with a much larger business and team, and a
full slate of planned work before us: drilling of Perseverance-1 in The
Bahamas, which was the culmination of over a decade's work and efforts;
drilling of Saffron-2 in Trinidad; operating the producing fields in Trinidad;
and undertaking the initial work needed to mature the assets in Uruguay and
Suriname.
The Drilling Campaigns
The Group's 2021 drilling campaigns both occurred in the first half of the
year: the bulk of drilling for the Perseverance-1 exploration well in The
Bahamas occurred in January 2021 with the well completed in early February
2021, and the Saffron-2 appraisal well in Trinidad was drilled in June - July
2021.
We are proud of the fact that, despite many challenges, we did what we said we
would do: we drilled both wells safely and without incident and met the
objective of testing the relevant structures at the chosen drilling locations.
This was no small feat, especially for a Group of our size: we had to secure
the financing needed, we had to recruit an experienced operations team, and in
two different geographies we had to operate complex drilling programmes more
typically undertaken by much larger companies. We did all of this at the peak
of the global pandemic, and in the case of The Bahamas, whilst successfully
overcoming a legal challenge from environmental activists that was frivolously
launched at the very last minute.
This highlights the commitment, professionalism and dedication of the people
who work at Challenger Energy, as well as our robust business systems and
procedures, all of which remain core assets of the Group as we move forward.
In terms of outcomes, Perseverance-1 did not result in the commercial
discovery we hoped for, but a substantial amount of data and learning was
obtained from the drilling of the well, which was the first in the region
linked to 3D seismic and using modern techniques. During the balance of 2021
we analysed this data, and concluded that The Bahamas might yet offer
long-term potential. In simple terms, Perseverance-1 only tested one part of
one structure, but there are at least four other locations and multiple
structures that were upgraded following the Perseverance-1 outcome, and which
therefore in the future could merit further analysis and testing. Data from
Perseverance-1 also provides encouraging support for the possibility of a
deeper, sizeable Jurassic oil play.
As I have observed before, in frontier basins it is not at all uncommon for
several exploration wells to be required before the potential of that basin is
unlocked. Given this, in March 2021 we submitted documentation for renewal of
our Bahamian licences into a third, three-year exploration period - this
remains pending with The Bahamian Government, but the Group has completed all
of its work obligations and is thus entitled to a renewal. At the same time,
we have been clear on our go-forward strategy in The Bahamas - any future
activity will require a "big brother" partner, ideally a larger industry
player, to provide expertise and the capital that will be needed for the next
phase of activity.
Turning to the Saffron-2 well in Trinidad, it did not provide the immediate
production boost we were seeking from Lower Cruse reservoir units, although
that well, along with Saffron-1 (drilled prior to Challenger Energy assuming
control of the asset) provided much data on the viability of production from
the Upper Cruse and Middle Cruse sands across the broader licence area. Thus,
during the second half of 2021 and continuing into 2022, technical work
commenced to assess the commercial feasibility of a development focused only
on these upper reservoir horizons. A project of this nature would not be of
the same scale as what we had hoped for based on a Lower Cruse development,
but an Upper and Middle Cruse focused development, if economic, would still
enable us to access valuable increased production, and derive benefit from our
extensive licence position in the area. Over the coming months we will
complete the work needed to firm up our plans.3
Production Operations in Trinidad and Tobago
During 2021 we strategically repositioned the Group so as to prioritise our
producing assets in Trinidad and Tobago. We also established a very clear,
simple objective for the operations in Trinidad: to focus on production, to
manage costs tightly, and to thereby try to generate positive cashflow from
these operations.
There were three reasons for this strategic repositioning. One, routine
production provides a baseline level of cashflow, which we can use to plan our
business around. Two, we believe that by applying efficient oilfield
management practices, production at our fields can be sustained and thereafter
increased, producing surplus cash that could be reinvested in value-adding
work in the fields themselves, as well as applied towards covering the
business' total operating cost. And three, the oil and gas industry is
cyclical, and in the last few years higher-risk activities - especially those
considered to be "frontier exploration" - have fallen largely out of favour.
By contrast, in the context of the recent industry environment, investors and
capital providers have seemed far more interested in that part of our business
offering a lower-risk, predictable cashflow profile, even if that does not
offer the same level of upside potential as successful high-impact exploration
activities.
In support of this strategic repositioning, the work undertaken in Trinidad
and Tobago during 2021 broadly fell into two categories of work, "above
ground" and "below ground".
The focus of our "above ground" work essentially related to the fact that
prior to Challenger Energy assuming control of the Trinidadian production
assets in August 2020, they had been starved of cash, and generally poorly
managed. This was evident in low field activity levels, poor morale amongst
staff, inadequate policies and procedures, poor record keeping, many local
suppliers who had not been paid, and a business reputation in-country that was
suffering, especially with the regulators.
"Below ground", the work focus related to the fact that our assets in Trinidad
are mature - some have been producing oil for more than 60 years now. The
reservoirs are thus depressurised and the resource depleted, such that there
is always going to be a natural, inevitable level of production decline each
year. This has to be offset through efficient mature oilfield management
practices, targeted production enhancement activities, very tight cost
control, and ultimately the maturation of resources and drilling of new wells
in areas of the fields that have previously not been tapped.
Insofar as "above ground" work is concerned, all through 2021 we made
operational improvements: well workover rates increased, preventative
maintenance increased, we restructured the staff base, we worked to restore
staff morale and productivity, and we rescheduled and cleared the Trinidadian
business of many old debts and claims. Policies and procedures were revamped,
and new country management was identified (with key new hires, including a new
Country Manager, taking effect from early 2022 onward).
A good measure of our success in this regard is the restored business
relationship we have seen with various suppliers essential to ongoing
operations (many of whom were previously threatening to suspend services).
Another measure of success is the fact that toward the end of 2021 and into
2022 we secured extensions of two key licences in Trinidad, I believe largely
because we could demonstrate to the regulators the extent of the improvements
we had made.
Therefore, in relation to the "above ground", my report is that 2021 and H1
2022 have been periods of solid progress.
We systematically tackled many issues so that, in an operational sense, the
overall business in Trinidad and Tobago today is in a
far better shape today than it was 18 months ago.
More challenging, however, has been the "below ground" work I mentioned above
- i.e., the work needed to offset natural production decline, sustain and
enhance baseline production, and generate positive cashflow. This was
especially difficult because during the first half of 2021 attention and
capital was focused on our drilling activities, and access to Trinidad was
restricted due to the pandemic. Then, from the middle of 2021 onwards,
available capital and our ability to do substantive work in this area was
greatly limited until the restructuring process (which I discuss further
below) was completed.
Through 2021 we thus saw a decline in our average production rate
-approximately 450 barrels of oil produced per day toward the start of the
year, and then declining to end the year at below 350 barrels of oil produced
per day. Since completing the restructure and recapitalisation of the Group in
March 2022 we have been able to turn our attention fully to production
maintenance and enhancement activities. This, along with the benefit of
greater access as Covid-19 restrictions have lifted, means we have since seen
steady improvement with production rates improving during the first half of
2022 and ranging between 375 - 400 barrels of oil produced per day towards the
end of 2H2022. Given current oil prices, and with the in-country cost
structure we now have in place, this means we have achieved our first goal: a
baseline level of production that can sustain the business in Trinidad (the
average oil price realised in 2021 was approximately US$60 per barrel, a level
considerably below current prices being realised).
Beyond this, we hope to see further improvements in the coming months as
various production enhancement initiatives are rolled-out, and we've developed
a plan for additional field work, potential new well drilling, and various
Enhanced Oil Recovery (EOR) initiatives over the coming 12 months. We are also
continuously assessing various opportunities to expand our producing asset
base through adding new licences.
Therefore, in relation to the "below ground" challenge we face in Trinidad, my
report is that 2021 and the first half of 2022 were periods of laying
foundations, but we are still at the early stages of executing a long-term
plan to build a production base of scale in Trinidad. I hope next year to be
able to report on our continued progress.
Other Activities
Notwithstanding the unambiguous focus placed on the production business in
Trinidad and Tobago since mid-2021, we continued to progress the broader asset
portfolio, albeit in a low-cost, "below the radar" way. These activities can
be summarised as follows:
Weg naar Zee PSC in Suriname
There was no field activity in relation to the WNZ block in Suriname during
2021. We had initially hoped for drilling of an initial pilot well in late
2021 or early 2022, but the pandemic made this impossible - Covid-19
restrictions in Suriname remained in place until early 2022. Instead, we took
the opportunity during 2021 to completely revisit all of our assumptions on
this project and update our thoughts on well design and development pacing. We
have also applied for an extension of the initial period under our licence,
given the delays occasioned by the pandemic - approval is pending with the
regulators. Subject to this approval, we expect to be able to resume activity
in Suriname during 2023, and between now and then, we are working on
developing potential partnering opportunities for this asset. Further updates
will be provided in due course.
AREA OFF-1 in Uruguay
In June 2020, we were awarded the AREA OFF-1 licence block, offshore Uruguay.
However, through all of 2021 there was minimal activity on the licence, while
we waited for its ratification by the Uruguayan Ministry and regulatory
agency, ANCAP. This had been delayed due to the impacts of Covid-19 in
Uruguay. Subsequently, it was only on 25 May 2022 that all procedural matters
were completed and the licence formally executed. As a result, our initial
four-year exploration period only commenced on 25 August 2022.
To remind shareholders, our minimum work obligation for this period is to
licence 2,000 kms of 2D seismic from ANCAP, to reprocess / re-interpret that
data, and to complete two geological studies. There is no obligation to
acquire 3D seismic, nor obligation to drill a well in the first exploration
period. We are well advanced in the process of meeting this minimum work
obligation, having recently licenced the required 2D seismic, with
reprocessing already underway - we expect to have the full results of this
work in early 2023.
We anticipate that this initial activity - low cost as it may be - will prove
to be very timely, because the delay experienced while waiting for formal
licence ratification has been serendipitous. Specifically, as I noted in the
2020 Annual Report, two "wildcat" exploration wells had been planned for late
2021 in Namibia by two different majors (Total Energies and Shell), on the
conjugate margin of AREA OFF-1, and we were thus keenly interested in the
outcomes. As it turns out, in both cases the drill results, which became known
in February 2022, were what have been described as "mega-discoveries".
This in turn has unleashed a huge amount of industry interest over the past
few months not only offshore Namibia, but also offshore Uruguay and northern
Argentina, because the successful Namibian wells have de-risked the potential
presence of a high-quality, oil-prone source rock and charge on the western
sides of the South Atlantic margin. The Uruguayan basin has thus become,
almost overnight, an emerging industry "hotspot". For AREA OFF-1 in
particular, the chance of eventual success has increased significantly, with
multiple leads and prospects and a resource potential in excess of 1 billion
barrels.
Of course, it is perfectly understandable that shareholders might be
sceptical, given the recent exploration experiences in The Bahamas and
Trinidad. However, Uruguay is a different asset in both below and above ground
profile, and success or failure in one location is not indicative of the
potential of another entirely independent play or drill prospect. More than
that, the early proof is that in May 2022 Shell and APA (a division of Apache)
both bid for and were awarded licences in Uruguay - including AREA OFF-2 which
is directly adjacent to AREA OFF-1. But whereas our minimum work obligation,
as set in 2020, was modest, Shell and APA have committed to spending more than
US$200 million on their Uruguayan acreage in the coming years. Clearly,
therefore, we are not the only ones who see great promise in Uruguay.
Finally, it is also worth noting that our early entry, first-mover strategy
for Uruguay is different to previous ventures, in that we are going to seek a
partner very early in the asset life cycle, so that the Group does not bear
all of the financial risk. We have already seen strong interest in potential
partnering arrangements from multiple parties, and we will update shareholders
as matters develop.
ESG
At Challenger Energy, achieving our commercial objectives will never be at the
expense of harm to people or the environment - this is a non-negotiable
principle of how we do business. Moreover, as a participant in the
international energy industry, everything we do depends on what is sometimes
described as the "social licence to operate": the way in which our activities
and operations impact on our employees, stakeholders, host Governments,
regulators, the communities in which we live and work, and the environment.
Maintaining consistently excellent performance in relation to what is nowadays
generally referred to as ESG (Environmental, Social and Governance) has become
critical for many businesses in the modern world, not just because it is a
moral duty, but because it makes good business sense.
The Group thus devotes a considerable amount of focus to this area, every day.
We have full-time staff committed to ensuring strong ESG performance, overseen
at Board level by a Health, Safety, Environment & Security (HSES)
Committee. This Committee meets regularly to ensure adequacy of and compliance
with standards, processes, systems and procedures. Beyond this, we seek to
embed ESG awareness into every aspect of the business, and every person who
works at Challenger Energy, no matter their seniority, role or location, is
required as a condition of their job to participate actively in various
ESG-related activities - things as diverse as crisis management simulations,
daily safety briefings, diversity training, and anti-bribery and corruption
seminars.
The results of this commitment to ESG as a business priority have been
evident. As already noted, during 2021 the Group operated two substantial and
complex drilling campaigns, in two different countries, and at the peak of the
pandemic. Both drilling campaigns were completed without any incident -
whether personal injury, property damage or environmental. More generally, the
Group's operations throughout 2021, routine and non-routine, took place
without the occurrence of any Lost Time Incidents, and in the same period we
saw a marked improvement in staff morale and the manner in which external
stakeholders viewed and engaged with the Group. We were especially pleased,
after an extensive audit process, to be awarded Safe to Work (STOW)
accreditation for the first time. This certification is local to Trinidad and
Tobago, and is only given to companies that are adjudged to possess a
world-class, robust and functional HSES Management System.
There is always room for improvement in the area of ESG, and over the coming
year we will continue to seek out ways to do even better, as well as formalise
a structure for setting ESG goals and then tracking and reporting against
those goals. Overall, however, I believe that shareholders should be pleased
with the Group's ESG performance and track record in 2021. Further details in
relation to ESG are set out on page 11 of this Annual Report.
Corporate Restructuring
As noted, the two wells drilled during the first half of 2021 were both
completed safely and without incident, and advanced our technical
understanding of the relevant reservoirs, thus providing key inputs for
consideration of future activity plans which in the long-run we hope will yet
offer value creation opportunities. However, I do not wish to sugar-coat the
fact that neither of the wells were the immediate success we had been hoping
for. Perseverance-1 did not prove commercial volumes of hydrocarbons,
Saffron-2 was not able to achieve sustained production from the deeper Cruse
reservoir units that we were targeting and the final cost of both wells was
considerably higher than anticipated pre-drill.
These were clearly not the outcomes longstanding shareholders (myself
included) had been hoping for. But, as I have commented before, this is the
risk assumed when investing in the oil and gas exploration business. Companies
with significant exposure to exploration outcomes will inevitably face adverse
business and financial consequences if those outcomes are below expectation.
In our case, the below expectation outcomes of the two successive drills meant
that in my initial few months as CEO (I assumed the role in June 2021), the
priority became to initiate a difficult but necessary Group restructuring
process.
First, we engaged in a dialogue with various contractors and creditors,
reaching common agreement with almost every contractor and creditor whereby
each agreed to accept a discounted payment in final settlement for work
undertaken on the drilling campaigns. Second, we worked to reshape our
operations and reduce the overhead costs of the business - ultimately by
approximately 80%. Third, as mentioned previously, we refocused the business
strategy so as to prioritise our producing assets in Trinidad and Tobago. And
fourth, we brought in fresh capital.
The overall process took some time to complete, but in March 2022 we
successfully closed a fundraising of approximately
US$10 million, which allowed us to complete the restructure, clean up the
balance sheet and put the Group into a position where
it was largely free of financial debts, and able to fund planned activities
during 2022.
As we wrapped up the restructuring process in March 2022, a number of members
of the Board and executive ceased in various roles, Iain McKendrick joined as
our new Non-Executive Chairman, and several key hires, especially in support
of our operations in Trinidad and Tobago, took effect. We also changed our
corporate broker and "revamped" many of our longstanding corporate advisory
and services relationships, in pursuit of further operating efficiencies and
cost reductions.
Finally, it is worth mentioning that through the restructuring process we were
able to attract a number of larger shareholders to our register, such that as
at the date of this report approximately 45% of the Group's shares are now
held by a relatively small group of shareholders and management (including
myself).
2022, 2023, and Beyond
In summary, 2021 can largely be described as having been a year of two
distinct parts for the Group: the first half of the year dominated by active
exploration and appraisal drills in The Bahamas and then Trinidad; and
directly following on from that, the second half of the year (and into the
first half of 2022), dominated by the work needed to "reset" the Group based
upon the outcomes of those drilling activities.
We have come through that now, and Challenger Energy's go-forward business
strategy is guided by a simple objective: to focus on production, to manage
costs tightly, and to thereby grow cashflow from the Trinidadian operations.
At the same time, we will seek to maximise value of the other exploration
assets by introducing strategic partners as early as possible.
In pursuit of this objective, during 2021 we made strong progress
operationally, and the business today is leaner, more responsive, and
unburdened of legacy issues. We have also undoubtedly benefitted from the
rising oil price environment, such that our operations in Trinidad &
Tobago have reached a point where they are largely self-sustaining.
This improved operational position has also provided the platform on which we
can work towards a broader goal: the Group as a whole generating positive
operating cashflow. Achieving this goal will require being able to drive an
increase in production from current levels, a task which has been a
work-in-progress to-date, and which work will continue into 2023. As noted in
my report above, this is not a simple technical "nut" to crack, given that the
fields we have are mature, and production is often disrupted for reasons we
cannot always control (wells go offline, power supplies get disrupted in
inclement weather, etc). We have, however, been seeing good initial results
from the work we are doing to maintain and optimise field performance, and we
have outlined a plan for further field improvements, new well drilling and
various Enhanced Oil Recovery (EOR) initiatives over the coming 12 months, so
we remain hopeful we will get there.
We also expect that the next 12 months will be a defining time for our asset
in Uruguay, and which I hope might provide an unexpected upside surprise for
shareholders. As mentioned before, the industry we operate in is cyclical, and
the cycle appears to once again be turning, with interest in high-quality
exploration prospects on the increase. We should be a prime beneficiary if
this trend continues.
Finally, I would like to take this opportunity to thank all those Board
members, employees and consultants who made a contribution to Challenger
Energy - in some cases over many years - but who, as a result of the
restructuring during 2021, are no longer with the Group. We are grateful for
your past efforts. I would also like to extend my sincere thanks to all of our
continuing staff, who have given 100% at all times. And collectively, all of
us who work at Challenger Energy wish to express our deep appreciation for the
patience and support we have received over the past 18 months, from
stakeholders, regulators, suppliers, contractors and especially our
shareholders, old and new.
Eytan Uliel
Chief Executive Officer
29 September 2022
Assets Summary
Trinidad and Tobago
The Group has five producing fields and one dormant field, all onshore
Trinidad and Tobago. Across the fields there are a total of approximately 250
wells, of which approximately 80 are in production at any given time. The
Group also has a large licence position in the South-West Peninsula of
Trinidad (SWP), with a potential shallow development project at the Bonasse
licence (based on the outcomes of the Saffron-1 and Saffron-2 wells drilled in
2020 and 2021 respectively), and several exploration prospects identified in
the SWP more broadly.
Goudron Field
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
terms 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 Field
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 September 2022 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 has
identified certain well recompletion opportunities and is undertaking a
comprehensive well optimisation and swabbing programme with the objective of
achieving production stability, growth and longevity, and reduced field
operating costs. During 2020 and 2021, a CO2 enhanced oil recovery pilot
project was undertaken on the field and the Group continues to undertake
technical work to evaluate potential to undertake further CO(2) projects in
other parts of the field.
South Erin Field
The Group owns and operates 100% of the South Erin field by way of a farm-out
agreement with Heritage. The farm-out agreement has been renewed until 31
December 2023 and is extendable up to 30 September 2031 subject to work
programme completion. The Group is in the process of defining a well drilling
programme targeting additional production from undrained reservoir
compartments, and that would satisfy the work programme requirements necessary
for extension of the farm-out agreement.
Southwest Peninsula (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.
Cory Moruga Field
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). The Group has formally
written to the Trinidadian Ministry of Energy and Energy Industries ("MEEI")
proposing a programme of further appraisal work conditional on past dues being
waived and annual licence fees being rebased to an appropriate level. To the
extent a suitable arrangement of this nature cannot be agreed with MEEI, the
Group intends to surrender the licence.
Suriname - Wag naar Zee Project
The Group holds 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"). The PSC has a 30-year term with
the initial exploration period expiring in October 2022. The Group has applied
to extend the initial exploration term for a period of 18 months given
disruptions occasioned by the Covid-19 pandemic, and confirmation of such
extension is pending.
WNZ is a large block covering approximately 900 km(2) in a proven hydrocarbon
province with 70 historical wells and 2D seismic coverage. Up to 24 MMbbls
STOIIP (15° API) has been identified in eight pools with the CPR assessing 2C
resources of 1.1 MMbbls and 3C resources of 3.5 MMbbls.
The Group is currently working with Gaffney, Cline & Associates to review
the available technical information pertaining to the WNZ block and redesign
an extended well test accordingly, which is likely to include a horizontal
pilot well along with the potential use of certain enhanced oil recovery
techniques, so as to maximise production and oil recovery from the reservoir.
Uruguay
The Group holds a 100% working interest in and is the operator of the 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 AREA OFF-1 block covers a total area of 14,557 km(2) and is situated in
water depths ranging from 20 to 1,000 metres, approximately 100 kms off the
Uruguayan coast. The Group's minimum work obligation during the initial
four-year exploration period is to undertake relatively modest and low-cost
reprocessing and reinterpretation of selected historical 2D seismic. There is
no 3D seismic or drilling obligation in the initial phase. The relatively
modest level of work required in the initial licence phase reflects the
first-mover advantage gained by the Group in applying for its Uruguay acreage
based on perceived technical merit in April 2020, notwithstanding the then
uncertain potential longer-term impacts of the Covid-19 pandemic.
The prospect and lead screening undertaken by ANCAP, the Uruguayan oil and gas
regulatory body, includes the specific identification of the syn-rift Lenteja
prospect on AREA OFF-1 with a P50 estimated ultimate recovery volume (EUR) of
1.359 billion barrels of oil and, located in just 80 metres of water depth.
This volume estimate is consistent with the Group's internal estimate.
The AREA OFF-1 play system is directly analogous to the recent prolific,
conjugate margin discoveries made offshore Namibia by TotalEnergies (Venus
well) and Shell (Graff well), where reported multi-billion-barrel Cretaceous
turbidite reservoirs have been encountered. The AREA OFF-1 licence exhibits
the same Aptian play source rock as these Namibia discoveries with similar
petroleum systems present and hence the AREA OFF-1 is thought to be analogous
with these recent discoveries.
More recently, on 23 June 2022, ANCAP announced that three further offshore
blocks had been awarded - two to Shell (including one block directly adjacent
to the Group's AREA OFF-1 block) and one to APA (a division of Apache). Both
awards have been granted with substantial minimum work obligations, as
announced by ANCAP to be over US$200 million in aggregate between the 3
blocks.
The Group has recently licenced 2,000 kms of legacy 2D seismic data and
commenced reprocessing of this data. This work would allow for the Group to
undertake geological and geophysical studies, identify specific leads and
prospects, update the resource assessment, and thus complete all of the
minimum work obligation for the entire first four-year exploration term by
early 2023. In parallel, the Group is considering early-stage partnership
possibilities for the AREA OFF-1 licence, with a view to expediting 3D seismic
acquisition and processing work.
The Bahamas
The Group is the 100% owner of four conjoined exploration licences offshore
The Bahamas. The Perseverance-1 exploration well was drilled in the licence
area, from 20 December 2020 to 7 February 2021, at a location approximately 20
miles from the Bahamas-Cuba maritime border, in water depth of approximately
518 metres. Perseverance-1 represented the first exploration drilling in The
Bahamas since the mid-1980s, and the first test of any prospect located in
deeper waters off the shallower water carbonate banks.
The well reached a depth of 3,905 metres, having intersected five Albian,
Upper Aptian, and Mid-Aptian horizons of interest but did not result in a
commercial discovery at the drilling location. Notwithstanding the outcome of
Perseverance-1, 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 - all of
which might merit further exploration activity in the future. As such, the
Group is considering partnering opportunities for any potential next phase of
activity in The Bahamas. In parallel, in March 2021, the Group notified the
then Government of The Bahamas of its intent to renew the licences into a
third 3-year exploration period. A new Government was elected in The Bahamas
in September 2021, and the Group is engaging with the administration on the
renewal process.
Reserves and Resources
In late 2020, the Group commissioned an independent Competent Person's Report
("CPR") from ERC Equipoise ("ERCE"). The scope of the report was to focus on
reserves and resources across the Group's producing assets in Trinidad and
Tobago, and the Group's Weg naar Zee licence in Suriname. ERCE certified net
2P reserves of 1.29 MMbbls and net 2C contingent resources of 7.46 MMbbls
across the portfolio of assets in Trinidad and Suriname, summarised as
follows:
Reserves (MMbbls)(1) 1P 2P 3P
Total as of 30 September 2020(3) 0.69 1.29 1.92
Contingent Resources (MMbbls)(2) 1C 2C 3C
Total as of 30 September 2020(3) 0.71 7.46 24.70
Remaining Estimated Ultimate Recoverable
The CPR also included the Remaining Estimated Ultimate Recoverable ("Remaining
EUR") volumes, without considering economic limit and excluding contingent
resources, across the Group's five producing fields as of 30 September 2020 at
low, best and high levels of confidence. An aggregate summary of the Remaining
EUR volumes as of 30 September 2020 as per the ERCE CPR and the Group's
internal estimate of Remaining EUR volumes as of 31 December 2021, after
adjusting for production from October 2020 to December 2021, are summarised
below:
Remaining EUR (MMbbls)(4) High (1P) Best (2P) Low (3P)
Total Remaining EUR as of 30 September 2020(3) 0.97 1.69 2.69
Less: Production for the period from 1 October 2020 to 31 December 2021 (0.17) (0.17) (0.17)
Estimated Remaining EUR as of 31 December 2021(5) 0.80 1.52 2.52
Notes
1. Group Working Interest reserves are based on the working interest share
of the field gross resources and are prior to deduction of royalties but after
applying economic cut-off. Challenger Energy hold a 100% interest in all
relevant fields, being Goudron, Inniss-Trinity, South Erin, Icacos and Bonasse
in Trinidad, and Weg naar Zee in Suriname.
2. The Contingent Resources are on unrisked basis and have not been risked
for chance of development and are sub-classified as development unclarified.
3. Totals are added arithmetically which means statistically there is a
greater than 90% chance of exceeding the total IP or 1C and less than a 10%
chance of exceeding the total 3P or 3C.
4. Remaining Estimated Ultimate Recoverable volumes are volumes estimated to
be technically recoverable from the existing wells across the five producing
fields. These estimates do not consider economic limit and exclude contingent
resources. High (1P), Best (2P) and Low (3P) represent level of confidence.
5. Estimated Remaining EUR as of 31 December 2021 is the Group's internal
estimate of volumes based on volumes estimated in the CPR as of 30 September
2020 reduced by the volume of production for the period from 1 October 2020 to
31 December 2021. This estimate is not certified by ERCE and has not been
included in the CPR.
6. ERCE did not audit the Group's prospective exploration acreage in the
South West Peninsula of Trinidad as part of its CPR.
2P reserves relate to known oil that is capable of being produced
economically, and thus the 2P reserves as certified by ERCE relate solely to
production capable of being generated from the Group's existing wells in
existing fields. The 2P reserves do not assume any contribution from infill
drilling and enhanced oil recovery projects. Moreover, apart from routine
operating costs required to keep wells online, accessing this production
potential does not require material amounts of incremental capital
expenditure.
At oil prices ranging from US$60 to US$90 per barrel, it is estimated this
level of 2P reserves represent US$75 million to
US$120 million of gross cashflow potential to the Group, and a reserve base
equivalent to a baseline production of 400 bopd for approximately nine years.
Environmental, Social and Corporate
Governance Report
In recent years, many businesses, including those operating in the energy
industry, have seen an emerging need to develop strategies relating to, and
then monitoring and reporting performance against, a diverse range of business
activities that collectively are commonly referred to as Environmental, Social
and Corporate Governance, or "ESG". In broad terms:
· Environment relates to considerations of the impact that a
company's business has on the natural environment, and how to best minimise /
manage that impact. Relevant areas include the energy a company utilises in
conducting its business, the waste it produces, the resources it needs, and
the consequences of its operations in terms of emissions, waste, water,
biodiversity and climate change.
· Social relates to the manner in which a company seek to
discharge its broader social obligations, including those owed to its
employees, external stakeholders, and the communities in which it operates.
Relevant areas include employee engagement and training, diversity and
inclusion, labour relations, and community involvement and development.
· Governance relates to the controls and procedures a company
adopts to govern itself. Examples of relevant governance areas include
considerations of board composition, how a company's board functions in
practice, and preventing bribery and corruption.
Set out below are details of Challenger Energy's ESG Philosophy and Management
framework, approach to Corporate Governance and certain other ESG related
areas, as well as selected ESG Highlights from 2021.
ESG Philosophy and Management
At Challenger Energy, we believe that pursuit of 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. Our objective is to create a
working environment that supports our people while challenging them to deliver
their best and to develop their own skills and experiences.
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. We are committed to
promoting an environment where our people learn and develop in a collaborative
manner, regardless of who they are.
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. We
recognise and respect the dignity of all human beings and seek to improve the
life of the communities in which we function. 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 committed
to the responsible stewardship of the environment and at all times we seek to
operate safely and responsibly. During operations we maintain work procedures
and field access infrastructure to minimise encroachment on the environment,
and we remain alert at all times to potential environmental hazards and
incidents that can result from our operations, as well as having clear and
tested response protocols should any incidents occur. At the conclusion of our
operations, we return our sites to the condition in which we found them. 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 with
Company-wide application, designed to promote and foster excellence in all
relevant areas of HSES. The HSES Management System is reviewed periodically,
and was substantially revised and updated in early 2021, the focus of doing so
being to ensure that a functional system, tailored to the needs of the Group's
operations, is in place and operating effectively at all times.
A central component of the HSES Management System is the HSES Working Group,
which comprises Board members, senior executives, and representatives from all
levels of operations. The HSES Working Group functions without hierarchy, and
meets weekly to ensure adequacy of and compliance with HSES standards,
processes, systems and procedures. The HSES Working Group operates
independently from, and reports to, the formal HSES Committee of the Board of
Directors (as described under Corporate Governance, below).
Corporate Governance
Challenger Energy operates in the energy sector, a global industry that is
typically subject to strict laws and rules and regulations imposed by host
Governments and international regulators, as well as intense public scrutiny
given the essential nature of the product we supply and the risks associated
with that supply. 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.
The QCA Code emphasises the need for well balanced, effective boards, with a
strong emphasis on overseeing risk management aimed at protecting the Group
from unnecessary risk to enable the Group to secure its long-term future. In
addition, the QCA Code highlights the alignment of remuneration policies with
shareholder interests and sound shareholder relations. 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. The
Board currently consists of the Chairman, the Chief Executive Officer, and two
Non-executive Directors. All Directors have access to the Company Secretary
and the Group's professional advisers.
Records of the board meetings
There were 14 board meetings of the parent entity of the Group during the
financial year.
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 in particular direct access to the Group's
auditor. The Audit Committee meets on a regular basis, and in 2021 met on four
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 2021 met on two occasions, with all members being present for
all meetings.
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 2021 the
HSES Committee met on 11 occasions, with all members being present for all
meetings.
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
The Directors have prepared a cash flow forecast which anticipates the Group
and Company being able to continue in operation for at least the next twelve
months from the date of this report. The forecasts include certain assumptions
and underlying estimates. Certain of these items are outside of the Group and
Company's control and unfavourable actual outcomes may materially and
adversely affect the Group's cash resources and cast significant doubt about
the Group and the Company's ability to continue as a going concern, as further
detailed in the independent auditor's report. Further information regarding
the appropriateness of the use of the going concern assumption in the basis of
preparation can be found in note 1 to the consolidated financial statements.
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 2021, 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 is committed to
fighting these threats by harnessing the strength of the Group and its
associates. The Group exercises the utmost vigilance wherever its operations
are taking place. 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 2021, over 100 anti-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.
2021 ESG Highlights
Challenger Energy intends to adopt a formalised ESG monitoring / reporting
framework in 2023. However, the diverse aspects that comprise ESG have always
been treated as business priorities for Challenger Energy, and thus ESG
awareness, performance culture and accountability is already embedded across
the Group. It is a core principle of how we do business that the pursuit of
ESG excellence should not just be an aspirational statement, but rather should
manifest daily in tangible actions and activities, with measurable impact,
across every aspect of the Group's business.
During 2021, all Group policies and procedures were reviewed and updated, and
a comprehensive business continuity plan was prepared and adopted. In
addition, key ESG-related themes of specific relevance to the Group's expanded
operations were selected for emphasis throughout the year. These themes were
(i) behavioural safety, (ii) training, (iii) Covid-19 management, and (iv) the
environment.
Specific ESG-related highlights of note from 2021 are:
· There were no Lost Time Incidents recorded in 2021 in any
of the Group's operations, both routine and non-routine. This exemplary track
record has continued into 2022 - from the start of January 2022 to the date of
this report, no Lost Time Incidents have been recorded in any of the Group's
operations.
· Two complex drilling campaigns were carried out during
2021 - the Perseverance-1 well offshore The Bahamas, and the Saffron-2 well
onshore in Trinidad. Both drilling campaigns were executed safely and
responsibly, without any incidents or harm to people or the environment, and
in full compliance with all applicable laws, regulations and international
standards.
· It is a requirement by Heritage Petroleum Company
Limited, the Trinidadian state-owned oil & gas company, that all
contractors and operators are Safe-To-Work ("STOW") certified. Challenger
Energy underwent the requisite STOW audit process in February 2021 and
attained accreditation for a 2-year period in August 2021. Being independently
accredited was a milestone event for the Group.
· In 2021, the Group obtained all relevant approvals from
NIMOS, the Surinamese environmental regulator, for the drilling of an initial
test well in Suriname (albeit the drilling did not subsequently proceed, owing
to the impact of the pandemic). Similarly, the Group had previously (in 2020)
obtained Environmental Approval ("EA") for the drilling of Perseverance-1 in
The Bahamas. In early 2021 the Group vigorously defended a legal challenge
that had been brought in The Bahamas seeking to halt the drilling programme on
the basis of alleged inadequacies of the EA. Drilling proceeded and the legal
challenge was ultimately dismissed in May 2021, reflecting the robust,
world-class work undertaken by the Group in preparing the EA over a period of
more than 2 years.3
· In terms of field operations, three areas of specific
relevance to the Group's operations were selected for focus during 2021. These
were:
o water disposal: the Group's activities result in production of a
considerable volume of water, which prior to release into the environment
undergoes treatment to ensure it is free of contaminants, so as to minimise
harm to the environment. A programme was initiated to evaluate the potential
for unused well within the producing fields to be reassigned as water disposal
wells, which (subject to regulatory approval) would enable produced and
treated water to be injected back into the ground, and thus not discharged
into the natural environment at all. Evaluation is ongoing, with the
expectation is that initial water reinjections might commence in 2023;
o field energy efficiency: a field-wide programme was implemented to
introduce more sustainable and efficient pumps. The impact was a measurable
impact in well runtimes and uptimes for relevant wells, and a measured 5%
increase in energy efficiency; and
o roads: a road audit was undertaken, resulting in various road repairs
and improvements initiated across the Group's Trinidad portfolio. Road repair
and improvement allows for greater operating efficiencies, as well as reducing
driver fatigue, wear and tear of vehicles and carbon emissions, and rig
movements.
· Challenger Energy's goal is to operate with zero
environmental incidents. During 2021 there was one environmental incident,
which was occasioned as a result of illegal dumping of waste hydrocarbon
substances by third parties in one of the Group's site pits at an operating
field in Trinidad. Adverse weather in the area led to the pit overflowing, and
a number of nearby residences being affected by oil contaminated floodwaters.
Notwithstanding that the incident arose as a result of illegal third-party
activity, because it involved the Group's assets the incident was managed in
accordance with the Group's incident response and contingency plans. This
included the Group arranging for clean-up of all affected residences, and care
packages being distributed to affected people. Heritage and all relevant
regulatory agencies in Trinidad were informed, a number of post incident site
visits were conducted, and the measures taken by the Group in response to this
incident was found to be satisfactory, with no residual environmental impact.
· The Group's HR focus in 2021 was to ensure a competent
and trained workforce, reflecting the increased scope of the Group's
activities in the period. This involved a systematic programme of internal and
external meetings, engagements and formal training programs, including a
number of sizeable incident response simulations, mandatory attendance at
various training events, and the roll-out of various initiatives specifically
targeting practical areas of concern. This included internal awareness
sessions conducted in the areas of risk assessment and job safety analysis,
oil spill response, permit to work, management of change and incident
reporting and investigation. Additionally, external training sessions were
provided to employees in Defensive Driving, First Aid and CPR, Fire Warden and
Well Control. The Group exceeded almost all internal-set metrics established
in relation to engagement and training. For example, the Group has an internal
goal to undertake one "toolbox talk" safety briefing per day, or a target of
365 each full year. During 2021, a total of 665 such toolbox talks were
conducted.
· In terms of community engagement, the focus in 2021 was
to assist with ameliorating the impacts of the pandemic in local communities
in which we operate. In Trinidad, this took the form of the Group
participating in a programme of computer equipment donation in the
Guayaguayare, Moruga and Southwest Peninsula areas, to enable online schooling
during the pandemic for children whose families would otherwise have been
unable to afford the equipment. In The Bahamas, the Group provided aid to a
number of families severely impacted as a result of Covid-19 lockdowns, in the
form of emergency food supplies and rental assistance.
· More broadly, the Group has continued throughout to
support local education and community service, in addition to social and
community cash contributions required as conditions of the Group's various
licences. Tangible support initiatives have included Christmas Hamper
donations to families in need in more remote areas of Trinidad, a donation to
the Mayaro Past Pupils Association towards their SEA Awards and Back to School
Initiative, the sponsorship of two students pursuing Master of Science and
Public Health degrees in Suriname, the sponsorship of an MBA and LLB Admission
to Bar in The Bahamas, and the support (both in terms of time and money) of
UK-based staff participating in the UK Army Reserves.
· In relation to Covid-19, throughout 2021 stringent
protocols were implemented on a Group-wide basis focused on social behaviours
and interaction in the workplace, and covering all field staff and
office-based staff. Working from home was encouraged where possible and clear
protocols were put in place for instances when symptoms were identified or
suspected. Specific Covid-19 protocols enabled uninterrupted operations
throughout 2021, including during the two drilling campaigns in the first half
of the year. A concerted effort was made to encourage vaccination across the
Group, with the Company-wide vaccination rate as at the end of 2021
approximately 80%, well in excess of national averages in jurisdictions of
operation.
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 targeted
development activity across the existing portfolio together with selective
acquisition activity to grow the asset portfolio.
The Group's current production is derived from later-life production assets
that are in the latter portion of the production decline curve.
Potential impact: High Probability: Moderate
Risk appetite
The continued 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 ultimate success of the Group is based on its ability to maintain and grow
production from existing assets and to create value through targeted
development activity across the existing portfolio together with selective
acquisition activity to grow the asset portfolio.
The Group has some tolerance for this risk and acknowledges the need to have
effective controls in place in this area.
Mitigation
The Group's current production derived from later-life production assets that
are in the latter portion of the production decline curve. 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 is undertaken
periodically by an independent petroleum engineering firm.
The recently appointed country manager for Trinidad is a qualified reservoir
engineer with significant Trinidad and other international experience, having
previously worked with a major international reservoir engineering firm for
more than 15 years.
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 will selectively add new development or production onshore Trinidad
or elsewhere in the Atlantic margin through
specific and M&A activity or partnering arrangements with drilling
contractors related to the existing Trinidad fields.
The Group holds an appraisal / development asset in Suriname that is related
to an existing production area. Development options for the asset remain under
consideration and may involve farm-out of a portion of the asset as a method
of financing. The development of Suriname, if successful, will mitigate this
risk.
In addition, the Group holds an exploration licence in Uruguay that is on the
conjugate margin of recent significant discoveries by both Shell and
TotalEnergies offshore Namibia. Progressing work in Uruguay will likely
include some form of partnering, for instance through farm-out, to share risk
and bring additional experience and financing to pursue higher capital work
programme so as to de-risk and make the project drill-ready.
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 track record over many years of successfully raising finance
to fund its activities as and when required.
Funds raised in March 2022 (the most recent capital raising) are being
deployed in specific, targeted development activity including lower-risk
recompletions to open new productive zoned in existing production wells. Funds
are also being deployed for
the purchase of additional in-field equipment to reduce reliance on third
party contractors and their availability to undertake straightforward workover
activity.
The objective of the planned work is to increase production in order to move
the Trinidad assets from self-sufficiency to cashflow accretive. Generating
surplus cash from operations is expected to translate to additional funding
options including reserve based lending and other potential alternative
financing.
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 2021 Corruption Perceptions Index for the jurisdictions where
the Group has presence are as below:
2021 2021
(2020) (2020)
Jurisdiction Rank score
The Bahamas 30 (30) 64 (63)
Suriname 87 (94) 39 (38)
Trinidad and Tobago 82 (86) 41 (40)
United Kingdom 11 (11) 78 (77)
Uruguay 18 (21) 73 (71)
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 would adversely affect the Group's
profitability, cash flow, financial position, and ability to invest.
Oil sales in Trinidad are closely linked to the West Texas Intermediate (WTI)
crude oil benchmark price with the realised oil price by the Group being
typically at approximately 10% discount to the WTI benchmark.
In addition, the Trinidad supplementary petroleum tax regime has a regressive
effect when realised oil prices are between US$75 and US$95 per barrel. This
is due to SPT applying at a flat rate above the trigger oil price (presently,
US$75).
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 benefit 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 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. Impact of Covid-19 virus
The emergence of Covid-19 as a global pandemic has had a significant effect on
economies worldwide and has been disruptive to
commercial and operating activity.
Potential impact: High Probability: Moderate
Appetite
The Covid-19 virus that was first identified in China in late 2019 spread
rapidly in early 2020, becoming prevalent in Europe and Asia initially,
followed by North America, South America, and Africa. Almost all countries
have now been affected by the virus that is extremely contagious.
The almost universal initial governmental response was one of social
distancing, self-isolation and quarantine. Whilst the global roll-out of
vaccines has largely mitigated the most severe consequences of contracting
Covid-19, not all jurisdictions have the same level of vaccine uptake or are
as advanced in their roll-out programmes as they might be.
Mitigation
The Group has strict Covid-19 protocols at all locations and operates an
active isolation and test programme where Covid-like
symptoms are experienced by staff or contractors.
The Group actively encourages the take-up of vaccinations by all staff. The
Group has a low appetite for risk related to Covid-19 and has contingency /
business continuity plans in place in the event of another Covid-19 wave or a
similar health emergency.
10. Fiscal and political
The majority of the Group's operations are located in Trinidad and Tobago and
it is therefore exposed to both in-country fiscal and
political risk. In addition, the Group has operations in The Bahamas, Suriname
and Uruguay with limited activity at present.
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 in Trinidad and Tobago dollars as
majority of the Group's activities are presently in Trinidad and Tobago, and
Pound Sterling as a significant amount of the Group's cash holdings are
denominated in Pound Sterling. Currency hedging instruments are not currently
used due to the historically stable relationship between the Trinidad and
Tobago dollar and the United States dollar (the functional currency of the
companies comprising the Group) and unexpected recent volatility in Pound
Sterling.
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. The Group
interacts indirectly with the Trinidad and Tobago Government through its
relationships with both the state-owned oil and gas company and the Ministry
of Energy and Energy Industries. The Group does not undertake any lobbying
activity with any members of the Trinidad and Tobago Government or in any
other jurisdiction.
Fiscal
The currency used in Trinidad is the Trinidad and Tobago dollar (TTD) and has
been relatively stable, fluctuating between
TTD 6.60 and TTD 6.80 to the US dollar during the reporting period. Similarly,
Pound Sterling has been relatively stable fluctuating
between USD 1.32 to USD 1.42 to the Pound Sterling during the reporting
period, however, has witnessed sharp depreciation
recently.
Political
The Group considers the jurisdictions of its operations to have low political
risk. World Bank's Worldwide Governance Indicators
(2020 percentile rankings, 100 being the highest rank) for the jurisdictions
where the Group has presence are set out below:
Jurisdiction Political Stability and Absence of Violence / Terrorism Government Effectiveness
The Bahamas 73.58 69.71
Suriname 58.96 33.17
Trinidad and Tobago 53.3 61.06
United Kingdom 61.31 89.42
Uruguay 87.74 75.00
Mitigation
Fiscal
The relationship of the TTD to the US dollar is subject of a managed float
regime under which the exchange rate is actively managed by the Government of
Trinidad and Tobago through currency purchases and sales. Pound Sterling on
the other hand is largely a floating currency and exposed to market
volatility. 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.
Political
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 the state-owned oil and gas company and the
Ministry of Energy and Energy Industries in relation to its operations in
Trinidad and maintains a regular and open dialogue with each. In addition, the
Group interacts with the Bahamian Government in relation to the renewal of its
licences in The Bahamas.
No Russian Exposure
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 2021.
Directors
The following persons were Directors of the Company during the financial year
under review:
Stephen Bizzell (appointed 1 June 2021)
Adrian Collins (resigned 25 May 2021)
Leo Koot (resigned 22 January 2021)
Ross McDonald (resigned 1 June 2021)
Simon Potter
William Schrader (resigned 5 March 2022)
James Smith (resigned 5 March 2022)
Eytan Uliel (appointed 1 June 2021)
Subsequent to the financial year under review, the following persons joined
the Board of Directors:
Iain McKendrick (appointed 5 March 2022)
Timothy Eastmond (appointed 5 March 2022, resigned 15 July 2022)
Principal Activity
The principal activity of the Group and the Company consists of oil & gas
production, development, appraisal and exploration in Trinidad and Tobago,
Suriname, Uruguay and The Bahamas.
Results and dividends
The results of the Group for the year are set out on page 28 and show a loss
for the year ended 31 December 2021 of $23,697,000 (2020: loss of
$13,992,000). The total comprehensive expense for the year of $23,845,000
(2020: expense of $13,845,000) has been transferred to the retained deficit.
The Directors do not recommend payment of a dividend (2020: nil).
Significant Shareholders
The following tables represent shareholdings of 3% or more notified to the
Company at 31 December 2021 and at the date of this report respectively:
Top shareholders at 31 December 2021 (by parent company)
Shareholder 31-Dec-21 %
Hargreaves Lansdown Asset Management 147,595,687 18.53
Interactive Investor 95,437,257 11.98
Bizzell Capital Partners 87,658,600 11.01
Halifax Share Dealing 72,591,395 9.11
Barclays Wealth 39,293,238 4.93
TOTAL 442,576,177 55.56
Top shareholders as of the date of this Report (by parent company)
Shareholder At the date of this report %
Bizzell Capital Partners 914,633,600 9.51
Choice Investments (Dubbo) Pty Ltd 837,000,000 8.70
Hargreaves Lansdown Asset Management 780,382,175 8.11
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
Jarvis Investment Management 509,491,516 5.30
Merseyside Pension Fund 417,350,000 4.34
G.P. (Jersey) Ltd 390,000,000 4.05
RAB Capital Holdings Ltd 336,800,000 3.50
UBS 309,668,912 3.22
TOTAL 6,128,700,165 63.71
Directors' Shareholding and Options
The interests in the Company 31 December 2021 and at the date of this Report
respectively 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.
Director Number of Shares Number of Options
31-Dec-21 31-Dec-21
William Schrader (resigned 5 March 2022) 2,713,138 1,800,000
James Smith (resigned 5 March 2022) 1,451,134 1,650,000
Simon Potter 12,436,472 8,750,000
Eytan Uliel (appointed 1 June 2021) 10,373,962 19,500,000
Stephen Bizzell (appointed 1 June 2021) 4,314,286 -
Director Number of Shares date of this report Number of Options
date of this report
William Schrader (resigned 5 March 2022) 29,796,471 -
James Smith (resigned 5 March 2022) 19,159,467 -
Simon Potter 71,462,807 -
Eytan Uliel (appointed 1 June 2021) 545,373,962 340,000,000
Stephen Bizzell (appointed 1 June 2021) 51,189,286 -
Iain McKendrick (appointed 5 March 2022) 50,000,000 100,000,000
Record of Board Meetings
There were 14 board meetings of the parent entity of the Group during the
financial year.
Director Number of Board Meetings Attended Number of Board Meetings Eligible to Attend
William Schrader (resigned 5 March 2022) 13 14
James Smith (resigned 5 March 2022) 14 14
Eytan Uliel (appointed 1 June 2021) 7 7
Simon Potter 14 14
Stephen Bizzell (appointed 1 June 2021) 7 7
Adrian Collins (resigned 25 May 2022) 7 7
Ross McDonald (resigned 1 June 2021) 7 7
Leo Koot (resigned 22 January 2021) 2 2
21
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") as adopted by the European Union. 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 as adopted by the European Union 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
29 September 2022
Independent auditor's report to the members
of Challenger Energy Group PLC
Report on the audit of the financial statements
Our opinion
In our opinion, Challenger Energy Group PLC's consolidated and company
financial statements (the "financial statements"):
· give a true and fair view of the state of the Group's affairs as
at 31 December 2021 and of its loss and its cash flows for the year then ended
in accordance with International Financial Reporting Standards as adopted by
the European Union;
· give a true and fair view of the state of the Company's affairs
as at 31 December 2021 and of its cash flows for the year then ended in
accordance with International Financial Reporting Standards as adopted by the
European Union as applied in accordance with the provisions of the Isle of Man
Companies Act 1982; and
· have been properly prepared in accordance with the Isle of Man
Companies Acts 1931 to 2004. What we have audited
Challenger Energy Group PLC's financial statements comprise:
· the consolidated and company statements of financial position as
at 31 December 2021;
· the consolidated statement of comprehensive income for the year
then ended;
· the consolidated and company statements of changes in equity for
the year then ended;
· the consolidated and company statements of cash flows for the
year then ended; and
· the notes to the financial statements, which include significant
accounting policies and other explanatory information.
Basis for opinion
We conducted our audit in accordance with International Standards on Auditing
("ISAs"). Our responsibilities under those standards are further described in
the "Auditor's responsibilities for the audit of the financial statements"
section of our report.
We believe that the audit evidence we have obtained is sufficient and
appropriate to provide a basis for our opinion.
Independence
We are independent of the Group in accordance with the International Code of
Ethics for Professional Accountants (including International Independence
Standards) issued by the International Ethics Standards Board for Accountants
("IESBA Code"). We have fulfilled our other ethical responsibilities in
accordance with the IESBA Code.
Material uncertainty related to going concern
In forming our opinion on the financial statements, which is not modified, we
have considered the adequacy of the disclosures made in note 1.28 (ii) of the
financial statements concerning the Group's and the Company's ability to
continue as a going concern.
As at 31 December 2021, following the difficulties experienced drilling
Perseverance-1, the Group and Company had cash and cash equivalents of $1.6
million and $0.9 million and trade and other payables of $23.5 million and
£10.8 million respectively. Management were in the process of restructuring
the Group, which required shareholder and creditor agreement and additional
fund raising.
Subsequent to the year end, the restructuring was progressed with settlement
agreements for creditors and an additional $10 million (before expenses)
raised through the issue of new shares. Following the restructuring, the
Directors have prepared a cash flow forecast which anticipates the Group and
Company being able to continue in operation for at least the next twelve
months from the date of this report. However, as explained in note 1.28 (ii)
the cash flow forecast includes a number of underlying assumptions and
estimates. Certain of these items are outside of the Group and Company's
control and unfavourable actual outcomes may lead to the Group and Company
needing to take additional measures such as fund raising, cost savings or the
sale of assets.
These conditions, along with the other matters explained in the notes to the
financial statements, indicate the existence of a material uncertainty that
may cast significant doubt on the Group's and the Company's ability to
continue as a going concern.
The financial statements do not include the adjustments that would result if
the Group and the Company were unable to continue as a going concern. In
auditing the financial statements, we have concluded that the directors' use
of the going concern basis of accounting in the preparation of the financial
statements is appropriate.3
Our evaluation of the directors' assessment of the Group's and the 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 to other external and internal sources, including the impairment
assessments, where appropriate;
· assessing and validating the impact of post year end cash
movements and commitments;
· 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.
Our responsibilities and the responsibilities of the directors with respect to
going concern are described in the relevant sections of this report.
Our audit approach
Overview
As part of designing our audit, we determined materiality and assessed the
risks of material misstatement in the financial statements. In particular, we
considered 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. As in all of our
audits, we also addressed the risk of management override of internal
controls, including among other matters, consideration of whether there was
evidence of bias that represented a risk of material misstatement due to
fraud.
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
period. These matters were addressed in the context of our audit of the
financial statements as a whole, and in forming our opinion thereon, and we do
not provide a separate opinion on these matters.
Key audit matter How our audit addressed the key audit matter
Recoverability of the Group's intangible exploration and evaluation assets / We critically evaluated management's assessment of each impairment trigger per
Recoverability of the Company's investment in subsidiaries and amounts owed by 'IFRS 6 - Exploration for and Evaluation of Mineral Resources', including but
subsidiary undertakings (Group and Company) not limited to:
Refer to notes 1.28, 10, 14 and 16 of the financial statements. · Assessing whether the Group had the rights to explore in the relevant
geographical areas by obtaining supporting documentation such as licence
At 31 December 2021 the carrying value of the intangible exploration and agreements and assessed compliance with licence conditions.
evaluation assets was $94.4 million (2020: $75.3 million). As the carrying
value of these intangible exploration and evaluation assets are significant to · Enquiring to determine whether management had the intention to carry
the financial statements of the Group, we consider it necessary to assess out exploration and evaluation activity in the relevant exploration areas. We
whether any facts or circumstances exist to suggest that the carrying amount reviewed management's cash flow forecast models to assess the level of the
of these assets may exceed their recoverable amount. budgeted expenditure on these areas, and obtained details of contracts.
The Company's investment in subsidiaries holding the Group's intangible · Critically assessing the outcome of drilling activities as to whether
exploration and evaluation assets totalled $29.6 million (2020: $29.6 million) any impairment indicators were present to suggest that the carrying value of
and the amount owed by subsidiary undertakings totalled $113.2 million (2020: these exploration and evaluation assets is unlikely to be recovered through
$83.8 million). The recoverability of the Company's investments in development or a sale.
subsidiaries and amounts owed by subsidiary undertakings are dependent on
successful development or sale of the respective licence areas. · Validating the capitalised costs on a sample basis for adherence with
the criteria set out in IFRS 6.
Having completed our work, we did not identify any material misstatements
regarding the carrying value of the intangible exploration and evaluation
assets and, as a result, no material issues were noted with respect to the
recoverability of the Company's investment in subsidiaries and amounts owed by
subsidiary undertakings.
Key audit matter How our audit addressed the key audit matter
Recoverability of the Group's tangible oil and gas assets / Recoverability of Our audit work included, but was not restricted to:
the Company's investment in subsidiaries (Group and Company)
Refer to notes 1.28, 11 and 14 to the financial statements.
· Assessing the impairment model prepared by management and challenging
the key assumptions in the discounted value in use cash flows, remaining
sceptical of explanations and obtaining supporting evidence as necessary.
At 31 December 2021 the carrying value of the tangible oil and gas assets
after management's impairment was $21.0 million (2020: $22.3 million). · Considering whether the model used was appropriate and checking the
related calculations and production assumptions.
· Discussing key assumptions underlying the impairment model with
As the carrying value of these tangible oil and gas assets are significant to management and performing procedures to validate their reasonableness.
the financial statements of the Group, we consider it necessary to assess
whether any facts or circumstances exist to suggest that the carrying amount · Independently determining WACC rates and comparing with management's
of these assets may exceed their recoverable amount. assessment.
· Reviewing projections and sensitivities including independent stress
testing of key WACC, oil price, capex and decline rate assumptions.
The Company's investment in subsidiaries holding the Group's tangible oil and
gas assets totalled $21.4 million (2020: $21.4 million). The recoverability of · Issuing instructions to and directing the work of the component
these investments in subsidiaries is dependent on successful development and auditor in Trinidad in relation to the audit of tangible oil and gas assets.
commercial exploitation, increasing production through optimisation of
existing wells, drilling of new infill wells and/or the application of · Holding regular meetings with and reviewing the working papers of the
improved oil recovery methods or alternatively, sale of the respective licence component auditor to ensure that sufficient appropriate audit evidence was
areas. obtained over the recoverability of the Group's tangible oil and gas assets.
Having completed our work, we did not identify any material misstatements
regarding the carrying value or disclosures of the tangible oil and gas assets
and, as a result, no material issues were noted with respect to the
recoverability of the Company's investment in subsidiaries.
Other information
The other information comprises all of the information in the Annual Report
and Financial Statements 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 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 identified above 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, 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 the directors for the financial statements
The directors are responsible for the preparation of the financial statements
that give a true and fair view in accordance with International Financial
Reporting Standards as adopted by the European Union and Isle of Man law, and
for such internal control as the directors determine is necessary to enable
the preparation of financial statements that are free from material
misstatement, whether due to fraud or error.
In preparing the financial statements, the directors are responsible for
assessing the Group's 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 the directors either intend to
liquidate the Group and Company or to cease operations, or have no realistic
alternative but to do so.
Auditor's responsibilities for the audit of the financial statements
Our objectives 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 our opinion.
Reasonable assurance is a high level of assurance, but is not a guarantee that
an audit conducted in accordance with ISAs 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.
As part of an audit in accordance with ISAs, we exercise professional
judgement and maintain professional scepticism throughout the audit. We also:
· Identify and assess the risks of material misstatement of the
financial statements, whether due to fraud or error, design and perform audit
procedures responsive to those risks, and obtain audit evidence that is
sufficient and appropriate to provide a basis for our opinion. The risk of not
detecting a material misstatement resulting from fraud is higher than for one
resulting from error, as fraud may involve collusion, forgery, intentional
omissions, misrepresentations, or the override of internal control.
· Obtain an understanding of internal control relevant to the audit
in order to design audit procedures that are appropriate in the circumstances,
but not for the purpose of expressing an opinion on the effectiveness of the
Group's and Company's internal control.
· Evaluate the appropriateness of accounting policies used and the
reasonableness of accounting estimates and related disclosures made by the
directors.
· Conclude on the appropriateness of the directors' use of the
going concern basis of accounting and, based on the audit evidence obtained,
whether a material uncertainty exists related to events or conditions that may
cast significant doubt on the Group's and Company's ability to continue as a
going concern. If we conclude that a material uncertainty exists, we are
required to draw attention in our auditor's report to the related disclosures
in the financial statements or, if such disclosures are inadequate, to modify
our opinion. Our conclusions are based on the audit evidence obtained up to
the date of our auditor's report. However, future events or conditions may
cause the Group and Company to cease to continue as a going concern.
· Evaluate the overall presentation, structure and content of the
financial statements, including the disclosures, and whether the financial
statements represent the underlying transactions and events in a manner that
achieves fair presentation.
· Obtain sufficient appropriate audit evidence regarding the
financial information of the entities or business activities within the Group
to express an opinion on the consolidated financial statements. We are
responsible for the direction, supervision and performance of the Group audit.
We remain solely responsible for our audit opinion.
We communicate with the directors regarding, among other matters, the planned
scope and timing of the audit and significant audit findings, including any
significant deficiencies in internal control that we identify during our
audit.
We also provide the directors with a statement that we have complied with
relevant ethical requirements regarding independence, and to communicate with
them all relationships and other matters that may reasonably be thought to
bear on our independence, and where applicable, actions taken to eliminate
threats or safeguards applied.
From the matters communicated with the directors, we determine those matters
that were of most significance in the audit of the financial statements of the
current period and are therefore the key audit matters. We describe these
matters in our auditor's report unless law or regulation precludes public
disclosure about the matter or when, in extremely rare circumstances, we
determine that a matter should not be communicated in our report because the
adverse consequences of doing so would reasonably be expected to outweigh the
public interest benefits of such communication.
This report, including the opinion, has been prepared for and only for the
Company's members as a body in accordance with Section 15 of the Isle of Man
Companies Act 1982 and for no other purpose. We do not, in giving this
opinion, accept or assume responsibility for any other purpose or to any other
person to whom this report is shown or into whose hands it may come save where
expressly agreed by our prior consent in writing.
Report on other legal and regulatory requirements
Adequacy of accounting records and information and explanations received
Under the Isle of Man Companies Acts 1931 to 2004 we are required to report to
you by exception if, in our opinion:
· we have not received all the information and explanations we
require for our audit;
· proper books of account have not been kept, or proper returns
adequate for our audit have not been received from branches not visited by us;
· the company financial statements are not in agreement with the
books of account and returns; and
· certain disclosures of directors' loans and remuneration
specified by law have not been complied with.
We have no exceptions to report arising from this responsibility.
Andrew Dunn
for and on behalf of PricewaterhouseCoopers LLC
Chartered Accountants
Douglas, Isle of Man
29 September 2022
Consolidated Statement of Comprehensive
Income
For the year ended 31 December 2021
Note Year ended 31 December 2021 $ 000's Year ended 31 December 2020 $ 000's
Net petroleum revenue 2 4,360 1,417
Cost of sales
(6,121) (2,781)
Gross loss (1,761) (1,364)
Administrative expenses 3 (9,098) (9,793)
Impairment charges 3/10/11 (7,416) (2,435)
Operating foreign exchange (losses) / gains (17) 32
Operating loss (18,292) (13,560)
Other income 256 3
Finance income 9 7 202
Finance costs 9 (5,630) (628)
Loss before taxation (23,659) (13,983)
Income tax expense 5 (38) (9)
Loss for the year attributable to equity holders of the parent company (23,697) (13,992)
Other comprehensive income
Exchange differences on translation of foreign operations (148) 147
Other comprehensive (expense)/income for the year net of taxation (148) 147
Total comprehensive expense for the year attributable to equity holders of the (23,845) (13,845)
parent company
Loss per share (cents)
Basic and diluted 8 (3.6) (0.5)
All operations are considered to be continuing (see note 2).
The accompanying accounting policies and notes form an integral part of these
financial statements.
Consolidated Statement of Financial Position
At 31 December 2021
Note At 31 December 2021 $ 000's At 31 December 2020 $ 000's
Assets
Non-current assets
Intangible exploration and evaluation assets 10 94,405 75,259
Goodwill 10/15 4,610 4,610
Tangible assets 11 22,748 25,783
Right of use assets 12 14 97
Investment in associate 13 - 47
Escrow and abandonment funds 16 1,564 1,297
Deferred tax asset 5 6,929 8,975
Total non-current assets 130,270 116,068
Current assets
Trade and other receivables 16 4,274 5,313
Inventories 17 259 172
Restricted cash 18 560 946
Cash and cash equivalents 1,555 17,862
Total current assets 6,648 24,293
Total assets 136,918 140,361
Liabilities
Current liabilities
Trade and other payables 19 (23,537) (18,620)
Lease liabilities 20 (36) (105)
Borrowings 21 (643) (498)
Total current liabilities (24,216) (19,223)
Non-current liabilities
Borrowings 21 (187) (1,639)
Provisions 22 (6,294) (6,314)
Deferred tax liability 5 (6,941) (8,974)
Total non-current liabilities (13,422) (16,927)
Total liabilities (37,638) (36,150)
Net assets 99,280 104,211
Shareholders' equity
Called-up share capital 23 218 123
Share premium reserve 23 171,734 152,717
Share based payments reserve 24 5,312 5,228
Retained deficit (101,381) (77,684)
Foreign exchange reserve (1) 147
Convertible debt option reserve 21 114 396
Other reserves 23 23,284 23,284
Total equity attributable to equity holders of the parent company 99,280 104,211
The accompanying accounting policies and notes form an integral part of these
financial statements.
These financial statements were approved and authorised for issue by the Board
of Directors on 29 September 2022 and signed on its behalf by:
Eytan Uliel Simon Potter
Director
Director
Company Statement of Financial Position
At 31 December 2021
Note At 31 December 2021 $ 000's At 31 December 2020 $ 000's
Assets 11 59 78
Non-current assets 12 14 12
Property, plant and equipment 14 50,940 50,940
Right of use assets
Investment in subsidiaries 16 113,187 83,839
Trade and other receivables
Total non-current assets 164,200 134,869
Current assets
Trade and other receivables 16 166 238
Restricted cash 18 57 57
Cash and cash equivalents 914 17,160
Total current assets 1,137 17,455
Total assets 165,337 152,324
Liabilities
Current liabilities
Trade and other payables 19 (10,775) (504)
Lease liabilities 20 (14) (13)
Borrowings 21 (462) -
Total current liabilities (11,251) (517)
Non-current liabilities
Borrowings 21 - (1,120)
Total non-current liabilities - (1,120)
Total liabilities (11,251) (1,637)
Net assets 154,086 150,687
Shareholders' equity
Called-up share capital 23 218 123
Share premium reserve 23 171,734 152,717
Share based payments reserve 24 4,942 4,858
Retained deficit (52,457) (36,942)
Convertible debt option reserve 21 114 396
Other reserve 23 29,535 29,535
Total equity attributable to equity holders of the parent company 154,086 150,687
The accompanying accounting policies and notes form an integral part of these
financial statements.
These financial statements were approved and authorised for issue by the Board
of Directors on 29 September 2022 and signed on its behalf by:
Eytan Uliel Simon Potter
Director
Director
Consolidated Statement of Cash Flows
For the year ended 31 December 2021
Year ended 31 December 2021 $ 000's Year ended 31 December 2020 $ 000's
Cash flows from operating activities
Loss before taxation (23,659) (13,983)
Decrease/(increase) in trade and other receivables 772 (204)
Decrease in trade and other payables and provisions (5,105) (1,164)
Increase in inventories (87) (18)
Impairment of goodwill - 2,435
Impairment of tangible and intangible assets 7,416 -
Depreciation of property, plant and equipment (note 11) 2,944 1,446
Depreciation of right of use asset (note 12) 86 214
Loss on disposal of investment in associate 47 -
Loss on disposal of property, plant and equipment (note 11) 11 105
Amortisation (note 10) 263 113
Share settled payments (note 24) 644 2,455
Other income (256) (3)
Finance income (note 9) (7) (202)
Finance costs (note 9) 5,630 628
Share based payments (note 24) 84 360
Income tax paid (99) (9)
Foreign exchange loss/(gain) on operating activities 17 (32)
Net cash outflow from operating activities (11,299) (7,859)
Cash flows from investing activities
Purchase of property, plant and equipment (note 11) (5,385) (228)
Proceeds from sale of property, plant and equipment 36 -
Payments for exploration and evaluation assets (13,745) (14,566)
Decrease/(increase) in restricted cash 386 (9)
Cash acquired from business combination (note 15) - 1,039
Other income received 256 3
Interest received (note 9) 7 202
Net cash outflow from investing activities (18,445) (13,559)
Cash flows from financing activities
Issue of ordinary share capital 14,456 29,536
Share issue costs (19) -
Principal elements of lease payments (note 20) (86) (216)
Interest payable on lease liabilities (note 20) (7) (17)
Finance costs (2,575) (176)
Repayment of borrowings (648) (2,694)
Proceeds of borrowings 2,259 1,515
Net cash inflow from financing activities 13,380 27,948
Net (decrease)/increase in cash and cash equivalents (16,364) 6,530
Effects of exchange rate changes on cash and cash equivalents 57 180
Cash and cash equivalents at beginning of year 17,862 11,152
Cash and cash equivalents at end of year 1,555 17,862
The accompanying accounting policies and notes form an integral part of these
financial statements.
Company Statement of Cash Flows
For the year ended 31 December 2021
Year ended 31 December 2021 $ 000's Year ended 31 December 2020 $ 000's
Cash flows from operating activities
Loss before taxation (15,515) (12,392)
Decrease/(increase) in trade and other receivables 72 (14)
Increase/(decrease) in trade and other payables 23 (869)
Depreciation (notes 11 and 12) 37 31
Provision for doubtful recovery of intercompany receivable 5,813 7,171
Share settled payments 638 2,455
Other income - (3)
Finance income - (46)
Finance costs 5,418 81
Foreign exchange loss/(gain) on operating activities 213 (142)
Share based payments (note 24) 84 360
Net cash outflow from operating activities (3,217) (3,368)
Cash flows from investing activities
Payments to acquire tangible assets (note 11) (3) (79)
Interest received (note 9) - 46
Other income received - 3
Increase in restricted cash - (31)
Advances to and payments on behalf of group companies (27,239) (21,610)
Net cash outflow from investing activities (27,242) (21,671)
Cash flows from financing activities
Issue of ordinary share capital 14,456 29,536
Share issue costs (19) -
Principle elements of lease payments (note 20) (16) (15)
Interest payable on lease liabilities (note 20) (1) (1)
Finance costs (2,369) (79)
Proceeds of borrowings 2,259 1,515
Net cash inflow from financing activities 14,310 30,956
Net (decrease)/increase in cash and cash equivalents (16,149) 5,917
Effects of exchange rate changes on cash and cash equivalents (97) 143
Cash and cash equivalents at beginning of year 17,160 11,100
Cash and cash equivalents at end of year 914 17,160
The accompanying accounting policies and notes form an integral part of these
financial statements.
Statement of Changes in Equity
For the year ended 31 December 2021
Called up share capital $ 000's Share premium reserve $ 000's Share based payments reserve $ 000's Retained deficit $ 000's Foreign exchange reserve $ 000's Convertible Other reserves $ 000's Total
debt option
Equity
$ 000's
reserve
$ 000's
Group 61 96,157 4,868 (63,692) - - 23,284 60,678
- - - (13,992) - - - (13,992)
- - - - 147 - - 147
At 1 January 2020
Loss for the year
Currency translation
differences
Total comprehensive (expense)/income - - - (13,992) 147 - - (13,845)
Share capital issued Recognition of conversion feature (note 21) 62 56,560 - - - - - 56,622
- - - - - 396 - 396
Share based payments - - 360 - - - - 360
Total contributions by and distributions to owners of the Company 62 56,560 360 - - 396 - 57,378
At 31 December 2020 123 152,717 5,228 (77,684) 147 396 23,284 104,211
Loss for the year - - - (23,697) - - - (23,697)
Currency translation
differences - - - - (148) - - (148)
Total comprehensive expense - - - (23,697) (148) - - (23,845)
Share capital issued Recognition of conversion feature (note 21) Realisation 95 19,017 - - - - - 19,112
of conversion feature (note 21)
- - - - - 505 - 505
- - - - - (787) - (787)
Share based payments - - 84 - - - - 84
Total contributions by and distributions to owners of the Company 95 19,017 84 - - (282) - 18,914
At 31 December 2021 218 171,734 5,312 (101,381) (1) 114 23,284 99,280
Called up share capital $ 000's Share premium reserve $ 000's Share based payments reserve $ 000's Retained deficit $ 000's Convertible Other Total
debt option
reserve
Equity
$ 000's
$ 000's
reserve
$ 000's
Company 61 96,157 4,498 (24,551) - 29,535 105,700
- - - (12,391) - - (12,391)
At 1 January 2020
Loss for the year
Total comprehensive expense - - - (12,391) - - (12,391)
Share capital issued 62 56,560 - - - - 56,622
Recognition of conversion feature (note 21) - - - - 396 - 396
Share based payments - - 360 - - - 360
Total contributions by and distributions to owners of the Company 62 56,560 360 - 396 - 57,378
At 31 December 2020 123 152,717 4,858 (36,942) 396 29,535 150,687
Loss for the year - - - (15,515) - - (15,515)
Total comprehensive expense - - - (15,515) - - (15,515)
Share capital issued 95 19,017 - - - - 19,112
Recognition of conversion feature (note 21) - - - - 505 - 505
Realisation of conversion feature (note 21) - - - - (787) - (787)
Share based payments - - 84 - - - 84
Total contributions by and distributions to owners of the Company 95 19,017 84 - (282) - 18,914
At 31 December 2021 218 171,734 4,942 (52,457) 114 29,535 154,086
The accompanying accounting policies and notes form an integral part of these
financial statements.
Notes to the financial statements for the year ended 31 December 2021
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 holder of several oil & gas exploration and production
licences located in Trinidad & Tobago, Suriname, Uruguay 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 34 North Quay, Douglas,
Isle of Man IM1 4LB. 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) as adopted by the European
Union. The Company's financial statements have been prepared in accordance
with IFRS as adopted by the European Union 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.
New and revised standards and interpretations not applied
Certain new accounting standards and interpretations have been published that
are not mandatory for 31 December 2021 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 1.28 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.
The investment in associate (an entity over which the Group has significant
influence) has been recorded at cost and has not been adjusted to reflect the
Group's 25% share of the net profits/losses and assets/liabilities of the
associate from the date of acquisition to the balance sheet date as it was
deemed immaterial.
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 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 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 statement of
comprehensive income.
Gains and losses on disposals are determined by comparing proceeds with
carrying amount and are recognised in the statement of comprehensive income.
1.11 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.
1.12 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.
1.13 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 Statement of comprehensive income.
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.
1.14 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.
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.
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.
1.15 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', 'escrow 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.
1.16 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.
1.17 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 proceeds. Net proceeds are disclosed in the
statement of changes in equity.
1.18 Finance costs
Borrowing costs are recognised as an expense when incurred.
1.19 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. 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 our
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.
1.20 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.
1.21 Dividends
Dividends are reported as a movement in equity in the period in which they are
approved by the shareholders.
1.22 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 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.
1.23 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 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.
1.24 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 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 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.
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.
1.25 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 three geographical
segments: Trinidad and Tobago and Suriname, the Bahamas 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.
1.26 Share issue expenses and share premium account
Costs of share issues are written off against the premium arising on the
issues of share capital.
1.27 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.
1.28 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 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 2021 is $101,405,000
(31 December 2020: $72,885,000) relating to the cost of exploration licences,
geological and geophysical consultancy, seismic data acquisition and
interpretation and the drilling of exploration wells, being made up of
$93,952,000 (2020: $72,880,000) in exploration costs in the Bahamian offshore
licences and $7,453,000 (2020: $3,176,000) of costs over exploration licences
in Trinidad. 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 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 was 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. Commercial volumes of movable
hydrocarbons were not present at this drilling location. Subsequently the
Group has undertaken 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 has undertaken 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 2021. 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 on 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. The Group has and 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.
In June 2021 the Group notified the Government of The Bahamas that it did not
intend to further discussions regarding renewal of the Miami licence area,
against which capitalised costs totalling $416,000 were carried. The Group has
thus impaired these costs in full in the financial statements to 31 December
2021.
Trinidad and Tobago oil and gas exploration costs
The exploration oil and gas costs in relation to the Group's business in
Trinidad and Tobago predominantly relate to the Group's Bonasse field onshore
Trinidad. The Bonasse field comprises of historical wells in production, as
well as the two further recent wells, namely the Saffron-1 well drilled in
2020 and the Saffron-2 well drilled during 2021.
The Saffron-1 well resulted in the discovery of oil in the deeper Lower Cruse
horizon in addition to proving reservoir continuity and producibility in the
shallower Upper Cruse and Middle Cruse horizons. Following this, the Saffron-2
well was drilled during 2021 with the Lower Cruse horizons as the primary
target for testing, as well as to confirm reservoir continuity and
producibility in the Upper and Middle Cruse horizons. The Saffron-2 well was
successfully drilled to the Lower Cruse horizon and demonstrated flow of oil
to surface from the Lower Cruse horizon, however, the well could not be put on
sustained production due to technical and mechanical issues encountered during
attempted production tests in the Lower Cruse horizon. Subsequently, the Lower
Cruse horizon was isolated and the well was completed in the Middle Cruse
horizon.
Based on the results of the Saffron-1 and the Saffron-2 wells and the
broadened subsurface understanding, the Company considers that a shallow well
development on the Bonasse licence is potentially viable, and the Group is in
the process of undertaking detailed evaluation to identify potential well
locations that would allow for a field development plan to be carefully
validated and submitted to the Trinidadian Ministry of Energy and Energy
Resources.
The Group has therefore determined that there is no indication that the
carrying value of this asset is impaired at 31 December 2021.
Impairment of Trinidad and Tobago intangible and tangible oil and gas assets
and property plant and equipment The Directors carried out an impairment
review of the Group's tangible and intangible 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, and again at 31 December
2020. Consequently, an impairment of related intangible assets of $1,653,000
(2020: nil) and tangible assets of $5,347,000 (2020: nil) within this CGU has
been recognised at balance sheet date. No impairment has been recognised to
goodwill of $4,610,000 (2020: $2,435,000) at the balance sheet date. Refer to
note 10 (intangible assets) and note 11 (tangible assets).
(ii) Going concern
These financial statements have been prepared by the Directors on a going
concern basis, which assumes that the Group
and Company will continue in operation for the foreseeable future.
As at 31 December 2021, the Group and Company had $1,555,000 and $914,000 in
unrestricted cash funding respectively.
Subsequent to the end of the financial year, in March 2022 the Group and
Company completed a comprehensive restructuring and recapitalisation exercise
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 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 subsequent to the year-end, predominantly in the first
quarter of 2022. As a substantial majority of these settlement agreements were
conditional on making settlements post year end, the liabilities as of the
balance sheet date reflect full amounts that would otherwise have been payable
in the absence of settlement agreements (see Note 19 for further information);
and
iii) the Company reducing its net current liability position from
approximately $10.1 million at balance sheet date to a net current asset
position of approximately $4.1 million as a result of the settlements and
recapitalisation made subsequent to year end.
Following the restructuring and recapitalisation, the Directors have prepared
a cash flow forecast which anticipates the Group and Company being able to
continue in operation for at least the next twelve months from the date of
this report.
The cash flow forecast includes underlying assumptions and estimates,
including oil price, sustained production from the Group's producing fields in
Trinidad and Tobago along with certain incremental production from the
intended work programme, reliability of reserves estimates and renewal of
licences upon expiry.
In addition, the projections assume offsetting of certain tax liabilities and
deferral of certain historical liabilities in Trinidad
and Tobago that the Directors believe are either not likely to require
settlement in cash or are capable of being deferred and settled on long-dated
payment terms so as to not require material amounts of cash during the
forecast period.
Certain of these items are outside of the Group and Company's control and
unfavourable actual outcomes may materially and adversely affect the Group's
cash resources and cast significant doubt about the Group and the Company's
ability to continue as a going concern. In such an event, the Group and the
Company may be required to implement certain other measures including, but not
limited to,
i) raising additional third-party capital in form of equity,
debt or other instruments of a similar nature, and / or
ii) undertake cost reduction, and / or
iii) sell certain assets of the Group,
and a successful outcome of such measures cannot be guaranteed.
These financial statements do not include the adjustments that would result if
the Group or the Company were unable to continue as a going concern.
Following the outbreak of the Covid-19 global pandemic, the Group had
implemented appropriate remote working procedures, where necessary, across all
of its teams and operations to ensure the ongoing safety of its staff and
consultants. As a consequence, the Group does not consider the Covid-19
pandemic to have any material impact on its operations.
(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 2021 stood at $50,940,000 (2020:
$50,940,000) and $113,187,000 (2020: $83,839,000) 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 2021 a loss allowance for expected credit losses of $12,984,000
(2020: $7,171,000) was held in respect of the recoverability of amounts due
from subsidiary undertakings.
1.29 Earnings per share
Basic earnings 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.
1.30 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 three geographical segments:
Trinidad & Tobago & Suriname (operating), The Bahamas (operating) and
The Isle of Man, UK, Uruguay, 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 non-operating segment
including the Isle of Man (the Group's parent), which provides management
service to the Group and entities in Uruguay, 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, or in the case of Uruguay had not yet
commenced operations as of the year-end. Their results are consolidated and
reported on together as a single segment.
Year ended 31 December 2021 Trinidad & Suriname Operating $ 000 Bahamas Non-Operating Entities (*) Total
Operating
$ 000 $ 000
$ 000
Operating loss by geographical area 4,360 - - 4,360
Net petroleum revenue (**)
Operating loss (11,638) (2,083) (4,571) (18,292)
Other income 75 16 165 256
Finance costs (209) (3) (5,418) (5,630)
Finance income 7 - - 7
Loss before taxation (11,765) (2,070) (9,824) (23,659)
Other information
Depreciation, amortisation (3,185) (54) (54) (3,293)
Impairment charges (7,000) (416) - (7,416)
Capital additions 5,385 21,486 20 26,891
Segment assets
Tangible and intangible assets 23,061 93,991 4,725 121,777
Deferred tax asset 6,929 - - 6,929
Escrow and abandonment funds 1,564 - - 1,564
Trade and other receivables 3,519 542 213 4,274
Inventories 259 - - 259
Restricted cash 503 - 57 560
Cash 591 4 960 1,555
Consolidated total assets 36,426 94,537 5,955 136,918
Segment liabilities
Trade and other payables (11,615) (1,049) (10,873) (23,537)
Borrowings (368) - (462) (830)
Deferred tax liability (6,941) - - (6,941)
Lease liabilities - (22) (14) (36)
Provisions (3,760) - (2,534) (6,294)
Consolidated total liabilities (22,684) (1,071) (13,883) (37,638)
Year ended 31 December 2020 Trinidad & Bahamas Non-Operating Entities (*) Total
Suriname
Operating
Operating
$ 000 $ 000
$ 000
$ 000
Operating loss by geographical area 1,417 - - 1,417
Net petroleum revenue (**)
Operating loss (3,081) (2,167) (8,312) (13,560)
Other income - - 3 3
Finance costs (96) (21) (511) (628)
Finance income - - 202 202
Loss before taxation (3,177) (2,188) (8,618) (13,983)
Other information
Depreciation, amortisation (1,529) (197) (47) (1,773)
Impairment charges - - (2,435) (2,435)
Capital additions 78 22,441 79 22,598
Segment assets
Tangible and intangible assets 27,985 73,000 4,764 105,749
Investment in associate 47 - - 47
Deferred tax asset 8,975 - - 8,975
Escrow and abandonment funds 1,297 - - 1,297
Trade and other receivables 3,123 1,882 308 5,313
Inventories 172 - - 172
Restricted cash 889 - 57 946
Cash 577 97 17,188 17,862
Consolidated total assets 43,065 74,979 22,317 140,361
Segment liabilities
Trade and other payables (8,979) (8,738) (903) (18,620)
Borrowings (1,017) - (1,120) (2,137)
Deferred tax liability (8,974) - - (8,974)
Lease liabilities (41) (51) (13) (105)
Provisions (3,562) - (2,752) (6,314)
Consolidated total liabilities (22,573) (8,789) (4,788) (36,150)
(*) Intercompany balances and transactions between Group entities have
been eliminated.
(**) Sales revenues were derived from a single customer within each of these
operating countries.
3 Operating loss - Group 2021 $ 000's 2020
$ 000's
Operating loss is arrived at after charging:
Fees payable to the Company's auditors and its associates for:
- the audit of the Company and Group financial statements 325 315
- non audit related services - 48
Directors' emoluments - fees and benefits (*) 1,311 1,693
Impairment of goodwill (**) - 2,435
Impairment of tangible and intangible assets 7,416 -
Loss on disposal of associate 47 -
Depreciation (***) 3,030 1,660
Amortisation 263 113
(*) See note 7 for further details.
(**) See note 10 for further details.
(***) Depreciation of certain oil and gas assets of $2,330,000 (2020:
$1,113,000) has been recognised within cost of sales.
2021 $ 000's 2020
$ 000's
Administrative expenses
Staff costs - cash settled 2,714 1,521
Staff costs - share settled (note 24) 506 1,425
Travel and accommodation 190 206
Professional fees - cash settled 2,896 3,324
Professional fees - share settled (note 24) 482 1,030
Depreciation and amortisation 963 660
Share based payments 84 360
Other 1,263 1,267
Total 9,098 9,793
4 Staff costs - Group
2021 2020
$ 000's $ 000's
Wages and salaries - cash 3,230 1,733
Wages and salaries - share settled (note 24) 506 1,425
Share based payments 17 169
Other staff costs 483 441
Total 4,236 3,768
5 Taxation - Group
2021 2020
$ 000's $ 000's
Analysis of tax charge in the year 38 9
Tax charge on ordinary activities
Factors affecting the tax charge for the year:
Loss on ordinary activities before tax 23,659 13,983
Standard rate of income tax in the IOM -% -%
Loss on ordinary activities multiplied by the standard rate of income tax - -
Effects of:
Overseas tax on profits 38 9
Current tax charge for the year 38 9
Deferred tax:
The net deferred tax balances solely relate to the Company's Trinidad and
Tobago operations. The components of the asset and
liability for the years ended December 31, 2021 and 2020 were as follows:
2021 $ 000's 2020
$ 000's
Losses carried forward 6,929 8,974
Leased property
- 1
Deferred tax asset 6,929 8,975
Property and equipment 6,941 8,974
Deferred tax liability 6,941 8,974
Deferred tax assets related to tax losses have been recognised to the extent
to which deferred tax liabilities have been recognised 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 2021, the Group had an unrecognised deferred tax
asset of $47,000,000 (2020: $47,700,000) calculated at 46.8% (2020: 45.7%)
(weighted average across taxable entities) in respect of an estimated
$123,100,000 (2020: $100,500,000) 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 statement of comprehensive income for the year have given
rise to a net deferred tax charge of nil (2020: nil).
6 Dividends
During the year, no dividends were paid or proposed by the Directors (2020:
nil).
7 Directors' remuneration - Group 2021 2020
$ 000's
$ 000's
Directors' remuneration (details set out in tables below) 1,311 1,693
Cash Share based *Share-settled
payments Other payments payments Total
Directors' remuneration - 2021 $ 000's $ 000's $ 000's $ 000's $ 000's
Executive Directors
Simon Potter 253 7 1 213 474
Eytan Uliel (appointed 1 June 2021) 365 - 6 220 591
Non-Executive Directors
William Schrader (resigned 5 March 2022) 44 - 1 46 91
James Smith (resigned 5 March 2022) 44 - 1 15 60
Adrian Collins (resigned 25 May 2021) 19 - - 10 29
Ross McDonald (resigned 1 June 2021) 27 - - 2 29
Stephen Bizzell (appointed 1 June 2021) 33 - - - 33
Leo Koot (resigned 22 January 2021) 4 - - - 4
789 7 9 506 1,311
* 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 24 for further details.
Directors' remuneration - 2020 Cash Other Share based *Share-settled Total
$ 000's
payments
$ 000's
payments $ 000's
payments
$ 000's
$ 000's
Executive Directors
Simon Potter 450 24 40 739 1,253
Non-Executive Directors
William Schrader (resigned 5 March 2022) 27 - 28 80 135
James Smith (resigned 5 March 2022) 18 - 18 52 88
Adrian Collins (resigned 25 May 2021) 21 - 22 61 104
Ross McDonald (resigned 1 June 2021) 18 - 18 52 88
Leo Koot (resigned 22 January 2021) 17 - - 8 25
551 24 126 992 1,693
* 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 24 for further
details.
8 Loss per share - Group
The calculation of loss per share is based on the loss after taxation divided
by the weighted average number of shares in issue during the year:
2021 2020
Loss for the year attributable to equity holders of the parent company ($ 23,697 13,992
000's)
Weighted average number of ordinary shares used in calculating basic loss per 667 2,895
share (millions)
Basic loss per share (expressed in cents) 3.6 0.5
Diluted
Diluted loss per share is calculated by adjusting the weighted average number
of ordinary shares outstanding to assume conversion of all dilutive potential
ordinary shares. The Company had one category of dilutive potential ordinary
shares: share options/warrants. For these share options/warrants, a
calculation is performed to determine the number of shares that could have
been acquired at fair value (determined as the average annual market share
price of the Company's shares) based on the monetary value of the subscription
rights attached to outstanding share options/warrants. The number of shares
calculated as above is compared with the number of shares that would have been
issued assuming the exercise of the share options/warrants. Share
options/warrants outstanding at the reporting date were as follows:
2021 2020
Total share options and warrants in issue (number) (see note
24)
96,797,894 486,159,599
As the inclusion of potentially issuable ordinary shares would result in a
decrease in the loss per share, they are considered to be anti-dilutive and as
such, a diluted loss per share is not included.
9 Finance costs/(income) - Group
2021 2020
$ 000's $ 000's
Finance costs* (5630) (628)
Finance income - Interest received 7 202
* Included in this balance is a $5,000,000 finance charge derived from direct
well funding financial instruments which were utilised by the Group to finance
the drilling
of the Perseverance 1 well in Q1 2022. A final reconciliation "make good"
payment of £371,000 (US$518,000) was charged in respect of the sale of shares
held by the investor with a downside protection clause on the subscription
value of shares originally placed in late 2020. An additional make good
payment was also payable to the same investor following their exercise of a
187,500,000 share (£3.75 million) put option in early 2021, resulting in a
final reconciliation payment payable in April 2021 of £3,300,000
(US$4,482,000) following the sale of these shares.
10 Intangible assets - Group Goodwill $ 000's 2021 Exploration & evaluation assets $ 000's
Cost 7,045 75,372
- 21,489
- (29)
At 1 January 2021
Additions
Foreign exchange difference on translation
At 31 December 2021 7,045 96,832
Accumulated amortisation and impairment 2,435 113
At 1 January 2021
Amortisation - 263
Impairment - 2,069
Foreign exchange difference on translation - (18)
At 31 December 2021 2,435 2,427
Net book value
At 31 December 2021 4,610 94,405
At 31 December 2020 4,610 75,259
Intangible assets - Group
2020
Exploration &
Goodwill evaluation assets
$ 000's $ 000's
Cost - 50,570
At 1 January 2020
Acquisition of Columbus Energy Resources PLC (note 15) 7,045 2,492
Additions - 22,310
At 31 December 2020 7,045 75,372
Accumulated amortisation and impairment - -
At 1 January 2020
Amortisation - 113
Impairment 2,435 -
At 31 December 2020 2,435 113
Net book value
At 31 December 2020 4,610 75,259
At 31 December 2019 - 50,570
11 Tangible assets
Oil and gas assets $ 000's Property, plant and equipment (*) $ 000's Decom- missioning costs $ 000's Group 2021
Total Company
$ 000's
Property, plant and equipment (*) $ 000's
Cost or Valuation
At 1 January 2021 23,398 2,258 1,995 27,651 177
Additions 5,065 79 241 5,385 3
Disposals - (117) - (117) (2)
Foreign exchange difference on translation (160) (207) (11) (378) -
At 31 December 2021 28,303 2,013 2,225 32,541 178
Accumulated depreciation and Impairment 1,115 616 137 1,868 99
At 1 January 2021
Depreciation 2,330 346 268 2,944 22
Disposals - (83) - (83) (2)
Impairment 3,933 68 1,346 5,347 -
Foreign exchange difference on translation (84) (196) (3) (283) -
At 31 December 2021 7,294 751 1,748 9,793 119
Net book value
At 31 December 2021 21,009 1,262 477 22,748 59
At 31 December 2020 22,283 1,642 1,858 25,783 78
(*) Property, plant and equipment includes leasehold improvements.
Tangible assets
Oil and gas assets $ 000's Property, plant and equipment (*) $ 000's Decom- missioning costs $ 000's Group 2020 Company
Total Property, plant and equipment (*) $ 000's
$ 000's
Cost or Valuation - 450 1,671 169 (33) - 450 100 - 78 (1) -
At 1 January 2020 23,412 59 (72) (1) 1 1,994 - - 1 27,077
Acquisition of Columbus Energy Resources PLC (note 15) 228
Additions (105)
Disposals 1
Foreign exchange difference on translation
At 31 December 2020 23,398 2,258 1,995 27,651 177
Accumulated depreciation and Impairment - 419 - 419 84
At 1 January 2020
Depreciation 1,113 197 136 1,446 16
Disposals - (1) - (1) (1)
Foreign exchange difference on translation 2 1 1 4
At 31 December 2020 1,115 616 137 1,868 99
Net book value
At 31 December 2020 22,283 1,642 1,858 25,783 78
At 31 December 2019 - 31 - 31 16
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