ANNUAL REPORT 2022
THE SEQUOIA 3D MARINE
SEISMIC SURVEY WILL
ALLOW THE JOINT VENTURE
TO EVALUATE THE
FULL POTENTIAL OF T/49P
WITH HIGH-QUALITY,
MODERN 3D SEISMIC
Executive Chairman’s Letter
to shareholders
Review of operations
Directors' report
2
4
21
Auditor's independence declaration
32
Consolidated statement of profit or
loss and other comprehensive income
Consolidated statement
of financial position
Consolidated statement of changes
in equity
34
35
36
Consolidated statement of cash flows 37
Notes to the consolidated
financial statements
Directors' declaration
Independent auditor's report
to the members of 3D Oil Limited
Shareholder information
Corporate directory
Front cover image courtesy of Shearwater
38
60
61
64
66
1
EXECUTIVE CHAIRMAN’S
LETTER TO SHAREHOLDERS
Dear fellow Shareholders
In last years chairman's letter I state that
“3D Oil is now fully committed to becoming
a significant east coast gas producer…”.
I am pleased to report the Company
has again progressed towards reaching
that objective.
The high points for the Company during the
year included;
— Acquired a new and highly
prospective exploration license in the
Otway Basin VIC/P79.
— Entered into a farmout agreement with
ConocoPhilips Australia for VIC/P79.
— Completed, along with its Joint Venture
partner (ConocoPhilips Australia) an
extensive seismic program over the
T/49P exploration license.
— Continue farmout discussions on
WA-527-P.
— Acquired a prospective gas storage license
(GSEL 759) with the Company working on
energy transitional strategies for the new
and emerging energy demands.
— Secure approximately A$4.6 million in
cash as a result of farmout activities
during the year thereby reducing the
need raise funds from shareholder.
— At the time of this report the
Company has commitments for the
funding (free carry) from Joint Venture
partners for two offshore well up to
US$65m (~A$95m).
— The Company has had zero
Lost Time Incidents (LTI’s) and
zero Environmental Incidents
I would like to expand a little on this
summary and to provide some detail on
what has been a very successful year for our
Company. From the outset let me point to
one of the significant achievements in the
history of 3D Oil, the acquisition of VIC/P79
in the offshore Otway Basin, followed shortly
thereafter by the farmout of the license
with ConocoPhillips Australia (“COP”),
comprising fantastic terms for 3D Oil. As
I write this letter, we are currently nearing
completion of the remaining agreements
required to finalise the farm-in.
The Company’s technical analysis prior
to bidding for VIC/P79 allowed 3D Oil to
develop an aggressive bid and achieve the
ultimate success of securing the Permit.
Our analysis of the permit indicates that it
offers significant gas potential. This view
is enhanced, in part by its proximity to the
significant gas fields including Geographe
and Thylacine. Shortly after being awarded
VIC/P79 the Company negotiated a farm-in
deal which included a US$35m (`A$50m)
free carry for an exploration well and
US$3m (`A$4.35m) cash consideration.
This transaction follows our recent
transaction with ConocoPhillips in T/49P.
Arguably these farm-in agreements are
among the best in the Australian oil and gas
sector for almost two decades providing
~A$95m of value for 3D Oil based on today’s
exchange rate.
The result is that 3D Oil now has two
funded wells in the Otway Basin due to
be drilled by early 2025. This is consistent
with the Company’s strategy to provide
funding solutions by attracting quality Joint
Venture partners and provide a catalyst
for significant growth while maintaining a
pathway for the ultimate goal of becoming
an east coast gas producer.
At a technical level the Company has
already identified a drillable prospect within
VIC/P79. The Vanguard prospect has a
best estimate prospective of 160 bcf of gas
(refer ASX Announcement dated 8 June
2022). This prospect has associated seismic
amplitude anomalies which are comparable
to anomalies encountered in fields drilled in
the Otway basin that have achieved a 100%
success rate over almost two decades.
Additional amplitude supported features
have also been recognized down-dip
from the La Bella gas discovery and it’s
becoming increasingly clear to 3D Oil that
significant prospectivity remains to be
uncovered in the Permit.
The T/49P planned Sequoia 3D Seismic
Survey was completed during November
2021, with the final versions of the
processed data now being received from
COP. While it is too early to map prospects
on the data, all signs are very encouraging.
We expect to have prospects delineated in
the coming months. The Company believes
that the T/49P permit is the last place on
the east coast where significantly large
gas reserves can potentially be uncovered
which can be delivered economically to the
east coast market.
The drilling of the two upcoming
exploration wells has come with the
backdrop of a gas energy crisis that
emerged on the east coast in the winter
of 2022. In support of the 3D Oil gas
exploration strategy the Australian Energy
Market Operator (AEMO) has indicated
[2022 Gas Statement of Opportunities] that
gas is projected to maintain its importance
in the Australian domestic energy mix to at
least to the 2040s
2
Image courtesy of Shearwater
VIC/P74 is located offshore in the
Gippsland basin also forms a strategically
important asset for 3D Oil with respect
to the east coast gas market, having 1.8 tcf
of best estimate prospective resources
(refer ASX Announcement dated
16 February 2021). The recent withdrawal
of Hibiscus from the 3D Oil Joint Venture
now provides the Company with increased
equity enabling 3D Oil to consider new
farmout opportunities
Adding to our two highly prospective
offshore Otway blocks is the recent
addition of the Caroline Field in the onshore
Otway Basin. The acquisition of GSEL
759 represents an exciting gas storage
opportunity for the Company thereby
broadening the Company’s strategy within
the rapidly changing east coast energy
market. The license is ideally situated being
located only 20km southeast of Mount
Gambier and proximal to the South East
Pipeline System. Over the next few months,
the Company will undertake technical
work to better understand the reservoirs’
suitability for gas storage applications,
including storage capacity, reservoir
deliverability and seal integrity, with a view
to determining the most feasible business
model from multiple gas storage and
supply scenarios.
As a longer-term strategy, WA-527-P is a
very large permit in the rapidly emerging and
prolific hydrocarbon province in the Bedout
Sub- Basin. In contemporary times the
uncovering a world class basin is extremely
rare. The recent announcement by Carnarvon
Energy Limited illustrated a plethora of
highly prospective leads and prospects
across the basin, with Starbuck and Flint
prospects located directly adjacent to the
3D Oil WA-527-P boundary. During the year
our permit’s potential was substantially
upgraded with the significant Pavo oil
discovery in the neighbouring Permit.
The Pavo 1 exploration well encountered
a significant light oil (~52°API) discovery
within excellent reservoirs of the Caley
Member, with 46m net pay (60m gross),
19% average porosity, 80% average oil
saturation with high permeabilities of
100-1000 millidarcies reported. Pavo
1 de-risks uncertainties around source
presence and hydrocarbon migration
away from previous discoveries and
towards the basin margin, supporting
the likely migration to any erosional
truncation leads in WA-527-P.
ENERGY IN A GLOBAL CONTEXT
I would like to now digress briefly and
discuss the role of oil and gas in the world
today – this provides important context
for 3D Oil’s future.
Hydrocarbons, including gas, supplied
83 per cent of all global energy in 2020 –
surprisingly that number rose in 2021 by
about 6 percent. It’s worth reminding
ourselves that thousands of products
depend on oil and natural gas, from
smart-phones and computers to sporting
equipment and the clothes on your back.
Petrochemicals are used in about half
a million different products. Australia is
completely dependent on gas, and coal,
for ourselves, as well as for export income.
Energy hungry Asia countries where
economic growth is tied to power usage
are dependent on Australian gas. In short,
while the world is seeking to transition
towards alternative energy, hydrocarbons
are projected to have role to play in the
ultimate energy mix.
The global energy sector is currently
changing at a pace never witnessed in
history. It was just over 2 years ago that
energy prices were the lowest in human
history. At that time oil was trading at
negative prices and the world enjoyed
these prices across many sectors including
the renewable energy manufacturing
sector. Very few saw the speed of current
energy crisis coming. What has occurred
within the two-year period is extremely
rapid increase in prices, particularly in the
retail and wholesale downstream markets,
reaching some of the highest prices in
history. The average range between peak
to trough pricing in some sectors around
a 90% differential. The impact of this has
a profound effect on the world from the
European energy crisis to the emerging
famine in many poorer countries around
the world largely related to fertilizer
and energy costs for food production.
Further, these prices have only hastened
the deindustrialization within the western
world with China and counter intuitively
Russia being the benefactors of these high
energy prices.
3D Oil is well placed during this period and
in the rapid transition to renewable energy.
I am pleased to re-emphasize that 3D Oil
shareholders are uniquely placed to benefit
from the upside that the Company’s
exploration strategy and current asset
position offers.
Finally, I would like to comment in a more
general sense. As a small Australian
company, we use all our efforts and
will continue to act responsibly in our
increasingly complex markets and operating
environment. I would like to thank our
shareholders, the communities, employees,
contractors and business partners who
continue to offers support and enable us to
continue adding value and benefits for all.
Noel Newell
Executive Chairman
3
REVIEW OF OPERATIONS
4
WA-527-P, BEDOUT SUB-BASIN,
OFFSHORE NORTHWEST SHELF
Figure 1 – WA-527-P location, leads and
Environmental Planning area for the Sauropod
MC3D.
Petroleum exploration permit WA-527-P is
a large permit that covers 6,500km2 of the
eastern margin of the Bedout Sub-basin,
a structural element of the Roebuck Basin
on the prolific Northwest Shelf of Australia
(Figure 1). TDO is the Operator and holds
100% interest in the permit, which is
situated approximately 50km along
trend from the recent Pavo discovery
(Carnarvon Energy 20%, Santos 80%).
EXPLORATION RATIONALE
The Bedout Sub-Basin is under-explored
relative to surrounding prolific petroleum
basins due to disappointing results with
some of the first exploration wells in the
1970s and 1980s. The discovery of what
was believed to be gas in the Phoenix wells
in the 1980s also meant the basin was
written off as gas-bearing for 32 years,
until Phoenix South 1 discovered a series of
light oil zones with the Barret sandstones
in 2014. Subsequent appraisal wells also
discovered gas condensate within the
Middle Triassic Caley Member (Archer
Formation). Roc-1 tested a faulted anticline
up-dip from Phoenix South and discovered
gas-condensate within sands of the Caley
Member also.
Dorado-1 was drilled up-dip from Roc
in 2018 and was the first test of a new
stratigraphic play, leading to the discovery
of the largest oil field in Australia over
the last 30 years. Dorado has fuelled a
resurgence of exploration activity in the
basin, hosting 162 MMbbls of liquids and
748 Bcf of gas within multiple reservoirs
of the Middle Triassic Archer Formation,
including the Caley, Baxter, Crespin and
Milne members.
Flow testing of the Dorado-3 appraisal well
in September 2019 confirmed excellent
reservoir quality, recording a maximum flow
rate of 48 mscf/day of gas and 4,500 bbl/
day of oil from the Baxter reservoir, while
the Caley reservoir achieved flow rates up to
11,100 bbl/day oil and 21mcf/day associated
gas (STO release, 8 Oct 2019). Flow rates
from both intervals were constrained by
surface equipment and are some of the best
recorded on the Northwest Shelf. These
are excellent results for reservoirs buried
greater than 4000m depth.
“Pavo 1 is a game changer
for the prospectivity of
WA-527-P, where the
Caley play shared many
of the same pre-drill risks
as Pavo”
5
Figure 2 – Comparison of undrilled prospectivity in the under explored Bedout Sub-Basin with the highly explored Northern Carnarvon Basin.
Inset bottom right creaming curve1 courtesy of Rystad Energy ECube June 2020, Rystad Energy Research and Analysis.
The exploration potential within the Bedout
Sub-Basin is best summarised by Figure 2,
which compares the undrilled leads in the
Bedout Sub-Basin with the highly explored
Northern Carnarvon Basin to the southwest.
Exploration has progressed from the basin
centre towards the margin, testing the
extent of the petroleum system with each
new well. The highly anticipated Pavo 1 and
Apus 1 exploration wells in March/April 2022
were the next wells to step out towards
the basin margin and further support the
Company’s long held view that the region
hosts a prolific petroleum system.
Pavo-1 intersected 46m net pay (60m
gross) of light oil (~52° API) within the
Caley Member. Log analysis of Pavo-1
indicates excellent reservoir quality with
19% average porosity, 80% average oil
saturation and permeabilities ranging from
100-1000 millidarcies. Similar excellent
reservoir quality can be anticipated within
WA-527-P, where any drill targets defined
by the planned Sauropod MC3D Seismic
Survey will be located at similar depths.
The Pavo-1 discovery provides significant
uplift in relation to the prospectivity of
WA-527-P, where the Caley play shared
many of the same pre-drill risks as Pavo.
Pavo-1 de-risks uncertainties around source
6
presence and hydrocarbon migration away
from existing discoveries. The discovery
highlights the existence of a new charge
cell on the eastern side of a structural ridge
that extends from Roc to Dorado. The Roc
South-1 dry well suggests migration from
the Dorado charge cell hasn’t crossed this
ridge to charge Pavo structure. A new
charge cell east of the Roc-Dorado ridge
supports migration towards the basin
margin and any erosional truncation leads
in WA-527-P (Figure 3).
Pavo-1 also confirms the presence and
effectiveness of the Hove Member top/
lateral seals along trend from WA-527-P,
where the top seal is thinning out of the
basin. Importantly the Pavo-1 discovery has
also indicated that small structural closures
(5-6km2) form an important part of
exploration portfolios in the region, hosting
a volume of 43 MMbbls of high-quality oil
(gross 2C).
Despite the commercial failure of the
Apus-1 exploration well, the Company
believes there is a strong positive take
away for WA-527-P. The Carnarvon
Energy ASX release states that “while
hydrocarbons were observed in the well a
commercial hydrocarbon pool has not been
discovered”. The Apus trap is an isolated
remnant closure formed by the Dorado/
Apus canyons and top/lateral sealed by
the transgressive Hove Member shales.
These canyons prevent the migration
of hydrocarbon from the Dorado/Roc
charge cell and the only way to provide
hydrocarbons to Apus structure is from a
deeper, previously untested source rock.
The presence of any hydrocarbons at Apus
points to a deeper expelling source rock
that may extend into the WA-527-P permit.
Carnarvon attributed well failure to a lack of
sufficient quantity of hydrocarbons to form
a commercial pool, or the inability to retain
significant hydrocarbons with the closure.
The Pavo-1 and Apus-1 wells de-risk some of
the critical elements within the Caley Member
play in WA-527-P. Traps are the final piece
of the puzzle. The potential for analogous
stratigraphic and structural traps to Dorado
and Pavo, respectively, has been delineated
along the western margin of WA-527-P
utilising reprocessed legacy 2D seismic
(Figure 4). The planned Sauropod MC3D
Seismic Survey will support the definition of
any potential traps and provide the means
to capitalise on TDOs early entry into what
remains a highly under explored basin.
1 Northern Carnarvon Basin (blue curve), Bonaparte
Basin (lower green curve), Browse Basin (upper
green curve), Bedout Sub-Basin (red curve).
Figure 3 – Pavo demonstrates the presence of a new charge cell operating in the Bedout Sub-Basin.
Figure 4 – Amplitude anomaly (full stack) on
reprocessed 2D seismic, truncated by a potential
erosional channel system within WA-527-P (red
arrows delineate edges of channel).
“Pavo and Apus de-risk
some of the critical
elements within the
Caley Member play in
WA-527-P. Traps are the
final piece of the puzzle.”
7
ACTIVITIES
Over the course of the year, 3D Oil
progressed with plans to acquire the
Sauropod MC3D in the next available
acquisition window and entered discussions
with seismic company CGG to acquire the
survey as multi-client data. On 6 September
2021, the Sauropod MC3D Environment Plan
(EP) was re-submitted for a one-month
public comment period. The EP delineated
the same acquisition parameters as
previously proposed, including a maximum
full fold acquisition area of 3447km2 (Figure
1). The Company was subsequently notified
by NOPSEMA (National Offshore Petroleum
Safety and Environmental Management
Authority) of the acceptance of the EP on
16th February 2022.
Despite the award of the EP, the Company
was disappointed to miss the January-
May (inclusive) 2022 acquisition window.
The acquisition was contingent on the
availability of an appropriate vessel
relative to the timing of approval of the EP.
Unfortunately, the award of the EP came
after the deadline for the procurement
of a vessel had already passed. The only
available vessel, the Geo Coral, had already
been contracted by Santos and Korea
National Oil Company for other surveys.
3D Oil remains committed to acquiring the
Sauropod MC3D Seismic Survey, which
underpins the WA-527-P exploration
strategy. The survey has several objectives,
however, is primarily aimed at determining
the potential for remnant traps associated
with a Triassic erosional channel system that
is analogous to the trapping mechanism for
the nearby Dorado discovery.
Recent 3D seismic acquisition in the basin
using the latest imaging techniques and
long offset streamer lengths has yielded
a significant uplift in image quality. The
Sauropod MC3D will enable the Company
to develop a risked and ranked leads and
prospects portfolio to attract favourable
farm-in terms in fulfillment of the primary
term work program.
The Company is currently preparing to
resubmit the previously approved EP for
an acquisition window covering January-
May (inclusive) 2023, or January-May
(inclusive) 2024. As recommended by
NOPTA (National Offshore Petroleum
Titles Administrator), the Company will
apply for a 2-year EP and aims to re-
submit the revised EP in Q3, 2022. To this
end, re-engagement with NOPSEMA and
key stakeholders has commenced. The
Company would ideally acquire the survey
in 2023, however based on the availability
of seismic vessels in Australia, a two-year
period for the EP is prudent.
The Company has launched a renewed
farmout campaign following the Pavo
oil discovery, which has significantly
upgraded the prospectivity of the Caley
Sandstone play in WA-527-P (Refer TDO
ASX Announcement 24 March 2022).
The Company has observed significant
renewed interest from the farm-in market
and continues to hold active discussions
and data rooms with interested farm-in
candidates.
PROSPECTIVITY
Mesozoic Leads
The Company has identified a series of
structures along the western side of the
acreage that may host Triassic sands like
those encountered at Dorado and Roc.
Trap types in the Triassic play include
a combination of conventional faulted
anticlines and possible stratigraphic
traps, sealed laterally by the incised valley
channel systems. Additional inversion and
fault-bound targets within the Jurassic
sections are also identified.
The largest of the Mesozoic leads include
Whaleback and Salamander, with a Best
Estimate Prospective Resource of 86
MMbbls and 190 MMbbls respectively. In fact,
Salamander is the third largest undrilled
Triassic closure in the Bedout Sub-Basin.
The Sauropod MC3D will allow the Company
to delineate the structural closure of these
features more accurately, and thus update
the prospective resource estimates.
Palaeozoic Leads
The Company has identified the presence
of at least six reef-like features that could
form viable oil targets, ranging in size from
3-30km2. These are mostly identified within
the eastern side of the acreage, within what
is interpreted as an extensive Palaeozoic
Barrier Reef System. The extension of this
system in the onshore Canning Basin is a
proven petroleum system at the Blina and
Ungani oil fields. The Sauropod MC3D will
provide imaging for the largest of these
features located in the north of the permit.
Table 1: WA-527-P Prospective Resource Estimate (MMbbls) Recoverable Oil
(100% Net Prospective Resources to TDO. Refer to ASX announcement 26-Feb-18)
Prospect
Salamander
Jaubert
Whaleback
WA-527-P Total
Status
Low
Lead
Lead
Lead
57
17
16
90
Best
191
72
87
High
713
205
219
349
1,138
The estimated quantities of petroleum that may potentially be recovered by the application of
a future development project(s) relate to undiscovered accumulations. These estimates have
both an associated risk of discovery and a risk of development. Further exploration appraisal
and evaluation is required to determine the existence of a significant quantity of potentially
moveable hydrocarbons.
8
T/49P, OTWAY BASIN,
OFFSHORE TASMANIA
Figure 5 – T/49P exploration permit relative to
Otway Basin discoveries and infrastructure. Note
the recently acquired Sequoia 3D MSS covers
prospective leads in the central corridor.
TDO holds 20% interest in the T/49P
petroleum exploration permit, which is
operated by ConocoPhillips Australia.
The permit is situated west of King Island,
Tasmania and covers 4,960 km2, a massive
and under explored area of the offshore
Otway Basin (Figure 5). The Otway Basin
covers an area of ~150,000 km2 along the
southern margin of Australia and has been
an important supplier of gas to the east
coast since the 1980s. T/49P is located
adjacent to the producing Thylacine and
Geographe gas fields (Beach Energy
operator, ASX: BPT) and is optimally located
to contribute much needed additional
resources to the east coast market.
9
The survey was completed in full
compliance with stringent Environmental
Plan (EP) conditions, including all marine
mammal and invertebrate management
requirements, and fulfills ConocoPhillips’
commitment to acquire 3D seismic over
a minimum area of 1580 km2 within the
Permit, as per the Farmout Agreement
(“FOA”) and TDO ASX Announcement on
18 Dec 2019. No costs were incurred by TDO
towards the acquisition of the survey.
In combination with the Flanagan 3D MSS,
acquired by TDO in 2014, the Sequoia 3D
MSS will allow the Joint Venture to evaluate
the full potential of the permit with high-
quality, modern 3D seismic. Processing of the
Sequoia 3D MSS is currently under way and a
preliminary fast-track volume was received in
July 2022. A significant uplift in data quality
is anticipated with the continued progression
of processing workflows towards a final
volume. A full evaluation of the potential
of the permit, including seismic attribute
analysis, will be possible once the final
volume has been received.
Upon interpretation of the Sequoia 3D MSS
and high grading of potential gas targets,
COPA may elect to drill an exploration well
in fulfillment of the current Year 6 work
program. As per the FOA, TDO will be carried
for up to US$30 million in drilling costs after
which it will contribute 20% of drilling costs
in line with its interest in the Permit.
EXPLORATION RATIONALE
T/49P is highly prospective for gas and
contains numerous structures in water
depths generally no greater than 100m.
The north of the permit is covered by the
974 km2 Flanagan 3D Marine Seismic Survey
(MSS), while the central corridor is covered
by 1700km2 of the newly acquired Sequoia
3D MSS. Only two early exploration wells
have been drilled in the permit (in 1967 and
1970) on historic, widely spaced 2D seismic.
In subsequent years the region was largely
overlooked by the industry despite the
proximity of the Thylacine and Geographe
gas fields.
TDO management believes the south-east
Australian gas market will be strong in
coming years as existing gas production
in both the Gippsland and Otway Basin
declines. Gas will play an important role
as the nation switches from coal fired
power and will support the uptake of
renewable energy by filling gaps in the
grid where renewable energy generation is
intermittent.
TDO recognised the potential for the
shortfall in gas supply to south-east
Australia as early as 2012 and acquired the
T/49P exploration permit on that basis. The
wider industry now shares the view that the
region contains significant yet-to-find gas.
As a result, there is significant exploration
and development activity in the basin.
Beach Energy has just completed a seven
(7) well drilling campaign that has resulted
in the Artisan-1 gas discovery and supported
an increase in average daily Otway Gas
Plant production by 46% to 94 TJ/day gross
(Beach Energy Annual Report 2022).
Beach Energy has announced an FY24
drilling program around the development
of Artisan and La Bella, potentially followed
by exploration drilling in FY25 near the
Enterprise gas discovery. Cooper Energy
(ASX:COE) recently announced a targeted
Q3 FY23 Final Investment Decision (FID)
for its Otway Phase 3 development project.
This involves the development of the Annie
gas field, with first gas being targeted
before winter 2025 in combination with
potential exploration drilling at the Elanora
Prospect.
Yet another compelling indication of the
importance of the Otway Basin to future
east coast gas supply is the expansion of
ConocoPhillips’ title holding in the Otway
Basin, by way of farm-in to TDO’s newest
acreage, VIC/P79 exploration permit.
ACTIVITIES
This financial year saw the highly
anticipated acquisition of the Sequoia
3D Marine Seismic Survey (MSS). The
Environmental Plan (EP), submitted by
Operator ConocoPhillips Australia, was
accepted by NOPSEMA (National Offshore
Petroleum Safety and Environmental
Management Authority) on 10 August 2021
and was valid from 10 August 2021 –
31 October 2021.
The Shearwater vessel Geo Coral
commenced acquisition of the Sequoia 3D
MSS in late August and safely completed
the acquisition at midnight on 31 October
2021, in accordance with the approved
EP from NOPSEMA. The Sequoia 3D MSS
was hampered by unprecedented weather
in Bass Strait early in the acquisition
window which, in addition to further EP
conditions, resulted in a total acquisition
area of approximately 1700km2, less than
the approved 2450km2. Despite this,
prioritisation of the survey across the
central corridor has yielded coverage
across the most prospective leads
(Figure 5), including all pre-existing leads
(excluding Flanagan).
“TDO management
believes the south-east
Australian gas market
will be strong in coming
years as existing gas
production in both the
Gippsland and Otway
Basin declines”
10
PROSPECTIVITY
FLANAGAN PROSPECT
Figure 6 – Modelled gas expulsion and migration
From a geological standpoint, one of
the key reasons T/49P was acquired was
due to its unique position with respect to
the regional structural configuration of
the southern Otway Basin. The permit is
located along the edge of a paleo-shelf
break, the depositional focus of a series
of thick progradational clinoforms over
the last 35 Million Years. These clinoforms
have resulted in rapid loading of the proven
sources rocks in this section of the Otway
Basin. TDO interprets that this mechanism
is responsible for providing gas of the
largest offshore Otway Basin gas fields,
Thylacine and Geographe, and is likely to
contribute hydrocarbons to the leads and
prospects of T/49P (Figure 6).
Flanagan is a ‘drill ready’ prospect located
in shallow water and defined by the
Flanagan 3D MSS, acquired in 2014. The
structure has a maximum aerial closure of
approximately 80 km2 and is ideally located
adjacent to multiple source kitchens. The
prospect has a best estimate prospective
resource of 1.34 TCF (announced 27th
July 2017) and is the closest drill target to
existing infrastructure at Thylacine and
Geographe fields.
The potential for gas in the Flanagan
Prospect is supported by quantitative
geophysical modelling, which indicates the
presence of a Class III Amplitude Versus
Offset (AVO) anomaly. In the Otway Basin,
this type of response is known to be
indicative of gas bearing sands.
“TDO recognized the
potential for the shortfall
in gas supply to south-
east Australia as early
as 2012 and acquired the
T/49P exploration permit
on that basis”
11
Figure 7 – Seismic Interpretation and high
amplitude zones at the Seal Rocks lead
SEAL ROCKS LEAD
Located in the south of the permit and
at an analogous shelf-break location to
Thylacine Field, one of the key objectives
of the Sequoia 3D MSS is the Seal Rocks
lead (Figure 7). In 2019 TDO completed
reprocessing and interpretation of legacy
2D seismic and defined the presence of
several high amplitude zones, likely to
represent good quality reservoir sands
(Figure 7). These reservoirs appear to fit
a series of tilted fault-blocks, and while
the reprocessed 2D seismic has provided
a more accurate understanding of the
structure at Seal Rocks, 3D seismic is
required to determine the true resource
potential of the structure.
Table 2: T/49P Prospective Resource Estimate (BCF) Gross Recoverable Gas
(Net TDO Recoverable Gas)
(20% Net Prospective Resources to TDO. Refer to ASX announcement 27-Jul-17)
Location
Flanagan
Seal Rocks
Whistler Point
British Admiral
Harbinger
Munro (in-permit)
T/49P Total
Status
Prospect
Lead
Lead
Lead
Lead
Lead
Low
530 (106)
950 (190)
820 (164)
370 (74)
330 (66)
40 (8)
Best
1340 (268)
4640 (928)
2040 (408)
1030 (206)
790 (158)
190 (38)
High
2740 (548)
10640 (2128)
8950 (1790)
4450 (890)
1430 (286)
570 (114)
3040 (608)
10030 (2006)
28780 (5756)
The estimated quantities of petroleum that may potentially be recovered by the application of
a future development project(s) relate to undiscovered accumulations. These estimates have
both an associated risk of discovery and a risk of development. Further exploration appraisal
and evaluation is required to determine the existence of a significant quantity of potentially
moveable hydrocarbons
12
VIC/P79, OTWAY BASIN,
OFFSHORE VICTORIA
3D Oil holds 100% interest in the VIC/P79
exploration permit, awarded from the 2020
Offshore Petroleum Exploration Acreage
Release however the Company is currently
in the process of farming down to COPA.
The permit covers 2,575km2 of the offshore
Otway Basin and is located adjacent to the
producing Thylacine and Geographe gas
fields (Operated by Beach Energy Limited
(ASX: BPT)) and the La Bella gas discovery
(Figure 8).
The permit builds on a strong portfolio
of leads and prospects already defined in
nearby T/49P (owned 20% TDO), which will
likely further grow after the processing and
interpretation of the Sequoia 3D Marine
Seismic Survey (MSS), recently acquired by
operator ConocoPhillips Australia (COPA).
In conjunction with T/49P, the Company has
now strategically gained exposure to >60%
of Otway Basin exploration by area.
EXPLORATION RATIONALE
Exploration permit VIC/P79 (Figure 8)
covers a large area with little exploration
drilling, with water depths ranging from
100-200m. The eastern half of the permit
lies within the Shipwreck Trough and is
proximal to the largest gas discoveries in
the basin, Thylacine and Geographe. In
addition, the La Bella gas discovery flanks
the permit to the north on the margin of
the Mussel Platform, pointing to a rich-gas
prone petroleum system operating within
the permit.
TDO bid aggressively in the Offshore
Acreage Release to secure the sought-after
permit having recognised the previously
overlooked Vanguard Prospect in the
eastern half of the acreage, characterised
by Direct Hydrocarbon Indicators (DHIs)
such as flat spots. Accordingly, TDO bid
a well in the primary term, which was
designed to progress Vanguard to drill-
ready status. The acquisition of a DHI
supported prospect situated within the
proven gas fairway of the region greatly
upgrades the Company’s position within
the Otway Basin. The basin has witnessed
a significant success rate for almost two
decades due to the identification of DHIs.
The area to the west of the Nautilus-A1
and Triton-1 wells is under explored, with
no exploration wells and 2D seismic
of varying quality. In-house regional
evaluation suggests this area may also host
prospective reservoir and seal sections,
the potential extension of existing plays
Figure 8 – VIC/P79 location relative to
surrounding fields and infrastructure
to the northeast. Proximal discoveries
include Henry, Netherby and Pecten
fields. The secondary term will focus
on the acquisition and processing of a
new 1000km2 3D seismic survey in the
west, with the intention of searching for
additional closures.
ACTIVITIES
VIC/P79 was awarded in February 2022
and shortly thereafter TDO embarked on
an accelerated farmout campaign, given
early expressions of interest in the permit
and the well commitment in the primary
term. Preliminary seismic interpretation has
been ongoing through this time, leading
to the identification of the Defiance and
Trident leads, both exhibiting amplitude
conformance with structure. Please refer to
ASX Announcement dated 8 June 2022 for
further information.
On 30 June 2022, the Company executed
a Farmout Agreement (“FOA”) with
ConocoPhillips Australia SH2 Pty Ltd
(“ConocoPhillips Australia”) in relation to
the offshore Victorian Exploration Permit
VIC/P79 (TDO ASX Announcement, 1
July 2021). Under the terms of the FOA,
ConocoPhillips Australia will acquire an
13
Figure 9 – Lower Waarre depth map of the Vanguard Prospect showing the location and extent of the observed flat spot.
80% interest in the Permit and operatorship
in exchange for an upfront payment of
USD$3 million. ConocoPhillips Australia
will also undertake to drill an exploration
well as required by the permit’s Primary
Term minimum work commitment
(currently required by February 2025). The
Company will be carried for up to USD$35
million in well costs, above which it will
contribute 20% of costs in line with its
interest in the Permit. At the date of this
report, agreement is subject to conditions
precedent, including the agreement and
signing of a Joint Operating Agreement
by both parties and required government/
regulatory approvals.
This second major deal with ConocoPhillips
Australia is an outstanding result for the
Company, especially given the timeline
from permit award to farmout. It should be
noted that the FOA is subject to conditions
precedent, including the agreement and
signing of a Joint Operating Agreement
by both parties and required government/
regulatory approvals.
PROSPECTIVITY
Vanguard Gas Prospect
Vanguard is an east-west trending tilted
fault-block trap located on the eastern side
of VIC/P79 (Figure 9), approximately 5km
northwest of Geographe Field between
Geographe and the La Bella gas discovery.
Vanguard is constrained by the La Bella
and Investigator 3D seismic surveys and
seismic interpretation shows the structure
hosts stacked reservoir sands of the Waarre
Formation. The structure’s potential was first
realised through the identification of a flat
spot within the Lower Waarre (Figure 10).
DHIs have been observed on the
Investigator 3D MSS from three
stratigraphic levels across the structure,
ranging in depth from approximately
2200-2400mSS. Vanguard boasts a
strong amplitude response, and potential
Amplitude Variation with Offset (AVO),
which is common to adjacent gas
discoveries and producing fields and can
indicate the presence of hydrocarbons.
In fact, these gas signatures have been
identified on 3D seismic data across most
offshore Otway Basin gas discoveries
throughout the last two decades.
Defiance and Trident Leads
Both Defiance and Trident leads are tilted
fault block closures (Figure 11) directly
down-dip from the La Bella gas discovery
to the east and similarly exhibit amplitude
conformance with structure (Figure 12).
Defiance exhibits amplitude conformance
with structure at both the Upper Waarre
and Lower Waarre horizons, where the
Upper Waarre horizon conforms with the
deeper, larger gas zone at La Bella-1. The
Defiance structure has an areal closure of
1.1-1.6km2, however, approximately 50% of
the Defiance structure lies outside of the
permit to the north and east (Figure 11).
Trident has an areal closure of 1.9km2 and
exhibits amplitude conformance with
structure at the Lower Waarre horizon
only, what is commonly referred to as
the Waarre A reservoir at in-board wells,
based on the La Bella-1 well-tie. Amplitude
conformance with structure is considered
one of the most reliable and robust
Direct Hydrocarbon Indicators (DHIs),
representing buoyancy driven fluid phase
boundaries (i.e., gas-water contacts), and
significantly reduces uncertainty around
the presence of hydrocarbons.
“The acquisition of a DHI
supported prospect
situated within the
proven gas fairway of the
region greatly upgrades
the Company’s position
within the Otway Basin”
14
Figure 10 – Vanguard structure on the Investigator 3D MSS with flat spot at the Lower Waarre.
Figure 11 – Lower Waarre TWT structure map showing Defiance and Trident leads.
15
Figure 12 – Lower Waarre RMS amplitude map
showing strong conformance of amplitude with
structure. Note amplitudes extend beyond the
permit towards the north.
Table 3: VIC/P79 Prospective Resources Estimate Gross Recoverable Gas (Bcf)
(100% Prospective Resources to TDO2. Refer to ASX announcement 8-Jun-22)
Lead/Prospect
Vanguard
Trident
Defiance
La Bella East
La Bella SW
VIC/P79 Total
Status
Prospect
Lead
Lead
Lead
Lead
Low
52.5
19.5
17.2
17
12
118.2
Best
161.5
37.2
32.5
37.5
29
297.7
High
425
65
59.9
65.5
54
669.4
The estimated quantities of petroleum that may potentially be recovered by the application of
a future development project(s) relate to undiscovered accumulations. These estimates have
both an associated risk of discovery and a risk of development. Further exploration appraisal
and evaluation is required to determine the existence of a significant quantity of potentially
moveable hydrocarbons.
2 Prospective resource estimates will reduce from 100% to 20% net
to TDO on NOPTA approval of the FOA with ConocoPhillips Australia.
16
“This second major deal
with ConocoPhillips
Australia is an
outstanding result for
the Company, especially
given the timeline from
permit award to farmout”.
Figure 13 – VIC/P74 Location
VIC/P74, GIPPSLAND BASIN
OFFSHORE VICTORIA
EXPLORATION RATIONALE
Exploration well post-mortems completed
by TDO identified that several well failures
in VIC/P74 can be attributed to trap
presence, owing to drilling on coarse legacy
2D seismic, as well as depth conversion
issues caused by velocity anomalies in
the shallow overburden. VIC/P57 on
the northern flank of the basin has the
same velocity issues, however, TDO has
significantly enhanced depth models by
licencing CGG’s 3D seismic reprocessing
over VIC/P57. TDO observed a significant
uplift in seismic quality and velocities,
which has enhanced the accuracy of depth
models over Felix Prospect and supported
the maturation of Pointer Prospect.
TDOs exploration rationale in acquiring
VIC/P74 was to licence the CGG multiclient
3D seismic reprocessing to exploit recent
advances in reprocessing techniques and
resolve previously missed traps within a
prolific petroleum system.
The VIC/P74 petroleum exploration
permit was awarded to TDO on 26th July
2019 and covers an area of 1,006 km2 of
the offshore Gippsland Basin, in shallow
water depths ranging up to 70m (Figure
13). The Company will hold 100% in the
permit pending the withdrawal of Hibiscus
Petroleum in 2022.
Geologically, the permit straddles the
boundary of the Southern Terrace and the
Central Deep on the southern flank of the
Gippsland Basin.
VIC/P74 is ideally situated, flanking several
important discoveries in the basin (Figure
13). Kingfish Field, the largest oil field in
Australia, lies 5km to the east and has
produced over 1 billion barrels from the
classic top Latrobe play. Likewise, Bream
Field lies 5km to the north and represents a
significant gas-condensate discovery within
the same play. An exploration campaign
in the 1980s by former operator Aquitane
yielded the first and only discovery inside
the permit, consisting of gas condensate
within the lower Latrobe Group at Omeo
Field – a three-way downside dip closure
located adjacent to newly discovered leads
against the Southern Terrace.
17
ACTIVITIES
VIC/P74 entered Year 3 of the primary
work program on 26 July 2021. Early in
the year, the Company released an update
to the market on Prospective Resource
estimates within the permit (refer to ASX
announcement dated 7 October 2021). This
update was based on stratigraphic, seismic
interpretation and depth conversion studies
in the deeper Emperor Subgroup play
where additional gas prospectivity has been
identified at several existing leads, including
Oarfish and Megatooth. Importantly, these
closures are located along strike to the gas
sands at the Omeo discovery.
Oarfish is now the largest un-risked gas
target in the permit (Figure 14), having a
total best estimate prospective resource
of 544 Bcf, up from 338 Bcf. The lead
is situated 2km to the east of Omeo 1A
and reservoir/seal pairs are anticipated
to be similar. Oarfish essentially has the
same trapping configuration as the Omeo
structure, which has hydrocarbons at
equivalent levels based on log analysis and
RFT recovery of water and gas with a thin
film of oil/condensate.
Megatooth now has a total best estimate
recoverable prospective resource of 465
Bcf (Figure 14), up from 204 Bcf. The lead
is well situated relative to the kitchen
underlying Bream towards the northeast
and migration can be demonstrated by
gas-condensates intersected within the
Lower Latrobe Group at Omeo 1A. Emperor
gas sands at the Omeo wells lie within 1km
of Megatooth.
Having now completed the primary term,
the next stage of exploration in VIC/P74
will involve the acquisition or purchase
of modern 3D seismic data to assist with
maturing the best potential lead(s) to
prospect status. Prior to entry into the
secondary term, where obligations are
year-to-year and entry in the following year
is optional, the Joint Venture has completed
a strategic review. Accordingly, Hibiscus
Petroleum have elected to transfer their
50% participating interest back to 3D Oil.
The Joint Venture applied for a Transfer of
Title in July, which is currently under review.
18
Figure 14 – Top Golden Beach Subgroup depth
map with identified closures (purple outlines)
The Company recognises the potential for
VIC/P74 to help address the impending
east coast gas supply shortage and remains
committed to fulfilling the secondary work
program. The Year 4 work commitments
are designed to assist with lead maturation
and include the acquisition or purchase of
200km2 of modern 3D seismic data, as well
as seismic interpretation, depth conversion,
inversion and AVO. The Joint Venture
have applied to NOPTA for a ‘Variation of
Title Conditions’ before entry into Year 4,
seeking to alter aspects of the secondary
work program. This application is currently
under review.
TDO has been approached by interested
parties over the course of the year and is
continuing the farmout campaign. The Joint
Venture is seeking the best possible terms
to facilitate the next stages of exploration,
including seismic acquisition and drilling.
“The next stage of
exploration in VIC/
P74 will involve the
acquisition or purchase of
modern 3D seismic data
to assist with maturing
the best potential lead(s)
to prospect status”
Paleogeographic maps indicate these
resources will likely be hosted by coastal
plain sands top sealed by Campanian aged
volcanics, which have been intersected in
nearby offset wells, including the Omeo
wells, Speke 1, and Melville 1. Volcanics are
proven to form a competent top seal at
analogous producing fields in the basin,
including Kipper and Manta.
The structure has a large throw and relies
on cross-fault seal with the F.longus lower
coastal plain, consisting of interbedded
shales, siltstones and coals. Volcanic
intrusions within fault planes form
important cross-fault seals for fields along
the margin of the Northern Terrace and
may also provide an additional cross-fault
sealing mechanism at Bigfin, given the
presence of local intrusive volcanics.
PROSPECTIVITY
Bigfin Lead
Bigfin lies in shallow waters (~80m) directly
adjacent to the world class Kingfish
structure. The trap is a two-way dip closure
(maximum closing contour) at the top
Golden Beach Subgroup (~2950m TVDSS)
and has a large areal closure (~29km2)
and vertical relief (up to 230m). Imaging
of the trap, including faults and deeper
reflectivity, has been improved through
the 3D seismic reprocessing completed
by CGG (Figure 15). Detailed mapping and
depth conversion of this data supports a
prospective best estimate gas resource of
534 Bcf (502 Bcf in permit).
Overlying shallower closures were tested
in 1969 by Gurnard-1, a dry hole that
recovered an oil show from formation water
in the overlying F.longus reservoir. Well
failure at the primary Top Latrobe objective
is attributed to a lack of cross-fault seal.
Gurnard 1 did not intersect the underlying
Golden Beach section, which TDO
estimates could hold as much as 783 Bcf
and 38.6 MMbbls in the high estimate.
Figure 15 – Comparison between
legacy and CGG 3D reprocessed
seismic at Bigfin Lead
“The Company recognises
the potential for VIC/
P74 to help address the
impending east coast
gas supply shortage and
remains committed to
fulfilling the secondary
work program”
19
Table 4: VIC/P74 Prospective Resources Estimate (Bcf) Recoverable Gas
(Net TDO Recoverable Gas)
(50% Net Prospective Resources to TDO3. Refer to ASX announcement 07-Oct-21).
Lead/Prospect
Status
Oarfish
Bigfin
Megatooth
Stargazer
VIC/P74 Total
Lead
Lead
Lead
Lead
Low
303 (152)
296 (148)
259 (130)
192 (96)
Best
544 (272)
502 (251)
465 (233)
344 (172)
High
918 (459)
783 (392)
784 (392)
564 (282)
1050 (526)
1855 (928)
3049 (1525)
Table 5: VIC/P74 Prospective Resources Estimate (MMbbls) Recoverable Condensate
(Net TDO Recoverable Condensate)
Lead/Prospect
Status
Oarfish
Bigfin
Megatooth
Stargazer
VIC/P74 Total
Lead
Lead
Lead
Lead
Table 6: VIC/P74 Prospective Resources Estimate (MMbbls) Recoverable Oil
(Net TDO Recoverable Oil)
Lead/Prospect
Megatooth
Oarfish
VIC/P74 Total
Status
Lead
Lead
Low
4 (2)
2 (1)
4 (2)
3 (1.5)
13 (6.5)
Low
28 (14)
23 (11)
51 (26)
Best
19 (9)
19 (10)
16 (8)
12 (6)
66 (33)
Best
58 (29)
40 (20)
98 (49)
High
60 (30)
39 (20)
51 (26)
37 (19)
187 (95)
High
107 (54)
71 (35)
178 (89)
The estimated quantities of petroleum that may potentially be recovered by the application of
a future development project(s) relate to undiscovered accumulations. These estimates have
both an associated risk of discovery and a risk of development. Further exploration appraisal
and evaluation is required to determine the existence of a significant quantity of potentially
moveable hydrocarbons.
VIC/P57, GIPPSLAND BASIN
OFFSHORE VICTORIA
Exploration Permit VIC/P57 lies in shallow
waters of the northwest offshore Gippsland
Basin, where it covers 246 km2 (Figure 13).
TDO holds a 24.9% interest in VIC/P57,
which was renewed by the Joint Venture
in 2018 for a further five years, with the
primary term designed to de-risk and
high grade the prospect inventory and
ultimately progress prospects to ‘drill-
ready’ status. VIC/P57 entered the final
year of the Primary Term on 7 March 2020.
The JV subsequently received a 12-month
Suspension and Extension to the Primary
Term, extending the Primary Term to 6
March 2022.
ACTIVITIES
The JV has completed the guaranteed
primary term (Years 1-3) work program
commitments and has worked diligently
to attract a potential partner in the
VIC/P57 exploration permit, ahead of
the Year 4 work commitment for one
exploration well. After a commercial review
of the permit, the JV lodged a ‘Consent to
Surrender Title’ application with NOPTA
(National Offshore Petroleum Titles
Administrator) for the entirety of the
VIC/P57 petroleum exploration permit.
As of 11 August 2022, VIC/P57 has been
officially surrendered, as published in the
Australian Government Gazette.
20
3 The Joint Venture submitted a Transfer of
Title application to NOPTA in July 2022. Once
approved, this will change to 100% Prospective
Resources to TDO.
DIRECTORS’
REPORT
21
The Directors present their report, together
with the financial statements, on the
consolidated entity (referred to hereafter
as the 'Consolidated Entity') consisting
of 3D Oil Limited (referred to hereafter as
the 'Company' or 'parent entity') and the
entities it controlled at the end of, or during,
the year ended 30 June 2022.
DIRECTORS
The following persons were Directors of
3D Oil Limited during the whole of the
financial year and up to the date of this
report, unless otherwise stated:
Mr Noel Newell
Mr Ian Tchacos
Mr Leo De Maria
Mr Trevor Slater
(appointed on 15 November 2021)
PRINCIPAL ACTIVITIES
During the financial year the principal
continuing activities of the Company
consisted of exploration and development
of upstream oil and gas assets.
DIVIDENDS
There were no dividends paid or declared
during the current or previous financial
year.
The Consolidated Entity does not have
franking credits available for subsequent
financial years.
REVIEW OF OPERATIONS
The loss for the Consolidated Entity after
providing for income tax amounted to
$1,147,179 (30 June 2021: $1,142,095).
Refer to the detailed Review of Operations
preceding this Directors' Report.
FINANCIAL POSITION
The net assets decreased by $1,135,294
to $6,474,226 at 30 June 2022 (30 June
2021: $7,609,520). During the year the
Consolidated Entity spent a net amount
after reimbursements of $715,100 (2021:
$851,721) on exploration, mainly in relation
to WA/527P, T49/P and VIC/P74.
The working capital position of the
Consolidated Entity as at 30 June 2022
is $137,577 (30 June 2021: $2,067,184).
The Consolidated Entity incurred net
operating cash outflows of $992,645
(2021: $1,048,675). The cash balances as
at 30 June 2022 was $1,243,195 (2021:
$3,048,802).
22
RISKS AND UNCERTAINTIES
Commodity price risks
The Company is subject to risks that
are specific to the Company and the
Company’s business activities, as well as
general risks.
Future funding risks
The Company is involved in exploration
and development of upstream oil and gas
assets and is yet to generate revenues.
The Company has a cash and cash
equivalents balance of $1,243,195 and net
assets of $6,474,226 as at 30 June 2022.
The Company may require substantial
additional financing in the future to
sufficiently fund exploration commitments
and its other longer-term objectives.
As the Company is still in the early stages of
exploration it has the ability to control the
level of its operations and hence the level
of its expenditure over the next 12 months.
However, the Company's ability to raise
additional funds will be subject to, among
other things, factors beyond the control of
the Company and its Directors, including
cyclical factors affecting the economy and
share markets generally. If for any reason
the Company was unable to raise future
funds, its ability to meet the exploration
commitments and future development
would be significantly affected.
The Directors regularly review the spending
pattern and ability to raise additional
funding to ensure the Company’s ability to
generate sufficient cash inflows to settle its
creditors and other liabilities.
Joint Venture Operations Risks
The Company participates in a number of
joint ventures for its business activities.
This is a common form of business
arrangement designed to share risk and
other costs. Under certain joint venture
operating agreements, the Company may
not control the approval of work programs
and budgets and a Joint Venture Partner
may vote to participate in certain activities
without the approval of the Company. As
a result, the Company may experience
a dilution of its interest or may not gain
the benefit of the activity, except at a
significant cost penalty later in time.
Failure to reach agreement on exploration,
development and production activities may
have a material impact on the Company’s
business. Failure of the Company’s Joint
Venture Partner’s to meet financial and
other obligations may have an adverse
impact on the Company’s business.
The Company works closely with its Joint
Venture Partner’s.
Future value, growth and financial
conditions are dependent upon the
prevailing prices for oil and gas. Those
prices are subject to fluctuations and are
affected by numerous factors beyond the
control of the Company.
Prospective resources estimate risks
Oil and gas resource estimates are
expressions of judgement based on
knowledge, experience and industry
practice. These estimates may alter
significantly or become uncertain when
new information becomes available
and/or there are material changes of
circumstances which may result in the
Company altering its plans. This could
have a positive or negative effect on the
Company’s operations. Other risks may
affect the resource estimate, for example,
commodity price movements.
Environmental and social risks
The business of exploration, development
and production, involves a variety of risks
which may impact the community and the
environment.
The Company’s exploration and
development activities are subject to local,
state, and federal environmental laws
and regulations. Oil and gas exploration
and development can be potentially
environmentally hazardous, giving rise
to substantial costs for environmental
rehabilitation, damage control and losses.
The legal framework governing this area of
law is complex and constantly developing.
There is a risk that the environmental
regulations may become more onerous,
making the Company’s operations more
expensive or causing delays.
It is the Company’s policy to conduct
its activities to the highest standard
of environmental obligation. There is
no assurance that new environmental
laws, regulations or stricter enforcement
policies, if implemented, will not oblige the
Company to incur significant expense and
undertake significant investment, which
could have a material adverse effect on its
business, financial conditions and results of
operations.
The long-term viability of the Company
is closely associated to the wellbeing of
the communities and environments in
which the Company conduct operations.
At any stage, the Company’s operations
and activities may have or be seen to have
significant adverse impacts on communities
and environments. In these circumstances,
the Company may fail to meet the evolving
expectations of our stakeholders (including
investors, governments, employees,
suppliers, customers and community
Impact of COVID-19
The global impact of the COVID-19
pandemic, and the advice and responses
from health and regulatory authorities, is
continuously evolving. The global economic
outlook is facing uncertainty due to the
COVID-19 pandemic which has had and
may continue to have a significant impact
on capital markets and share prices.
To date, COVID-19 has affected equity
markets, governmental action, regulatory
policy, quarantining, self-isolations and
travel restrictions. These impacts are
creating risks for the Company's business
and operations in the short to medium
term.
The Company has in place business
continuity plans and procedures to help
manage the key risks that may cause a
disruption to the Company's business and
operations, but their adequacy cannot
be predicted. The Company's Directors
are closely monitoring the situation and
considering the impact on the Company’s
business from both a financial and
operational perspective.
Regulatory risk
The Company operates in a highly
regulated environment and complies with
regulatory requirements. There is a risk that
regulatory approvals are withheld or take
longer than expected, or that unforeseen
circumstances arise where requirements
may not be adequately addressed in the
eyes of the regulator and costs may be
incurred to remediate perceived non-
compliance and/or obtain approval(s).
The Company’s business or operations may
be impacted by changes in personnel and
Governments, or in monetary, taxation and
other laws in Australia or overseas.
The Company’s permits and activities may
be subject to extensive regulation by local,
state and federal governments. There is no
assurance that future government policy
will not change, and this may adversely
affect the long-term prospects of the
Company. Future changes in governments,
regulations and policies may have an
adverse impact on the Company.
SIGNIFICANT CHANGES IN THE
STATE OF AFFAIRS
In accordance with the announcement
of 1 March 2021, the Consolidated Entity
announced on 11 August 2021 that
ConocoPhillips Australia SH1 Pty Ltd
(“ConocoPhillips Australia”) as operator of
the T/49P joint venture with TDO’s wholly-
owned subsidiary, 3D Oil T49P Pty Ltd, will
commence acquisition of the Sequoia MSS
3D seismic survey using the Shearwater
vessel the Geo Coral.
The survey is planned to cover an area of
approximately 2,500 km² with the seismic
survey acquisition estimated to take
approximately 60 days between the middle
of August and the end of October 2021.
ConocoPhillips Australia is the operator
of the T/49P joint venture with an 80%
interest in the T/49P Permit, the Company
having the remaining 20% interest.
Under the terms of the Farmout
Agreement, ConocoPhillips Australia was
to acquire a minimum of 1580 km2 of 3D
seismic at no expense to the Company
(TDO ASX Announcement 11 June 2020).
The proposed increase in size of the
acquisition area will provide coverage of
all leads within the T/49P Permit and tie in
with the previously acquired Flanagan 3D
seismic survey.
On 7 October 2021, the Consolidated
Entity announced an update surrounding
the delineation of additional prospectivity
within the VIC/P74 exploration permit.
This included an update to the Prospective
Resources estimates for Leads and
Prospects released to the market on 16
February 2021.
On 29 October 2021, the Consolidated
Entity announced the appointment of Mr
Trevor Slater as a Non-Executive Director,
with his appointment effective at the
conclusion of the Company’s Annual
General Meeting on 15 November 2021. In
addition, Ms Melanie Leydin stepped down
as Joint Company Secretary, effective
29 October 2021, with Mr Stefan Ross
continuing in the officeholder position as
sole Company Secretary.
members) whose support is needed to
realise our strategy and purpose. This
could lead to loss of stakeholder support or
regulatory approvals, increased taxes and
regulation, enforcement action, litigation
or class actions, or otherwise impact our
licence to operate and adversely affect our
reputation, fund raising capability, ability
to attract and retain talent, operational
continuity and financial performance.
Exploration and development risks
Exploration is a speculative activity with
an associated risk of discovery to find oil
and gas in commercial quantities, and a
risk of development. If the Company is
unsuccessful in locating and developing
or acquiring new reserves and resources
that are commercially viable, this may
have a material adverse effect on future
business, results of operations and financial
conditions.
Oil and gas exploration is a speculative
endeavour and the nature of the business
carries a degree of risk associated with
failure to find hydrocarbons in commercial
quantities or at all.
The Company utilises well-established
prospect evaluation, ranking methodologies
and experienced personnel to manage
exploration and development risks.
Reliance on key personnel
The Company’s success depends to a
significant extent upon its key management
personnel, as well as other management
and technical personnel including those
employed on a contractual basis. The
loss of the services of such personnel or
the reduced ability to recruit additional
personnel could have an adverse effect on
the performance of the Company.
The Company maintains a mixture of
permanent staff and expert consultants
to advance its programs and ensure
access to multiple skill sets. The Company
reviews remunerations to human resources
regularly.
IT system failure and cyber security risks
Any information technology system is
potentially vulnerable to interruption and/
or damage from a number of sources,
including but not limited to computer
viruses, cyber security attacks and other
security breaches, power, systems, internet
and data network failures, and natural
disasters.
The Company is committed to preventing
and reducing cyber security risks through
outsourced the IT management to a
reputable services provider.
23
MATTERS SUBSEQUENT TO THE
END OF THE FINANCIAL YEAR
On 2 September 2022, the Consolidated
Entity announced that the South Australia
Department of Energy and Mining has
awarded the Company the GSEL 759 Gas
Storage Exploration Licence in onshore
Otway Basin. The licence covers an area
of 1.02km2, centrally located around
the plugged and abandoned Caroline-1
wellhead, over part of the now depleted
Caroline Field, originally used for the
production of carbon dioxide in the Otway
Basin. The Field is potentially suitable for
the storage of hydrogen, natural gas, or
carbon dioxide. The acquisition of GSEL
759 represents an exciting development
opportunity for the Company in broadening
3D Oil’s strategy in the rapidly changing
East Coast energy market.
No other matter or circumstance has arisen
since 30 June 2022 that has significantly
affected, or may significantly affect the
Consolidated Entity's operations, the results
of those operations, or the Consolidated
Entity's state of affairs in future financial
years.
LIKELY DEVELOPMENTS AND
EXPECTED RESULTS FROM
OPERATIONS
The Consolidated Entity will continue to
pursue its exploration interest in
INFORMATION ON DIRECTORS
Mr Noel Newell
Executive Chairman
Qualifications
B App Sc (App Geol)
Experience and expertise
Noel Newell holds a Bachelor of Applied
Science and has over 30 years' experience
in the oil and gas industry, with 20 years of
this time with BHP Billiton and Petrofina.
With these companies Mr Newell has been
technically involved in exploration of areas
around the globe, particularly South East
Asia and all major Australian offshore
basins. Prior to leaving BHP Billiton in 2002,
Mr Newell was Principal Geologist working
within the Southern Margin Company and
primarily responsible for exploration within
the Gippsland Basin.
Mr Newell has a number of technical
publications and has co-authored Best
Paper and runner up Best Paper at the
Australian Petroleum Production &
Exploration Association conference and
Best Paper at the Western Australian Basins
Symposium. Mr Newell is the founder of 3D
Oil. Immediately prior to starting 3D Oil, Mr
Newell was a technical advisor to Nexus
Energy Limited and was directly involved in
their move to explore in the offshore of the
Gippsland Basin.
— VIC/P74 in the offshore Gippsland Basin
of Victoria;
— T49P in partnership with Conoco Phillips
Other current directorships
None
Australia SH1 Pty Ltd;
Former directorships (last 3 years)
— WA/527-P in the Roebuck Basin of
None
Western Australia:
— VIC/P79 in partnership with Conoco
Phillips Australia SH2 Pty Ltd: and
Special responsibilities
None
— GSEL759 in the Otway Basin of South
Interests in shares
Australia.
44,381,998 ordinary fully paid shares.
Interests in options
None
ENVIRONMENTAL REGULATION
The Consolidated Entity holds participating
interests in a number of oil and gas areas.
The various authorities granting such
tenements require the licence holder to
comply with the terms of the grant of the
licence and all directions given to it under
those terms of the licence. There have
been no known breaches of the tenement
conditions, and no such breaches have
been notified by any government agencies
during the year ended 30 June 2022.
On 4 February 2022, the Consolidated
Entity announced that the National
Offshore Petroleum Titles Administrator
(“NOPTA”) has awarded the Consolidated
Entity the VIC/P79 exploration permit in
the offshore Otway Basin. The 2,576km2
permit is located adjacent to the largest
gas fields in the offshore Otway Basin,
Thylacine and Geographe, and contains the
highly prospective Vanguard Prospect. The
Permit was awarded with a minimum work
commitment that includes one exploration
well. The acquisition of VIC/P79 accelerates
3D Oil’s strategy to be a significant east
coast gas producer and compliments our
Otway Basin Joint Venture in T/49P with
ConocoPhillips.
On 8 June 2022, the Consolidated Entity
announced an update surrounding the
delineation of additional prospectivity
within the VIC/P79 exploration permit,
Otway Basin, Victoria. This included
an update to the prospective resource
estimates for leads and prospectus released
to the market on 4 February 2022.
On 30 June 2022, the Company and
ConocoPhillips Australia SH2 Pty Ltd
(“ConocoPhillips Australia”) has executed
a Farmout Agreement (“FOA”) in relation
to the offshore Victorian Exploration
Permit VIC/P79 (“Permit”), located in the
Otway Basin.
Under the terms of the FOA, ConocoPhillips
Australia will acquire an 80% interest in
the Permit and operatorship in exchange
for an upfront payment of USD$3 million
(~AUD$4.35 million). ConocoPhillips
Australia will also undertake to drill an
exploration well as required by the Permit’s
Primary Term minimum work commitment
(currently required by February 2025).
The Consolidated Entity will be carried
for up to USD$35 million (~AUD$50.75
million) in well costs, above which it will
contribute 20% of costs in line with its
interest in the Permit. It should be noted
that the FOA is subject to conditions
precedent, including the agreement and
signing of a Joint Operating Agreement
by both parties and required government
/ regulatory approvals. At the date of this
report, agreement is subject to conditions
precedent, including the agreement and
signing of a Joint Operating Agreement
by both parties and required government/
regulatory approvals.
There were no other significant changes
in the state of affairs of the Consolidated
Entity during the financial period.
24
Mr Leo De Maria
Non-Executive Director
Trevor Slater (appointed 15 November 2021)
COMPANY SECRETARY
Non-Executive Director
Mr Stefan Ross BBus (Acc)
Company Secretary
Experience and expertise
Qualifications
Stefan Ross has over 10 years of
experience in accounting and secretarial
services for ASX listed companies. His
extensive experience includes ASX
compliance, corporate governance
control and implementation, statutory
financial reporting, shareholder meeting
requirements, capital raising management,
and board and secretarial support. Stefan
has a Bachelor of Business majoring in
Accounting.
Melanie Leydin – BBus (Acc. Corp Law)
CA FGIA
Joint Company Secretary
(resigned on 29 October 2021)
Melanie Leydin holds a Bachelor of
Business majoring in Accounting and
Corporate Law. She is a member of the
Institute of Chartered Accountants, Fellow
of the Governance Institute of Australia
and is a Registered Company Auditor. She
graduated from Swinburne University in
1997, became a Chartered Accountant in
1999 and from February 2000 to October
2021 was the principal of Leydin Freyer.
In November 2021 Vistra acquired Leydin
Freyer and, Melanie is now Vistra Australia's
Managing Director. Vistra is a prominent
provider of specialised consulting and
administrative services to clients in the
Fund, Corporate, Capital Markets, and
Private Wealth sectors.
Melanie has over 25 years’ experience in
the accounting profession and over 15
years’ experience holding Board positions
including Company Secretary of ASX listed
entities. She has extensive experience in
relation to public company responsibilities,
including ASX and ASIC compliance,
control and implementation of corporate
governance, statutory financial reporting,
reorganisation of Companies, initial
public offerings, secondary raisings and
shareholder relations.
Leo De Maria is a Chartered Accountant
with extensive experience in company
management, financial management,
mergers and acquisitions and risk
management.
Other current directorships
None
Former directorships (last 3 years)
None
Special responsibilities
Chairman of the Audit and the
Remuneration and Nomination Committees
Interests in shares
650,070 ordinary fully paid shares.
Interests in options
None
Interests in rights
112,903 performance rights
Mr Ian Tchacos
Non-Executive Director
B.Bus (Acc), Fellow of CPA Australia, Fellow
of the Governance Institute of Australia.
Experience and expertise
Trevor has extensive experience in the
development and operations of resource
and construction projects within Australia
and overseas performing as a director or
senior executive in ASX listed or unlisted
companies for over 30 years. Formerly,
Trevor operated as an executive director
for a gas production and storage project
in Bass Strait; and as country director
and manager for oil and gas exploration
projects in Brunei.
Trevor has also held senior roles in the
development of oil and gas fields in the
Timor Sea and consulted widely in South-
East Asia. He has also been extensively
involved in the development of significant
resource projects including the Ballarat
Gold Project where as CFO, he assisted the
Company in its initial exploration programs
and project development.
Other current directorships
None
Former directorships (last 3 years)
Experience and expertise
None
Interests in shares
264,753 ordinary fully paid shares
Interests in options
None
Interests in rights
None
Ian Tchacos is an oil and gas professional
with over 30 years international
experience in corporate development
and strategy, mergers and acquisitions,
petroleum exploration, development and
production operations, decision analysis,
commercial negotiation, oil and gas
marketing and energy finance. He has
a proven management track record in a
range of international energy company
environments.
Other current directorships
ADX Energy Ltd
Former directorships (last 3 years)
Xstate Resources Limited
(resigned on 26 November 2019)
Special responsibilities
Member of the Audit Committee and the
Remuneration and Nomination Committee
Interests in shares
428,500 ordinary fully paid shares
Interests in options
None
Interests in rights
112,903 performance rights
'Other current directorships' quoted above are current directorships for listed entities only and
excludes directorships in all other types of entities, unless otherwise stated.
'Former directorships (in the last 3 years)' quoted above are directorships held in the last 3
years for listed entities only and excludes directorships in all other types of entities, unless
otherwise stated.
25
MEETINGS OF DIRECTORS
The number of meetings of the Company's
Board of Directors ('the Board') held during
the year ended 30 June 2022, and the
number of meetings attended by each
Director were:
Mr N Newell
Mr L De Maria
Mr I Tchacos
Mr T Slater
Meetings
Held
Meetings
Attended
5
5
5
3
5
5
5
3
Held: represents the number of meetings
held during the time the Director held
office.
REMUNERATION REPORT
(AUDITED)
The remuneration report, which has
been audited, outlines the director and
executive remuneration arrangements
for the Company, in accordance with the
requirements of the Corporations Act 2001
and its Regulations.
Key management personnel are those
persons having authority and responsibility
for planning, directing and controlling the
activities of the entity, directly or indirectly,
including all Directors.
The remuneration report is set out under
the following main headings:
— Principles used to determine the nature
and amount of remuneration
— Details of remuneration
— Service agreements
— Share-based compensation
— Additional information
— Additional disclosures relating to key
management personnel
Principles used to determine the nature and
amount of remuneration
Additionally, the reward framework should
seek to enhance executives' interests by:
The objective of the Consolidated Entity's
executive reward framework is to ensure
reward for performance is competitive and
appropriate for the results delivered. The
framework aligns executive reward with the
achievement of strategic objectives and
the creation of value for shareholders, and
conforms with the market best practice for
delivery of reward. The Board of Directors
('the Board') ensures that executive reward
satisfies the following key criteria for good
reward governance practices:
— rewarding capability and experience
— reflecting competitive reward for
contribution to growth in shareholder
wealth
— providing a clear structure for earning
rewards
In accordance with best practice corporate
governance, the structure of non-
executive Director and executive Director
remuneration is separate.
— competitiveness and reasonableness
Non-executive Directors remuneration
— acceptability to shareholders
— alignment of executive compensation
— transparency
The Board is responsible for determining
and reviewing remuneration arrangements
for its directors and executives. The
performance of the Consolidated Entity
and the Company depends on the quality
of its directors and executives. The
remuneration philosophy is to attract,
motivate and retain high performance and
high quality personnel.
The Board has structured an executive
remuneration framework that is market
competitive and complementary to the
reward strategy of the Consolidated Entity.
The reward framework is designed to align
executive reward to shareholders' interests.
The Board have considered that it should
seek to enhance shareholders' interests by:
— focusing on sustained growth in
shareholder wealth, consisting of
dividends and growth in share price,
and delivering constant or increasing
return on assets as well as focusing the
executive on key non-financial drivers
of value
— attracting and retaining high calibre
executives
Fees and payments to non-executive
directors reflect the demands which are
made on, and the responsibilities of, the
directors. Non-executive directors fees and
payments are reviewed annually by the
Board.
ASX listing rules requires that the
aggregate non-executive directors
remuneration shall be determined
periodically by a general meeting. The most
recent determination was at the Annual
General Meeting held on 21 November
2012, where the shareholders approved an
aggregate remuneration of $400,000.
Executive remuneration
The Consolidated Entity aims to reward
executives with a level and mix of
remuneration based on their position and
responsibility, which are both fixed.
The executive remuneration and reward
framework have three components:
— base pay, annual leave, short term
incentives and non-monetary benefits
— share-based payments; and
— other remuneration such as
superannuation and long service leave
The combination of these comprises the
executive's total remuneration.
26
Consolidated Entity performance and link to
remuneration
Commencing in the 2021 financial year,
Directors and employees' remuneration
packages include performance-based
components. Performance rights may be
granted which offer the recipient the right,
upon achieving predetermined milestones,
to participate in the benefits accruing to
shareholders through the alignment of
the terms of the performance rights to
the shareholders' interests. During the
year ended 30 June 2021, the Company
granted performance rights to Non-
executive Directors (and employees) which
are conditional upon the achievement
of a target share price and tenure of
employment. The intention of this program
is to facilitate goal congruence between
Directors, Executives and employees with
that of the business and shareholders.
Generally, the executive's remuneration is
tied to the Consolidated Entity's successful
achievement of certain key milestones as
they relate to its operating activities. There
were no performance-based remuneration
to the Executive Director during the year
(2021: $50,000).
Voting and comments made at the
Company's 15 November 2021 Annual
General Meeting ('AGM')
The Company received 98.32% of 'for' votes
in relation to its remuneration report for the
year ended 30 June 2021. The Company
did not receive any specific feedback at the
AGM regarding its remuneration practices.
Fixed remuneration, consisting of base
salary, superannuation and non-monetary
benefits, are reviewed annually by the
Board, based on individual and business
unit performance, the overall performance
of the Company and comparable market
remunerations.
Executives can receive their fixed
remuneration in the form of cash or other
fringe benefits (for example motor vehicle
benefits) where it does not create any
additional costs to the Company and adds
additional value to the executive.
All Executives are eligible to receive a base
salary (which is based on factors such
as experience and comparable industry
information) or consulting fee. The
Board reviews the Executive Chairman's
remuneration package, and the Executive
Chairman reviews the senior Executives'
remuneration packages annually by
reference to the Consolidated Entity's
performance, executive performance
and comparable information within the
industry. The chairman is not present at
any discussions relating to determination
of his/her own remuneration.
The performance of Executives is measured
against criteria agreed annually with each
executive and is based predominantly on
the overall success of the Consolidated
Entity in achieving its broader corporate
goals. Bonuses and incentives are linked to
predetermined performance criteria. The
Board may, however, exercise its discretion
in relation to approving incentives, bonuses,
and options or performance rights and
can require changes to the Executive's
remuneration. This policy is designed to
attract the highest calibre of Executives and
reward them for performance that results in
long-term growth in shareholder wealth.
All remuneration paid to Directors and
Executives is valued at its cost to the
Consolidated Entity and expensed. Options
and performance rights are valued using
the Hoadley Trading & Investment Tools
(“Hoadley”) ESO5 option valuation model.
The long-term incentives ('LTI') includes
long service leave and share-based
payments. Shares, options or performance
rights are awarded to executives on the
discretion of the Board based on long-term
incentive measures.
27
DETAILS OF REMUNERATION
Amounts of remuneration
Details of the remuneration of key
management personnel of the
Consolidated Entity are set out in the
following tables.
Details of the remuneration of the directors
and other key management personnel
(defined as those who have the authority
and responsibility for planning, directing
and controlling the major activities of the
company) of the Company are set out in
the following tables.
The key management personnel of the
Consolidated Entity consisted of the
following Directors of 3D Oil Limited:
— Mr Noel Newell
— Mr Ian Tchacos
— Mr Leo De Maria
— Mr Trevor Slater
(appointed on 15 November 2021)
Short-term
benefits
Short term
incentives
Post-
employment
benefits
Long-term
benefits
Equity settled
share based
payments
Bonus
Super-
annuation
Long
service leave
Performance
rights
2022
Non-Executive Directors:
Mr I Tchacos
Mr L De Maria
Mr T Slater*
Executive Directors:
Mr N Newell
2021
Non-Executive Directors:
Mr I Tchacos
Mr L De Maria
Executive Directors:
Mr N Newell
Salaries
and fees
$
43,004
40,956
25,568
346,439
455,967
$
43,151
41,096
$
-
-
-
-
-
$
-
-
$
4,296
4,091
2,557
23,100
34,044
$
4,099
3,904
350,794
50,000
21,694
435,041
50,000
29,697
$
-
-
-
8,893
8,893
$
-
-
6,752
6,752
$
2,590
2,590
-
-
Total
$
49,890
47,637
28,125
378,432
5,180
504,084
$
$
1,597
1,597
48,847
46,597
-
429,240
3,194
524,684
The proportion of remuneration linked to performance and the fixed proportion are as follows:
Fixed
remuneration
At-risk short- term
remuneration
At-risk long term
remuneration
2022
2021
2022
2021
2022
2021
94%
95%
100%
100%
97%
97%
-
89%
-
-
-
-
-
-
-
11%
6%
5%
-
-
3%
3%
-
-
Name
Non-Executive Directors:
Mr I Tchacos
Mr L De Maria
Mr T Slater
Executive Directors:
Mr N Newell
28
SERVICE AGREEMENTS
Remuneration and other terms of
employment for key management
personnel are formalised in service
agreements. Details of these agreements
are as follows:
Mr N Newell
Executive Chairman
Agreement commenced
1 November 2006
Details
(i) Mr Newell may resign from his position
and thus terminate this contract by
giving 6 months written notice.
(ii) The Company may terminate this
employment agreement by providing
6 months written notice.
(iii) The Company may terminate the
contract at any time without notice
if serious misconduct has occurred.
Where termination with cause occurs,
Mr Newell is only entitled to that
portion of remuneration which is fixed,
and only up to the date of termination.
(iv) On termination of the agreement, Mr
Newell will be entitled to be paid those
outstanding amount owing to him up
until the Termination date.
Key management personnel have no
entitlement to termination payments in the
event of removal for misconduct.
Share-based compensation
Issue of shares
There were no ordinary shares issued to
directors and key management personnel
as part of compensation during the year
ended 30 June 2022 (2021: Nil).
Options
There were no options over ordinary shares
granted to or vested by Directors and other
key management personnel as part of
compensation during the year ended
30 June 2022 (2021: Nil).
Performance rights
There were 225,806 performance rights
over ordinary shares issued to Directors
as part of compensation that were
outstanding as at 30 June 2022
(2021: 225,806).
Grant date
17 November 2020
Vesting date and
exercisable date
Expiry date
Share price
hurdle for
vesting
Fair value per
right at grant
date
17 November 2022
17 November 2023
$0.090
$0.046
Name
Number of
rights granted
Grant date
Vesting date and
exercisable date
Expiry date
Mr Ian Tchacos
Mr Leo De Maria
112,903
112,903
17 November 2020
17 November 2022
17 November 2023
17 November 2020
17 November 2022
17 November 2023
Share price
hurdle for
vesting
Fair value
per right at
grant date
$0.090
$0.090
$0.046
$0.046
Performance rights granted carry no dividend or voting rights. No performance rights vested
and were exercised during the year.
29
Additional information
The earnings of the Consolidated Entity
for the five years to 30 June 2022 are
summarised below:
Other income including interest income
Net loss before tax
Net loss after tax
2022
$
467
2021
$
2020
$
2019
$
2018
$
87,478
85,279
43,629
27,696
(1,147,179)
(1,142,095)
(3,006,065)
(1,089,254)
(1,154,810)
(1,147,179)
(1,142,095)
(3,006,065)
(1,089,254)
(1,154,810)
The factors that are considered to affect total shareholders return ('TSR') are summarised below:
Share price at financial year start ($)
Share price at financial year end ($)
Basic loss per share (cents per share)
Additional disclosures relating to key
management personnel
Shareholding
The number of shares in the Company
held during the financial year by
each Director and other members of
key management personnel of the
Consolidated Entity, including their
related parties, is set out below:
Ordinary shares
Mr N Newell
Mr L De Maria
Mr I Tchacos
Mr T Slater *
2022
0.05
0.05
(0.43)
2021
0.07
0.05
(0.43)
2020
0.11
0.07
(1.13)
2019
0.05
0.11
(0.42)
2018
0.04
0.05
(0.49)
Balance at
the start of
the year
Received
as part of
remuneration
Additions
Disposals/
other
44,192,229
650,070
428,500
-
45,270,799
-
-
-
-
-
189,769
-
-
164,753
354,522
-
-
-
100,000
100,000
45,725,321
Balance at
the end of
the year
44,381,998
650,070
428,500
264,753
* Mr Trevor Slater was appointed as a Non-
Performance rights holding
Executive Director on 15 November 2021. The
balance disclosed in the “Disposals/other”
column represents his shareholding at the date of
appointment.
The number of performance rights over
ordinary shares in the Company held during
the financial year by each Director of the
Consolidated Entity, including their related
parties, is set out below:
Balance at
the start of
the year
112,903
112,903
225,806
Granted
Vested
Expired/
forfeited/
other
Balance at
the end of
the year
-
-
-
-
-
-
-
-
-
112,903
112,903
225,806
Performance rights over ordinary shares
Mr L De Maria
Mr I Tchacos
This concludes the remuneration report, which has been audited.
30
Shares under option
Shares under performance rights
There were no unissued ordinary shares of
3D Oil Limited under option outstanding at
the date of this report.
Unissued ordinary shares of 3D Oil Limited
under performance rights at the date of this
report are as follows:
Grant date
17 November 2020
28 January 2021
29 January 2021
1 February 2021
No person entitled to exercise the
performance rights had or has any right
by virtue of the performance right to
participate in any share issue of the
Company or of any other body corporate.
Shares issued on the exercise of options
There were no ordinary shares of 3D Oil
Limited issued on the exercise of options
during the year ended 30 June 2022 and
up to the date of this report.
Shares issued on the exercise of
performance rights
There were no ordinary shares of 3D
Oil Limited issued on the exercise of
performance rights during the year ended
30 June 2022.
Indemnity and insurance of officers
The Consolidated Entity has indemnified
the directors of the Company for costs
incurred, in their capacity as a director, for
which they may be held personally liable,
except where there is a lack of good faith.
During the financial year, the Company
paid a premium in respect of a contract to
insure the directors of the Company against
a liability to the extent permitted by the
Corporations Act 2001. The contract of
insurance prohibits disclosure of the nature
of liability and the amount of the premium.
Indemnity and insurance of auditor
The Company has not otherwise, during
or since the financial year, indemnified or
agreed to indemnify the auditor of the
Company or any related entity against a
liability incurred by the auditor.
During the financial year, the Company has
not paid a premium in respect of a contract
to insure the auditor of the Company or any
related entity.
Expiry date
17 November 2023
28 January 2024
29 January 2024
1 February 2024
Exercise price
Number under rights
$0.000
$0.000
$0.000
$0.000
225,806
80,645
80,645
56,451
443,547
Proceedings on behalf of the Company
Forward looking statements
This Financial Report includes certain
forward-looking statements that have
been based on current expectations about
future acts, events and circumstances.
These forward-looking statements are,
however, subject to risks, uncertainties
and assumptions that could cause those
acts, events and circumstances to differ
materially from the expectations described
in such forward-looking statements.
These factors include, among other things,
commercial and other risks associated
with the meeting of objectives and other
investment considerations, as well as other
matters not yet known to the Company or
not currently considered material by the
Company.
This report is made in accordance with a
resolution of Directors, pursuant to section
298(2)(a) of the Corporations Act 2001.
On behalf of the Directors
Noel Newell
Executive Chairman
30 September 2022
Melbourne
No person has applied to the Court under
section 237 of the Corporations Act 2001
for leave to bring proceedings on behalf
of the Company, or to intervene in any
proceedings to which the Company
is a party for the purpose of taking
responsibility on behalf of the Company for
all or part of those proceedings.
Non-audit services
There were no non-audit services provided
during the financial year by the auditor.
Officers of the Company who are former
partners of Grant Thornton Audit Pty Ltd
There are no officers of the Company who
are former partners of Grant Thornton
Audit Pty Ltd.
Auditor's independence declaration
A copy of the auditor's independence
declaration as required under section 307C
of the Corporations Act 2001 is set out
immediately after this Directors' report.
This report is made in accordance with a
resolution of Directors, pursuant to section
306(3)(a) of the Corporations Act 2001.
Auditor
Grant Thornton Audit Pty Ltd continues in
office in accordance with section 327 of the
Corporations Act 2001.
Rounding of amounts
3D Oil Limited is a type of Company
that is referred to in ASIC Corporations
(Rounding in Financial/Directors’ Reports)
Instrument 2016/191 and therefore the
amounts contained in this report and in
the financial report have been rounded to
the nearest dollar.
31
Grant Thornton Audit Pty Ltd
Level 22 Tower 5
Collins Square
727 Collins Street
Melbourne VIC 3008
GPO Box 4736
Melbourne VIC 3001
T +61 3 8320 2222
Auditor’s Independence Declaration
To the Directors of 3D Oil Limited
In accordance with the requirements of section 307C of the Corporations Act 2001, as lead auditor for the audit
of 3D Oil Limited for the year ended 30 June 2022, I declare that, to the best of my knowledge and belief, there
have been:
a no contraventions of the auditor independence requirements of the Corporations Act 2001 in relation to
the audit; and
b no contraventions of any applicable code of professional conduct in relation to the audit.
Grant Thornton Audit Pty Ltd
Chartered Accountants
D G Ng
Partner – Audit & Assurance
Melbourne, 30 September 2022
www.grantthornton.com.au
ACN-130 913 594
Grant Thornton Audit Pty Ltd ACN 130 913 594 a subsidiary or related entity of Grant Thornton Australia Limited ABN 41 127 556 389 ACN 127 556 389.
‘Grant Thornton’ refers to the brand under which the Grant Thornton member firms provide assurance, tax and advisory services to their clients and/or
refers to one or more member firms, as the context requires. Grant Thornton Australia Limited is a member firm of Grant Thornton International Ltd (GTIL).
GTIL and the member firms are not a worldwide partnership. GTIL and each member firm is a separate legal entity. Services are delivered by the member
firms. GTIL does not provide services to clients. GTIL and its member firms are not agents of, and do not obligate one another and are not liable for one
another’s acts or omissions. In the Australian context only, the use of the term ‘Grant Thornton’ may refer to Grant Thornton Australia Limited ABN 41 127
556 389 ACN 127 556 389 and its Australian subsidiaries and related entities. Liability limited by a scheme approved under Professional Standards
Legislation.
w
32
FINANCIAL REPORTS
33
CONSOLIDATED STATEMENT OF PROFIT
OR LOSS AND OTHER COMPREHENSIVE INCOME
For the year ended 30 June 2022
Other income
Interest income
Expenses
Corporate expenses
Employment expenses
Occupancy expenses
Depreciation and amortisation expense
Exploration costs
Share based payments
Finance costs
Loss before income tax expense
Income tax expense
Note
2022
5
$
-
467
Consolidated
2021
$
82,908
4,570
(473,583)
(451,925)
6
(505,620)
(563,528)
(14,449)
(43,954)
(121,275)
(118,136)
(15,994)
(11,886)
(4,839)
(33,088)
(9,072)
(9,870)
(1,147,179)
(1,142,095)
-
-
6
14
6
7
Loss after income tax expense for the year attributable to the owners of 3D Oil Limited
(1,147,179)
(1,142,095)
Other comprehensive income for the year, net of tax
-
-
Total comprehensive income for the year attributable to the owners of 3D Oil Limited
(1,147,179)
(1,142,095)
Basic earnings per share
Diluted earnings per share
32
32
Cents
(0.43)
(0.43)
Cents
(0.43)
(0.43)
The above consolidated statement of profit or loss and other comprehensive income should be read in conjunction with the accompanying notes
34
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
As at 30 June 2022
Assets
Current assets
Cash and cash equivalents
Other receivables
Short term investments
Prepayments
Total current assets
Non-current assets
Property, plant and equipment
Right-of-use assets
Intangibles
Exploration and evaluation
Total non-current assets
Total assets
Liabilities
Current liabilities
Trade and other payables
Lease liabilities
Employee benefits
Total current liabilities
Non-current liabilities
Lease liabilities
Employee benefits
Total non-current liabilities
Total liabilities
Net assets
Equity
Issued capital
Reserves
Accumulated losses
Total equity
Note
Consolidated
2022
$
2021
$
8
9
10
11
12
13
14
15
20
16
20
17
1,243,195
3,048,802
29,992
93,577
-
31,752
93,577
41,924
1,366,764
3,216,055
17,542
257,109
47,212
16,525
79,156
76,641
6,207,257
5,374,599
6,529,120
5,546,921
7,895,884
8,762,976
925,255
820,345
75,488
96,614
228,444
231,912
1,229,187
1,148,871
190,555
1,916
192,471
-
4,585
4,585
1,421,658
1,153,456
6,474,226
7,609,520
18
55,483,678
55,483,678
17,559
9,072
(49,027,011)
(47,883,230)
6,474,226
7,609,520
The above consolidated statement of financial position should be read in conjunction with the accompanying notes
35
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
For the year ended 30 June 2022
Consolidated
Balance at 1 July 2020
Loss after income tax expense for the year
Other comprehensive income for the year, net of tax
Total comprehensive income for the year
Transactions with owners in their capacity as owners:
Share-based payments
Balance at 30 June 2021
Consolidated
Balance at 1 July 2021
Loss after income tax expense for the year
Other comprehensive income for the year, net of tax
Total comprehensive income for the year
Transactions with owners in their capacity as owners:
Lapse of performance rights
Share-based payments
Balance at 30 June 2022
Issued
capital
Accumulated
losses
$
$
55,483,678
(46,741,135)
(1,142,095)
-
(1,142,095)
-
-
-
-
Reserves
Total equity
$
-
-
-
-
$
8,742,543
(1,142,095)
-
(1,142,095)
-
9,072
9,072
55,483,678
(47,883,230)
9,072
7,609,520
Issued
capital
Accumulated
losses
Reserves
Total equity
$
$
$
$
55,483,678
(47,883,230)
9,072
7,609,520
-
-
-
-
-
(1,147,179)
-
(1,147,179)
-
-
-
(1,147,179)
-
(1,147,179)
3,398
-
(3,398)
11,885
-
11,885
55,483,678
(49,027,011)
17,559
6,474,226
The above consolidated statement of changes in equity should be read in conjunction with the accompanying notes
36
CONSOLIDATED STATEMENT OF CASH FLOWS
For the year ended 30 June 2022
Cash flows from operating activities
Payments to suppliers and employees (inclusive of GST)
Interest received
Interest on lease liabilities paid
COVID-19 incentives
Note
Consolidated
2022
$
2021
$
(993,446)
(1,132,676)
811
(4,839)
4,963
(9,870)
(997,474)
(1,137,583)
-
88,908
Net cash used in operating activities
31
(997,474)
(1,048,675)
Cash flows from investing activities
Payments for computer equipment
Payments for intangibles
Payments for exploration and evaluation
Net cash used in investing activities
Cash flows from financing activities
Payment of principal element of lease liabilities
Net cash used in financing activities
Net decrease in cash and cash equivalents
Cash and cash equivalents at the beginning of the financial year
11
13
(6,362)
(6,862)
-
(30,001)
(715,100)
(851,721)
(721,462)
(888,584)
(86,671)
(91,130)
(86,671)
(91,130)
(1,805,607)
(2,028,389)
3,048,802
5,077,191
Cash and cash equivalents at the end of the financial year
8
1,243,195
3,048,802
The above consolidated statement of cash flows should be read in conjunction with the accompanying notes
37
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
30 June 2022
NOTE 1. GENERAL
INFORMATION
The financial statements cover 3D Oil
Limited as a consolidated entity consisting
of 3D Oil Limited and the entities it
controlled at the end of, or during, the year.
The financial statements are presented in
Australian dollars, which is 3D Oil Limited's
functional and presentation currency.
3D Oil Limited is a listed public company
limited by shares, incorporated and
domiciled in Australia. Its registered office
and principal place of business is:
Level 18
41 Exhibition Street
Melbourne VIC 3000
A description of the nature of the
Consolidated Entity's operations and its
principal activities are included in the
Directors' report, which is not part of the
financial statements.
The financial statements were authorised
for issue, in accordance with a resolution
of Directors, on 30 September 2022. The
Directors have the power to amend and
reissue the financial statements.
NOTE 2.
SIGNIFICANT
ACCOUNTING
POLICIES
The principal accounting policies adopted
in the preparation of the financial
statements are set out either in the
respective notes or below. These policies
have been consistently applied to all the
years presented, unless otherwise stated.
NEW OR AMENDED
ACCOUNTING STANDARDS AND
INTERPRETATIONS ADOPTED
The Consolidated Entity has adopted
all of the new or amended Accounting
Standards and Interpretations issued
by the Australian Accounting Standards
Board ('AASB') that are mandatory for the
current reporting period.
Any new or amended Accounting
Standards or Interpretations that are not yet
mandatory have not been early adopted.
GOING CONCERN
The financial report has been prepared on
the going concern basis, which assumes
continuity of normal business activities and
38
the realisation of assets and the settlement of
liabilities in the ordinary course of business.
The working capital position as at 30 June
2022 of the Consolidated Entity results in
an excess of current assets over current
liabilities of $137,577. The Consolidated
Entity made a loss after tax of $1,147,179,
incurred operating cash outflows of
$997,474 and invested $715,100 in
exploration and evaluation during the year.
The cash balances, including term deposits,
as at 30 June 2022 was $1,336,772.
In addition, on 30 June 2022, the Company
and ConocoPhillips Australia executed a
Farm Out Agreement (“FOA”) in relation to
the offshore Victorian Exploration Permit
VIC/P79, located in the Otway Basin. Under
the terms of the FOA, ConocoPhillips
Australia will acquire an 80% interest in
the Permit and operatorship in exchange
for an upfront payment of USD$3 million
(~AUD$4.35 million). ConocoPhillips
Australia will also undertake to drill an
exploration well as required by the Permit’s
Primary Term minimum work commitment
(currently required by February 2025). The
Company will be carried for up to USD$35
million (~AUD$50.75 million) in well costs,
above which it will contribute 20% of
costs in line with its interest in the Permit.
It should be noted that at the date of this
report, the FOA is subject to conditions
precedent, including the agreement and
signing of a Joint Operating Agreement by
both parties and required government /
regulatory approvals.
The continuing viability of the Consolidated
Entity and its ability to continue as a
going concern is dependent upon the
Consolidated Entity being successful in its
continuing efforts in exploration projects
and accessing additional sources of capital
to meet the commitments as and when
required. To meet the Consolidated Entity's
funding requirements as and when they
fall due the Consolidated Entity will need
to take appropriate steps, including a
combination of:
— Raising capital by one of or a
combination of the following: placement
of shares, rights issue, share purchase
plan, etc;
— Meeting its obligations by either farm-
out or partial sale of the Consolidated
Entity’s exploration interests;
— Subject to negotiation and approval,
minimum work requirements may be
varied or suspended, and/or permits may
be surrendered or cancelled; or
— Other avenues that may be available to
the Consolidated Entity.
The Consolidated Entity’s market
capitalisation at 30 June 2022 is in excess
of its net assets position of $6,474,226.
As the Consolidated Entity is still in the
exploration phase of activities, subject to
necessary regulatory approvals, it has the
ability to control the level of its operations
and hence the level of its expenditure
over the next 12 months. Should there be
any delay in the funds from the VIC/P79
farmout, management are confident that
they can reduce their level of expenditure in
order to retain appropriate cash balances.
Management remains very diligent in their
ongoing monitoring of cash balances day
by day.
Having assessed the potential uncertainties
relating to the Consolidated Entity’s ability
to effectively fund exploration activities
and operating expenditures, the Directors
believe that the Consolidated Entity will
continue to operate as a going concern for
the foreseeable future. The Directors are
therefore confident that the going concern
basis of preparation is appropriate as at the
date of this report.
ROUNDING OF AMOUNTS
3D Oil Limited is a type of Company
that is referred to in ASIC Corporations
(Rounding in Financial/Directors’ Reports)
Instrument 2016/191 and therefore the
amounts contained in this report and in
the financial report have been rounded to
the nearest dollar.
BASIS OF PREPARATION
These general purpose financial statements
have been prepared in accordance with
Australian Accounting Standards and
Interpretations issued by the Australian
Accounting Standards Board ('AASB') and
the Corporations Act 2001, as appropriate
for for-profit oriented entities. These
financial statements also comply with
International Financial Reporting Standards
as issued by the International Accounting
Standards Board ('IASB').
Historical cost convention
The financial statements have been prepared
under the historical cost convention, except
for, where applicable, the revaluation of
financial assets and liabilities at fair value
through profit or loss, financial assets at fair
value through other comprehensive income,
investment properties, certain classes
of property, plant and equipment and
derivative financial instruments.
non-controlling interest in the subsidiary
together with any cumulative translation
differences recognised in equity. The
Consolidated Entity recognises the fair value
of the consideration received and the fair
value of any investment retained together
with any gain or loss in profit or loss.
extent that it is no longer probable that
future taxable profits will be available
for the carrying amount to be recovered.
Previously unrecognised deferred tax
assets are recognised to the extent that it
is probable that there are future taxable
profits available to recover the asset.
Critical accounting estimates
The preparation of the financial statements
requires the use of certain critical
accounting estimates. It also requires
management to exercise its judgement in
the process of applying the Consolidated
Entity's accounting policies. The areas
involving a higher degree of judgement or
complexity, or areas where assumptions
and estimates are significant to the financial
statements, are disclosed in note 3.
PARENT ENTITY INFORMATION
In accordance with the Corporations Act
2001, these financial statements present
the results of the Consolidated Entity only.
Supplementary information about the
parent entity is disclosed in note 27 .
INTEREST INCOME
Interest revenue is recognised as interest
accrues using the effective interest
method. This is a method of calculating
the amortised cost of a financial asset and
allocating the interest income over the
relevant period using the effective interest
rate, which is the rate that exactly discounts
estimated future cash receipts through the
expected life of the financial asset to the
net carrying amount of the financial asset.
PRINCIPLES OF CONSOLIDATION
Other revenue
The consolidated financial statements
incorporate the assets and liabilities of all
subsidiaries of 3D Oil Limited ('Company' or
'parent entity') as at 30 June 2022 and the
results of all subsidiaries for the year then
ended. 3D Oil Limited and its subsidiaries
together are referred to in these financial
statements as the 'Consolidated Entity'.
Subsidiaries are all those entities over
which the Consolidated Entity has control.
The Consolidated Entity controls an entity
when the Consolidated Entity 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 to direct the activities of the
entity. Subsidiaries are fully consolidated
from the date on which control is
transferred to the Consolidated Entity.
They are de-consolidated from the date
that control ceases.
Intercompany transactions, balances
and unrealised gains on transactions
between entities in the Consolidated
Entity are eliminated. Unrealised losses
are also eliminated unless the transaction
provides evidence of the impairment of
the asset transferred. Accounting policies
of subsidiaries have been changed where
necessary to ensure consistency with the
policies adopted by the Consolidated Entity.
The acquisition of subsidiaries is accounted
for using the acquisition method of
accounting. A change in ownership interest,
without the loss of control, is accounted
for as an equity transaction, where the
difference between the consideration
transferred and the book value of the share
of the non-controlling interest acquired is
recognised directly in equity attributable to
the parent.
Where the Consolidated Entity loses
control over a subsidiary, it derecognises
the assets including goodwill, liabilities and
Other revenue is recognised when it is
received or when the right to receive
payment is established.
INCOME TAX
The income tax expense or benefit for the
period is the tax payable on that period's
taxable income based on the applicable
income tax rate for each jurisdiction,
adjusted by the changes in deferred
tax assets and liabilities attributable to
temporary differences, unused tax losses
and the adjustment recognised for prior
periods, where applicable.
Deferred tax assets and liabilities are
recognised for temporary differences at the
tax rates expected to be applied when the
assets are recovered or liabilities are settled,
based on those tax rates that are enacted
or substantively enacted, except for:
— When the deferred income tax asset or
liability arises from the initial recognition
of goodwill or an asset or liability in
a transaction that is not a business
combination and that, at the time of
the transaction, affects neither the
accounting nor taxable profits; or
— When the taxable temporary difference
is associated with interests in
subsidiaries, associates or joint ventures,
and the timing of the reversal can be
controlled and it is probable that the
temporary difference will not reverse in
the foreseeable future.
Deferred tax assets are recognised for
deductible temporary differences and unused
tax losses only if it is probable that future
taxable amounts will be available to utilise
those temporary differences and losses.
The carrying amount of recognised and
unrecognised deferred tax assets are
reviewed at each reporting date. Deferred
tax assets recognised are reduced to the
Deferred tax assets and liabilities are offset
only where there is a legally enforceable
right to offset current tax assets against
current tax liabilities and deferred tax
assets against deferred tax liabilities; and
they relate to the same taxable authority on
either the same taxable entity or different
taxable entities which intend to settle
simultaneously.
3D Oil Limited (the 'head entity') and its
wholly-owned Australian subsidiaries
have formed an income tax consolidated
group under the tax consolidation regime.
The head entity and each subsidiary in
the tax consolidated group continue to
account for their own current and deferred
tax amounts. The tax consolidated group
has applied the 'separate taxpayer within
group' approach in determining the
appropriate amount of taxes to allocate to
members of the tax consolidated group.
CURRENT AND NON-CURRENT
CLASSIFICATION
Assets and liabilities are presented in the
statement of financial position based on
current and non-current classification.
An asset is classified as current when: it is
either expected to be realised or intended
to be sold or consumed in the Consolidated
Entity's normal operating cycle; it is held
primarily for the purpose of trading; it is
expected to be realised within 12 months
after the reporting period; or the asset is
cash or cash equivalent unless restricted
from being exchanged or used to settle
a liability for at least 12 months after the
reporting period. All other assets are
classified as non-current.
A liability is classified as current when:
it is either expected to be settled in the
Consolidated Entity's normal operating cycle;
it is held primarily for the purpose of trading;
it is due to be settled within 12 months
after the reporting period; or there is no
unconditional right to defer the settlement
of the liability for at least 12 months after
the reporting period. All other liabilities are
classified as non-current.
Deferred tax assets and liabilities are always
classified as non-current.
JOINT OPERATIONS
A joint operation is a joint arrangement
whereby the parties that have joint
control of the arrangement have rights
to the assets, and obligations for the
39
liabilities, relating to the arrangement.
The Consolidated Entity has recognised
its share of jointly held assets, liabilities,
revenues and expenses of joint operations.
These have been incorporated in the
financial statements under the appropriate
classifications.
EXPLORATION EXPENDITURE
Exploration expenditure incurred is
accumulated in respect of each identifiable
area of interest. These costs are only carried
forward in relation to each area of interest
to the extent the following conditions are
satisfied:
(a) the rights to tenure of the area of
interest are current; and
(b) at least one of the following conditions
is also met:
(i) the exploration and evaluation
expenditures are expected to
be recouped through successful
development and exploitation of
the area of interest, or alternatively,
by its sale; or
(ii) exploration and 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.
Accumulated costs in relation to an
abandoned area are written off in full
against profit in the year in which the
decision to abandon the area is made.
When production commences, the
accumulated costs for the relevant area of
interest are amortised over the life of the
area according to the rate of depletion of
the economically recoverable reserves.
A regular review is undertaken of
each area of interest to determine the
appropriateness of continuing to carry
forward cost in relation to that area of
interest.
Costs of site restoration are provided over
the life of the facility from when exploration
commences and are included in the cost
of that stage. Site restoration costs include
the dismantling and removal of mining
plant, equipment and building structures,
waste removal, and rehabilitation of the site
in accordance with clauses of the mining
permits. Such costs have been determined
using estimates of future costs, current
legal requirements and technology on an
undiscounted basis.
40
Any changes in the estimates for the
costs are accounted on a prospective
basis. In determining the costs of site
restoration, there is uncertainty regarding
the nature and extent of the restoration
due to community expectations and future
legislation. Accordingly the costs have
been determined on the basis that the
restoration will be completed within one
year of abandoning the site.
IMPAIRMENT OF NON-FINANCIAL
ASSETS
Non-financial assets are reviewed for
impairment whenever events or changes
in circumstances indicate that the carrying
amount may not be recoverable. An
impairment loss is recognised for the
amount by which the asset's carrying
amount exceeds its recoverable amount.
Recoverable amount is the higher of an
asset's fair value less costs of disposal
and value-in-use. The value-in-use is the
present value of the estimated future
cash flows relating to the asset using a
pre-tax discount rate specific to the asset
or cash-generating unit to which the
asset belongs. Assets that do not have
independent cash flows are grouped
together to form a cash-generating unit.
LEASES
At inception of a contract, the Consolidated
Entity assesses whether a contract is, or
contains, a lease. A contract is, or contains,
a lease if the contract conveys the right
to control the use of an identified asset
for a period of time in exchange for
consideration. To assess whether a contract
conveys the right to control the use of an
identified asset, the Consolidated Entity
assesses whether:
— The contract involves the use of an
identified asset – this may be specified
explicitly or implicitly and should
be physically distinct or represent
substantially all of the capacity of a
physically distinct asset. If the supplier
has a substantive substitution right, then
the asset is not identified;
— The Consolidated Entity has the
right to obtain substantially all of the
economic benefits from use of the asset
throughout the period of use; and
— The Consolidated Entity has the right
to direct the use of the asset. The
Consolidated Entity has this right when
it has the decision-making rights that
are most relevant to changing how and
for what purpose the asset is used. In
rare cases where the decision about how
and for what purpose the asset is used is
predetermined, the Consolidated Entity
has the right to direct the use of the
asset if either:
— The Consolidated Entity has the right
to operate the asset; or
— The Consolidated Entity designed the
asset in a way that predetermine how
and for what purpose it will be used.
At inception or on reassessment of a
contract that contains a lease component,
the Consolidated Entity allocates the
consideration in the contract to each lease
component on the basis of their relative
stand-alone prices. However, for the
leases of land and buildings in which it is a
lessee, the Consolidated Entity has elected
not to separate non-lease components
and account for the lease and non-lease
components as a single lease component.
As a lessee
The Consolidated Entity recognises a right-
of-use asset and a lease liability at the lease
commencement date. The right-of-use
asset is initially measured at cost, which
comprises the initial amount of the lease
liability adjusted for any lease payments
made at or before the commencement date,
plus any initial direct costs incurred and an
estimate of costs to dismantle and remove
the underlying asset or to restore the
underlying asset or the site on which it is
located, less any lease incentives received.
The right-of-use asset is subsequently
depreciated using the straight-line method
from the commencement date to the earlier
of the end of the useful life of the right-of-
use asset or the end of the lease term. The
estimated useful lives of right-of-use assets
are determined on the same basis as those
of property and equipment. In addition, the
right-of-use asset is periodically reduced by
impairment losses, if any, and adjusted for
certain remeasurements of the lease liability.
The lease liability is initially measured at the
present value of the lease payments that
are not paid at the commencement date,
discounted using the interest rate implicit
in the lease or, if that rate cannot be readily
determined, the Consolidated Entity’s
incremental borrowing rate. Generally, the
Consolidated Entity uses its incremental
borrowing rate as the discount rate.
Lease payments included in the
measurement of the lease liability comprise
the following:
— Fixed payments, including in-substance
fixed payments;
— Variable lease payments that depend
on an index or a rate, initially measured
using the index or rate as at the
commencement date;
— Amounts expected to be payable under
a residual value guarantee; and
— The exercise price under a purchase
option that the Consolidated Entity is
reasonably certain to exercise, lease
payments in an optional renewal period
if the Consolidated Entity is reasonably
certain to exercise an extension option,
and penalties for early termination of a
lease unless the Consolidated Entity is
reasonably certain not to terminate early.
The lease liability is measured at amortised
cost using the effective interest method,
It is remeasured when there is a change
in future lease payments arising from
a change in an index or rate, if there is
a change in the Consolidated Entity’s
estimate of the amount expected to be
payable under a residual value guarantee,
or if the Consolidated Entity changes its
assessment of whether it will exercise a
purchase, extension or termination option.
When the lease liability is remeasured in
this way, a corresponding adjustment is
made to the carrying amount of the right-
of-use assets, or is recorded in profit or loss
if the carrying amount of the right-of-use
asset has been reduced to zero.
Short-term leases and leases of
low-value assets
The Consolidated Entity has elected not
to recognise right-of-use assets and lease
liabilities for short-term leases that have a
lease term of 12 months or less and leases
of low-value assets, including IT equipment.
The Consolidated Entity recognises the
lease payments associated with these
leases as an expense on a straight-line basis
over the lease term.
GOODS AND SERVICES TAX ('GST')
AND OTHER SIMILAR TAXES
Revenues, expenses and assets are
recognised net of the amount of
associated GST, unless the GST incurred is
not recoverable from the tax authority. In
this case it is recognised as part of the cost
of the acquisition of the asset or as part of
the expense.
Receivables and payables are stated inclusive
of the amount of GST receivable or payable.
The net amount of GST recoverable from,
or payable to, the tax authority is included
in other receivables or other payables in the
statement of financial position.
Cash flows are presented on a gross basis.
The GST components of cash flows arising
from investing or financing activities
which are recoverable from, or payable
to the tax authority, are presented as
operating cash flows.
Commitments and contingencies are
disclosed net of the amount of GST
recoverable from, or payable to, the
tax authority.
FAIR VALUE MEASUREMENT
When an asset or liability, financial or
non-financial, is measured at fair value for
recognition or disclosure purposes, the fair
value is based on the price that would be
received to sell an asset or paid to transfer
a liability in an orderly transaction between
market participants at the measurement
date; and assumes that the transaction will
take place either: in the principal market; or
in the absence of a principal market, in the
most advantageous market.
Fair value is measured using the
assumptions that market participants
would use when pricing the asset or
liability, assuming they act in their
economic best interests. For non-financial
assets, the fair value measurement is based
on its highest and best use. Valuation
techniques that are appropriate in the
circumstances and for which sufficient
data are available to measure fair value,
are used, maximising the use of relevant
observable inputs and minimising the use
of unobservable inputs.
NEW ACCOUNTING STANDARDS
AND INTERPRETATIONS NOT YET
MANDATORY OR EARLY ADOPTED
Australian Accounting Standards and
Interpretations that have recently been
issued or amended but are not yet
mandatory, have not been early adopted
by the Consolidated Entity for the annual
reporting period ended 30 June 2022. The
Consolidated Entity has not yet assessed
the impact of these new or amended
Accounting Standards and Interpretations.
NOTE 3. CRITICAL
ACCOUNTING
JUDGEMENTS,
ESTIMATES AND
ASSUMPTIONS
The preparation of the financial statements
requires management to make judgements,
estimates and assumptions that affect the
reported amounts in the financial statements.
Management continually evaluates its
judgements and estimates in relation to
assets, liabilities, contingent liabilities,
revenue and expenses. Management bases
its judgements, estimates and assumptions
on historical experience and on other
various factors, including expectations of
future events, management believes to
be reasonable under the circumstances.
The resulting accounting judgements and
estimates will seldom equal the related actual
results. The judgements, estimates and
assumptions that have a significant risk of
causing a material adjustment to the carrying
amounts of assets and liabilities (refer to the
respective notes) within the next financial
year are discussed below.
Share-based payment transactions
The Consolidated Entity measures the
cost of equity-settled transactions with
employees by reference to the fair value
of the equity instruments at the date at
which they are granted. The fair value is
determined by using either the Hoadley
Trading & Investment Tools (“Hoadley”)
ESO5 option valuation model taking into
account the terms and conditions upon
which the instruments were granted. The
accounting estimates and assumptions
relating to equity-settled share-based
payments would have no impact on the
carrying amounts of assets and liabilities
within the next annual reporting period but
may impact profit or loss and equity.
Recovery of deferred tax assets
Deferred tax assets are recognised for
deductible temporary differences only
if the Consolidated Entity considers it is
probable that future taxable amounts will
be available to utilise those temporary
differences and losses.
Exploration and evaluation costs
Exploration and evaluation costs have
been capitalised on the basis that the
Consolidated Entity will commence
commercial production in the future, from
which time the costs will be amortised in
proportion to the depletion of the mineral
resources. Key judgements are applied
in considering costs to be capitalised
which includes determining expenditures
directly related to these activities and
allocating overheads between those that
are expensed and capitalised. In addition,
costs are only capitalised that are expected
to be recovered either through successful
development or sale of the relevant mining
interest. The expectation of recovery
of the costs capitalised is based on the
assumption that the Group will be able
to obtain adequate financing to allow the
continued exploration and subsequent
development of areas of interest by either
successfully farming out a proportion
of existing permits or raising adequate
capital in its own right. To the extent
that capitalised costs are determined
not to be recoverable in the future, they
will be written off in the period in which
this determination is made. Significant
judgement is required by management
when assessing each of area of interest and
therefore management's judgement carries
the risk of been misstated.
41
NOTE 4. OPERATING SEGMENTS
The chief decision makers, being the Board
of Directors, assess the performance of the
Consolidated Entity as a whole and as such
through one segment.
AASB 8 requires operating segments to be
identified on the basis of internal reports
about the components of the Consolidated
Entity that are regularly reviewed by the
chief decision maker in order to allocate
resources to the segment and to assess
its performance. 3D Oil Limited operates
in the development of oil and gas within
Australia. The Consolidated Entity's
activities are therefore classified as one
operating segment.
ACCOUNTING POLICY FOR
OPERATING SEGMENTS
Operating segments are presented using
the 'management approach', where the
information presented in this financial
statements is on the same basis as the
internal reports provided to the Chief
Operating Decision Makers ('CODM').
The CODM is responsible for the allocation
of resources to operating segments and
assessing their performance.
NOTE 5. OTHER INCOME
COVID-19 incentives
COVID-19 incentives represent the job keeper and cash flow boost payments received
from Federal Government in response to ongoing novel coronavirus (COVID-19) pandemic.
Government grants are recognised in the financial statements at expected values or actual
cash received when there is a reasonable assurance that the Consolidated Entity will comply
with the requirements and that the grant will be received. The Consolidated Entity has
recognised its share of revenues, expenses and expenses reimbursements of joint operations,
which give rise to job keeper payments, within exploration assets in the financial statements.
NOTE 6. EXPENSES
Loss before income tax includes the following specific expenses:
Depreciation
Plant and equipment
Right-of-use assets
Total depreciation
Amortisation
Software
Total depreciation and amortisation
Post-employment benefit plans – Superannuation contributions
Employment entitlements
Total employment costs
Finance costs
Consolidated
2021
$
82,908
2022
$
-
Consolidated
2022
$
2021
$
(5,355)
(4,368)
(86,491)
(86,340)
(91,846)
(90,708)
(29,429)
(27,428)
(121,275)
(118,136)
(37,498)
(26,306)
(468,122)
(537,222)
(505,620)
(563,528)
Interest and finance charges paid/payable on lease liabilities
(4,839)
(9,870)
42
NOTE 7. INCOME TAX EXPENSE
Numerical reconciliation of income tax expense and tax at the statutory rate
Loss before income tax expense
Tax at the statutory tax rate of 25% (2021: 26%)
Tax effect amounts which are not deductible/(taxable) in calculating taxable income:
Entertainment expenses
Share-based payments
Prior year under/over adjustment
Change in unrecognised temporary differences
Amounts not brought to account as deferred tax assets
Income tax expense
Petroleum Resource Rent Tax
Petroleum Resource Rent Tax (PRRT) applies
to petroleum projects in Australian onshore
and offshore areas under the Petroleum
Resource Rent Tax Assessment Act 1987.
PRRT is assessed on a project basis or
production licence area and is levied on the
taxable profits of a petroleum project at a
rate of 40%. Eligible expenditure incurred in
relation to permits VIC/P57, VIC/P74, T49P
and WA-527-P, attach to the permit and
can be carried forward. Certain specified
un-deducted expenditure is eligible
for annual compounding at set rates.
The compound amount can be deducted
against assessable receipts in future years.
The Company has not recognised a
deferred tax asset with respect to the
carried forward un-deducted expenditure.
Deferred tax assets not recognised
Deferred tax assets not recognised comprises temporary differences attributable to:
Tax losses
Total deferred tax assets not recognised
The above potential tax benefit, which
includes tax losses, for deductible temporary
differences has not been recognised in
the statement of financial position as the
recovery of this benefit is uncertain.
The taxation benefits of tax losses and
temporary difference not brought to
account will only be obtained if:
(i) the Consolidated Entity derives future
assessable income of a nature and of
an amount sufficient to enable the
benefit from the deductions for the
losses to be realised;
(ii) the Consolidated Entity continues
to comply with the conditions for
deductibility imposed by law; and
(iii) no change in tax legislation adversely
affects the Company in realising the
benefits from deducting the losses.
Consolidated
2022
$
2021
$
(1,147,179)
(1,142,095)
(286,795)
(296,945)
349
2,972
(234,022)
(195,629)
949
2,359
60,223
7,145
713,125
(226,269)
-
-
Consolidated
2022
$
2021
$
15,960,358
15,247,233
15,960,358
15,247,233
43
NOTE 8. CURRENT ASSETS – CASH AND CASH EQUIVALENTS
Consolidated
2022
$
2021
$
1,243,195
3,048,802
Consolidated
2022
$
2021
$
18,024
23,659
129
11,839
472
7,621
29,992
31,752
Cash at bank
Accounting policy for cash and cash
equivalents
Cash and cash equivalents includes cash
on hand, deposits held at call with financial
institutions, other short-term, highly
liquid investments with original maturities
of three months or less that are readily
convertible to known amounts of cash and
which are subject to an insignificant risk of
changes in value.
NOTE 9. CURRENT ASSETS – OTHER RECEIVABLES
Other receivables
Interest receivable
GST receivable
Other receivables represent reimbursement
of venture costs by joint venture partners.
No interest is charged on the receivables.
The Consolidated Entity has financial risk
management policies in place to ensure
that all receivables are received within the
credit timeframe. Due to the short-term
nature of these receivables, their carrying
value is assumed to be approximate to their
fair value.
Accounting policy for other receivables
Other receivables are recognised at
amortised cost, less any allowance for
expected credit losses.
NOTE 10. CURRENT ASSETS – SHORT TERM INVESTMENTS
Cash on deposit
This amount relates to cash on deposit held with an original term to maturity
greater than 3 months. One of these cash deposits is pledged as a security
for the lease arrangement for office space.
Consolidated
2022
$
2021
$
93,577
93,577
44
NOTE 11. NON-CURRENT ASSETS – PROPERTY, PLANT
AND EQUIPMENT
Furniture and equipment – at cost
Less: Accumulated depreciation
Computer equipment – at cost
Less: Accumulated depreciation
Reconciliations
Reconciliations of the written down values
at the beginning and end of the current and
previous financial year are set out below:
Consolidated
Balance at 1 July 2020
Additions
Depreciation expense
Balance at 30 June 2021
Additions
Depreciation expense
Balance at 30 June 2022
Accounting policy for furniture, computer
and equipment
Furniture and computer equipment are
stated at historical cost less accumulated
depreciation and impairment. Historical
cost includes expenditure that is directly
attributable to the acquisition of the items.
Depreciation is calculated on a straight-
line basis to write off the net cost of each
item of property, plant and equipment
(excluding land) over their expected useful
lives as follows:
Computer and equipment
3-7 years
The residual values, useful lives and
depreciation methods are reviewed, and
adjusted if appropriate, at each reporting
date.
Consolidated
2022
$
2021
$
184,083
184,083
(184,083)
(184,083)
-
-
32,080
(14,538)
17,542
25,708
(9,183)
16,525
17,542
16,525
Computer
equipment
$
14,031
6,862
(4,368)
16,525
6,372
(5,355)
Total
$
14,031
6,862
(4,368)
16,525
6,372
(5,355)
17,542
17,542
45
NOTE 12. NON-CURRENT ASSETS – RIGHT-OF-USE ASSETS
The Consolidated Entity has a lease
arrangement for office space. In June 2022,
the lease was renewed for a three-year
period 1 June 2022 to 31 May 2025 with
no further option to extend. This note
provides information for leases where the
Consolidated Entity is a lessee.
Lease terms are negotiated on an individual
basis and may 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.
Consolidated
2022
$
2021
$
516,286
251,842
(259,177)
(172,686)
257,109
79,156
Office space –
right-of-use
$
165,496
(86,340)
79,156
264,444
(86,491)
Total
$
165,496
(86,340)
79,156
264,444
(86,491)
257,109
257,109
Office space – right-of-use
Less: Accumulated depreciation
Refer note 20 to these financial statements
for the current and non-current lease
liabilities. Depreciation expenses of right
of use assets and finance charges on lease
liabilities are presented in note 6 to the
financial statements.
The Consolidated Entity had no short-term
lease arrangements during the year ended
30 June 2022.
Reconciliations
Reconciliations of the written down values
at the beginning and end of the current and
previous financial year are set out below:
Consolidated
Balance at 1 July 2020
Depreciation expense
Balance at 30 June 2021
Additions
Depreciation expense
Balance at 30 June 2022
Accounting policy for right-of-use assets
A right-of-use asset is recognised at the
commencement date of a lease. The
right-of-use asset is measured at cost,
which comprises the initial amount of the
lease liability, adjusted for, as applicable,
any lease payments made at or before
the commencement date net of any lease
incentives received, any initial direct costs
incurred, and, except where included in the
cost of inventories, an estimate of costs
expected to be incurred for dismantling
and removing the underlying asset, and
restoring the site or asset.
46
Right-of-use assets are depreciated on a
straight-line basis over the unexpired period
of the lease or the estimated useful life of
the asset, whichever is the shorter. Where
the Consolidated Entity expects to obtain
ownership of the leased asset at the end of
the lease term, the depreciation is over its
estimated useful life. Right-of use assets are
subject to impairment or adjusted for any
remeasurement of lease liabilities.
The Consolidated Entity has elected not
to recognise a right-of-use asset and
corresponding lease liability for short-term
leases with terms of 12 months or less and
leases of low-value assets. Lease payments
on these assets are expensed to profit or
loss as incurred.
NOTE 13. NON-CURRENT ASSETS – INTANGIBLES
Software – at cost
Less: Accumulated amortisation
Reconciliations
Reconciliations of the written down values
at the beginning and end of the current and
previous financial year are set out below:
Consolidated
Balance at 1 July 2020
Additions
Amortisation expense
Balance at 30 June 2021
Amortisation expense
Balance at 30 June 2022
Accounting policy for intangible assets
Software
Significant costs associated with software
are deferred and amortised on a straight-
line basis over the period of their expected
benefit, being their finite life of 5 years.
Intangible assets acquired as part of
a business combination, other than
goodwill, are initially measured at their
fair value at the date of the acquisition.
Intangible assets acquired separately
are initially recognised at cost. Indefinite
life intangible assets are not amortised
and are subsequently measured at cost
less any impairment. Finite life intangible
assets are subsequently measured at cost
less amortisation and any impairment.
The gains or losses recognised in profit
or loss arising from the derecognition of
intangible assets are measured as the
difference between net disposal proceeds
and the carrying amount of the intangible
asset. The method and useful lives of
finite life intangible assets are reviewed
annually. Changes in the expected pattern
of consumption or useful life are accounted
for prospectively by changing the
amortisation method or period.
Consolidated
2022
$
2021
$
364,791
364,791
(317,579)
(288,150)
47,212
76,641
Software
$
74,068
30,001
Total
$
74,068
30,001
(27,428)
(27,428)
76,641
76,641
(29,429)
(29,429)
47,212
47,212
47
NOTE 14. NON-CURRENT ASSETS – EXPLORATION AND EVALUATION
Exploration and evaluation expenditure
Reconciliations
Reconciliations of the written down values
at the beginning and end of the current and
previous financial year are set out below:
Consolidated
2022
$
2021
$
6,207,257
5,374,599
Area of interest
T49P
Area of interest
VIC/P74
Area of interest
WA-527-P
Area of interest
VIC/P79
Consolidated
Balance at 1 July 2020
Additions
Balance at 30 June 2021
Additions
$
$
$
3,592,827
424,751
4,017,578
342,452
185,709
339,241
524,950
38,309
768,001
64,070
832,071
327,418
Total
$
4,546,537
828,062
5,374,599
$
-
-
-
124,479
832,658
Balance at 30 June 2022
4,360,030
563,259
1,159,489
124,479
6,207,257
The exploration and evaluation assets
relate to VIC/P74, an offshore project in
the Gippsland Basin in Victoria, T/49P
which is an offshore project in the Otway
Basin in Tasmania, WA-527-P in Western
Australia and VIC/P79, an offshore
exploration permit in the Otway Basin.
The recoverability of the exploration
and evaluation expenditure's carrying
amounts is dependent on the successful
development and commercial exploitation,
or alternatively the farm-out or sale, of the
respective areas of interest.
The Consolidated Entity has carried out an
impairment review of the carrying amount
of its exploration expenditure in relation
to VIC/P74, T/49P, WA-527-P and VIC/P79
following the end of the financial year as
at 30 June 2022. Based on the review no
impairments were identified in relation to
these tenements.
Farm-out in the exploration and e
valuation phase
Accounting policy for exploration and
evaluation assets
The Consolidated Entity does not record
any expenditure made by the farminee
on its account. It also does not recognise
any gain or loss on its exploration and
evaluation farm-out arrangements
but redesignates any costs previously
capitalised in relation to the whole interest
as relating to the partial interest retained.
Any cash consideration received directly
from the farminee is credited against
costs previously capitalised in relation
to the whole interest with any excess
accounted for by the farmor as a gain on
disposal. Please refer to note 29 for further
information on the Consolidated Entity’s
farm-out arrangements.
Exploration and evaluation expenditure
in relation to separate areas of interest
for which rights of tenure are current is
carried forward as an asset in the statement
of financial position where it is expected
that the expenditure will be recovered
through the successful development and
exploitation of an area of interest, or by its
sale; or exploration activities are continuing
in an area and activities have not reached
a stage which permits a reasonable
estimate of the existence or otherwise of
economically recoverable reserves. Where
a project or an area of interest has been
abandoned, the expenditure incurred
thereon is written off in the year in which
the decision is made.
Exploration and evaluation costs expensed
The Consolidated Entity expensed
exploration costs of $15,994 (2021:
$33,088) related to VIC/P57 Exploration
Permit (which was surrendered subsequent
to the financial year) in the statement of
profit or loss and other comprehensive
income in the year ended 30 June 2022.
48
NOTE 15. CURRENT LIABILITIES – TRADE AND OTHER PAYABLES
Trade payables
Research and development tax grant
Sundry payables and accrued expenses
The Research and development tax grant
relates to an R&D tax incentive refund
received during the financial year ended
30 June 2012. The Company had received a
notification that AusIndustry had reversed
this claim, and hence this amount is carried
as a liability.
Refer to note 21 for further information on
financial instruments.
Accounting policy for trade and
other payables
These amounts represent liabilities for
goods and services provided to the
Consolidated Entity prior to the end of the
financial year and which are unpaid. Due to
their short-term nature they are measured
at amortised cost and are not discounted.
The amounts are unsecured and are usually
paid within 30 days of recognition.
NOTE 16. CURRENT LIABILITIES – EMPLOYEE BENEFITS
Annual leave
Long service leave
Employee benefits
Amounts not expected to be settled within
the next 12 months
The current provision for long service leave
includes all unconditional entitlements
where employees have completed the
required period of service and also those
where employees are entitled to pro-rata
payments in certain circumstances. The
entire amount is presented as current,
since the company does not have an
unconditional right to defer settlement.
Accounting policy for employee benefits
Short-term employee benefits
Liabilities for wages and salaries, including
non-monetary benefits, annual leave,
long service leave and accumulating
sick leave expected to be settled wholly
within 12 months of the reporting date
are measured at the amounts expected
to be paid when the liabilities are settled.
Non-accumulating sick leave is expensed
to profit or loss when incurred.
Consolidated
2021
$
54,467
695,894
69,984
2022
$
119,505
695,894
109,856
925,255
820,345
Consolidated
2022
$
2021
$
69,769
58,076
134,591
136,956
24,084
36,880
228,444
231,912
49
NOTE 17. NON-CURRENT LIABILITIES – EMPLOYEE BENEFITS
Long service leave
Consolidated
2022
$
2021
$
1,916
4,585
Accounting policy for long-term employee
benefits
The liability for long service leave not
expected to be settled within 12 months
of the reporting date are measured as the
present value of expected future payments
to be made in respect of services provided
by employees up to the reporting date
using the projected unit credit method.
Consideration is given to expected future
wage and salary levels, experience of
employee departures and periods of
service. Expected future payments are
discounted using market yields at the
reporting date on high quality corporate
bond rates with terms to maturity and
currency that match, as closely as possible,
the estimated future cash outflows.
NOTE 18. EQUITY – ISSUED CAPITAL
2022
Shares
2021
Shares
Consolidated
2022
$
2021
$
Ordinary shares – fully paid
265,188,372
265,188,372
55,483,678
55,483,678
Ordinary shares
Capital risk management
Ordinary shares entitle the holder to
participate in dividends and the proceeds
on the winding up of the Company in
proportion to the number of and amounts
paid on the shares held. The fully paid
ordinary shares have no par value and the
Company does not have a limited amount
of authorised capital.
On a show of hands every member present
at a meeting in person or by proxy shall
have one vote and upon a poll each share
shall have one vote.
The company's objectives when managing
capital are to safeguard its ability to
continue as a going concern, so that it
can provide returns for shareholders and
benefits for other stakeholders and to
maintain an optimum capital structure to
reduce the cost of capital.
Capital is regarded as total equity, as
recognised in the statement of financial
position, plus net debt. Net debt is
calculated as total borrowings less cash and
cash equivalents.
In order to maintain or adjust the capital
structure, the Company may adjust the
amount of dividends paid to shareholders,
return capital to shareholders, issue new
shares or sell assets to reduce debt.
The Consolidated Entity would look to
raise capital when an opportunity to invest
in a business or Company was seen as
value adding relative to the current parent
entity's share price at the time of the
investment. The Company is not actively
pursuing additional investments in the
short term as it continues to integrate and
grow its existing businesses in order to
maximise synergies.
The capital risk management policy
remains unchanged from the 30 June 2021
Annual Report.
Accounting policy for issued capital
Ordinary shares are classified as equity.
Incremental costs directly attributable
to the issue of new shares or options are
shown in equity as a deduction, net of tax,
from the proceeds.
NOTE 19. EQUITY – DIVIDENDS
There were no dividends paid or declared
during the current or previous financial year.
The Consolidated Entity does not have
franking credits available for subsequent
financial years.
Accounting policy for dividends
Dividends are recognised when declared
during the financial year and no longer at
the discretion of the Company.
50
NOTE 20. LEASE LIABILITIES
Lease liabilities
Current lease liabilities
Non-current lease liabilities
Total lease liabilities
Right of use lease assets note 12
Lease liability maturity analysis – contractual
undiscounted cash flows
Less than one year
Two to five years
Total undiscounted lease liabilities
Lease liability finance costs
During the year ended 30 June 2022,
the Consolidated Entity incurred interest
charges of $4,839, as disclosed in note 6.
Lease liability outflows
Lease liability related cash outflows are
disclosed in the statement of cashflows.
Accounting policy for lease liabilities
A lease liability is recognised at the
commencement date of a lease. The lease
liability is initially recognised at the present
value of the lease payments to be made
over the term of the lease, discounted using
the interest rate implicit in the lease or, if
that rate cannot be readily determined,
the Consolidated Entity's incremental
borrowing rate. Lease payments comprise
of fixed payments less any lease incentives
receivable, variable lease payments that
depend on an index or a rate, amounts
expected to be paid under residual value
guarantees, exercise price of a purchase
option when the exercise of the option
is reasonably certain to occur, and any
anticipated termination penalties. The
variable lease payments that do not
depend on an index or a rate are expensed
in the period in which they are incurred.
Consolidated
2022
$
2021
$
75,488
190,555
96,614
-
266,043
96,614
Consolidated
2022
$
2021
$
257,109
79,156
Consolidated
2022
92,045
203,591
2021
96,614
-
295,636
96,614
Lease liabilities are measured at amortised
cost using the effective interest method.
The carrying amounts are remeasured if
there is a change in the following: future
lease payments arising from a change in
an index or a rate used; residual guarantee;
lease term; certainty of a purchase option
and termination penalties. When a lease
liability is remeasured, an adjustment is
made to the corresponding right-of use
asset, or to profit or loss if the carrying
amount of the right-of-use asset is fully
written down.
NOTE 21. FINANCIAL
INSTRUMENTS
FINANCIAL RISK MANAGEMENT
OBJECTIVES
The Consolidated Entity's activities expose
it to a variety of financial risks: market
risk (including foreign currency risk, price
risk and interest rate risk), credit risk and
liquidity risk. The Consolidated Entity's
overall risk management program focuses
on the unpredictability of financial markets
and seeks to minimise potential adverse
effects on the financial performance of
the Consolidated Entity. The Consolidated
Entity uses different methods to measure
different types of risk to which it is
exposed. These methods include sensitivity
analysis in the case of interest rate, foreign
exchange and other price risks, ageing
analysis for credit risk and beta analysis
in respect of investment portfolios to
determine market risk.
Risk management is carried out by senior
finance executives ('Finance') under policies
approved by the Board of Directors ('the
Board'). These policies include identification
and analysis of the risk exposure of the
Consolidated Entity and appropriate
procedures, controls and risk limits. Finance
identifies, evaluates and hedges financial
risks within the Consolidated Entity's
operating units. Finance reports to the
Board on a monthly basis.
MARKET RISK
Foreign currency risk
The Consolidated Entity undertakes
certain transactions denominated in
foreign currency and is exposed to foreign
currency risk through foreign exchange
rate fluctuations. The Consolidated Entity
operates a US dollar bank account for the
purpose of transacting in US dollars. The
transactions and balances denominated
in US dollars are not material to these
financial statements.
51
The Consolidated Entity operated a
US dollar bank account. There were no
other assets or liabilities denominated in
foreign currencies at the year end. The US
balance on the account was US$23 and the
exchange rate used to translate the balance
at 30 June 2022 was $0.6878 (30 June
2021: $0.6878).
Foreign exchange risk arises from future
commercial transactions and recognised
financial assets and financial liabilities
denominated in a currency that is not the
entity's functional currency. The risk is
measured using sensitivity analysis and
cash flow forecasting.
Price risk
The Consolidated Entity is not exposed to
any significant price risk.
CREDIT RISK
Credit risk refers to the risk that a
counterparty will default on its contractual
obligations resulting in financial
loss to the Consolidated Entity. The
Consolidated Entity has a strict code of
credit, including obtaining agency credit
information, confirming references and
setting appropriate credit limits. The
Consolidated Entity obtains guarantees
where appropriate to mitigate credit risk.
The maximum exposure to credit risk at
the reporting date to recognised financial
assets is the carrying amount, net of
any provisions for impairment of those
assets, as disclosed in the statement of
financial position and notes to the financial
statements. The Consolidated Entity does
not hold any collateral.
Interest rate risk
LIQUIDITY RISK
The Consolidated Entity's only exposure to
interest rate risk is in relation to deposits
held. Deposits are held with reputable
banking financial institutions.
The tables below illustrate the impact on
profit before tax based upon expected
volatility of interest rates using market data
and analysis forecasts.
Vigilant liquidity risk management requires
the Consolidated Entity to maintain
sufficient liquid assets (mainly cash and
cash equivalents) and available borrowing
facilities to be able to pay debts as and
when they become due and payable.
The Consolidated Entity manages liquidity
risk by maintaining adequate cash
reserves and available borrowing facilities
by continuously monitoring actual and
forecast cash flows and matching the
maturity profiles of financial assets and
liabilities.
Remaining contractual maturities
The following tables detail the Consolidated
Entity's remaining contractual maturity
for its financial instrument liabilities. The
tables have been drawn up based on
the undiscounted cash flows of financial
liabilities based on the earliest date on
which the financial liabilities are required
to be paid. The tables include both interest
and principal cash flows disclosed as
remaining contractual maturities and
therefore these totals may differ from
their carrying amount in the statement of
financial position.
Consolidated – 2022
Non-derivatives
Non-interest bearing
Trade and other payables
Interest-bearing – fixed rate
Lease liability
Total non-derivatives
Consolidated – 2021
Non-derivatives
Non-interest bearing
Trade and other payables
Interest-bearing – fixed rate
Lease liability
Total non-derivatives
Weighted
average
interest rate
%
-
1 year or less
$
925,255
7.50%
92,045
%
-
7.50%
1,017,300
$
820,345
96,614
916,959
Between
1 and 2 years
Between
2 and 5 years
Over 5 years
$
-
$
-
104,397
104,397
99,194
99,194
$
-
-
-
$
-
-
-
$
-
-
-
$
-
-
-
Remaining
contractual
maturities
$
925,255
295,636
1,220,891
$
820,345
96,614
916,959
The cash flows in the maturity analysis
above are not expected to occur
significantly earlier than contractually
disclosed above.
Fair value of financial instruments
Unless otherwise stated, the carrying
amounts of financial instruments reflect
their fair value. The carrying amounts of
trade receivables and trade payables are
assumed to approximate their fair values
due to their short-term nature. Where
appropriate, the fair value of financial
liabilities is estimated by discounting the
remaining contractual maturities at the
current market interest rate that is available
for similar financial instruments.
52
NOTE 22. KEY MANAGEMENT PERSONNEL DISCLOSURES
Directors
The following persons were Directors of
3D Oil Limited during the financial year:
Mr Noel Newell
Mr Ian Tchacos
Mr Leo De Maria
Mr Trevor Slater
Executive Chairman
Non-Executive Director
Non-Executive Director
Non-Executive Director (appointed on 15 November 2021)
Compensation
The aggregate compensation made
to Directors and other members of
key management personnel of the
Consolidated Entity is set out below:
Short-term employee benefits
Post-employment benefits
Long-term benefits
Share-based payments
NOTE 23. REMUNERATION OF AUDITORS
During the financial year the following fees
were paid or payable for services provided
by Grant Thornton Audit Pty Ltd, the
auditor of the Company:
Audit services – Grant Thornton Audit Pty Ltd
Audit or review of the financial statements
NOTE 24. CONTINGENT LIABILITIES
The Consolidated Entity provided a security
deposit of $48,827 (2021: $48,827). The
Consolidated Entity will forgo this deposit
if conditions of return are not met. With
the exception to the above matter, the
Consolidated Entity does not have any
other contingent liabilities at reporting date.
Consolidated
2022
$
2021
$
455,967
485,041
34,044
29,697
8,893
5,180
6,752
3,194
504,084
524,684
Consolidated
2022
$
2021
$
58,500
55,000
53
NOTE 25. COMMITMENTS
Exploration Licenses – Commitments for Expenditure
Committed at the reporting date but not recognised as liabilities, payable:
Within one year
Two to five years
WA-527-P, the current indicative
expenditure commitment for Years 5-6
is currently gross $30.8 million and this
would be occurring in 2022-2025 years.
T49P
The Consolidated Entity holds 20%
interest in the T/49P Exploration Permit
and ConocoPhillips Australia SH1 Pty Ltd
holds 80% interest in the Permit and is
Operator on behalf of the Joint Operation.
The commitments above do not include
commitments for indicative expenditure
relating to Exploration Permit T49P, as they
are expected to be covered by the farm-in
partner, ConocoPhillips Australia Pty Ltd, as
per Joint Operating Agreement. Under the
terms of Joint Operating Agreement, the
Company will contribute 10% of the Joint
Operation expenses until ConocoPhillips
Australia has completed an exploration
well or spent at least US$30 million toward
drilling of an exploration well.
On 16 March 2021, NOPTA issued a variation
notice to the Exploration Permit T/49P, as a
result of which seismic acquisition and drill
planning works in Year 5 and the drilling
of an exploration well in Year 6 have been
deferred to the year ended 21 August 2023
and 21 August 2024, respectively.
VIC/P79
The Company holds 100% interest in the
VIC/P79 Exploration Permit which was
granted in 2020. On 30 June 2022, the
Company executed a Farmout Agreement
with ConocoPhillips Australia SH2 Pty
Ltd in relation to the VIC/P79 Exploration
Permit. Under the terms of the agreement,
ConocoPhillips Australia will acquire an
80% interest in the Exploration Permit
and will become the Operator on behalf
of the Joint Operation. At the date of this
report, agreement is subject to conditions
precedent, including the agreement and
signing of a Joint Operating Agreement
by both parties and required government/
regulatory approvals.
In order to maintain current rights of tenure
to exploration tenements, the Consolidated
Entity is required to outlay rentals and to
meet the minimum work requirements and
associated indicative expenditure of the
NOPTA. Minimum commitments may be
subject to renegotiation and with approval
may otherwise be avoided by sale, farm out
or relinquishment. These obligations are
therefore not provided for in the financial
statements as payable.
VIC/P74
On 8 October 2020, NOPTA approved
Hibiscus Petroleum Berhad to enter into
an agreement for a Joint Operations with
the Company for the offshore Gippsland
Basin Exploration Permit VIC/P74.
The Company remained as the operator
with 50% equity. In July 2022, Hibiscus
Petroleum have decided to transfer their
50% participating interest back to the
Company and applied for a Transfer of
Title which is currently under review with
NOPTA. Accordingly, the Company has
included in the above commitments its
share of indicative expenditure relating
to VIC/P74 for year 4 at 100% (2021:
50%). Commitments from year 4 onwards
are confirmed on a year-by-year basis
dependent on the Company agreeing
to proceed. If the Company was to
proceed beyond year 5 in relation to
VIC/P74, the current indicative
expenditure commitment for Years 5-6
is currently gross $40.6 million, and this
would be occurring in 2023-2025 years.
WA-527-P
The Company holds 100% interest in the
WA-527-P Exploration Permit, which
covers 6,500km2 of the offshore Bedout
Sub-basin. The Company has included its
commitments for indicative expenditure
in the year 3. Commitments from year 4
onwards are confirmed on a year-by-year
basis dependent on the Company agreeing
to proceed. If the Company was to
proceed beyond year 4 in relation to
54
Consolidated
2022
$
2021
$
4,660,000
3,060,000
80,000
-
4,740,000
3,060,000
Year one (1) to three (3) commitments for
VIC/P79 Exploration Permit is $900,000
in total for seismic data acquisition and
geological and geophysical studies. The
above commitment note include 20% of
year one (1) to three (3) commitment,
which the Company expects to contribute
in line with its interest in the Exploration
Permit.
The commitments above do not include
Drill Exploration Well commitment, as
they are expected to be covered by
the farm-in partner, ConocoPhillips
Australia Pty Ltd, upon signing of a Joint
Operating Agreement. It is expected that
the ConocoPhillips Australia will also
undertake to drill an exploration well as
required by the Permit’s Primary Term
minimum work commitment (currently
required by February 2025). The Company
will be carried for up to USD$35 million
(~AUD$50.751 million) in well costs, above
which it will contribute 20% of costs in line
with its interest in the Exploration Permit.
Commitments from year 4 onwards
are confirmed on a year-by-year basis
dependent on the Company agreeing to
proceed. If the Company was to proceed
beyond year 4 in relation to VIC/P79, the
current indicative expenditure commitment
for Years 4-6 is currently gross $12.8 million
and this would be occurring in 2025-2028
years.
VIC/P57
The Company held 24.9% interest in the
VIC/P57 Exploration Permit with remaining
equity held by Joint Operation partner and
operator, Hibiscus Petroleum. During the
year, the Joint Operation has submitted
a ‘Consent to Surrender Title’ application
ahead of the Year 4 work program, which
was accepted by NOPTA subsequent to
the end of financial year. Therefore, the
commitments note above do not include
commitments for indicative expenditure
relating to Exploration Permit VIC/P57.
NOTE 26. RELATED PARTY TRANSACTIONS
Parent entity
Key management personnel
3D Oil Limited is the parent entity.
Subsidiaries
Interests in subsidiaries are set out in note 28.
Disclosures relating to key management
personnel are set out in note 22 and
the remuneration report included in the
Directors' report.
Receivable from and payable to
related parties
There were no trade receivables from or
trade payables to related parties at the
current and previous reporting date.
Joint operations
Transactions with related parties
Loans to/from related parties
Interests in joint operations are set out in
note 29.
There were no transactions with related
parties during the current and previous
financial year.
There were no loans to or from related
parties at the current and previous
reporting date.
NOTE 27. PARENT ENTITY INFORMATION
Set out below is the supplementary
information about the parent entity.
Statement of profit or loss and other
comprehensive income
Loss after income tax
Total comprehensive income
Statement of financial position
Total current assets
Total assets
Total current liabilities
Total liabilities
Equity
Issued capital
Share-based payments reserve
Accumulated losses
Total equity
2022
$
Parent
2021
$
(1,147,188)
(1,142,047)
(1,147,188)
(1,142,047)
2022
$
Parent
2021
$
1,274,029
3,123,331
5,144,732
5,976,850
1,229,187
1,113,888
1,421,658
1,118,473
55,483,678
55,483,678
17,559
9,072
(51,778,163)
(50,634,373)
3,723,074
4,858,377
Guarantees entered into by the parent entity
in relation to the debts of its subsidiaries
The parent entity had no guarantees in
relation to the debts of its subsidiaries as at
30 June 2022 and 30 June 2021.
Contingent liabilities
The parent entity had no contingent
liabilities as at 30 June 2022 and
30 June 2021.
Capital commitments – Property, plant and
equipment
The parent entity had no capital
commitments for property, plant and
equipment as at 30 June 2022 and
30 June 2021.
55
Significant accounting policies
The accounting policies of the parent
entity are consistent with those of the
Consolidated Entity, as disclosed in note 2,
except for the following:
— Investments in subsidiaries are
accounted for at cost, less any
impairment, in the parent entity.
— Investments in associates are accounted
for at cost, less any impairment, in the
parent entity.
— Dividends received from subsidiaries
are recognised as other income by the
parent entity and its receipt may be
an indicator of an impairment of the
investment.
— Significant estimates and judgement –
recoverability of loan to subsidiary. No
objective indicators of impairment as
the current best estimates of potential
resources indicate a quantity of oil/gas
that would allow recovery of the amount
due in full.
Ownership interest
2022
%
2021
%
100.00%
100.00%
Ownership interest
2022
%
20.00%
50.00%
24.90%
100.00%
2021
%
20.00%
50.00%
24.90%
-
NOTE 28. INTERESTS IN SUBSIDIARIES
The consolidated financial statements
incorporate the assets, liabilities and
results of the following subsidiary in
accordance with the accounting policy
described in note 2:
Name
3D Oil T49P Pty Ltd
Principal place of business / Country of incorporation
Australia
NOTE 29. INTERESTS IN JOINT OPERATIONS
The Consolidated Entity has recognised
its share of jointly held assets, liabilities,
revenues and expenses of joint operations.
These have been incorporated in the
financial statements under the appropriate
classifications. Information relating to
joint operations that are material to the
Consolidated Entity are set out below:
Name
Principal place of business / Country of incorporation
T/49P, Otway Basin, offshore Tasmania
VIC/P74, Gippsland Basin, offshore Victoria
Australia
Australia
VIC/P57, Gippsland Basin, offshore Victoria*
Australia
VIC/P79, Otway Basin, offshore Victoria**
Australia
* The Company held 24.9% interest
in the VIC/P57 Exploration Permit
with remaining equity held by joint
venture partner and operator, Hibiscus
Petroleum. During the financial year,
the Joint Venture has submitted a
‘Consent to Surrender Title’ application
ahead of the Year 4 work program with
NOPTA, which was accepted by NOPTA
subsequent to the end of financial year.
** On 4 February 2022, the Consolidated
Entity announced that the NOPTA
had awarded the Consolidated Entity
the VIC/P79 exploration permit in the
offshore Otway Basin. On 30 June 2022,
the Consolidated Entity announced
that ConocoPhillips Australia SH2 Pty
Ltd and the Company have executed
a Farmout Agreement in relation to
the offshore Victorian Exploration
Permit VIC/P79 (“Permit”), located in
the Otway Basin. Under the terms of
the FOA, ConocoPhillips Australia will
acquire an 80% interest in the Permit and
operatorship.
56
NOTE 30. EVENTS AFTER THE REPORTING PERIOD
On 2 September 2022, the Consolidated
Entity announced that the South Australia
Department of Energy and Mining has
awarded the Company the GSEL 759 Gas
Storage Exploration Licence in onshore
Otway Basin. The licence covers an area
of 1.02km2, centrally located around
the plugged and abandoned Caroline-1
wellhead, over part of the now depleted
Caroline Field, originally used for the
production of carbon dioxide in the Otway
Basin. The Field is potentially suitable for
the storage of hydrogen, natural gas, or
carbon dioxide. The acquisition of GSEL
759 represents an exciting development
opportunity for the Company in broadening
3D Oil’s strategy in the rapidly changing
East Coast energy market.
No other matter or circumstance has arisen
since 30 June 2022 that has significantly
affected, or may significantly affect
the Consolidated Entity's operations,
the results of those operations, or the
Consolidated Entity's state of affairs in
future financial years.
NOTE 31. RECONCILIATION OF LOSS AFTER INCOME TAX TO NET
CASH USED IN OPERATING ACTIVITIES
Loss after income tax expense for the year
Adjustments for:
Depreciation, amortisation net of other non-cash lease adjustments
Share-based payments
Change in operating assets and liabilities:
Decrease/(increase) in other receivables
Decrease/(increase) in prepayments
Decrease in trade and other payables
Increase in employee benefits
Net cash used in operating activities
Consolidated
2022
$
2021
$
(1,147,179)
(1,142,095)
112,920
118,136
11,886
9,072
(3,875)
41,924
123
(2,477)
(19,808)
(113,832)
6,658
82,398
(997,474)
(1,048,675)
57
NOTE 32. LOSS PER SHARE
Loss after income tax attributable to the owners of 3D Oil Limited
(1,147,179)
(1,142,095)
Weighted average number of ordinary shares used in calculating basic loss per share
Number
Number
265,188,372
265,188,372
Weighted average number of ordinary shares used in calculating diluted loss per share
265,188,372
265,188,372
Consolidated
2022
$
2021
$
Cents
(0.43)
(0.43)
Cents
(0.43)
(0.43)
Basic earnings per share
Diluted earnings per share
Accounting policy for earnings loss per share
Diluted loss per share
Basic loss per share
Basic loss per share is calculated by
dividing the loss attributable to the owners
of 3D Oil Limited, excluding any costs
of servicing equity other than ordinary
shares, by the weighted average number
of ordinary shares outstanding during the
financial year, adjusted for bonus elements
in ordinary shares issued during the
financial year.
Diluted loss per share adjusts the figures
used in the determination of basic loss per
share to take into account the after income
tax effect of interest and other financing
costs associated with dilutive potential
ordinary shares and the weighted average
number of shares assumed to have been
issued for no consideration in relation to
dilutive potential ordinary shares.
NOTE 33. SHARE-BASED PAYMENTS
On 17 November 2020, the Company
issued 225,806 performance rights
to Directors and on 15 February 2021,
516,128 performance rights to employees.
The performance rights issued to the
Company's Directors have an exercise
price of nil, a share price hurdle of $0.09 (9
cents), vesting date of 17 November 2022
and expire on 17 November 2023.
The performance rights issued to the
Company's employees in February 2021
have an exercise price of nil, a share price
hurdle of $0.09 (9 cents), a vesting date
of 17 November 2022 and expire 3 years
following the grant date.
58
2022
Grant date
Expiry date
Exercise price
17/11/2020
17/11/2023
28/01/2021
28/01/2024
29/01/2021
29/01/2024
01/02/2021
01/02/2024
11/02/2021
11/02/2024
$0.000
$0.000
$0.000
$0.000
$0.000
For the performance rights issued during
the current financial year, the valuation
model inputs used to determine the fair
value at the grant date, are as follows:
Balance at
the start
of the year
225,806
80,645
80,645
112,903
241,935
741,934
Granted
Exercised
-
-
-
-
-
-
-
-
-
-
-
-
Expired/
forfeited/
other
-
-
-
(56,452)
(241,935)
(298,387)
Balance at
the end
of the year
225,806
80,645
80,645
56,451
-
443,547
Grant date
Expiry date
17/11/2020
17/11/2023
28/01/2021
28/01/2024
29/01/2021
29/01/2024
01/02/2021
01/02/2024
11/02/2021
11/02/2024
Share price
at grant date
Exercise price
Expected
volatility Dividend yield
Risk-free
interest rate
Fair value at
grant date
$0.056
$0.057
$0.055
$0.055
$0.054
$0.000
$0.000
$0.000
$0.000
$0.000
80.000%
80.000%
80.000%
80.000%
80.000%
-
-
-
-
-
0.110%
0.105%
0.105%
0.105%
0.105%
$0.045
$0.054
$0.054
$0.054
$0.054
If the non-vesting condition is within
the control of the Consolidated Entity
or employee, the failure to satisfy the
condition is treated as a cancellation. If
the condition is not within the control of
the Consolidated Entity or employee and
is not satisfied during the vesting period,
any remaining expense for the award is
recognised over the remaining vesting
period, unless the award is forfeited.
If equity-settled awards are cancelled,
it is treated as if it has vested on the
date of cancellation, and any remaining
expense is recognised immediately. If a
new replacement award is substituted for
the cancelled award, the cancelled and
new award is treated as if they were a
modification.
The weighted average remaining
contractual life of performance rights at
30 June 2021 is 1.62 years.
Accounting policy for share-based payments
Equity-settled and cash-settled share-
based compensation benefits are provided
to employees.
Equity-settled transactions are awards
of shares, or options over shares, that are
provided to employees in exchange for
the rendering of services. Cash-settled
transactions are awards of cash for the
exchange of services, where the amount
of cash is determined by reference to the
share price.
The cost of equity-settled transactions are
measured at fair value on grant date. Fair
value is independently determined using
the Hoadley Trading & Investment Tools
(“Hoadley”) ESO5 option valuation model.
The option pricing model that takes into
account the exercise price, the share hurdle
price, the impact of dilution, the share price
at grant date and expected price volatility
of the underlying share, the expected
dividend yield and the risk free interest
rate for the term of the option, together
with non-vesting conditions that do not
determine whether the Consolidated
Entity receives the services that entitle the
employees to receive payment.
The cost of equity-settled transactions
are recognised as an expense with a
corresponding increase in equity over the
vesting period. The cumulative charge to
profit or loss is calculated based on the
grant date fair value of the award, the
best estimate of the number of awards
that are likely to vest and the expired
portion of the vesting period. The amount
recognised in profit or loss for the period
is the cumulative amount calculated at
each reporting date less amounts already
recognised in previous periods.
Market conditions are taken into
consideration in determining fair value.
Therefore, any awards subject to market
conditions are considered to vest
irrespective of whether or not that market
condition has been met, provided all other
conditions are satisfied.
If equity-settled awards are modified, as
a minimum an expense is recognised as
if the modification has not been made.
An additional expense is recognised, over
the remaining vesting period, for any
modification that increases the total fair
value of the share-based compensation
benefit as at the date of modification.
59
DIRECTORS'
DECLARATION
30 June 2022
In the Directors' opinion:
— the attached financial statements and
notes comply with the Corporations
Act 2001, the Accounting Standards,
the Corporations Regulations 2001 and
other mandatory professional reporting
requirements;
— the attached financial statements and
notes comply with International Financial
Reporting Standards as issued by the
International Accounting Standards
Board as described in note 2 to the
financial statements;
— the attached financial statements
and notes give a true and fair view
of the Consolidated Entity's financial
position as at 30 June 2022 and of its
performance for the financial year ended
on that date; and
— there are reasonable grounds to believe
that the Company will be able to pay its
debts as and when they become due and
payable.
The Directors have been given the
declarations required by section 295A of
the Corporations Act 2001.
Signed in accordance with a resolution of
Directors made pursuant to section 295(5)
(a) of the Corporations Act 2001.
On behalf of the Directors
Noel Newell
Executive Chairman
30 September 2022
Melbourne
60
Grant Thornton Audit Pty Ltd
Level 22 Tower 5
Collins Square
727 Collins Street
Melbourne VIC 3008
GPO Box 4736
Melbourne VIC 3001
T +61 3 8320 2222
Independent Auditor’s Report
To the Members of 3D Oil Limited
Report on the audit of the financial report
Opinion
We have audited the financial report of 3D Oil Limited (the Company) and its subsidiaries (the Group), which
comprises the consolidated statement of financial position as at 30 June 2022, the consolidated statement of
profit or loss and other comprehensive income, consolidated statement of changes in equity and
consolidated statement of cash flows for the year then ended, and notes to the consolidated financial
statements, including a summary of significant accounting policies, and the Directors’ declaration.
In our opinion, the accompanying financial report of the Group is in accordance with the Corporations Act
2001, including:
a giving a true and fair view of the Group’s financial position as at 30 June 2022 and of its performance
for the year ended on that date; and
b complying with Australian Accounting Standards and the Corporations Regulations 2001.
Basis for opinion
We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under those
standards are further described in the Auditor’s Responsibilities for the Audit of the Financial Report section
of our report. We are independent of the Group in accordance with the auditor independence requirements
of the Corporations Act 2001 and the ethical requirements of the Accounting Professional and Ethical
Standards Board’s APES 110 Code of Ethics for Professional Accountants (including Independence
Standards) (the Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled
our other ethical responsibilities in accordance with the Code.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our
opinion.
Material uncertainty related to going concern
We draw attention to Note 2 in the financial statements, which indicates that the Group incurred a net loss of
$1,147,179 during the year ended 30 June 2022, and as of that date, the Group’s current assets exceeded its
current liabilities by $137,577. As stated in Note 2, these events or conditions, along with other matters as set
forth in Note 2 , indicate that a material uncertainty exists that may cast doubt on the Group’s ability to continue
as a going concern. Our opinion is not modified in respect of this matter.
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Key audit matters
Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of
the financial report of the current period. These matters were addressed in the context of our audit of the financial
report as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these
matters.
In addition to the matter described in the Material uncertainty related to going concern section, we have
determined the matters described below to be the key audit matters to be communicated in our report.
Key audit matter
How our audit addressed the key audit matter
Exploration and Evaluation Assets – valuation (Note 14)
As all of the tenements held by the Group are in the
exploration stage, exploration expenditure is
capitalised in accordance with Australian Accounting
Standard AASB 6 Exploration for and Evaluation of
Mineral Resources.
The Group is required to assess at each reporting date
if there are any triggers for impairment which may
suggest the carrying value is in excess of the
recoverable value. Any impairment losses are then
measured in accordance with AASB 136 Impairment of
Assets.
Our procedures included, amongst others:
• obtaining management’s reconciliation of capitalised
exploration and evaluation expenditure and agreeing
to the general ledger;
• selecting a sample of capitalised exploration and
evaluation expenditure and obtain documentation to
support the amount capitalised in line with AASB 6;
• evaluating management's assessment of impairment
indicators for the capitalised exploration assets
under AASB 6 by:
AASB 6 requires exploration and evaluation asset to
be assessed for impairment when facts and
circumstances suggest that the carrying amount of an
exploration and evaluation asset may exceed its
recoverable amount. AASB 6 provides a list of four
indicators, however that list is not exhaustive and
therefore subjectivity is involved in the assessment.
This area is a key audit matter as significant judgement
is required in determining whether the facts and
circumstances suggest that the carrying amount of an
exploration and evaluation asset may exceed its
recoverable amount, and then consequently in
measuring any impairment loss.
− assessing the right to explore the areas of
interest has not expired or will not expire in the
near future without an expectation of renewal;
− making enquires management regarding their
intentions to carry out exploration and evaluation
activity in the relevant exploration area, including
review of managements’ budgeted expenditure;
− obtaining an understanding as to whether any
data exists that indicates the carrying value of
these exploration and evaluation assets are
unlikely to be recovered from successful
development or by sale;
− considering any other available evidence of
impairment;
• assessing management's consequent determination
of impairment loss (if any); and
• evaluating related financial statement disclosures.
Information other than the financial report and auditor’s report thereon
The Directors are responsible for the other information. The other information comprises the information included
in the Group’s annual report for the year ended 30 June 2022, but does not include the financial report and our
auditor’s report thereon.
Our opinion on the financial report 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 report, our responsibility is to read the other information and, in doing
so, consider whether the other information is materially inconsistent with the financial report 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.
Grant Thornton Australia Limited
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Responsibilities of the Directors for the financial report
The Directors of the Company are responsible for the preparation of the financial report that gives a true and fair
view in accordance with Australian Accounting Standards and the Corporations Act 2001 and for such internal
control as the Directors determine is necessary to enable the preparation of the financial report that gives a true
and fair view and is free from material misstatement, whether due to fraud or error.
In preparing the financial report, the Directors are responsible for assessing the Group’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 or to cease operations, or have no realistic
alternative but to do so.
Auditor’s responsibilities for the audit of the financial report
Our objectives are to obtain reasonable assurance about whether the financial report as a whole is 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 the Australian Auditing Standards 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 this financial report.
A further description of our responsibilities for the audit of the financial report is located at the Auditing and
Assurance Standards Board website at: https://www.auasb.gov.au/auditors_responsibilites/ar1_2020.pdf. This
description forms part of our auditor’s report.
Report on the remuneration report
Opinion on the remuneration report
We have audited the Remuneration Report included in pages 27 to 31 of the Directors’ report for the year
ended 30 June 2022.
In our opinion, the Remuneration Report of 3D Oil Limited, for the year ended 30 June 2022 complies with
section 300A of the Corporations Act 2001.
Responsibilities
The Directors of the Company are responsible for the preparation and presentation of the Remuneration Report
in accordance with section 300A of the Corporations Act 2001. Our responsibility is to express an opinion on the
Remuneration Report, based on our audit conducted in accordance with Australian Auditing Standards.
Grant Thornton Audit Pty Ltd
Chartered Accountants
D G Ng
Partner – Audit & Assurance
Melbourne, 30 September 2022
Grant Thornton Australia Limited
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63
SHAREHOLDER INFORMATION
30 June 2022
The shareholder information set out below
was applicable as at 12 September 2022.
DISTRIBUTION OF EQUITABLE
SECURITIES
Analysis of number of equitable security
holders by size of holding:
Ordinary shares
Number of
holders
Ordinary
shares %
of total
shares issued
total shares
issued
%
performance
rights
Number of
performance
rights
Number of
performance
holders
1 to 1,000
1,001 to 5,000
5,001 to 10,000
10,001 to 100,000
100,001 and over
51
116
130
462
254
0.01
0.15
0.42
7.16
15,355
390,080
1,120,183
18,991,830
92.26
244,670,924
-
-
-
-
-
-
49.09
50.91
217,741
225,806
1,013
100.00
265,188,372
100.00
443,547
Holding less than a marketable parcel
239
0.36
945,618
-
-
-
-
-
3.00
2.00
5.00
-
EQUITY SECURITY HOLDERS
Twenty largest quoted equity security
holders
The names of the twenty largest security
holders of quoted equity securities are
listed below:
Mr Noel Newell (Newell Family A/C)
Oceania Hibiscus SDN BHD\C
Mr John Philip Daniels
Bill Hopper
Citicorp Nominees Pty Limited
Sanlirra Pty Ltd (Sanlirra Super Fund A/C)
BNP Paribas Noms Pty Ltd (DRP)
HSBC Custody Nominees (Australia) Limited
Northern Business Planning Centre Pty Ltd (Newell Super A/C)
Mr Tai Tran
HSBC Custody Nominees (Australia) Limited – A/C 2
Blamnco Trading Pty Ltd
Pengold Pty Ltd (Pengold Super Fund A/C)
Vin Naidu + Wendy Naidu
Mr Richard John Loveridge + Mrs Katrina Loveridge (Rj Loveridge S/Fund A/C)
Mr Giovanni Monteleone + Mrs Frances Monteleone
Mr Russell Barwick
Eilie Sunshine Pty Ltd (Eilie Sunshine Superfund A/C)
Mr Michael Andrew Jaket
Mr Peter Alaric Hayes
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Number held
38,604,620
30,963,000
7,557,500
6,475,000
5,710,094
5,000,000
4,840,950
4,691,161
4,675,385
4,500,000
4,322,940
4,000,000
3,714,000
2,837,500
2,771,419
2,550,000
2,500,000
2,500,000
2,250,000
2,237,000
Ordinary shares % of
total shares issued
14.56
11.68
2.85
2.44
2.15
1.89
1.83
1.77
1.76
1.70
1.63
1.51
1.40
1.07
1.05
0.96
0.94
0.94
0.85
0.84
142,700,569
53.82
Number
on issue
443,547
Number
of holders
5
Ordinary shares
% of total
shares issued
16.66
11.68
Number held
44,192,229
30,963,000
CORPORATE GOVERNANCE
STATEMENT
The Company’s 2022 Corporate
Governance Statement is available on the
Company’s website at:
https://www.3doil.com.au/about/
corporate-governance
ANNUAL GENERAL MEETING
3D Oil Limited advises that its Annual
General Meeting will be held on Thursday,
10 November 2022. The time and other
details relating to the meeting will be
advised in the Notice of Meeting to be
sent to all shareholders and released to
ASX in due course. In accordance with
the ASX Listing Rules and the Company’s
Constitution, the closing date for receipt
of nominations for the position of Director
are required to be lodged at the registered
office of the Company by 5.00pm (AEDT)
on 29 September 2022.
Unquoted equity securities
Performance rights over ordinary shares issued
SUBSTANTIAL HOLDERS
Substantial holders in the Company are set
out below:
Noel Newell
Oceania Hibiscus SDN BHD
VOTING RIGHTS
The voting rights attached to ordinary
shares are set out below:
Ordinary shares
All issued shares carrying voting rights on a
one-for-one basis.
Performance rights
There are no voting rights attached to
performance rights
There are no other classes of equity
securities.
PETROLEUM TENEMENT HOLDINGS
Tenement and Location
VIC/P79 Offshore Otway Basin, VIC1 & 2
T/49P Offshore Otway Basin, TAS
WA-527-P Offshore Roebuck Basin, WA
VIC/P57 Offshore Gippsland Basin, VIC3
VIC/P74 Offshore Gippsland Basin, VIC4
GSEL759 Otway Basin, SA5
1 On 4 February 2022, 3D Oil Limited announced the award of VIC/P79 100% to TDO.
2 On 1 July 2022, 3D Oil Limited announced the farmout of 80% interest in VIC/P79 and operatorship.
3 In February 2022, 3D Oil Limited applied to NOPTA to relinquish its participating interest in VIC/P57.
4 In July 2022, the Joint Venture applied to NOPTA to transfer 50% interest from Carnarvon Hibiscus to 3D
Oil Limited.
5 On 2 September 2022, 3D Oil Limited announced the award of GSEL gas storage exploration licence in
the onshore Otway Basin in South Australia.
Beneficial interest
%
100.00%
20.00%
100.00%
24.90%
50.00%
100.00%
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CORPORATE DIRECTORY
Directors
Noel Newell (Executive Chairman)
Ian Tchacos (Non-Executive Director)
Leo De Maria (Non-Executive Director)
Trevor Slater (Non-Executive Director)
Auditor
Grant Thornton Audit Pty Ltd
Collins Square Tower 5
727 Collins Street
Melbourne, Victoria 3008
Stock exchange listing
3D Oil Limited securities are listed on the
Australian Securities Exchange
(ASX Code: TDO)
Website
3doil.com.au
Company secretary
Stefan Ross
Registered office
Level 18, 41 Exhibition Street
Melbourne, VIC 3000
Telephone: (03) 9650 9866
Principal place of business
Level 18, 41 Exhibition Street
Melbourne, VIC 3000
Telephone: (03) 9650 9866
Share register
Computershare Investor Services
Pty Limited
452 Johnston Street
Abbotsford, Victoria 3067
Telephone: (03) 9415 5000
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ANNUAL REPORT 2022