Vintage Energy Limited Annual Report 2023

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FY2023 Annual Report · Vintage Energy Limited

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ANNUAL
REPORT 2023

Vintage Energy Ltd

ABN: 56 609 200 580

info@vintageenergy.com.au

www.vintageenergy.com.au

+61 8 7477 7680

CONTENTS

Chairman’s message _____________________________________________ 4
Note from the Managing Director ___________________________________ 6
Review of operations _____________________________________________ 9
Reserves & resources statement __________________________________ 14
Climate change & risk management ________________________________ 18
Directors’ report ________________________________________________ 20
Auditor’s independence declaration ________________________________ 30
Corporate governance statement __________________________________ 31
Statement of profit or loss and other comprehensive income _____________ 32
Statement of financial position _____________________________________ 33
Statement of changes in equity ____________________________________ 34
Statement of cash flows __________________________________________ 35
Notes to the financial statements __________________________________ 36
Directors’ declaration ____________________________________________ 56
Independent auditor’s report ______________________________________ 57
Schedule of tenements __________________________________________ 60
Information pursuant to the listing requirements of the ASX ______________ 61
Glossary ______________________________________________________ 63
Corporate directory _____________________________________________ 68

Competent persons statement

The hydrocarbon resource estimates in this report have been compiled by Neil Gibbins, Managing
Director, Vintage Energy Ltd. Mr Gibbins has over 40 years of experience in petroleum geology
and is a member of the Society of Petroleum Engineers. Mr Gibbins consents to the inclusion of
the information in this report relating to hydrocarbon reserves and contingent and prospective
resources in the form and context in which it appears. The reserve and resource estimates
contained in this report are in accordance with the standard definitions set out by the Society of
Petroleum Engineers, Petroleum Resource Management System.

CHAIRMAN’S MESSAGE

This was not merely unfortunate; diminishing the capital
raising capability of companies trying to bring new gas
supplies to market can only be counterproductive to the
realisation of lower gas prices and hinder competition
between producers.

Subsequent announcements, particularly the provision of
exemptions to companies engaged exclusively in
domestic supply, restored producer and buyer
confidence, evidenced by supply contracts and
memorandum of understanding. Investors, however,
having been disconcerted by the market intervention,
remained apprehensive of the risk it threatened. Equity
valuations for the sector remained low.

It was in this climate Vintage experienced delays in
establishing production from Vali-2 and Vali-3. We were
obliged to undertake a $5.6 million equity raising to fund
the necessary field work to boost cash flow and
production. This was well supported by institutions and
retail holders.

The pricing, at 5 cents per share, compares with the
year’s high of 13 cents, well below the preference of your
board. However, the funds raised have enabled Vintage
to push on with its plans to lift gas production and
complete the step change in revenue generation
expected from the commencement of gas supply from
Odin. We thank shareholders for their support in the
raising.

I am pleased to be able to report Odin commenced
production successfully subsequent to year end.
Conversely, work at Vali since year end has revealed
further work is required to bring Vali-2 and Vali-3 online.

As the Managing Director outlines in his report following,
trial and learning is an inherent element of the appraisal
process. Throughout this process there has been no
significant change to the size of the company’s gas
reserves and resources. In fact, the implied market value
of Vintage’s gas rose substantially during the year, as
evidenced by ACCC-published price data.

Directors expect the work planned for FY24 will result in
the company’s stock market value aligning closer to its
underlying value as a consequence of incremental
revenue generation from Odin and progress on the
pathway to increased gas production from Vali.

Vintage’s achievements in FY23 have brought the
company to a waypoint in its strategy such that the new
financial year will see some subtle changes in emphasis.

The company’s first three years were focussed on the
exploration for commercial gas reserves to supply
emerging contract opportunities in south-east Australia.
With the discoveries of Vali, and then Odin, our efforts for
the past two years have been directed to rapid appraisal,
commercialisation and the initiation of revenue
generation.

In doing so, Vintage made the transition from listing to
revenue generation within 5 years, a remarkable
achievement for a small resources company.

I am pleased to present the Vintage Energy Ltd
(“Vintage”) annual report for the 2023 financial year
(“FY23”), its fifth since listing on the ASX.

In presenting last year’s annual report, I advised the
company’s immediate focus would be “on taking Vali to
revenue generation and taking Odin to the point where
investment decisions and gas supply agreements can be
executed”.

Both of those objectives were realised in 2023.
Moreover, the market value of our uncontracted gas has
never been higher.

However, as this report outlines, it has not all been
smooth sailing.

Construction delays and downhole issues at some wells
meant production and revenue generation from Vali was
lower than anticipated.

Federal government policy announcements on regulation
of gas marketing conduct and pricing created the greatest
uncertainty experienced in gas contracting since supply
from the Cooper Basin and Bass Strait began 54 years
ago. The uncertainty diminished investor confidence and
equity market valuations of small gas companies were
derated promptly and substantially.

Focus now shifts to the maximisation of value from these
fields and the identification of new assets congruent with
our strategy from which the next step-up in business
scale and returns can be driven. Our tenement portfolio
includes licences in regions considered to hold the
potential for commercial gas and oil discoveries.

The proven experience of the board and management
team as operators of onshore oil and gas production has
the company well equipped to efficiently manage existing
operations and to assess the merit of synergistic new
business opportunities.

The premises of the company’s strategy have proven
correct and conservative. Demand for new supply of gas
remains keen and is expected to remain so as supply
from existing sources diminishes. The requirement for
reliable gas-fired power generation as a bulwark to
intermittent renewable generation is assuming mounting
significance as the scheduled retirement of coal-fired
power plants proceeds. (The inaugural supply contract
for Odin that was secured during the year typifies the
opportunities anticipated from the sector).

While Vintage is a young, and small, company it is
extraordinarily well placed to create value in this
environment. Our gas fields are connected to south-east
Australian markets. The large majority of our gas is
uncontracted and available for future supply.

The work planned by the management team for 2024 will
do much to delineate how this potential is to be realised in
the coming years for the benefit of shareholders.
It promises to be a busy, and important, year for the
company.

In closing, I record my appreciation and thanks to my
fellow directors for their guidance and efforts during the
year, and my congratulations and encouragement to Neil
and his team – and, of course, for the support of
shareholders, customers and financiers.

Reg Nelson
Chairman

Vali field separation and metering facility

NOTE FROM THE MANAGING DIRECTOR

Third, Vali is in the early stages of an appraisal program,
the initial objective of which is understanding the field’s
reservoir properties so the most value-accretive
development plan for Vali can be determined. The
lessons acquired during the year will be reflected in a
lower risk, better informed, development plan for Vali’s
uncommitted gas.

The expected value of this gas rose significantly during
the year. Markets tightened, buyers offered higher prices
to secure supply and the Competition and Consumer
(Gas Market Code) Regulations 2023 (Code) exempted
Vintage from the $12/gigajoule price cap. Vintage, with
over 42 PJ of uncommitted 2P gas reserves and two gas
fields connected to the south-east Australian gas
markets, has a soundly based fundamental value and
outlook.

Operations
Vintage’s operations for the year included capital works to
connect and commence production from the Vali gas
field, production of gas and gas liquids from the field and
connection of the Odin gas field to infrastructure.

Vali
The Vali gas field commenced production in February
2023, supplying gas to AGL. Sales gas totalling 239.0
terajoules (gross, Vintage share 119.5 TJ) was supplied
in the period to 30 June, virtually all of which came from
Vali-1, the first well brought online.

The second well to come online, Vali-3, produced briefly
in late March. However, fluid accumulation during a
scheduled downstream network outage required removal
operations for the well to re-start, a procedure which was
attempted numerous times. The most recent attempt was
conducted post year-end in conjunction with operations at
Vali-2, where excessive fluid production necessitated
deferral of start-up. Downhole investigation and logging
was proposed for both wells to identify the root cause and
potential remedial measures.

This work had mixed results. At Vali-2, multi production
logging tool (MPLT) data was acquired, interpreted and is
being considered by the joint venture.

At Vali-3, production from the well could not be restarted
and the MPLT logging proposed could not be
performed. The well is to remain shut-in as the joint
venture assesses the performance and potential
remediation options to improve performance of the
Toolachee producing zone in this well. Future options for
the well include production from other gas bearing zones
such as the Patchawarra formation.

Vali-1 is continuing to supply gas under the field’s
contract with AGL. The delays in establishing
production from the other wells represents a deferral,
rather than a loss, of revenue. Vali, with net 2P gas
reserves of 49 PJ at year-end is a substantial commercial
asset.

In the 2023 financial year, Vintage made the transition
from explorer to producer, commencing gas supply from
the Vali gas field and generating its first revenue.

We consolidated this position, accelerating connection of
a second gas field, Odin, and securing a second supply
agreement. Zero lost time injuries and zero environmental
incidents of reportable significance were incurred.

These milestones have been accompanied by
frustrations, initially through post-COVID bottlenecks,
which delayed completion of the Vali field facilities until
February 2023, and then subsurface, which prevented the
establishment of gas production from two of the field’s
three wells.

The detail of these complications and their status is
addressed following, under the heading ‘Operations’. For
the purpose of this overview of the company’s year-end
position, I note three points of significance.

First, the delay in production from these wells resulted in
production and cash generation being lower than
expected. This, together with additional costs brought by
the remedial field-based operations, necessitated the
$5.6 million capital raising conducted in June.

Second, as of September 2023, Vintage is no longer a
single field producer. The commencement of supply from
Odin is expected to substantially offset the impact in 2024
of lower output from Vali following disappointing
performance thus far at Vali-2 and Vali-3.

Odin
The commencement of production from the Odin gas field
subsequent to year-end was the culmination of a
concerted effort in 2023 to expedite revenue generation
from the field.

In particular, a simple processing plant is required to
transform wellhead output to a marketable, transportable
commodity. Vintage is directing its efforts to engagement
with parties most likely to collaborate in the development
of Nangwarry as processing plant owner and operator.

Concept engineering studies, commitment to a two-phase
connection, pipeline installation, securing of ACCC
authorisation and the gas supply contracting agreement
were all completed. Connection via the accelerated
connection was completed subsequent to year-end in
September.

While Odin is adjacent to Vali and connected to the Vali-
Beckler pipeline, it has some significant differences in its
completion, and supply contract, which make it a
complementary, rather than duplicate, asset.

Odin-1 will initially produce from the Epsilon and
Toolachee formations, without the Patchawarra
completion and stimulation employed in the Vali wells.
Odin’s supply contract is reflective of the gas market
dynamics prevailing in the first half of calendar 2023,
compared to the Vali agreement which was agreed in the
latter half of 2021 when price expectations were lower.

Like Vali, Odin production operations will initially involve
an appraisal via production philosophy. As a recently
discovered field tested by a single well to date, there is
much to learn. Reservoir characteristics are to be
assessed through production performance. Field extent
and volume is to be investigated through drilling.
Preparation and planning for the Odin-2 appraisal well
commenced during the year with a view to drilling in
FY24.

Other activities
Activities undertaken in respect of the company’s other
areas of interest are included in the Review of Operations
following in this report. These include exploration licences
in the Galilee and onshore Otway Basins situated well for
the discovery and supply of gas, the Nangwarry resource
and a Cooper Basin exploration permit considered
prospective for gas and oil.

Nangwarry
The Nangwarry gas resource is the most significant of the
company’s interests outside the Cooper Basin.

The potential value of Nangwarry, a long-life, high grade
carbon dioxide accumulation was highlighted during the
year by reports of rising scarcity of food-grade CO2 and
the implication of this for a range of essential or important
activities including healthcare, food and beverage
manufacture and storage, fire suppression and protected
horticulture. This was reinforced by inbound inquiry and
engagement with the South Australian government, who
are mindful of the implications of shortages of food-grade
CO2 and of the contribution of the nearby and analogous
Caroline field to the state’s CO2 requirements for nearly
50 years.

While there is a clear need, and ready market, for food-
grade CO2 such as can be produced from Nangwarry’s
output, the realisation of this economic potential will
require patience and capital.

Identifying parties willing to invest in CO2 production is
challenging in a world focussed on decarbonisation. But
the societal needs for food grade CO2 for healthcare, food
and beverages and the other applications noted remain.
The company will persist in its effort to find a capital
efficient solution to realising shareholder value for the
Nangwarry resource.

Commercial
The chief focus of our commercial activities for the year
was securing an inaugural supply agreement for the Odin
gas field. While interest from gas buyers was keen, the
securing of a contract required ACCC authorisations and
navigation of the greatest commercial uncertainty
experienced in the sector following the Federal
Government’s announcement of a temporary price cap
and its intention to introduce a mandatory code of
conduct.

Ultimately, we secured a well-priced contract; Odin gas is
flowing into the south-eastern Australian energy market
and Vintage has received clarity on our position as a
producer supplying less than 100 PJ of gas exclusively to
the domestic market. Vintage is not subject to the $12
price cap.

The receipt in May of ACCC authorisation to jointly
market Odin gas for longer periods than provided by the
previous interim authorisation opened the opportunity to
extend contract coverage of the field’s gas supply. Efforts
to secure an additional sales agreement from December
2024 to December 2026 commenced promptly and were
well received.

Success in this objective will take Vintage to the point
where it is effectively fully contracted over the medium
term for its current well configuration. Production from
Odin is expected to offer a significant uplift to Vintage’s
revenue stream and to date has been consistent with
expectations.

Reserves and resources
A detailed tabulation of the company’s proved and
probable reserves and resources is included in the
accompanying statement of this report. The company’s
2P reserves are currently restricted to those detailed for
the Vali gas field reported above and are largely
unchanged. Proved and probable reserves at 30 June
2023 were 4.06 million barrels of oil equivalent (MMboe)
compared with 4.08 MMboe at the beginning of the year.
Year-end contingent resources (2C) of 66 PJ are
unchanged.

Financial
At 30 June 2023 the company had cash reserves of $7.5
million. The company’s $10 million secure debt facility
was fully drawn.

Concluding comments and FY24 outlook
Our work in FY23 has Vintage entering the new year with
the ingredients in place for higher production, revenue
and cash generation and with greater diversity in its
production and contract portfolio.

The work program for FY24 is chiefly focussed on
production; initially to increase the number of stable
producing wells and latterly through finalisation of full field
development plans.

These plans will clarify the longer-term capital
expenditure, gas production profile and value generation
to be expected from Vali and Odin. The uncommitted gas
from these fields represents a substantial source of
shareholder value that, for now, remains latent pending
clarity on field production performance and future flows.
In addition, appraisal of the Odin gas field is planned.

In summary, whilst FY23 was directed towards
establishing first production and revenue, FY24 is largely
directed to building production and revenue generation.

Our interests in the Galilee, Otway and Bonaparte basins
are less mature gas prospective provinces possessing
potential aligned with our strategy. The FY24 work plans
for these licences are preparatory to testing this
prospectivity in future years.

At 30 June the Company’s staffing stood at 18 persons
compared with 15 a year earlier.

FY23 has been a demanding year, but one which has
clearly advanced the company in its strategy. Most
importantly, the year’s work has been conducted free
from lost time injuries and environmental incidents of
reportable significance. Thank you to the employees and
contractors whose diligence has enabled this safe
performance.

I would like to acknowledge the support and guidance the
board of directors has given the management team
during the year and thank shareholders, for their ongoing
patience and support.

Neil Gibbins
Managing Director

“Our work in FY23 has Vintage entering the new year with the ingredients
in place for higher production, revenue and cash generation and with
greater diversity in its production and contract portfolio”

REVIEW OF OPERATIONS
Description of operations

Vintage Energy’s operations involve exploration,
appraisal and commercialisation of oil and gas
accumulations onshore Australia. Activities are focussed
on proven petroleum basins offering high success rates
for drilling and where distance to market and adjacency of
existing infrastructure support rapid commercialisation.

At year-end the company held interests in petroleum
exploration licences in:

the Cooper/Eromanga basins, South Australia
and Queensland

the Otway Basin, South Australia and Victoria

the Galilee Basin, Queensland; and

the Bonaparte Basin, Northern Territory.

Cooper/Eromanga Basins,
Queensland and South Australia

ATP 2021, Queensland

Vintage 50% and Operator, Metgasco Ltd 25% and
Bridgeport (Cooper Basin) Pty Ltd 25%

ATP 2021 is located in Queensland adjacent to the
Queensland-South Australia border. ATP 2021 contains
the Vali gas field, discovered by Vali-1 ST1 in January
2020 and successfully appraised by Vali-2 and Vali-3.
These wells have been completed and connected to the
Cooper Basin gas gathering network.

The ATP 2021 Joint Venture has contracted to supply an
estimated 9 PJ to 16 PJ gas to AGL Energy from the Vali
gas field.

Operations during the first 8 months of the year focussed
on the completion of capital works to enable supply of gas
from Vali to AGL. This work included installation of a
14km pipeline connecting the field to the South Australian
Cooper Basin JV gas gathering network at Beckler,
installation of flowlines from the field’s wells and
installation of separation and metering facilities at Vali.

Vali-1 came online on 21 February and performed
consistently. The well and the Vali facilities recorded a
98% availability in the period to year-end. Third-party
downstream non-operated outages and maintenance
resulted in the loss of 24 days during the period.
The well’s performance was consistent with forecast.

Stable gas production from Vali-2 and Vali-3 was yet to
be established by year’s-end. Initial attempts were
prevented by fluid within the wellbores and work
programs to remove the fluid were delayed by equipment
and crew availability and recurring rainfall which brought
road closures and denied access. Restart of the wells
including logging of zonal contribution of gas and water
was scheduled for subsequent to year-end.

Vintage’s share of production from Vali was 120
terajoules of sales gas, 381 barrels of condensate, 18
tonnes of LPG and 4 terajoules of ethane.

ATP 2021 also offers other drilling targets and works
undertaken during the year advanced preparations for the
drilling of an appraisal well on the eastern flank of the
Odin gas field, which is mapped to extend into the permit,
and a future three-dimensional seismic survey over other
oil and gas prospects and leads.

Operations in FY24 will focus on establishing supply from
the field’s non-producing wells, optimising appraisal
production from the Vali field with a view to finalisation of
a full field development plan and appraisal of the Odin
discovery.

PRL 211, South Australia

Vintage 50% and Operator, Metgasco Ltd 25% and
Bridgeport (Cooper Basin) Pty Ltd 25%

PRL 211 lies in the South Australian Cooper Basin, with
the licence’s eastern boundary near the ATP 2021
western boundary. The licence is in close proximity to the
South Australian Cooper Basin Joint Venture’s gas
production infrastructure at the Beckler, Bow and
Dullingari fields.

The licence holds the western portion of the Odin gas
field, discovered by the PRL 211 joint venture in 2021.
The eastern portion of the field is mapped to extend into
ATP 2021, which has identical joint venture composition
to PRL 211. The field has one well, Odin-1, which has
been completed as a gas producer. As detailed in the
accompanying reserves and resources statement, Odin-1
is assessed to hold a gross 2C Contingent Resource of
39.7 PJ (19 PJ net to Vintage Energy). Operations and
developments in PRL 211 were directed to bringing the

Odin gas field into production at the earliest opportunity.
In November, the Joint Venture resolved to pursue a two-
stage connection of the field so supply could be
accelerated through an interim connection while a
superior permanent connection is being implemented.

The accelerated interim connection, which involves
installation of a 1.4 km pipeline linking Odin-1 to the Vali-
Beckler pipeline, was scheduled to enable gas supply
from Odin to commence within the first quarter of the
2024 financial year. Flowline was installed in January
2023 and tie-in operations were scheduled to commence
subsequent to year-end.

In May, the PRL 211 Joint Venture parties contracted to
supply gas from Odin to Pelican Point Power Limited, a
joint venture between ENGIE Australia and New Zealand
(72%) and Mitsui & Co Ltd (28%).

Under the contract, gas will be supplied from Odin from
field start-up until 31 December 2024, the maximum
period permissible for contracting under the then existing
interim ACCC authorisation for Odin.

PELA 679 South Australia

Vintage 100% subject to land title agreement

PELA 679 is a petroleum exploration licence application
in the south-west of the South Australian Cooper Basin
won through competitive bidding in 2019. On 30 June
2020, the company announced its bid had been
successful and, subject to establishment of an
appropriate land access agreement, it would hold a 100%
interest. Land access agreement negotiations are
ongoing.

Otway Basin, South Australia /
Victoria

PRL 249 (ex-PEL 155) South Australia

Vintage 50%, Otway Energy Pty Ltd 50% and
operator

PRL 249 contains the Nangwarry gas field, discovered in
January 2020. On testing, Nangwarry-1 produced raw
gas (~93% CO2, ~6% methane and ~1% nitrogen), at
flow rates of 10.5-10.8 million standard cubic feet per day
(“MMscfd”), measured through a 48/64” choke at a
flowing wellhead pressure of 1,415 psi over a 36-hour
period.

In July 2021 ERCE independently certified recoverable hydrocarbon and CO2 sales gas at Nangwarry as displayed in the
following table:

Nangwarry Field

CO2

Hydrocarbon

Pretty Hill Sandstone

Gross On-block Recoverable
Sales Gas (Bcf)
Best
25.9

High
64.4
Net On-block Recoverable
Sales Gas (Bcf)
12.9

32.2

Low
9.0

4.5

Gross Gas Contingent
Resources (Bcf)
2C
1.6
Net Gas Contingent
Resources (Bcf)
0.8

3C
4.1

2.0

1C
0.5

0.3

Notes to the table above:
1.
2.
3.

ERCE recoverable and resource estimates effective 7 July 2021. These resources were first announced to the ASX 12 July 2021.
Gross volumes represent a 100% total of estimated recoverable volumes within PRL 249.
Working interest volumes for Otway Energy Pty Ltd and Vintage’s share of the Gross recoverable volumes can be calculated by applying their
working interest in PRL 249, which is 50% each.
Sales gas stream for Nangwarry is CO2 gas.
These are unrisked Contingent Resources that have not been risked for Chance of Development and are sub-classified as Development
Unclarified.
Hydrocarbon gas also includes minor volumes of nitrogen

4.
5.

The Nangwarry Contingent Resource is assessed to
possess the volume, quality and reservoir properties for
an economic, significant and long-life food-grade CO2
production asset.

Food or industrial grade CO2 is a required input for a wide
range of sectors including hospitality, food and beverage
manufacture, protected horticulture, cold storage,
chemical, medical device and other manufacturing.
However, supply of food-grade CO2 is tightening as
availability from industrial sources declines with
decarbonisation.

The potential value of the Nangwarry resource to meet
this need was highlighted during the year through media
coverage of the economic impact of the scarcity of food
grade CO2 and increased inbound enquiry on the
prospect of supply from the field. This will necessitate
processing of raw gas and liquefaction for transport to
market.

Nangwarry is well suited for this purpose, possessing low
impurity levels, resources sufficient for a multi-decade
feedstock supply and being located close to the depleted
Caroline-1 well, which supplied CO2 for 49 years.

Vintage and Otway Energy are seeking an outcome
which will realise the economic value of the Nangwarry
resource.

The company is seeking to secure a collaborative
wellhead-to-product delivery solution to enable
commercialisation and, to this end, broadened its
engagement with participants in the industrial gas and
infrastructure sectors, and with government, during the
year.

The non-binding memorandum of understanding between
Supagas Pty Ltd, reported in the 2021 Annual Report,
has ended by mutual agreement.

PEP 171 Victoria

Vintage 25%, Somerton Energy Pty Ltd 75%

PEP 171 is located in the onshore Otway Basin and
effectively encompasses the entirety of the Victorian
section of the Penola Trough. While activity in the permit
has been suspended until recently pursuant to Victorian
Government moratorium, exploration in the nearby South
Australia section has confirmed the prospectivity of the
Penola Trough for conventionally produced gas, most
significantly at the fields held by Beach Energy Ltd such
as Haselgrove, Katnook, Ladbroke Grove and Limestone
Ridge.

The expiry of the Victorian onshore gas exploration
moratorium on 1 July 2021, was followed by new
regulations on 22 November 2021. All previous existing
oil and gas exploration permits of good standing (which
included PEP 171), were restarted from 1 July 2021 for
their first 5-year term.

Activity during the year was directed towards
recommencing exploration of the permit with the objective
of conducting a 3-D seismic survey, focussing on the
preparation of an operations plan. A full environmental
management plan was prepared and a stakeholder and
community engagement plan prepared and initiated.
Engagement under the plan was well underway at year-
end.

Galilee Basin, Queensland

ATPs 743, 744 & 1015 (“Deeps”)
PCAs 319, 320, 321, 322, 323 & 324

Vintage 30%, Comet Ridge Ltd (“Comet”) 70% and
operator

The Galilee Basin is a lightly explored gas province in
proximity to market and the proposed Galilee-Moranbah
pipeline. Vintage acquired a 30% participation into the
‘Deeps’ sandstone reservoir sequence of ATP 744, ATP
743 & ATP 1015 (all strata commencing underneath the
Permian coals (Betts Creek Beds or Aramac coals) with
the main target being the Galilee Sandstone sequence).

The Deeps was tested in 2018 by Albany-1, which
recorded the first measurable gas flow from the Galilee
Basin flowing at 230,000 scfd from the top 10% of the
target reservoir without stimulation. In 2019, Albany-2
was drilled and hydraulically stimulated and Albany-1 was
side-tracked but not flow-tested as operations ceased
during the Covid pandemic. The 2023 accounts include
an impairment made in respect of Albany-2.

Activity in these permits was suspended pending regulatory
review and decision of applications by the Deeps joint
venture for award of Potential Commercial Area (“PCA”)
titles over the main identified Deeps prospects and leads in
these ATPs. In September 2022, the regulator advised the
Deeps joint venture its applications for 6 titles: PCA 319,
PCA 320, PCA 321, PCA 322, PCA 323 and PCA 324 had
been successful. The PCAs have a 15-year tenure. ATPs
743 & 744, which occupy the same area as the overlying
PCAs, were renewed for twelve years in 2022 and ATP
1015 was renewed for twelve years in June 2023.

Vintage conducted a review of data from the Albany wells
and the region. The results of the review have been
shared with the Operator and are being used by the
Galilee Deeps JV to prioritise exploration activities in the
PCAs.

The Queensland government has announced a new
$21 million grant program to drive exploration for gas
reserves in the Bowen and Galilee Basins, which has the
potential to assist the Deeps JV’s exploration efforts.

Bonaparte Basin, Northern Territory

EP 126

Vintage 100%

The Bonaparte Basin is a frontier basin in the north of the
Northern Territory with a proven hydrocarbon system.
Several large gas fields have been discovered offshore
(undeveloped Contingent Resources of 2.7 Tcf in Petrel,
Tern and Frigate) and the producing Black Tip field (2P
933 Bcf) supplies gas to Darwin. The onshore Weaber
Gas Field (RL-1, Advent Energy 100%), and surface
bitumen seeps, provide direct evidence of a working
petroleum system in the Keep Inlet Sub-Basin.

EP 126 is a low-cost entry with excellent exploration
potential encompassing an area of 6,716 km2, hosting
multiple play types, with potential for large volumes of gas
and oil. Cullen-1 was drilled in 2014, with both oil and gas
shows, and was cased and suspended to be available as
an option to test.

Discussion with the Northern Territory Government
continued in relation to the declaration of approximately
50% of the permit, including the Cullen-1 well site, as a
’Reserved Area’. No regulated activities, other than
required maintenance, will be undertaken until the issue
is resolved.

Vali-1 wellsite configuration

RESERVES & RESOURCES STATEMENT

During 2023, Vintage Energy and its joint venture partners commenced sale of gas and gas liquids produced from the Vali gas
field in the Cooper Basin. Accordingly, and consistent with PRMS requirements, the 2023 reserves statement below reports
separate classification for each of the hydrocarbon products produced and sold: sales gas; ethane; liquified petroleum gas and
condensate. These volumes were reported as a single sales gas volume in previous years.

Proved (1P) Reserves

Area

FY22
(MMboe)

Production

Contingent
Resources
to Reserves

Revisions

FY23

Developed

Undeveloped

(MMboe)

Cooper Basin

Total

4.08

(0.02)

4.06

0.99

3.07

Proved and Probable (2P) Reserves

Area

FY22
(MMboe)

Production

Contingent
Resources
to Reserves

Revisions

FY23

Developed

Undeveloped

(MMboe)

Cooper Basin

Total

8.68

0.02

8.66

1.06

7.6

2P Reserves Net to Vintage by product

Area

FY23
Total
(MMboe)

Sales gas

Ethane

LPG

Condensate

(PJ)

(kTonne)

(MMbbl)

Cooper
Basin

8.66

46.75

1.97

11.07

0.20

Total

8.66

46.75

1.97

11.07

0.20

Notes to the Cooper Basin 1P and 2P reserve assessment:

1.
2.

4.
5.

6.
7.
8.
9.

Reserves estimates reported here are ERCE estimates, effective 31 October 2021.
Vintage is not aware of any new data or information that materially affects the reserves above and considers that all material assumptions and
technical parameters continue to apply and have not materially changed.
Reserves estimates have been made and classified in accordance with the Society of Petroleum Engineers (“SPE”) Petroleum Resources
Management System (“PRMS”) 2018.
Probabilistic methods have been used for individual sands and totals for each reservoir interval have been summed deterministically.
Company net entitlement reserves are based on the Vintage working interest share of 50% of the on block gross ATP 2021 Reserves as there are no
royalties payable.
Volumes are net of fuel and flare volumes.
Ethane has been reported separately from Sales Gas as it is sold separately in the case of Vali Field.
All quantities are subject to rounding to two decimal places for clarity purposes.
Conversion factors. Barrels of oil equivalent conversion factors applied are: sales gas and ethane 1 PJ=171.94 Kboe; LPG 1 Ktonne =8.458 Kboe;
1barrel (bbl) condensate = 0.935 boe

10. These reserves were first reported by Vintage in an ASX release dated 1 November 2021.

Contingent resources

2C Contingent Resource (PJ) Net to Vintage

Area

Galilee
Basin

Cooper
Basin

Otway*
Basin

0.8

Total

FY22
(PJ)

Acquisitions
&
Divestments

Contingent
Resources
to Reserves

Revisions

FY23 (PJ)

Gas (PJ)

0.8

*In the Otway Basin, the recoverable CO2 cannot be classified under PRMS as a contingent resource. For CO2 recoverable volumes see the
Operations section on page 11

Notes on Galilee Basin contingent resource assessment:

Estimates are in accordance with the Petroleum Resources Management System (SPE, 2007) and Guidelines for Application of the PRMS (SPE,
2011).

2. No reserves were estimated.
3.
4.

Probabilistic methods were used.
Sales gas recovery and shrinkage have been applied to the contingent resource estimation. The losses include those from the field use, as well as
fuel and flare gas.
These volumes were first reported by Vintage in the September 2018 prospectus for the Initial Public Offering of shares in Vintage and prior to that
by the Comet Ridge announcement of 5 August 2015.
The chance of development is classified as high, as several commercialisation possibilities exist for future gas supply export.

Notes on Cooper Basin contingent resource assessment:

1. Gross contingent resources represent 100% total of estimated recoverable volumes within PRL 211 and ATP 2021.
2. Working interest contingent resources represent Vintage’s share of the gross contingent resources based on its working interest in PRL 211, which

is 50%, and ATP 2021, which is 50%.
These are unrisked contingent resources that have not been risked for Chance of Development and are sub-classified as Development Unclarified.
Contingent resources volumes shown have had shrinkage applied to account for inerts removal and include hydrocarbon gas only.

3.
4.
5. No allowance for fuel and flare volumes has been made.
6.
7.
8.
9.
10. These Contingent resources were first disclosed in a release to the ASX on 16 September 2021.

Resources estimates have been made and classified in accordance with the Petroleum Resources Management System 2018 (“PRMS”).
Probabilistic methods have been used for individual sands and totals for each reservoir interval have been summed deterministically.
A conversion factor of 1.09 is applied to convert from billion standard cubic feet (Bscf) to petajoules (PJ).
Contingent resources certified by ERCE are as at 14 September 2021.

Notes on Otway Basin Contingent Resource assessment:

1. Nangwarry hydrocarbon resources have been sub-classified as “Development Unclarified” under the PRMS by ERCE and are assigned as Consumed

in Operations, that is used to fuel a CO2 plant.
The key contingencies are a final investment decision on development, committing to a CO2 sales agreement, any other necessary commercial
arrangements, and obtaining the usual regulatory approvals.
Volumes reported are unrisked in the sense that no adjustment has been for the risk that the project may not be developed in the form envisaged
or may not go ahead at all.
Probablistic totals have been estimated using the Monte Carlo method.
Volumes represent Vintage’s 50% working interest in PRL 249.

4.
5.

Reserves evaluator

SRK Consulting (Australasia) Pty Ltd –
Carmichael structure (Galilee Basin)
contingent resource assessment

SRK is an independent, international group providing
specialised consultancy services, with expertise in
petroleum studies and petroleum related projects. In
Australia SRK have offices in Brisbane, Melbourne,
Newcastle, Perth and Sydney and globally in over 40
countries. SRK has completed petroleum reserve and
resource assessments for many clients in Australia and
internationally.

The Contingent Resource for the Carmichael Albany
Structure referred to in this report is derived from an
independent report by Dr Bruce McConachie, an
Associate Principal Consultant with SRK Consulting
(Australasia) Pty Ltd, an independent petroleum reserve
and resource evaluation company. He has disclosed to
Vintage, the full nature of the relationship between
himself and SRK, including any issues that could be
perceived by investors as a conflict of interest.

Dr McConachie is a geologist with extensive experience
in economic resource evaluation and exploration. He is a
member of the American Association of Petroleum
Geologists, Society of Petroleum Engineers and
Australasian Institute of Mining and Metallurgy. His
career spans over 30 years and includes production,
development and exploration experience in petroleum,
coal, bauxite and various industrial minerals, covering

petroleum exploration programs, joint venture
management, farm-in and farm-out deals, onshore and
offshore operations, field evaluation and development, oil
and gas production and economic assessment, with
relevant experience assessing petroleum resource under
PRMS code (2007).

The Carmichael Structure Contingent Resources
information in this report has been issued with the prior
written consent of Dr McConachie in the form and context
in which it appears. His qualifications and experience
meet the requirements to act as a Competent Person to
report petroleum reserves in accordance with the Society
of Petroleum Engineers (“SPE”) 2007 Petroleum
Resource Management System (“PRMS”) Guidelines as
well as the 2011 Guidelines for Application of the PRMS
approved by the SPE.

ERC Equipoise Pte Ltd – Vali reserves
assessment and Odin and Nangwarry
contingent resource assessment
ERCE is an independent consultancy specialising in
petroleum reservoir evaluation. Except for the provision
of professional services on a fee basis, ERCE has no
commercial arrangement with any other person or
company involved in the interests that are the subject of
this Contingent Resources evaluation.

The work has been supervised by Mr Adam Becis,
formerly Principal Reservoir Engineer of ERCE’s Asia
Pacific office who has over 15 years of experience. He is
a member of the Society of Petroleum Engineers and a
member of the Society of Petroleum Evaluation
Engineers.

CLIMATE CHANGE & RISK MANAGEMENT

The Vintage Board has a policy on climate change which
recognises that the Company has a role to play in
reducing carbon emissions.

We recognise the world needs to access reliable,
affordable and sustainable energy delivered in cleaner
ways.

As an oil and gas exploration and production company,
Vintage understands that to be successful it must identify
and develop a long-term portfolio of assets that contribute
to a low-carbon future. In development it must ensure the
use of energy-efficient and low emission technologies to
ensure a low carbon footprint.

The Task Force on Climate-Related Financial Disclosures
(TCFD) recommends climate-related financial disclosure
under the following categories:

Climate change governance

The Vintage Board oversees risk management for the
business, including climate change policy and climate
change risks and opportunities. Climate-related issues
are considered regularly by the Board and in particular
the effect climate change may have on the Company’s
business strategy.

Climate change risk is specifically addressed by the
Company’s risk management committee, which reports to
the audit and risk committee.

The audit and risk committee’s purpose with respect to
climate change risks and opportunities is to:

• Have oversight of risk management

• Approve and recommend to the Board for
adoption, policies and procedures on risk
oversight and identifying, assessing, monitoring,
and managing risks and opportunities

• Assessing the adequacy of risk control systems

Management, through the risk management committee,
conducts regular risk assessments including climate
change risk and updates the risk register with identified
controls and progress against risk mitigation actions.
Reports on progress are provided regularly to the audit
and risk committee and the Board.

Strategy

Climate-related risks and opportunities to the business
strategy are:

• Effect of climate change on market sentiment,
which may result in capital being harder to
obtain and therefore it may fail to meet its
objectives.

• Vintage’s major assets are its gas exploration

and production permits in the Cooper Basin.
Natural gas is a transitional energy source to a
low carbon future and may provide significant
opportunities for commercialisation of these
assets currently being appraised.

• Physical risks that may eventuate from a hotter
global climate to the Vintage business could
include increased number of extreme heat days
that field workers are exposed to and extreme
weather conditions such as flooding events
could impact business continuity of field
operations.

•

Technology and energy sourcing opportunities
that provide options to transition products,
services and energy needs to lower emission
options and the costs associated with this
transition.

The Company routinely evaluates alternative
and/or renewable energy opportunities and has
secured a Gas Storage Exploration Licence
(GSEL) in the south-east of South Australia over
the area surrounding the depleted Caroline CO2
field.

Metrics and targets

Vintage is in the process of defining its future targets and
metrics as the business grows and operations become
more complex. It is envisaged these will be disclosed
over the coming financial years and reviewed regularly.

Risk management

Vintage has implemented an enterprise risk management
framework based on ISO 31000:2009.

Climate-related risks and opportunities are included in
Vintage’s corporate risk register which is reviewed
regularly by management and by the audit and risk
committee. As required by the framework, the risk register
includes events, causes, consequences and effects of
identified risks and opportunities. A risk weighting is then
applied based on the chance the event may happen and
the potential effect on the business. Mitigation actions are
identified, and appropriate follow-up actions are taken
and monitored. The categories of risk identified by the
Company and reported on as part of its systems and
processes for managing material business risk include
operational health and safety, environmental, reputational
and financial.

In particular, the Company has exposure in the following risk areas:

RISK

DESCRIPTION

The Company’s main activity is exploration and production of oil and gas. To continue its programme, the Company may be required

Funding

to raise additional capital. There is no assurance that the Company will be able to obtain additional financing when required in the

future, or that the terms and time frames associated with such funding will be acceptable to the Company, this may have an adverse

effect on the Company’s ability to achieve its strategic goals and have a negative effect on its financial results.

Government

regulation

The oil and gas industry is highly regulated by all levels of Government. Changes to regulation including Government taxes and

charges may affect the viability of the Company’s projects either because of access or technology restrictions or increased costs. The

Company has maintained communications with relevant parties to mitigate the effect of regulation change including membership of

industry bodies. The Company has also adopted internal compliance monitoring solutions to maintain currency with legislation and

regulatory obligations within the jurisdictions it operates.

The Company’s operations are subject to operating risks that could result in increased costs & breaches of regulations. To manage

Operating risk

this risk, the Company seeks to attract and retain high calibre employees and implement suitable systems and processes to ensure

targets are achieved.

The Company has environmental liabilities and obligations associated with its exploration licences which arise as a consequence of

its activities, including waste management, chemical management, water management and energy efficiency. The Company monitors

Environmental

its ongoing environmental obligations and risks, and implements preventative, rehabilitation and corrective actions as appropriate,

through compliance with its environmental management system which is part of the Health, Safety and Environmental Management

System (HSEMS).

The Company seeks to ensure that it provides a safe workplace to minimise risk of harm to its employees and contractors and the

impact of its operations on the environment and the communities in which it operates. It achieves this through an appropriate culture,

systems, training and emergency preparedness. The Company has implemented a Health, Safety and Environment (HSE)

Sustainability

management system to drive the organisation’s continuous improvement in HSE performance which has standards that include

risks

leadership and commitment, policies and strategic objectives, contractors and suppliers, asset design and integrity, stakeholder and

community, legal and regulatory compliance, risk management, planning and execution of activities. Subject to specific site conditions

and local regulatory requirements, management of identified HSE risks are to be standardised for all operational sites and embedded

in the Company’s Enterprise Risk Management Framework.

The Company operates within the oil & gas industry, which has committed to a set of Climate Change Policy Principles published by

the Australian Petroleum and Production Association (APPEA) that are designed to assist policymakers in developing efficient and

effective responses to this global issue. The Australian oil and gas industry supports a national climate change policy that delivers

greenhouse gas emissions reductions consistent with the objectives of the Paris Agreement at the lowest cost to the economy.

Climate change

Greater use of Australia’s extensive gas resources will be crucial in meeting the challenge of significantly reducing global greenhouse

gas emissions at lowest possible cost whilst enhancing Australia’s economic and export performance. As economies transition to a

lower emissions future there is a risk that the Company will need to alter its business strategy and practices to both mitigate the risks

and take advantage of the opportunities presented by the changing global energy mix. The Company continues to monitor current

reporting and other requirements in line with its present and future operational position to ensure it understands the risks,

opportunities and responsibilities associated with climate change and has adopted and published a climate change policy.

JV partnership

alignment

The ability to execute growth activity in a joint venture (“JV”) can be impacted by the strategy and appetite for capital investment by its

JV partners. The joint operating agreements (“JOAs”) that covers each of the Company’s JVs detail operating and voting procedures

for activities withing the relevant licences.

Vintage has certain restoration obligations with respect to its exploration and development licences, facilities and related

infrastructure. These liabilities are derived from legislative and regulatory requirements, which are subject to change. Vintage’s

Changes to

balance sheet incorporates estimates for such decommissioning and abandonment activity, with those estimates included within

restoration

obligations

provisions

provisions. Vintage conducts a review of restoration provisions on a semi-annual basis. This includes a review of the assumptions

included in the estimation, such as changes to the legislative and/or regulatory requirements for decommissioning and abandonment,

future remaining reserves estimates, timing and costs and resultant production from the commercialisation of contingent resources,

current prevailing market rates and costs to undertake decommissioning and abandonment activity, future inflation rates, and

appropriate discount rates.

DIRECTORS’ REPORT

The Directors of Vintage Energy Limited (“Vintage” or “the
Company”) present their report together with the financial
statements of the Company for the year ended 30 June
2023 and the independent audit report thereon.

Director details

The following persons were Directors of Vintage during or
since the end of the financial year:

Reg Nelson | Chairman (independent Director) has a
long and distinguished career in the Australian petroleum
industry and is widely respected within commercial and
government circles for his successful and innovative
leadership. As Managing Director of ASX-listed Beach
Energy Limited (“Beach”), until retiring from the position in
2015, he led the company to a position as one of
Australia’s top mid-tier oil and gas companies. He was
formerly Director of Mineral Development for the State of
South Australia, a Director of the Australian Petroleum
Production and Exploration Association (“APPEA”) for
eight years and was APPEA Chairman from 2004 to
2006. He was a Director of petroleum exploration
company FAR Limited and has been a Director of many
other Australian Securities Exchange (“ASX”) listed
companies. He was awarded the Reg Sprigg Medal by
APPEA in 2009 in recognition of his industry contribution.
Other directorships – Nil.

Previous directorships – FAR Limited (from May 2015 to
June 2021).

Committee memberships - Audit and risk committee,
Nomination committee and Remuneration committee.

Interest in shares and options

Ordinary shares

Options

18,357,986

2,000,000

Employee incentive rights

Neil Gibbins | Managing Director has over 40 years of
technical and leadership experience in the petroleum
industry in a wide variety of regions in Australia and
internationally and has been involved in many successful
exploration, development and corporate acquisition
projects. Neil was employed at both Esso Australia and
Santos Limited, initially as a geophysicist and later in
supervisory roles. He moved to Beach in 1997, initially as
Chief Geophysicist, and then as Exploration Manager in
2005, and Chief Operating Officer in 2012. Neil was
acting CEO in 2015 and led Beach during its merger with
DrillSearch Energy Limited in 2016. He is a member of
PESA, SEG, SPE and ASEG.
Other directorships – Nil.

Interest in shares and options

Ordinary shares

18,033,511

Options

Employee incentive rights

6,045,600

Nick Smart | Non-Executive Director (independent
Director) has over 40 years of corporate experience and
was a full associate member of the Sydney Futures
Exchange, a senior adviser with a national share broking
firm, and has significant international and local general
management experience. He has participated in capital
raisings for numerous private and listed natural resource
companies and technology start-up companies. This
includes commercialisation of the Synroc process for safe
storage of high-level nuclear waste, controlled
temperature and atmosphere transport systems and the
beneficiation of low rank coals.
Other directorships – Nil.

Committee memberships – Nomination committee,
Remuneration committee and Chair of Audit and risk
committee.

Interest in shares and options

Ordinary shares

Options

6,436,821

2,000,000

Employee incentive rights

Ian Howarth | Non-Executive Director (independent
Director) spent several years as a mining and oil analyst
with Melbourne-based May and Mellor. He had a career
in journalism as a senior resources writer at The
Australian and was the Resources Editor of the Australian
Financial Review for 18 years. He created Collins Street
Media, one of Australia’s leading resources sector
consultancies. Clients included APPEA and several listed
companies including Shell Australia. His expertise lies in
marketing and assisting in capital raising. Ian has a
certificate in financial markets from Securities Institute of
Australia.
Other directorships – Nil.

Committee memberships - Audit and risk committee,
Chair of the Nomination committee and Remuneration
committee.

Interest in shares and options

Ordinary shares

Options

15,331,180

2,000,000

Employee incentive rights

Company Secretary

The following person was Company Secretary of Vintage
during and since the end of the financial year:

Simon Gray | Company Secretary / Chief Financial
Officer has over 40 years' experience as a chartered
accountant and 20 years as a Partner with Grant
Thornton, a national accounting firm. In his last five years
at the firm, he was the national head of energy and
resources. Simon retired from active practice in July
2015. His key expertise lies in audit and risk, valuations,
due diligence and ASX Listings. His qualifications include
B.Ec. (Com). He is Chairman and Chief Financial Officer
of minerals exploration company Havilah Resources
Limited and Company Secretary of several other ASX-
listed companies.

Principal activities

The principal activities of the Company during the year
were gas and oil exploration, appraisal and production.

Vintage became a producer of hydrocarbons during the
financial year.

Results for the year

Statement of profit or loss

The Company incurred an operating loss of $11,261,626
for the financial year ended 30 June 2023 (2022
$7,978,704).

The movement in earnings between the periods is largely
explained at a high level by two features:

the commencement of gas production during the
year and with the associated increases in
production costs, depreciation and royalties.

the first full year interest and amortisation
charges associated with the company’s debt
facility.

Total income rose to $3,995,510 and was 78% higher
than the previous year’s income of $2,241,361. The
increase includes sales revenue of $949,333 (2022 nil)

following the commencement of gas sales from the Vali
gas field in February. Joint Venture recoveries rose from
$2,193,448 to $2,794,504, with the increase reflecting
increased activity and expenditure during 2023.

The more significant expenses during the year included:

- production costs of $1,492,611 (2022: Nil) which

includes expenditure on commissioning to bring wells
into production.

- depreciation charges totalling $560,707 (2022:

$241,820). Depreciation increased as a result of the
commencement of production.

- an impairment charge of $4,635,464 resulting from
assessment of Albany-2 in the Galilee Basin. The
2022 financial accounts included an impairment
charge of $4,173,827 relating to oil exploration in the
Perth Basin.

financing costs of $1,887,738 (2022: $116,461) which
included the first full year of interest charges under
the company’s debt facility and amortisation of
associated warrants.

increased employee benefits reflecting increased
activity levels.

Further detail and discussion of the year’s activities and
operational outcomes is provided in the Review of
Operations in this Annual Report.

Statement of financial position

Cash and cash equivalents reduced from $18,711,960 to
$7,507,716, principally due to expenditure to bring the
company’s gas fields to production. Property, plant and
equipment rose from $406,055 to $8,660,457 through
recognition of production and pipeline facilities which
became operational during the year.

The most significant movement in liabilities at 30 June
was the increase in provisions from $1,149,040 to
$4,239,426. The movement is largely attributable to the
increase in restoration provision from $970,000 to
$3,992,500.

Dividends

No dividends were paid or proposed during the year.

Significant changes in the state of affairs

On 21 February 2023, the Company achieved first gas supply from its Vali field (ATP 2021 Joint Venture). The initial phase of
testing of Vali is directed to field appraisal, with the data acquired to inform preparation of a full field development plan. The
appraisal process will be reflected in variable production as individual zones and formations are assessed, understood and
optimised.

On 15 May 2023, the Company announced the signing of a Gas Sales Agreement with Pelican Point Power for supply of gas
from the Odin Field from gas supply start-up to end 2024.

In June 2023, the Company issued 111,801,044 ordinary shares at $0.05 per share, to complete a $5,590,052 capital raise,
as announced 31 May 2023.

Subsequent events

Subsequent to year end, 1,845,300 short term incentive performance rights held by the Managing Director, 164,300 short term
incentive performance rights held by an associate of the Managing Director, 1,077,700 short term incentive performance rights
held by other key management personnel and 7,992,500 short term incentive performance rights held by management vested
upon their performance conditions being met.

On 12 September 2023, 1,598,600 STI performance rights were granted to key management personnel and 12,866,500 Class
STI performance rights were granted to management and staff, with a fair value of $578,604 on the following terms:

•

being employed by the Company at 1 July 2024

• Odin Production on line (or available) over a 9 month period during FY24

•

Full Field Development Plan finalised for the Vali Gas Field and approved by the joint venture

Total capital expenditure for FY24 maintained within 110% of the approved Corporate Budget capital expenditure,

On 14 September 2023, first gas was achieved from the Odin Field (PRL 211 Joint Venture). The initial phase of production
from Odin is directed to field appraisal, with the data acquired to inform preparation of a full field development plan.

Likely developments, business strategies and prospects

The Company will continue to develop its existing suite of exploration and evaluation assets and will work to identify other
assets and corporate opportunities that will grow the Company and enhance shareholder value.

Directors’ meetings

The number of meetings of Directors (including meetings of Committees of Directors) held during the year and the number of
meetings attended by each Director is as follows:

Board Member

Reg Nelson

Ian Howarth

Neil Gibbins

Nick Smart

Board

Meetings

Audit and Risk

Remuneration

Committee

Nomination
Committee

Notes to the table above:

A is the number of meetings held; B is the number of meetings attended; All Directors are members of all committees.

Share options granted to management and Directors during the year

No share options were granted to management or Directors during the year.

Performance rights granted to management and Directors during the year

Performance rights were issued to other key management personnel on 5 August 2022 on the following terms:

•

1,077,700 short term incentives – being employed by the Company at 1 July 2023, Odin gas sales contract in place
and construction commenced on flow line infrastructure;

A further 7,992,500 performance rights were issued to management and staff, on the following terms:

•

7,245,496 short term incentives issued 5 August 2022 – being employed by the Company at 1 July 2023,
Odin gas sales contract in place and construction commenced on flow line infrastructure;

449,200 short term incentives issued 5 August 2022 – being employed by the Company at 1 August 2023;

297,804 short term incentives issued 18 November 2022 – being employed by the Company at 17 October 2023 and
acceptable individual performance up to 17 October 2023.

1,845,300 performance rights were issued to the Managing Director and 164,300 to a related party of the Managing Director
on 25 November 2022, as approved at the Company AGM held 22 November 2022, on the following terms:

• Short term incentive – employed by the Company at 1 July 2023, a gas contract in place for Odin gas and construction

commenced on a connection pipeline.

A further 1,729,700 performance rights relating to the Managing Director, 1,010,200 relating to other key management
personnel and 6,255,500 relating to management and staff lapsed during the year, after performance conditions were not met.

Subsequent to the end of the financial year, as described above, 1,598,600 Class STI performance rights were granted to key
management personnel and 12,866,500 Class STI performance rights were granted to management.

Performance rights on issue

Performance rights to ordinary shares in the Company at the date of this report are:

•
•
•

4,036,000 performance rights held by the Managing Director;
3,955,600 performance rights held by other key management personnel, and;
22,527,904 performance rights held by management and staff.

Unissued shares under option

6,000,000 options have been issued to Directors, excluding the Managing Director, with an exercise price of $0.133 per option,
expiring 3 years from issue (29 November 2024). The options were approved at the Company AGM held 29 November 2021.

Options do not entitle the holder to participate in any share issue of the Company.

Shares issued during or since the end of the year as a result of exercise of options

No options have been exercised during or since the end of the financial year.

Shares issued during or since the end of the year as a result of exercise of performance rights

During the year, 549,200 performance rights relating to management were exercised into ordinary shares on satisfaction of
performance conditions.

Subsequent to the end of the financial year, 1,845,300 shares were issued to the Managing Director, 164,300 shares were
issued to a related party of the Managing Director, 1,077,700 shares were issued to other key management personnel and
7,992,500 shares were issued to management and staff on the exercise of Class STI performance rights upon satisfaction of
performance conditions.

Environmental legislation

The Company’s oil and gas operations are subject to environmental regulation under the legislation of the respective State,
Territory and Federal Government jurisdictions in which it operates. Approvals, licenses, hearings and other regulatory
requirements are performed by the operators of each permit or lease on behalf of joint operations in which the Company
participates. The Company is potentially liable for any environmental damage from its activities, the extent of which cannot
presently be quantified and would in any event be reduced by insurance carried by the Company or operator. The Company
applies the oil and gas experience of its personnel to develop strategies to identify and mitigate environmental risks.
Compliance by operators with environmental regulations is governed by the terms of respective joint operating agreements
and is otherwise conducted using oil industry best practices. Management actively monitors compliance with regulations and
as at the date of this report is not aware of any material breaches in respect of these regulations.

Remuneration report (audited)

Principles used to determine the nature and amount or remuneration

The remuneration policy of Vintage has been designed to align key management personnel objectives with shareholder and
business objectives by providing a fixed remuneration component and offering other incentives based on performance in
achieving key objectives as approved by the Board. The Board of Vintage believes the remuneration policy to be appropriate
and effective in its ability to attract and retain the best key management personnel to run and manage the Company, as well
as create goal congruence between Directors, executives and shareholders.

The Company’s policy for determining the nature and amounts of emoluments of Board members and other key management
personnel of the Company is as follows:

Remuneration and nomination

The remuneration committee oversees remuneration matters and sets remuneration policy, fees and remuneration packages
for non-executive Directors and senior executives. The objectives and responsibilities of the remuneration committee are
documented in the charter approved by the Board. A copy of the charter is available on the Company’s website.

The Company’s Constitution specifies that the total amount of remuneration of non-executive Directors shall be fixed from time
to time by a general meeting. The current maximum aggregate remuneration of non-executive Directors has been set at
$800,000 per annum. Directors may apportion any amount up to this maximum amount amongst the non-executive Directors
as they determine. Directors are also entitled to be paid reasonable travelling, accommodation and other expenses incurred
in performing their duties as Directors. The fees paid to non-executive Directors are not incentive or performance based but
are fixed amounts that are determined by reference to the nature of the role, responsibility and time commitment required for
the performance of the role, including membership of board committees.

Non-executive Director remuneration is by way of fees and statutory superannuation contributions. Non-executive Directors
do not participate in schemes designed for remuneration of executives and are not provided with retirement benefits other than
salary sacrifice and statutory superannuation.

Executive remuneration policies

Due to the current size and nature of the Company, the Directors do not consider a link between remuneration and financial
performance is appropriate.

The tables below set out summary information about the Company's earnings and movements in shareholder wealth to 30
June 2023:

Financial year

2019

Revenue

•
Loss for the year

•

2020

•

2021

•

2022

- •

2023

$949,333

•
(3,422,786)

(2,205,848)

•

•
($2,368,480)

($7,978,704)

•

($11,261,626)

Financial year

Share price at
beginning of year

Share price at
end of year

Basic loss per
ordinary share

•

Diluted loss per
ordinary share

•

2019

•
N/A *

$0.11 •

2020

$0.11 •

$0.06 •

2021

$0.06 •

$0.07 •

2022

$0.07 •

2023

$0.07

$0.05

•
($0.0157)

•
($0.0079)

•
($0.0044)

•
($0.0117)

($0.0149)

•
($0.0160)

•
($0.0079)

•
($0.0044)

•
($0.0117)

($0.0149)

*The Company’s first trading day on the ASX was 17 September 2018, with a listing price of $0.20.

The remuneration of the Managing Director is determined by the remuneration committee and approved by the Board. The
terms and conditions of his employment are subject to review from time to time.

The remuneration of other executive officers and employees is determined by the Managing Director subject to the review of
the remuneration committee. The Company’s remuneration structure is based on a number of factors including the particular
experience and performance of the individual in meeting key objectives of the Company.

The remuneration structure and packages offered to executives are summarised below:

Fixed remuneration

• Short-term incentive - The Company provides equity grants at the discretion of the Board based on the achievement of
key performance indicators. The Company may grant retention options or performance rights as considered appropriate
as a short-term incentive.

•

Long-term incentive – equity grants, which may be granted annually at the discretion of the Board. From time to time, the
Company may grant retention options or performance rights as considered appropriate as a long-term incentive for key
management personnel.

The intention of this remuneration is to facilitate the retention of key management personnel in order that the goals of the
business and shareholders can be met. Under the terms of the issue of the retention rights, the rights will vest over a period,
dependent upon company and individual performance.

At the Company’s Annual General Meeting, held 22 November 2022, 98.9% of eligible votes were cast in favour of the
remuneration report in the 2022 Annual Report of the Company being adopted.

Remuneration consultants

The Company did not use any remuneration consultants during the year.

Remuneration of Directors and key management personnel

This report details the nature and amount of remuneration for each key management personnel of the Company. The key
management personnel of the Company are the Board of Directors and Company Secretary/Chief Financial Officer.

Directors and key management personnel

The names and positions held by Directors and key management personnel of the Company during the whole of the financial
year are:

Name

Reg Nelson

Neil Gibbins

Nick Smart

Ian Howarth

Simon Gray

Date appointed

10 February 2017

9 November 2015

•

Position

Chairman

Managing Director

Non-Executive Director

Company Secretary and Chief Financial Officer

Remuneration summary Directors and other key management personnel

2023

Salary
& fees (3)

Share based
remuneration

Super-
annuation

Termination
benefits

Total

Share based
percentage
of total

Performance related
percentage

Non-executives

Reg Nelson

71,283

Ian Howarth

47,522

Nick Smart

47,522

Executives

Neil Gibbins

400,008

174,386 (1)

Simon Gray

132,320

100,763 (1)

698,655

275,149

7,485

4,990

27,492

12,043

57,000

78,768

52,512

601,886

245,126

1,030,804

29%

41%

29%

41%

2022

Salary
& fees (3)

Share based
remuneration

Super-
annuation

Termination
benefits

Total

Share based
percentage
of total

Performance
related percentage

Non-executives

Reg Nelson

71,283

Ian Howarth

47,522

Nick Smart

47,522

56,594 (2)

Executives

Neil Gibbins

343,782

120,732 (1)

Simon Gray

105,016

61,756 (1)

615,125

352,270

7,128

4,752

29,940

8,742

55,314

135,005

108,868

494,454

175,514

1,022,709

42%

52%

24%

35%

42%

52%

24%

35%

Notes to the two tables above:
(1) These amounts are calculated in accordance with accounting standards and represent the amortisation of accounting fair values of options or
performance rights that have been granted to key management personnel in this or prior financial years. The fair value of equity instruments have
been measured using a generally accepted valuation model. The fair values are then amortised over the entire vesting period of the equity
instruments. Total remuneration shown in ‘total’ therefore includes a portion of the fair value of unvested equity compensation during the year. The
amount included as remuneration is not related to or indicative of the benefit (if any) that individuals may ultimately realise should these equity
instruments vest and be exercised.

(2) Relates to fair value of options issued.

(3) Executive salaries include leave entitlements.

Service agreements

Remuneration and other terms of employment for Executive Directors and other key management personnel are formalised in
a Service agreement.

Details of agreements for Executive Directors and other key management personnel is set out below:

Mr. Neil Gibbins, Managing Director

Base Salary $434,310 (full time equivalent) inclusive of superannuation. The position is a 0.9 full time equivalent.

If the Board requires Mr. Gibbins to permanently transfer to another location outside of the Adelaide Metropolitan area, Mr.
Gibbins may terminate the Agreement and will be entitled to a sum equivalent of his annual salary. The Company may
terminate the Agreement immediately in several circumstances including serious misconduct or failure to carry out the
employee’s duties under the Agreement.

The Company and Mr. Gibbins may also terminate the Agreement on three months’ written notice.

Mr. Simon Gray, Company Secretary

Base Salary $253,636 (full time equivalent) inclusive of superannuation. The position is a 0.5 full time equivalent.

Share based remuneration

Details of performance rights and options granted over ordinary shares that were granted as remuneration to the Managing
Director and other key management personnel are set out below, on the following terms:

• Class short term incentives – performance rights – continued employment with the Company at 1 July 2023, a gas

contract in place for Odin gas and construction commenced on a connection pipeline.

• Class long term incentives 1 – performance rights – continued employment with Vintage at 30 June 2024 and CO2

production commenced or Nangwarry project monetised prior to 30 June 2024.

• Class long term incentives 2 – performance rights – continued employment with Vintage at 30 June 2024 and the

Company reach a market capitalisation of $100million prior to 30 June 2024.

Employee

Class

Number of
rights granted

Grant Date

$ Value at
Grant date

Number
converted

Number
lapsed

Neil Gibbins

Simon Gray

STI

LT1

LT2

STI

LT1

LT2

STI

1,729,700

30 November 2021

121,944

2,018,000

30 November 2021

113,815

2,018,000

30 November 2021

141,260

1,845,300

25 November 2022

117,562

1,010,200

2 August 2021

1,178,500

2 August 2021

1,178,500

2 August 2021

1,077,700

5 August 2022

45,459

42,426

9,428

69,512

(1,729,700)

(1,010,200)

Performance rights convert to ordinary shares on the completion of the performance conditions.

Performance rights carry no dividends or voting rights and when exercisable each right is converted into one ordinary share.
They are excisable at nil value.

Directors and other key management personnel equity remuneration, holdings and transactions

The number of shares in the Company held during the financial year by each Director and other key management personnel
of the Company, including their personal related parties, are set out below:

Name

Reg Nelson

Neil Gibbins

Ian Howarth

Nick Smart

Simon Gray

Balance
1 July 2022

Rights
Exercised

Options
Exercised

Net Change
Other

Balance
30 June 2023

16,747,637

14,768,193

13,986,340

6,236,821

6,136,728

1,610,350 (i)

1,420,018 (i)

1,344,840 (i)

200,000 (i)

18,357,986

16,188,211

15,331,180

6,436,821

6,336,728

Notes to the table above:

(i)

Shares were acquired during the year as part of the capital raise announced on 31 May 2023.

The number of options held by each Director and other key management personnel of the Company, including their personal
related parties are detailed below.

Name

Reg Nelson

Neil Gibbins

Ian Howarth

Nick Smart

Simon Gray

Opening
balance

2,000,000

Options
granted

Options
lapsed

Balance
30 June 2023

2,000,000

The number of performance rights held during the financial year by each Director and other key management personnel of the
Company, including their personal related parties are detailed below.

Name

Reg Nelson

Neil Gibbins

Ian Howarth

Nick Smart

Simon Gray

Balance
1 July 2022

Rights
lapsed

5,765,700

(1,729,700)

3,367,200

(1,010,200)

Rights
converted

Rights
granted

Balance
30 June 2023

1,845,300

5,881,300

1,077,700

3,434,700

Shares issued on exercise of remuneration options

No shares were issued to Directors or key management as a result of the exercise of options during the financial year.

Employee incentive plan

The shareholders of the Company approved an employee incentive plan for employees at the Annual General Meeting held
on 29 November 2021. Performance rights issued pursuant to the plan to eligible employees other than Directors and key
management personnel as at 30 June 2023 are detailed at Note 17 in the Notes to the Financial Statements.

Transactions with key management personnel

An affiliate of the Managing Director is employed with the Company in a technical exploration position, with remuneration
based on an arm’s length review and at a rate consistent with the position filled. The Managing Director has no role in the
determination of salary or benefits paid to the employee. Other than the above, there were no other transactions with other
key management personnel.

END OF REMUNERATION REPORT

Indemnities given to, and insurance premiums paid for, auditors and officers

Insurance of officers

During the year, Vintage paid a premium to insure officers of the Company. The officers covered by insurance include all
Directors and officers.

The liabilities insured are legal costs that may be incurred in defending civil or criminal proceedings that may be bought against
the officers in their capacity as officers of the Company, and any other payments arising from liabilities incurred by the officers
in connection with such proceedings, other than where such liabilities arise out of conduct involving a willful breach of duty by
the officers or the improper use by the officers of their position or of information to gain advantage for themselves or someone
else to cause detriment to the Company.

Details of the amount of premium paid in respect of insurance policies are not disclosed, as their disclosure is prohibited under
the terms of the contract. The Company has not otherwise, during or since the end of the financial year, except to the extent
permitted by law, indemnified or agreed to indemnify any current or former officer of the Company against a liability incurred
as such by an officer.

Indemnity of auditors

The Company has agreed to indemnify its auditors, Grant Thornton Audit Pty Ltd, to the extent permitted by law, against any
claim by a third party arising from the Company’s breach of its agreement. The indemnity requires the Company to meet the
full amount of any such liabilities including a reasonable amount of legal costs.

Proceedings of behalf of the Company

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

During the year, Grant Thornton Audit Pty Ltd, the Company’s auditors, performed certain other services in addition to their
statutory audit duties.

The Board has considered the non-audit services provided during the year by the auditor and is satisfied that the provision of
those non-audit services during the year is compatible with, and did not compromise, the auditor independence requirements
of the Corporations Act 2001 for the following reasons:

•

all non-audit services were subject to the corporate governance procedures adopted by the Company and have been

reviewed by the Directors to ensure they do not impact upon the impartiality and objectivity of the auditor.

•

the non-audit services do not undermine the general principles relating to auditor independence as set out in APES

110 Code of Ethics for Professional Accountants (including Independence Standards), as they did not involve

reviewing or auditing the auditor’s own work, acting in a management or decision-making capacity for the Company,

acting as an advocate for the Company or jointly sharing risks and rewards.

Details of the amounts paid to the auditors of the Company, Grant Thornton Audit Pty Ltd, and its related practices for audit
and non-audit services provided during the year are set out in Note 24 in the Notes to the Financial Statements.

A copy of the auditor’s independence declaration as required under s.307C of the Corporations Act 2001 is included on the
next page of this financial report and forms part of this Directors’ report.

Signed in accordance with a resolution of the Directors.

Reg Nelson
Chairman

28 September 2023

AUDITOR’S INDEPENDENCE DECLARATION

Grant Thornton Audit Pty Ltd
Grant Thornton House Level 3
170 Frome Street
Adelaide SA 5000
GPO Box 1270
Adelaide SA 5001

T +61 8 8372 6666

To the Directors of Vintage Energy Limited

In accordance with the requirements of section 307C of the Corporations Act 2001, as lead auditor for the audit of
Vintage Energy Limited for the year ended 30 June 2023, 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

J L Humphrey
Partner – Audit & Assurance

Adelaide, 28 September 2023

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.

CORPORATE GOVERNANCE STATEMENT

The Board is committed to achieving and demonstrating the highest standards of corporate governance. As such, the company
has adopted the fourth edition of the Corporate Governance Principles and Recommendations which was released by the ASX
Corporate Governance Council on 27 February 2019 and became effective for financial years beginning on or after 1 January
2020.

The company’s corporate governance statement for the financial year ending 30 June 2023 was approved and dated by the
Board on 28 September 2023. The corporate governance statement is available on Vintage’s website at:
https://www.vintageenergy.com.au/governance-policies.html

STATEMENT OF PROFIT OR LOSS AND OTHER
COMPREHENSIVE INCOME

For year ended 30 June 2023

Notes

Revenue from customers

Interest income

Joint operations recoveries

Other income

Total income

Production costs

Royalty expense

Depreciation expense

Exploration expense

Director remuneration expense

Employee benefits expense

Impairment expense

Financing costs

Other expenses

(Loss) before income tax

Income tax benefit

(Loss) for the year

Other comprehensive income

Total comprehensive (loss) attributable to owners of the

company for the year

Earnings per share

30 June
2023

949,333

124,456

2,794,504

127,217

3,995,510

(1,492,611)

(77,517)

(560,707)

(30,010)

(821,980)

(4,342,473)

(4,635,464)

(1,887,738)

(1,408,636)

(11,261,626)

30 June
2022

1,016

2,193,448

46,897

2,241,361

(241,820)

(9,000)

(847,196)

(3,188,135)

(4,173,827)

(116,461)

(1,643,626)

(7,978,704)

(11,261,626)

(7,978,704)

(11,261,626)

(7,978,704)

Basic (loss) per share from continuing operations (dollars)

Diluted (loss) per share from continuing operations (dollars)

(0.0149)

(0.0117)

(0.0149)

(0.0117)

This statement should be read in conjunction with the notes to the financial statements

STATEMENT OF FINANCIAL POSITION

As at 30 June 2023

Notes

Current Assets

Cash and cash equivalents

Trade and other receivables

Total current assets

Non-Current Assets

Other financial assets

Property, plant and equipment

Exploration and evaluation assets

Total non-current assets

Total Assets

Current Liabilities

Trade and other payables

Provisions

Contract liabilities

Other financial liabilities

Total current liabilities

Non-Current Liabilities

Provisions
Contract liabilities
Other financial liabilities

Total non-current liabilities

Total Liabilities

Net Assets

Equity

Share capital

Reserves

Accumulated (losses)

Total Equity

30 June
2023

30 June
2022

7,507,716

1,078,559

8,586,275

18,711,960

2,440,799

21,152,759

175,306

8,660,457

49,403,928

58,239,691

66,825,966

993,168

908,945

1,210,633

145,236

3,257,982

4,239,426

6,091,707

7,702,431

18,033,564

21,291,546

45,534,420

406,055

49,167,004

49,573,059

70,725,818

3,498,535

681,249

974,000

217,414

5,371,198

1,149,040

6,526,000

7,070,239

14,745,279

20,116,477

50,609,341

68,626,145

3,974,757

63,442,004

3,370,284

(27,066,482)

(16,202,947)

45,534,420

50,609,341

This statement should be read in conjunction with the notes to the financial statements

STATEMENT OF CHANGES IN EQUITY

For the year ended 30 June 2023

Notes

Share
capital

Accumulated
losses

Share
based
payments
reserve
$

Total equity

Balance at 1 July 2021

51,907,858

(8,562,680)

480,705

43,825,883

(Loss) for the year

Other comprehensive income

Total comprehensive (loss) for the year

Total transactions with owners

Issue of ordinary shares at $0.085

Issue of ordinary shares on conversion of rights

Fair value of warrants issued

Fair value of performance rights issued

Fair value of performance rights lapsed

Transaction costs

Balance at 30 June 2022

(7,978,704)

-
-

(43,500)

2,647,059

742,709

338,437

(456,689)

63,442,004

(16,202,947)

3,370,284

16 11,942,489

43,500

118,251

(570,094)

(7,978,704)

11,942,489

2,647,059

742,709

(570,094)

50,609,341

Balance at 1 July 2022

63,442,004

(16,202,947)

3,370,284

50,609,341

(Loss) for the year

Other comprehensive income

Total comprehensive (loss) for the year

(11,261,626)

Total transactions with owners

Issue of ordinary shares at $0.05

Issue of ordinary shares on conversion of rights

Fair value of performance rights and options issued

Fair value of performance rights lapsed

Transaction costs

Balance at 30 June 2023

5,590,052

24,714

(430,625)

398,091

68,626,145

(27,066,482)

3,974,757

-
-

(24,714)

1,027,278

(398,091)

This statement should be read in conjunction with the notes to the financial statements

(11,261,626)

5,590,052

1,027,278

(430,625)

45,534,420

STATEMENT OF CASH FLOWS

For the year ended 30 June 2023

Notes

Cash flows from operating activities

Receipts from customers

Payments to suppliers and employees

Interest received

Financing costs

Other income – recoveries

30 June
2023

658,407

(7,245,985)

124,455

(1,109,042)

78,578

30 June
2022

8,250,000

(4,780,993)

1,016

46,897

Net cash (used in) / from operating activities

(7,493,587)

3,516,920

Cash flows from investing activities

Payments for exploration and evaluation assets

Payments for property, plant and equipment

Cash flows (used in) investing activities

Cash flows from financing activities

Proceeds from issues of shares

Payment for share issue costs

Proceeds from borrowings

Transaction costs related to loans and borrowings

Payment of the principal portion of lease liabilities

Net cash from financing activities

(8,450,755)

(12,806,072)

(216,747)

(25,257)

(8,667,502)

(12,831,329)

5,590,052

(404,249)

(228,958)

4,956,845

11,942,489

(570,094)

10,000,000

(496,519)

(218,543)

20,657,333

Net change in cash and cash equivalents

(11,204,244)

11,342,924

Cash and cash equivalents at the beginning of year

Cash and cash equivalents at end of year

18,711,960

7,507,716

7,369,036

18,711,960

This statement should be read in conjunction with the notes to the financial statements

NOTES TO THE FINANCIAL STATEMENTS

1 Nature of operations

Vintage Energy Limited is an Australian listed public company, incorporated in Australia and operating in Australia. The
principal activities of the Company are disclosed in the Directors’ Report. Vintage’s registered office and its principal place of
business at the date of this report is 58 King William Road, Goodwood SA 5034.

2 General information and statement of compliance

The general-purpose financial statements of the Company have been prepared in accordance with the requirements of the
Corporations Act 2001, Australian Accounting Standards, and other authoritative pronouncements of the Australian Accounting
Standards Board (AASB). Compliance with Australian Accounting Standards results in full compliance with the International
Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). Vintage Energy
Limited is a for-profit entity for the purpose of preparing the financial statements. The financial statements for the year ended
30 June 2023 were approved and authorised for issue by the Board of Directors on 28 September 2023.

3 Changes in accounting policies

3.1 New and revised standards that are effective for these financial statements

There are no new or revised Accounting Standards issued, or issued but not yet effective, which are expected to have a
material impact on the financial statements.

4 Summary of accounting policies

4.1 Overall considerations

The financial statements have been prepared using the significant accounting policies and measurement bases summarised
below.

4.2

Basis of preparation

The financial statements have been prepared on the basis of historical cost except, where applicable, for the revaluation of
certain non-current assets and financial instruments. All amounts are presented in Australian dollars, unless otherwise noted.

The following significant accounting policies have been adopted in the preparation and presentation of the financial report.

4.3 Cash and cash equivalents

Cash and cash equivalents include cash on hand, deposits held at call with financial institutions and 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 on value.

Income taxes

4.4
Tax expense recognised in profit or loss comprises the sum of deferred tax and current tax not recognised in other
comprehensive income or directly in equity.

Current income tax assets and/or liabilities comprise those obligations to, or claims from, the Australian Taxation Office (ATO)
and other fiscal authorities relating to the current or prior reporting periods that are unpaid at the reporting date. Current tax
is payable on taxable profit, which differs from profit or loss in the financial statements. Calculation of current tax is based on
tax rates and tax laws that have been enacted or substantively enacted by the end of the reporting period.

Deferred income taxes are calculated using the liability method on temporary differences between the carrying amounts of
assets and liabilities and their tax bases. However, deferred tax is not provided on the initial recognition of goodwill or on the
initial recognition of an asset or liability unless the related transaction is a business combination or affects tax or accounting
profit. Deferred tax on temporary differences associated with investments in subsidiaries and joint ventures is not provided if
reversal of these temporary differences can be controlled by the Company and it is probable that reversal will not occur in the
foreseeable future.

Deferred tax assets and liabilities are calculated, without discounting, at tax rates that are expected to apply to their respective
period of realisation, provided they are enacted or substantively enacted by the end of the reporting period.

Deferred tax assets are recognised to the extent that it is probable that they will be able to be utilised against future taxable
income, based on the Company’s forecast of future operating results which is adjusted for significant non-taxable income and
expenses and specific limits to the use of any unused tax loss or credit. Deferred tax liabilities are always provided for in full.

Deferred tax assets and liabilities are offset only when the Company has a right and intention to set off current tax assets and
liabilities from the same taxation authority.

Changes in deferred tax assets or liabilities are recognised as a component of tax income or expense in profit or loss, except
where they relate to items that are recognised in other comprehensive income (such as the revaluation of land) or directly in
equity, in which case the related deferred tax is also recognised in other comprehensive income or equity, respectively.

4.5

Provisions

Provisions are recognised when the Company has a present obligation as a result of a past event, the future sacrifice of
economic benefits is probable, and the amount of the provision can be measured reliably.

The amount recognised as a provision is the best estimate of the consideration required to settle the present obligation at
reporting date, taking into account the risks and uncertainties surrounding the obligation. Where a provision is measured using
the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows. When
some or all of the economic benefits required to settle a provision are expected to be recovered from a third party, the
receivable is recognised as an asset if it is virtually certain that recovery will be received and the amount of the receivable can
be measured reliably.

4.6

Estimate of restoration costs

The Company estimates the future removal costs of wells and pipelines at different stages of the development and construction
of assets or facilities. In most instances, removal of assets occurs many years into the future. This requires judgemental
assumptions regarding removal date, future environmental legislation, the extent of reclamation activities required, the
engineering methodology for estimating cost, future removal technologies in determining the removal cost, and liability specific
discount rates to determine the present value of these cash flows. The provision amount represents the Company’s current
best estimate of its restoration obligations to be performed in the future based on current industry practice and expectations.
However, this will be dependent on approval by regulatory authorities prior to restoration activities being undertaken and may
be subject to change.

4.7

Employee benefits

Provision is made for the Company’s liability for employee benefits arising from services rendered by employees to reporting
date. Employee benefits that are expected to be settled within one year have been measured at the amounts expected to be
paid when the liability is settled, plus related on-costs.

Employee benefits payable later than one year have been measured at the present value of the estimated future cash outflows
to be made for those benefits. Those cash flows are discounted using high quality corporate bonds with terms to maturity that
match the expected timing of cash flows.

4.8

Trade and other payables

These amounts represent liabilities for goods and services provided to the Company prior to the end of the financial year which
are unpaid. The amounts are unsecured and are usually paid according to term.

4.9

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.

Assets and liabilities measured at fair value are classified, into three levels, using a fair value hierarchy that reflects the
significance of the inputs used in making the measurements. Classifications are reviewed at each reporting date and transfers
between levels are determined based on a reassessment of the lowest level of input that is significant to the fair value
measurement, which are described as follows:

•

Level 1 – inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the entity can
access at the measurement date;
Level 2 – inputs are inputs, other than quoted prices included in Level 1, that are observable for the asset or liability,
either directly or indirectly; and
Level 3 – inputs are unobservable inputs for the asset or liability

For recurring and non-recurring fair value measurements, external valuers may be used when internal expertise is either not
available or when the valuation is deemed to be significant. External valuers are selected based on market knowledge and
reputation. Where there is a significant change in fair value of an asset or liability from one period to another, an analysis is
undertaken, which includes a verification of the major inputs applied in the last valuation and a comparison, where applicable,
with external sources of data.

4.10 Goods and Services Tax (GST)

Revenues, expenses and assets are recognised net of the amount of GST, except where the amount of GST incurred is not
recoverable from the local taxation office. In these circumstances, the GST is recognised as part of the cost of acquisition of
the asset or as part of an item of the expense. Receivables and payables in the statement of financial position are shown
inclusive of GST. Cash flows are presented in the statement of cash flows on a gross basis, except for the GST component of
investing and financing activities, which are disclosed as operating cash flows.

4.11 Property, plant and equipment

Plant and equipment are stated at cost less accumulated depreciation and impairment. Cost includes expenditure that is
directly attributable to the acquisition of the item. Subsequent costs are included in the asset’s carrying amount or recognised
as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow
to the Company and the cost of the item can be measured reliably. All other repairs and maintenance are charged to the
statement of profit or loss and other comprehensive income during the financial period in which they are incurred.

All tangible assets have limited useful lives and are depreciated using the straight-line value method over their estimated useful
lives, considering estimated residual values, to write off the cost to its estimated residual value, as follows:

– Furniture and fittings: 20%

– Plant and equipment: 33%

– Field pipelines: 5%

– Field facilities: 10%

Leasehold improvements are depreciated over the period of the lease or estimated useful life, whichever is the shorter, using
the straight-line method.

The estimated useful lives, residual values and depreciation method are reviewed at the end of each annual reporting period
and adjusted if appropriate.

4.12

Impairment of assets

At each reporting date the Company reviews the carrying amounts of its assets to determine whether there is any indication
that those assets have suffered an impairment loss. If any such indication exists, the recoverable amount of the asset is
estimated to determine the extent of the impairment loss (if any). Where the asset does not generate cash flows that are
independent from other assets, the Company estimates the recoverable amount of the cash-generating unit to which the asset
belongs. Where a reasonable and consistent basis of allocation can be identified, corporate assets are also allocated to
individual cash-generating units or otherwise they are allocated to the smallest group of cash-generating units for which a
reasonable and consistent allocation basis can be identified.

4.13 Exploration and evaluation costs

Exploration and evaluation expenditure includes costs incurred in the search for hydrocarbon resources and determining its
commercial viability in each identifiable area of interest. Exploration and evaluation expenditure is accounted for in accordance
with the successful efforts method and is capitalised to the extent that:

ii.

the rights to tenure of the areas of interest are current and the Company controls the area of interest in which the
expenditure has been incurred; and
such costs are expected to be recouped through successful development and exploration of the area of interest, or
alternatively by its sale; or

iii. 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. An area of interest
refers to an individual geological area where the potential presence of an oil or a natural gas field is
considered favourable or has been proven to exist, and in most cases, will comprise an individual
prospective oil or gas field.

Exploration and evaluation expenditure which does not satisfy these criteria is written off.

Specifically, costs carried forward in respect of an area of interest that is abandoned or costs relating directly to the drilling of
an unsuccessful well are written off in the year in which the decision to abandon is made or the results of drilling are concluded.
The success or otherwise of a well is determined by reference to the drilling objectives for that well. For successful wells, the
well costs remain capitalised on the Statement of Financial Position if sufficient progress in assessing the reserves and the
economic and operating viability of the project is being made. A regular review is undertaken of each area of interest to
determine the appropriateness of continuing to carry forward costs in relation to that area of interest. Where an ownership
interest in an exploration and evaluation asset is exchanged for another, the transaction is recognised by reference to the
carrying value of the original interest. Any cash consideration paid, including transaction costs, is accounted for as an
acquisition of exploration and evaluation assets. Any cash consideration received, net of transaction costs, is treated as a
recoupment of costs previously capitalised with any excess accounted for as a gain on disposal of non-current assets. Where
a discovered oil or gas field enters the development phase the accumulated exploration and evaluation expenditure is
transferred to oil and gas assets.

4.14

Interest in 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 liabilities, relating to the arrangement.

Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the
relevant activities require the unanimous consent of the parties sharing control.

Under certain agreements, more than one combination of participants can make decisions about the relevant activities and
therefore joint control does not exist. Where the arrangement has the same legal form as a joint operation but is not subject to
joint control, the Company accounts for its interest in accordance with the contractual agreement by recognising its share of
jointly held assets, liabilities, revenues and expenses of the arrangement.

When the Company undertakes its activities under joint operations, the Company as a joint operator recognises in relation to
its interest in a joint operation:

•
•
•
•
•
•

Its assets, including its share of any assets jointly held;
Its liabilities, including its share of any liabilities incurred jointly;
Its revenue from the sale of its share of the output arising from the joint operation;
Its revenue from salary recoveries and overhead charges;
Its share of the revenue from the sale of the output by the joint operation; and
Its expenses, including its share of any expenses incurred jointly.

The Company accounts for its assets, liabilities, revenues and expenses relating to its interest in a joint operation in accordance
with the AASBs applicable to the particular assets, liabilities, revenues and expenses.

4.15 Financial instruments

Recognition, initial measurement and derecognition

Financial instruments, incorporating financial assets and financial liabilities, are recognised when the entity becomes a party
to the contractual provisions of the instrument. Trade date accounting is adopted for financial assets that are delivered within
timeframes established by marketplace convention.

Financial instruments are initially measured at fair value plus transactions costs where the instrument is not classified as at
fair value through profit or loss. Transaction costs related to instruments classified as at fair value through profit or loss are
expensed to profit or loss immediately.

Financial assets are derecognised when the contractual rights to the cash flows from the financial asset expire, or when the
financial asset and all substantial risks and rewards are transferred. A financial liability is derecognised when it is extinguished,
discharged, cancelled, or expires. Financial instruments are classified and measured as set out below.

Effective interest rate method

The effective interest method is a method of calculating the amortised cost of a financial asset or a financial liability (or group
of financial assets or financial liabilities) and of allocating the interest income or interest expense over the relevant period. The
effective interest rate is the rate that exactly discounts estimated future cash payments or receipts through the expected life of
the financial instrument or, when appropriate, a shorter period to the net carrying amount of the financial asset or financial
liability.

Income is recognised on an effective interest rate basis for debt instruments other than those financial assets ‘at fair value
through profit or loss’.

Classification and subsequent measurement

Trade and other receivables

Trade and other receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an
active market and are stated at amortised cost using the effective interest rate method, less provision for impairment.
Discounting is omitted where the effect of discounting is immaterial. The entity’s cash and cash equivalents, trade and most
other receivables fall into this category of financial instruments.

Financial liabilities

The entity’s financial liabilities include trade and other payables. Non-derivative financial liabilities are subsequently measured
at amortised cost using the effective interest rate method.

Fair value

Fair value is determined based on current bid prices for all quoted investments. Valuation techniques are applied to determine
the fair value for all unlisted securities, including recent arm’s length transactions, reference to similar instruments and option
pricing models.

4.16

Impairment of financial assets

Financial assets are assessed for indicators of impairment at each reporting date. Financial assets are impaired where there
is objective evidence that as a result of one or more events that occurred after the initial recognition of the financial asset the
estimated future cash flows of the investment have been impacted.

For financial assets carried at amortised cost, the amount of the impairment is the difference between the asset’s carrying
amount and the present value of estimated future cash flows, discounted at the original effective interest rate.

The carrying amount of financial assets including uncollectible trade receivables is reduced by the impairment loss using an
allowance account. Subsequent recoveries of amounts previously written off are credited against the allowance account.
Changes in the carrying amount of the allowance account are recognised in profit.

4.17 Government grants

The Company’s projects at times may be supported by grants received from the federal, state and local governments.
Government grants received in relation to drilling of exploration wells are initially deferred as a liability until the grant is spent.
Once spent, it is then recognised as a reduction in the carrying value of exploration and evaluation asset, or income if the
expenditure relating to the grant is expensed. The refundable research and development tax incentive is accounted for as a
government grant.

Government grants are assistance by government in the form of transfers of resources to the Company in return for past or
future compliance with certain conditions relating to the operating activities of the Company. Government grants are not
recognised until there is reasonable assurance that the Company will comply with the conditions attached to them and the
grant will be received.

4.18 Share-based payments

All goods and services received in exchange for the grant of any share-based payment are measured at their fair values.
Where employees are rewarded using share-based payments, the fair values of employees’ services are determined indirectly
by reference to the fair value of the equity instruments granted. This fair value is appraised at the grant date and excludes the
impact of non-market vesting conditions (for example profitability and sales growth targets and performance conditions).

All share-based remuneration is ultimately recognised as an expense in profit or loss with a corresponding credit to share
option reserve. If vesting periods or other vesting conditions apply, the expense is allocated over the vesting period, based on
the best available estimate of the number of share options expected to vest.

Non-market vesting conditions are included in assumptions about the number of options or rights that are expected to become
exercisable. Estimates are subsequently revised if there is any indication that the number of share options or rights expected
to vest differs from previous estimates. Any cumulative adjustment prior to vesting is recognised in the current period. No
adjustment is made to any expense recognised in prior periods if share options or rights ultimately exercised are different to
that estimated on vesting.

Upon exercise of share options, the proceeds received net of any directly attributable transaction costs are allocated to share
capital.

4.19 Leases

At inception of a contract, the Company assesses whether a lease exists – that is, does the contract convey the right to control
the use of an identified asset for a period of time in exchange for consideration.

This involves an assessment of whether:

•

The contract involves the use of an identified asset – this may be explicitly or implicitly identified within the
agreement. If the supplier has a substantive substitution right, then there is no identified asset.

The Company has the right to obtain substantially all of the economic benefits from the use of the asset throughout
the period of use.

The Company has the right to direct the use of the asset, that is, decision-making rights in relation to changing how
and for what purpose the asset is used.

At the lease commencement, the Company recognises a right-of-use asset and associated lease liability for the lease term.
The lease term includes extension periods where the Company believes it is reasonably certain that the option will be
exercised.

The right-of-use asset is measured using the cost model where cost on initial recognition comprises of the lease liability, initial
direct costs, prepaid lease payments, estimated cost of removal and restoration less any lease incentives received. The
right-of-use asset is depreciated over the lease term on a straight-line basis and assessed for impairment in accordance with
the impairment of assets accounting policy.

The lease liability is initially measured at the present value of the remaining lease payments at the commencement of the
lease. The discount rate is the rate implicit in the lease. However, where this cannot be readily determined then the Company’s
incremental borrowing rate is used.

After initial recognition, the lease liability is measured at amortised cost using the effective interest rate method. The lease
liability is remeasured whether there is a lease modification, change in estimate of the lease term or index upon which the
lease payments are based (for example, CPI) or a change in the Company’s assessment of lease term.

Where the lease liability is remeasured, the right-of-use asset is adjusted to reflect the remeasurement or is recorded in profit
or loss if the carrying amount of the right-of-use asset has been reduced to zero.

4.20 Revenue recognition

Applying Accounting Standard AASB 15 Revenue from Contracts with Customers, revenue from contracts with customers is
recognised in the income statement when or as the Company transfers control of goods or services to a customer at the
amount to which the Company expects to be entitled. If the consideration promised includes a variable amount, the Company
estimates the amount of consideration to which it will be entitled.

Revenue from the sale of hydrocarbons

Revenue from the sale of hydrocarbons is recognised based on volumes sold under contracts with customers, at the point in
time where performance obligations are considered met. Generally, regarding the sale of hydrocarbon products, the
performance obligation will be met when the product is delivered to the specified measurement point (gas) or point of
loading/unloading (liquids).

Contract Liabilities

A contract liability is recorded for obligations under sales contracts to deliver natural gas in future periods for which payment
has already been received. The Company applies the practical expedient in paragraph 121 of AASB 15 Revenue from
Contracts with Customers and does not disclose information on the transaction price allocated to performance obligations that
are unsatisfied.

4.21 Going concern

The financial statements are prepared on the going concern basis which assumes continuity of normal business activities and
the realisation of assets and settlement of liabilities and commitments in the normal course of business.

During the year ended 30 June 2023 the company recognised a loss of $11,261,626, had net cash outflows from operating
and investing activities of $16,161,089 and had accumulated losses of $27,066,482 as at 30 June 2023. The continuation of
the Company as a going concern is dependent upon its ability to generate sufficient net cash inflows from operating and
financing activities and manage the level of exploration and other expenditure within available cash resources. The Directors
consider that the going concern basis of accounting is appropriate, as the company has the following options:

• The ability to issue share capital under the Corporations Act 2001, by a share purchase plan, share placement or rights

issue;

• The option of farming out all or part of its assets;

• The option of selling interests in the Company’s assets; and

• The option of relinquishing or disposing of rights and interests in certain assets.

In the event that the Company is unsuccessful in implementing one or more of the funding options listed above, such
circumstances would indicate that a material uncertainty exists that may cast significant doubt as to whether the Company will
continue as a going concern and therefore whether it will realise its assets and discharge its liabilities in the normal course of
business and at the amounts stated in the financial report.

This financial report does not include any adjustments relating to the recoverability and classification of recorded asset amounts
or to the amounts and classification of liabilities that might be necessary should the Company not continue as a going concern.

4.22 Comparative figures

When required by Accounting Standards, comparative figures have been adjusted to conform to changes in presentation for
the current financial year.

4.23 Critical accounting estimates and judgements

The Directors evaluate estimates and judgements incorporated into the financial statements based on historical knowledge
and best available current information. Estimates assume a reasonable expectation of future events and are based on current
trends and economic data, obtained both externally and within the Company. Actual results may differ from these estimates.

The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are
recognised in the period in which the estimate is revised if the revision affects only that period or in the period of the revision
and future periods if the revision affects both current and future periods.

Critical judgements in applying the Company’s accounting policies

The following critical judgement, including estimations, that management has made in the process of applying the Company’s
accounting policies and that had the most significant effect on the amounts recognised in the financial statements.

Capitalised exploration and evaluation

The Company has capitalised significant exploration and evaluation expenditure on the basis either that this is expected to be
recouped through future successful development or alternatively sale of the areas of interest. If, ultimately, the areas of interest
are abandoned or are not successfully commercialised, the carrying value of the capitalised exploration and evaluation
expenditure would need to be written down to its recoverable amount.

Restoration costs

The Company has recognised restoration costs based on current estimates of the liability. This estimate requires judgemental
assumptions regarding removal date, future environmental legislation, the extent of reclamation activities required, the
engineering methodology for estimating cost, future removal technologies in determining the removal cost, and liability specific
discount rates to determine the present value of these cash flows.

Useful life of infrastructure

The company has estimated the useful life of the Vali and Odin infrastructure based on manufacturers’ advice on the
operational life of the individual components. The useful lives may change due to changes in operational conditions,
occupational health and safety changes and obsolescence.

Impairment of exploration and evaluation assets

The future recoverability of capitalised exploration and evaluation expenditure is dependent on a number of factors, including
whether the Company decides to exploit the related lease itself or, if not, whether it successfully recovers the related
exploration and evaluation asset through sale. Management is required to make certain estimates and assumptions in applying
this policy. Factors which could impact the future recoverability include the level of gas and oil resources, future technological
changes which could impact the cost of extraction, future legal changes (including changes to environmental restoration
obligations) and changes to commodity prices. These estimates and assumptions may change as new information becomes
available. To the extent that capitalised exploration and evaluation expenditure is determined not to be recoverable in the
future, this will reduce profits and net assets in the period in which this determination is made. In addition, exploration and
evaluation expenditure is capitalised if activities in the area of interest have not yet reached a stage which permits a reasonable
assessment of the existence or otherwise of economically recoverable gas and oil reserves or resources. To the extent that it
is determined in the future that this capitalised expenditure should be written off, this will reduce profits and net assets in the
period in which this determination is made.

4.24 Operating segments

The Directors have considered the requirements of AASB 8 Operating Segments and the internal reports that are reviewed by
the chief operating decision maker (the Board) in allocating resources and have concluded at this time there are no separately
identifiable segments.

Loss for the year

Loss for the year from continuing operations includes the following expenses:

Director remuneration expense

Director salary and fees

Director post-employment benefits

Share based payments

Employees benefit expense

30 June
2023

(566,334)

(44,957)

(210,689)

(821,980)

30 June
2022

(510,109)

(46,572)

(290,515)

(847,196)

Short-term employee benefits – salaries and fees

(2,687,513)

(1,937,763)

Post-employment benefits

Increase in employee benefit provisions
Recharge of salaries and fees to exploration expenditure
Share based payments

Other staff costs

Financing expenses

Amortisation of borrowing costs

Interest expense – debt facility

Other expenses

Accounting and audit

Conferences

Consulting expenses

Computer expenses

Insurances

Marketing

Travel and accommodation

Legal fees

Share registry and exchange costs

Subscriptions and technical publications

Sundry

(285,233)

(295,582)

84,952

(816,588)

(342,509)

(198,215)

(495,256)

103,399

(452,195)

(208,105)

(4,342,473)

(3,188,135)

(787,738)

(1,100,000)

(1,887,738)

(107,524)

(33,300)

(154,203)

(364,078)

(140,400)

(170,000)

(29,482)

(100,703)

(94,195)

(62,527)

(152,224)

(65,228)

(51,233)

(116,461)

(60,088)

(28,185)

(556,896)

(257,089)

(144,056)

(213,900)

(26,271)

(60,433)

(102,095)

(56,499)

(138,114)

(1,408,636)

(1,643,626)

Income taxes

The prima facie income tax expense on pre-tax accounting profit from operations reconciles to the income tax
expense in the financial statements as follows:

Loss from operations
Income tax expense / (benefit) calculated at 25% (2022: 25%)
Non-deductible expenses

Unused tax losses and tax offsets not recognised as deferred tax assets

Tax expense/(benefit)

Tax expense/(benefit) comprises

Current tax expense

Tax losses not brought to account (1)

Deferred tax liability not brought to account (2)

Tax expense (benefit)

30 June
2023

(11,261,626)

(2,815,407)

425,372

2,390,035

30 June
2022

(7,978,704)

(1,994,676)

201,467

1,793,209

(2,390,035)

4,022,799

(1,632,764)

(1,793,209)

4,862,684

(3,069,475)

(1) Total tax losses not brought to account at 30 June 2023 total $18,656,903 at 25% tax rate applicable, subject to

relevant carry-forward tax loss recoupment rules being met.

(2) Deferred tax liabilities relate primarily to capitalised exploration assets and property, plant & equipment.

For the Company’s policy on the accounting treatment of income taxes, refer to Note 4.4.

7 Cash and cash equivalents

Cash and cash equivalents consist of the following:

Cash on hand

Cash at bank (1)

Restricted cash (2)

30 June
2023

7,055,408

452,299

7,507,716

30 June
2022

18,254,946

457,005

18,711,960

(1) Includes amounts pledged as security for bank guarantees and credit facilities amounting

to $137,865 (2022 $137,865)

(2) Held by the ATP 2021 Joint Venture and the PRL 211 Joint Venture, which can only be utilised for their

respective expenditure programs.

Trade and other receivables

Trade receivables

Joint operations receivables

GST receivables

Other receivables

30 June
2023
$

153,412

663,033

43,172

218,942

1,078,559

30 June
2022
$

2,360,103

80,696

2,440,799

9 Other financial assets

Financial surety payments (i)

(i)

Financial surety payments made by the ATP 2021 Joint Venture and
PRL 211 Joint Venture, which relate to rehabilitation obligations
arising from their respective expenditure programs.

10 Property, plant and equipment

30 June
2023
$

175,306

30 June
2022
$

Assets at cost

Balance at 30 June 2021

Additions

Balance at 30 June 2022

Additions
Reclassified (i)

Balance at 30 June 2023

Accumulated depreciation

Balance at 30 June 2021

Depreciation expense

Balance at 30 June 2022

Depreciation expense

Balance at 30 June 2023

Field plant &
equipment
$

Furniture and
fittings
$

Right of use asset

Total

8,598,361

291,358

235,394

25,257

260,651

216,748

477,399

183,890

31,048

214,938

53,144

268,082

460,807

196,614

657,421

86,307

210,772

297,079

216,205

513,284

696,201

221,871

918,072

216,748

8,598,361

9,733,181

270,197

241,820

512,017

560,707

1,072,724

Net book value 30 June 2022

45,713

360,342

406,055

Net book value 30 June 2023

8,307,003

209,317

144,137

8,660,457

(i)

Reclassified from Exploration and Evaluation Assets

11 Exploration and evaluation assets

Exploration and evaluation

Exploration and evaluation – ATP 2021 capital work in progress

Balance at 1 July
Additions for the year (i)
Transfer to Property, Plant & Equipment (ii)
Impairment (iii)

Balance at 30 June

30 June
2023

30 June
2022

49,403,928

45,896,322

3,270,682

49,403,928

49,167,004

30 June
2023

49,167,004

13,470,749

(8,598,361)

(4,635,464)

30 June
2022

37,161,165

16,179,666

(4,173,827)

49,403,928

49,167,004

(i)

The increase in exploration and evaluation assets during the year included expenditure on:

Opening
balance
$

22,706,713

12,330,134

8,208,056

3,109,764

2,549,105

201,290

61,942

Additions
$

Reclassifi-

cation
$

Impairment
$

Closing
balance
$

10,558,788

(8,598,361) (ii)

24,667,140

206,569

286,824

1,603,058

371,769

372,006

71,735

(4,635,464) (iii)

7,901,239

8,494,880

4,712,822

2,920,874

573,296

133,677

49,167,004

13,470,749

(8,598,361)

(4,635,464)

49,403,928

ATP 2021 Joint Venture

Galilee Deeps Joint Venture *

PRL 249 Joint Venture*

PRL 211 Joint Venture

EP 126, Bonaparte Basin

PEP 171 Joint Venture

GSEL 672

Total

*non-operated permit

(ii)

(iii)

Capital work-in-progress was transferred to property, plant and equipment during the year, upon completion of ATP 2021
joint venture field facility/pipeline works.

Albany-2 well costs were impaired at 30 June 2023, as no economic hydrocarbons were produced during the flowback period
of the well and, after consideration during the year, it was determined there was a low likelihood of economic recovery of gas
from the well.

12 Trade and other payables

Trade and other payables consist of the following:

Current

Trade payables

GST payable

Other payables

Total trade & other payables

13 Provisions

Current
Employee Benefits

Non-current

Employee benefits

Restoration provision

Movement in employee benefits

Opening balance

Movement for the year

Closing balance

Movement in restoration provision

Opening balance

Movement for the year

Closing balance

30 June
2023
$

752,082

241,086

993,168

30 June
2022
$

2,842,945

438,028

217,562

3,498,535

30 June
2023
$

908,945

246,926

3,992,500

4,239,426

860,289

295,582

1,155,871

970,000

3,022,500

3,992,500

30 June
2022
$

681,249

179,040

970,000

1,149,040

365,033

495,256

860,289

925,000

45,000

970,000

14 Contract liabilities

Deferred revenues

Current
Non-current

Total

30 June
2023
$

1,210,633
6,091,707

7,302,340

30 June
2022
$

974,000
6,526,000

7,500,000

In the prior year, the ATP 2021 Joint Venture secured a Gas Sales Agreement with AGL Wholesale Gas Limited
which, upon satisfaction of certain conditions, resulted in the prepayment of $15,000,000 as partial payment for the
supply of gas (Vintage 50%) over calendar years 2022-2026.

Deferred revenue from contracts with customers represents gas pre-sold to customers which is yet to be delivered.
Amounts are recognised as contract liabilities when no cash settlement option exists for the customer.

15 Other financial liabilities

Current
Lease liability (i)

Non-current
Lease liability (i)
Loan facility – PURE Asset Management (ii)

(i)

Movement in lease liability

Opening balance

Lease liability recognised

Rent payments made during the year

Interest expense on lease liability recognised during the year

30 June
2023
$
145,236

145,236

7,702,431

366,002

(228,958)

8,192

145,236

30 June
2022
$
217,414

217,414

148,588

6,921,651

7,070,239

380,344

196,614

(218,543)

7,587

366,002

(ii)

Loan facility reconciliation

Financing facility (PURE Asset Management)

10,000,000

Net of transaction costs:

Fair value of warrants issued

Amortisation of warrants

Carrying amount of other financing facility establishment costs

(2,647,059)

716,912

(367,422)

7,702,431

55,148

(486,438)

6,921,651

On 8 June 2022, the Company drew down on the two $5 million debt facility tranches arranged with PURE Resources
Fund (“PURE”), as announced to the market on 6 December 2021. The facility was used to fund capital expenditure to
bring the Vali gas field to production.

Key terms of the facility are:

• Repayment due 48 months from first draw down.

•

Interest rate: 11.0% per annum payable every 3 months, reducing to 8.5% per annum once certain
operational cash flow conditions are met.

• Security: first ranking security over Vintage assets, where joint venture arrangements permit.

•

Financial covenants: include requiring a minimum of $1,500,000 cash in the bank.

• Early repayment provisions which use a sliding scale penalty of 1.5% to 1.0% of the funds.

•

58,823,529 share warrants were issued to PURE with an exercise price of 17 cents per warrant, as
approved by shareholders at the general meeting held 18 March 2022. The warrants are exercisable at
any time over the 4-year facility term and may be used to repay the debt or for other purposes.

Transaction costs are those costs directly related to the loan and include establishment fees, legal fees and warrants.
The fair value of the warrants issued was determined using the Black-Scholes valuation methodology.

16 Issued capital

Ordinary shares

Balance at 30 June

Shares issued and fully paid
Ordinary Shares (i)

Beginning of the year

30 June
2023

30 June
2022

68,626,145

63,442,004

68,626,145

63,442,004

30 June
2023
Number

30 June
2023
$

30 June
2022
Number

30 June
2022
$

Shares allotted during the period

111,801,044

5,590,052

140,499,869

746,168,216

63,442,004

605,305,847

Conversion of performance rights

Fair value of lapsed broker options

Share issue costs

Total ordinary shares

549,200

24,714

(430,625)

362,500

858,518,460

68,626,145

746,168,216

63,442,004

51,907,858

11,942,489

43,500

118,251

(570,094)

Total contributed equity at 30 June

858,518,460

68,626,145

746,168,216

63,442,004

(1)

Ordinary Shares

Subject to the Constitution and to the terms of issue of shares, all shares attract the following rights:

•

the right to receive notice of and to attend and vote at all general meetings of the Company;

the right to receive dividends; and

in a winding up or a reduction of capital, the right to participate equally in the distribution of the assets of the Company
(both capital and surplus), subject to any amounts unpaid on the share and, in the case of a reduction, to the terms of
the reduction.

The following shares were issued during the period:

•

59,256,812 ordinary shares via a capital placement at $0.05 per share

52,544,232 ordinary shares via an accelerated offer at $0.05 per share

549,200 ordinary shares on the conversion of performance rights

17 Share options and performance rights

Share options

In the prior year, 6,000,000 share options were issued to Directors with an exercise price of $0.133 per option, and an
expiration date of 3 years from issue (29 November 2024). The options were approved at the Company AGM held 29
November 2021. The fair value of the options granted were $169,783, calculated using the Black-Scholes methodology.

A summary of unissued shares held under option during the year is as follows:

Date options granted

Holder

Opening
balance

Granted
during the
year

Exercise
price

Lapsed

Closing
balance

29 November 2021

Total under option

Non-Executive
Directors

6,000,000

$0.133

6,000,000

Shares issued on exercise of remuneration performance rights
A total of 549,200 shares were issued to management on exercise of performance rights, following the meeting of
performance conditions. A further 8,995,400 performance rights lapsed during the year, after performance conditions
were not met.

Employee incentive plan
The shareholders of the Company approved an employee incentive plan for employees at the Annual General Meeting
held on the 29 November 2021.

The purpose of the employee incentive plan is to provide an incentive for eligible participants to participate in the future
growth of the Company and to offer options or performance rights to assist with the reward, retention, motivation and
recruitment of eligible participants.

Eligible participants are any full or part-time employee of the Company or a subsidiary, relevant contractors and casual
employees and prospective parties in these capacities. Non-executive Directors (and their associates) are not eligible
to participate in the employee incentive plan.

Subject to any necessary shareholder approval, the Board may offer options or performance rights to eligible
participants for nil consideration.

The following performance rights have been issued pursuant to the scheme to eligible employees:

Performance
Right

Grant
date

Opening
Balance

Granted
during the
year

Exercised on
performance
condition met

Lapsed

Closing
Balance

Fair value
at grant
date
$

Class STI

Class LT1

Class LT2

Class STI

Aug/Nov
2021

Aug/Nov

2022

9,544,600

7,878,300

11,377,604

(549,200)

(8,995,400)

473,614

7,878,300

324,786

7,878,300

188,142

11,377,604

732,370

The Class STI rights have been valued using the Black-Scholes methodology at the grant date.

(i)

Refer table below for rights issued to the Managing Director

Performance rights issued under the employee incentive plan have been issued under the following general
performance conditions:

Class STI performance rights – 10,630,600 rights – being employed by the Company at 1 July 2023, a gas contract
in place for Odin gas and construction commenced on a connection pipeline; 449,200 rights – being employed by the
Company at 2 August 2023; and 297,804 rights – being employed by the Company at 17 October 2023 and
acceptable individual performance up to 17 October 2023.

Class LT1 performance rights – being employed by Vintage at end of FY24 and CO2 production commenced, or
Nangwarry project monetised prior to end FY24.

Class LT2 performance rights – being employed by Vintage at end of FY24 and market cap of $100million reached
prior to end FY24.

Included within the table above, the following share-based performance rights were issued to Mr. Neil Gibbins,
Managing Director, pursuant to resolutions passed at the Company’s AGM on 22 November 2022:

Class of Performance Right

Maximum number of performance rights

Class ST1

1,845,300

18 Interest in joint operations

The Company has an interest in the following unincorporated joint operations whose principal activities are
oil and gas exploration:

Galilee Basin ATP-743, ATP-744 (i)

Galilee Basin ATP-1015 (i)

Galilee Basin PCAs 319-324 (i)

Otway Basin PRL 249 (ex PEL 155) (ii)

Otway Basin PEP 171

ATP 2021

PRL 211

PELA 679 (iii)

30 June
2023

% Interest

30 June
2022

% Interest

“Deeps’’ JV contractual agreement with Comet Ridge Ltd. This is defined as all strata commencing underneath the Permian coals
and without a lower limit. Potential Commercial Areas 319-324 have been granted over the most prospective areas of these ATPs
to secure tenure and ATPs 733 & 734 under the PCAs have been renewed for twelve years, while ATP 1015 under the PCAs is
also due to be renewed for twelve years.

ii. Petroleum Retention Licence (PRL) 249, covering the Nangwarry CO2 discovery area.

iii. Vintage was successful in bidding for Block CO2019-E (PELA 679) (“Block E”) in the south-west of the Cooper Basin in South
Australia. Once an appropriate land access agreement is in place with the Dieri Aboriginal Corporation RNTBC and the South
Australian government, Vintage will have a 100% interest in the permit with options to finance the firm work program through potential
introduction of a joint venture partner/s.

19 Earnings per share

Both the basic and diluted earnings per share have been calculated using the profit attributable to shareholders of the
Company as the numerator. The reconciliation of the weighted average number of shares for the purposes of diluted
earnings per share to the weighted average number of ordinary shares used in the calculation of basic earnings per
share is as follows:

Weighted average number of shares used in basic earnings per share

Weighted average number of shares used in dilutive earnings per share

Potential ordinary shares are antidilutive when their conversion to ordinary
shares would increase earnings per share or loss per share. As such, there
are no dilutive securities on issue.

30 June
2023
Number

30 June
2022
Number

755,988,402

683,979,739

755,988,402

683,979,739

20 Commitments

To maintain rights to tenure of exploration permits, the Company is required to perform minimum work programs
specified by various state and national governments. These obligations are subject to renegotiation in certain
circumstances such as when application for an extension of a permit is made and at other times. The minimum work
program commitments may be reduced by the Company by entering into sale or farm-out agreements or by
relinquishing permit interests. Should the minimum work program not be completed in full or in part in respect of a
permit then the Company’s interest in that exploration permit could be either reduced or forfeited. In some instances, a
financial penalty may result if the minimum work program is not completed. Approved expenditure for permits may be
more than the minimum expenditure or work commitment. Where the Company has a financial obligation in relation to
approved joint operation exploration expenditure that is greater than the minimum permit work program commitments
then these amounts are also reported as a commitment.

The current estimated expenditure for approved commitments and minimum work program commitments are as follows:

Exploration and evaluation

No longer than 1 year

Longer than 1 year but less than 5 years

21 Financial instruments

(a)

Capital risk management

30 June
2023
$

30 June
2022
$

4,371,000

683,500

5,054,500

12,950,700

6,338,000

19,288,700

The Company manages its capital to ensure that it will be able to continue as a going concern. As at 30 June 2023 the
capital structure of the Company consists of cash and cash equivalents and equity attributable to equity holders of the
parent comprising issued capital, reserves and accumulated losses. The company also has $10,000,000 in debt and
contract liabilities (deferred revenue) of $7,302,340.

(b)

Financial risk management objectives

The Company’s management provides services to the business and manages the financial risks relating to the
operations of the Company. The Company does not trade or enter into financial instruments, including derivative
financial instruments, for speculative purposes. The use of financial derivatives is governed by the Company’s policies
approved by the Board of Directors.

(c)

Categories of financial instruments

Financial assets

Cash and cash equivalents

Trade and other receivables

Other financial assets

Total financial assets

Financial liabilities

Trade and other payables

Other financial liabilities

Total financial liabilities

30 June
2023
$

30 June
2022
$

7,507,716

18,711,960

1,035,387

2,440,799

175,306

8,718,409

21,152,759

993,168

7,847,667

3,060,507

7,287,653

8,840,835

10,348,160

(d)

Commodity price risk management

The Company does not currently have any projects in production and has no exposure to commodity price
fluctuations.

(e)

Liquidity risk management

The Company manages liquidity risk by maintaining adequate reserves, banking facilities and reserve borrowing
facilities by continuously monitoring forecast and actual cash flows and matching the maturity profiles of financial assets
and liabilities.

Liquidity and interest risk tables

The following tables detail the Company’s remaining contractual maturity for its non-derivative financial assets and
liabilities. The tables have been prepared based on the undiscounted cash flows expected to be received/paid by the
Company.

Weighted
average
effective
interest
rate

0.00%

0.75%

3.05%

2023

Financial assets:

Non-interest bearing

Variable interest rate

Fixed interest rate

Financial
liabilities:
Non-interest bearing

Interest bearing (i)

11%

Weighted
average
effective
interest
rate

2022

Financial assets:

Less than 1
month

1 to
3 months

3 months
to 1 year

1 to 5 years

5
plus

Total

1,035,387

6,917,543

452,299

137,865

(993,168)

(145,236)

175,306

6,917,552

494,518

(7,371)

(9,824,694)

(10,000,000)

1,210,702

7,369,842

137,865

(1,138,404)

(10,000,000)

(2,419,995)

Less than 1
month

1 to 3
months

3 months to
1 year

1 to 5 years

5
plus

Total

Non-interest bearing

0.00%

2,440,799

Variable interest rate

0.75%

18,117,081

457,005

137,865

Fixed interest rate

1.50%

Financial
liabilities:

Non-interest bearing

Interest bearing (i)

11%

18,117,090

(162,703)

(79,549)

(10,148,588)

(i)

$10,000,000 interest bearing financial liabilities reported exclusive of transaction costs.

(3,060,507)

(217,414)

(148,588)

(10,000,000)

2,440,808

18,574,086

137,865

(3,426,509)

(10,000,000)

7,726,250

(f)

Interest rate risk management

The Company is exposed to interest rate risk as it earns interest at floating rates from a portion of its cash and cash
equivalents. The Company places a portion of its funds into short term fixed interest deposits which provide short term
certainty over the interest rate earned.

(g)

Interest rate sensitivity analysis

If the average interest rate during the year had increased/decreased by 10% the Company’s net loss after tax would
increase/decrease by $104,186.

(h)

Credit risk management

The Company does not have any significant credit risk exposure to any single counterparty or any group of
counterparties having similar characteristics. The credit risk on liquid funds and financial instruments is limited because
the counterparties are banks with high credit-ratings assigned by international credit-rating agencies. The carrying
amount of financial assets recorded in the financial statements, net of any allowances for losses, represents the
Company’s maximum exposure to credit risk.

(i)

Fair value of financial instruments

The Directors consider that the carrying amount of financial assets and financial liabilities recorded in the financial
statements approximates their fair values (2022: net fair value).

Financial assets and financial liabilities are recognised at amortised cost.

22 Contingent liabilities

No contingent liabilities exist as at the date of the financial report.

23 Related party transactions

(a)

Key management personnel

Key management of the Company are the executive members of Vintage Energy Limited and its Board of Directors.
Key management personnel remuneration, as detailed in the Company’s remuneration report within the Directors’
report, includes the following expenses:

Short-term employee benefits

Share based payments

Post-employment benefits

(b) Transactions with affiliates

30 June
2023
$

698,655

275,150

57,000

30 June
2022
$

615,125

352,270

55,314

1,030,805

1,022,709

An affiliate of the Managing Director is employed with the Company in a technical position, with remuneration based on
an arm’s length basis and at a rate consistent to the position filled.

No other related party transactions have occurred during the year (2022 – nil).

24 Remuneration of auditors

Audit or review of the financial report

Other Services

Other services include fees for taxation services.

The company’s auditor is Grant Thornton Audit Pty Ltd.

30 June
2023
$

96,965

7,990

104,955

30 June
2022
$

55,850

3,000

58,850

25 Cash flow information

Reconciliation of cash flows from operating activities

Loss for the year

Depreciation

Shares options and performance rights expensed

Wages and salaries capitalised to exploration

Recoveries offset against exploration

Impairment

Changes in assets and liabilities

Increase / (decrease) in contract liabilities

(Increase) / decrease in trade and other receivables

Increase in provisions

Increase / (decrease) in trade and other payables

Increase / (decrease) in other liabilities

30 June
2023
$

30 June
2022
$

(11,261,626)

(7,978,704)

560,707

1,027,277

241,820

797,857

(84,952)

(103,399)

(2,794,504)

(2,193,448)

4,635,464

(197,660)

1,362,240

295,582

(1,825,087)

788,972

8,250,000

1,767,923

(495,256)

3,230,127

(7,493,587)

3,516,920

26 Company information

The principal place of business of the company is 58 King William Road, Goodwood SA 5034.

DIRECTORS’ DECLARATION

In the opinion of the Directors of Vintage Energy Limited:

1. The financial statements and notes of Vintage Energy Limited are in accordance with the Corporations Act 2001, including:

ii.

Giving a true and fair view of its financial position as at 30 June 2023 and of its performance for the financial
year ended on that date;

Complying with Australian Accounting Standards (including the Australian Accounting Interpretations) and the
Corporations Regulations 2001;

2. The Managing Director and the Chief Financial Officer have each declared that:

ii.

iii.

the financial records of the Company for the year ended have been properly maintained in accordance with
section 295A of the Corporations Act 2001;

the financial statements and notes for the financial year comply with the Accounting Standards; and

the financial statements and notes give a true and fair view; and

3. There are reasonable grounds to believe that Vintage Energy Limited will be able to pay its debts as and when they

become due and payable.

Signed in accordance with a resolution of the Directors.

Reg Nelson
Chairman

28 September 2023

INDEPENDENT AUDITOR’S REPORT

Grant Thornton Audit Pty Ltd
Grant Thornton House Level
3
170 Frome Street
Adelaide SA 5000
GPO Box 1270
Adelaide SA 5001

T +61 8 8372 6666

To the Members of Vintage Energy Limited

Report on the audit of the financial report

Opinion

We have audited the financial report of Vintage Energy Limited (the Company), which comprises the
statement of financial position as at 30 June 2023, the statement of profit or loss and other comprehensive
income, statement of changes in equity and statement of cash flows for the year then ended, and notes to
the financial statements, including a summary of significant accounting policies, and the Directors’
declaration.

In our opinion, the accompanying financial report of the Company is in accordance with the Corporations Act
2001, including:

a giving a true and fair view of the Company’s financial position as at 30 June 2023 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.

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.

Material uncertainty related to going concern

We draw attention to Note 4.21 in the financial statements, which indicates that the Company incurred a loss of
$11,261,626 and had net cash outflows from operating and investing activities of $16,161,089 during the year ended
30 June 2023, and as of that date, the Company’s accumulated losses were $27,066,482. As stated in Note 4.21, these
events or conditions, along with other matters as set forth in Note 4.21, indicate that a material uncertainty exists that
may cast doubt on the Company’s ability to continue as a going concern. Our opinion is not modified in respect of this
matter.

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 – Note 11

At 30 June 2023 the carrying value of exploration and
evaluation assets was $49,403,928.

In accordance with AASB 6 Exploration for and
Evaluation of Mineral Resources, the Company 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.

The process undertaken by management to assess
whether there are any impairment triggers in each
area of interest involves an element of management
judgement.

This area is a key audit matter due to the significant
judgement involved in determining the existence of
impairment triggers.

Our procedures included, amongst others:

• obtaining the management reconciliation of capitalised
exploration and evaluation expenditure and agreeing to
the general ledger;

• evaluating management’s area of interest

considerations against AASB 6;

• evaluating management’s assessment of trigger
events prepared in accordance with AASB 6
including;

−

tracing projects to statutory registers, exploration
licenses and third party confirmations to determine
whether a right of tenure existed;

− enquiry of management regarding their intentions to
carry out exploration and evaluation activity in the
relevant exploration area, including review of
management’s budgeted expenditure;

− understanding whether any data exists to suggest
that the carrying value of these exploration and
evaluation assets are unlikely to be recovered
through development or sale;

• assessing the accuracy of impairment recorded for the

year as it pertained to exploration interests;

• evaluating the competence, capabilities and
objectivity of management’s experts in the
evaluation of potential impairment triggers; and

• assessing the appropriateness of the 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
Company’s annual report for the year ended 30 June 2023, 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.

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 Company’s ability to continue as a going
concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting
unless the Directors either intend to liquidate the Company 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: http://www.auasb.gov.au/auditors_responsibilities/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 the Directors’ report for the year ended 30 June
2023.

In our opinion, the Remuneration Report of Vintage Energy Limited, for the year ended 30 June 2023
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

J L Humphrey
Partner – Audit & Assurance

Adelaide, 28 September 2023

SCHEDULE OF TENEMENTS

Tenement

Basin

Operator

Interest held
30 June 2023

Interest held
30 June 2022

Queensland

ATP 743 (1)

ATP 744 (1)

ATP 1015 (1)

PCAs
319,320,321,322,323 &
324 (1)
ATP 2021

South Australia

Galilee

Comet Ridge Ltd

30%

Cooper/Eromanga

Vintage Energy Ltd

50%

PRL 211

Cooper/Eromanga

Vintage Energy Ltd

Otway

Otway Energy Pty Ltd

Vintage Energy Ltd

Cooper/Eromanga

Vintage Energy Ltd

50%

100%

30%

50%

100%

Otway

Vintage Energy Ltd

25%

PRL 249 (ex PEL 155)

GSEL 672

PELA 679 (2)

Victoria

PEP 171

Northern Territory

EP 126

Bonaparte

Vintage Energy Ltd

100%

Notes to the table above:

(1) "Deeps" JV contractual agreement with Comet Ridge Ltd. This is defined as all strata commencing underneath the
Permian coals and without a lower limit. ATP-743 & ATP-744 expired in 2021 and ATP-1015 expired in 2022.
However, ATP 743, ATP 744 and ATP 1015 have been renewed in support of the six Potential Commercial Areas
(PCAs) granted in September 2022, PCAs 319, 320, 321, 322, 323 & 324.

(2) Subject to reaching a Native Title Agreement, Vintage will acquire 100% interest in the permit.

INFORMATION PURSUANT TO THE LISTING
REQUIREMENTS OF THE ASX
Number of holders of equity securities

Ordinary shares

At 27 September 2023, the issued capital comprised of 869,598,259 ordinary shares held by 2,648 holders.

Employee performance rights

At 27 September 2023, there were 30,519,504 performance rights on issue with a $nil exercise price.
Each performance right converts into one share on the occurrence of certain conditions. They do not carry the
right to vote.

Spread details as at 27 September 2023 for ordinary shares

Holding Ranges

1 - 1,000

1,001 - 5,000

5,001 – 10,000

10,001 – 100,000

100,001 – 9,999,999,999

Totals

Holders

Total Units

% Issued Share Capital

350

1,283

905

2,648

4,177

280,707

2,777,983

52,445,308

814,090,084

869,598,259

0.00%

0.03%

0.32%

6.03%

93.62%

100.00%

Holders less than a marketable parcel = 712

Substantial shareholders as at 27 September 2023

Number of shares

HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED - A/C 2

43,260,609

4.97 %

Top twenty shareholders as at 27 September 2023

Position

Holder Name

Holding

HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED - A/C 2

CITICORP NOMINEES PTY LIMITED

BNP PARIBAS NOMS PTY LTD

HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED

HOWZAT SERVICES PTY LTD

DR GARY LILLICRAP, MR DAMIAN LILLICRAP & MRS IMELDA LILLICRAP

N M GIBBINS

MERRILL LYNCH (AUSTRALIA) NOMINEES PTY LIMITED

MR DOMINIC VIRGARA

RADELL PTY LTD

AURELIUS RESOURCES PTY LTD

VIEWADE PTY LIMITED

UBS NOMINEES PTY LTD

J P MORGAN NOMINEES (AUSTRALIA) PTY LIMITED

MR REGINALD NELSON & MRS SUSAN NELSON

MR CHRISTOPHER JAMIESON

MONLEY PTY LTD

MRS SUSANNA ANDERSON

MR STEVEN HEFFERNAN

MR JEFFREY BENNETTS & MRS HELEN BENNETTS

43,260,609

36,847,274

32,060,191

27,495,059

15,331,179

12,020,000

11,827,990

11,613,065

11,100,000

10,003,780

9,960,158

9,544,887

9,000,000

8,436,564

8,397,827

8,255,401

7,414,427

6,622,747

6,543,697

6,340,000

4.97%

4.24%

3.69%

3.16%

1.76%

1.38%

1.36%

1.34%

1.28%

1.15%

1.10%

1.04%

0.97%

0.95%

0.85%

0.76%

0.75%

0.73%

Total

Total Issued Capital

292,074,855

33.59%

869,598,259

100.00%

GLOSSARY

The following glossary of terms and abbreviations is divided into two parts:

1. Resources and reserves as defined by the SPE-PRMS;

2. General terms commonly used in the upstream petroleum industry.

Terms and abbreviations for resources and reserves as per the SPE-PRMS

PRMS

Petroleum Resources Management System. Reserves and Resources are defined by the
Society of Petroleum Engineers (‘SPE’), American Association of Petroleum Geologists
(‘AAPG’), World Petroleum Council (‘WPG’) and the Society of Petroleum Evaluation
Engineers (‘SPEE’). The detail of the PRMS is available as a download from the website of
the SPE: www.spe.org

The petroleum resources classification framework is illustrated below:

Prospective Resources

Those quantities of petroleum estimated, as of a given date, to be potentially recoverable
from undiscovered (hypothetical) accumulations by application of future development
projects. The categories of decreasing certainty are Low, Best and High Estimates.

Low, 1U

Best, 2U

High, 3U

Play

Lead

Prospect

Chance of Discovery

Low estimate of Prospective Resources. The abbreviation “1U” is an informal, alternative
acronym

Best estimate of Prospective Resources. The abbreviation “2U” is an informal, alternative
acronym.

High estimate of Prospective Resources. The abbreviation “3U” is an informal, alternative
acronym.

A project associated with a prospective trend of potential prospects, but which requires
more data acquisition and/or evaluation to define specific leads or prospects. The
succession of increasing maturity of concept is play, lead and then prospect.

A project associated with a potential accumulation that is currently poorly defined and
requires more data acquisition and/or evaluation to be classified as a prospect. A lead has a
greater maturity of concept than a play but less than a prospect.

A project associated with a potential accumulation that is sufficiently well defined to
represent a viable drilling target and does not require further data acquisition or evaluation
i.e., a prospect is mature for drilling.

The chance that the accumulation will result in the discovery of petroleum. The term chance
is preferred in lieu of risk for general usage. Commonly applied to a drillable prospect where
Prospective Resources are estimated, and factors include the product of the separate
chances of source rock, migration, reservoir and trap.

Chance of Development

The chance that a prior discovery of petroleum will be commercially developed.

Chance of Commerciality

For an undiscovered accumulation the chance of commerciality is the product of the chance
of discovery and chance of development

Discovery

Is one or more accumulations of petroleum for which one or more exploratory wells have
established through testing, sampling and/or logging the existence of significant quantities of
potentially moveable hydrocarbons. In this context “significant” implies that there is evidence
of a sufficient quantity of petroleum to justify estimating the in-place volume demonstrated
by the well(s) and for evaluating the potential for economic recovery.

Contingent Resources

Those quantities of petroleum are estimated, as of a given date, to be potentially
recoverable from known accumulations, but the applied project(s) are not yet currently
mature enough for commercial development due to one or more contingencies. The
categories of decreasing certainty are Low, Best and High estimates.

Reserves

Low estimate of Contingent Resources.

Best estimate of Contingent Resources.

High estimate of Contingent Resources.

Those quantities of petroleum anticipated to be commercially recoverable by application of
development projects to known accumulations from a given date forward under defined
conditions. The categories in decreasing certainty are Proved, Probable and Possible.

1P, Proved

Proved reserves (deterministic or probabilistic).

2P, Proved and Probable

Proved plus Probable reserves (deterministic or probabilistic).

3P, Proved, Probable and

Proved plus Probable plus Possible reserves (deterministic or probabilistic).

Possible

Range of Uncertainty

Deterministic

Probabilistic

P90

Probabilistic Estimate

P50

Probabilistic Estimate

P10

Probabilistic Estimate

The range of estimated quantities of potentially recoverable petroleum in any one of the
three categories, Prospective Resources, Contingent Resources and Reserves. Three
estimates are designated to describe the range, with decreasing certainty from low to high.
Because the absolute minimum and absolute maximum outcomes are the extreme cases it
is considered more practical to use low and high estimates as a reasonable representation
of the range of uncertainty. There are two methods; deterministic and probabilistic.

A deterministic estimate is a single discrete scenario within a range of outcomes. Each of
the input parameters is a single value.

The statistical uncertainty of individual reservoir parameters is used to calculate the
statistical uncertainty of the in-place and recoverable resource volumes. Often a stochastic
(i.e., Monte Carlo) method is used to calculate probability functions by random sampling of
the input distributions. The range of uncertainty is selected from volumes sampled at 90%,
50% and 10% of the output distribution.

From the probabilistic method there is a greater than 90% cumulative probability that
quantities estimated would ultimately be exceeded.

This category is considered to be the most likely outcome. From the probabilistic method
there is an equal (i.e., 50%) probability that quantities estimated would ultimately be greater
or smaller.

From the probabilistic method there is a less than 10% cumulative probability that quantities
estimated would ultimately be exceeded.

General terms and abbreviations used in this report and the petroleum industry

2D
3D
ASX
ATP
B
bbl
Bcf
Blooie Line

Boe

Bopd

Brent

Two dimensional; usually referring to a seismic survey with a coarse grid of orthogonal lines.

Three dimensional; usually referring to a seismic survey with a fine grid of orthogonal lines.
Australian Securities Exchange.
Authority to Prospect which is an exploration licence in Queensland.

Billion 109, or 1,000 million.

One barrel of crude oil contains 42 US gallons (or 34.97 imperial gallons, or, 159 litres).

Billion cubic feet.

Large diameter flow line for air or gas drilling, that diverts the flow of air or gas from the rig
into a discharge (flare) pit area.

Barrels of oil equivalent. Natural gas is converted to barrels of oil equivalent generally using
a ratio of approximately 6,000 cubic feet of natural gas as an amount equivalent to one
barrel of oil.

A liquid flow rate expressed in barrels of oil per day.

Brent crude oil marker. The price of oil from the giant Brent oil field in the North Sea became
a reference marker for other types of crude oil, plus or minus a differential for quality and
other factors. Thus, Brent Futures Contracts became tradeable on various financial markets
both for hedging purposes and as a part of commodities trading in general.

Carboniferous

A period 359 to 299 million years ago.

Condensate

Conventional

A liquid hydrocarbon phase that is slightly lighter than and with less calorific content than
crude oil. More usually occurs in association with natural gas. It is gaseous at reservoir
conditions but will condense from gaseous vapour to a liquid at the lesser temperature and
pressure at standard surface conditions.

Conventional hydrocarbons or Conventional Oil and Gas refers to petroleum, (crude oil and
raw natural gas) occurring in discrete accumulations or reservoirs where the source of
hydrocarbons is distant, and the hydrocarbons migrate to a trap. The hydrocarbons are
extracted from the ground by conventional means and methods, i.e., after drilling and using
the natural reservoir pressure or pumping and can include stimulation.

Cretaceous
CSG

A period from 145 to 66 million years ago.

Coal seam gas.

Devonian
DST

EP
Fault
Gas Condensate

GJ
Graben

Hydraulic fracturing

Hydrocarbon

Improved Recovery

Joule

Jurassic
KB

Km
Km2
LNG
LNG Netback Price

Logs

m
M
MM
Net pay

OGIP, OGIIP

OOIP, OOIIP

A period from 419 to 359 million years ago.

Drill stem test. A procedure for isolating and testing the pressure, permeability, and flow
capacity of a geological formation during the drilling of a well. Mechanical valves are in a
special cylindrical tool and connected at the base of a drill string and are activated into the
set, and open or closed position by applying weight or rotation of the drill pipe respectively.

Exploration Permit for petroleum as in the Northern Territory.

A fracture in a rock mass, with the movement of one side past the other.

Hydrocarbons which are gaseous at reservoir conditions, but which condense to liquids
when the temperature and pressure falls below the dewpoint. Refer also to condensate.

Gigajoule. A joule is a measure of heating value. 1 GJ is equal to 1 x 109 joules.

Is a fault block, generally greater in length than its width that has been downfaulted relative
to the adjacent blocks.

The high pressure injection of “fraccing fluid”, primarily water, minor thickening agents and
suspended proppants (e.g., sand or aluminium oxide micro-pellets) into a well to create
cracks propagated in the subsurface rocks for a small radius around the wellbore. When the
pressure is released, the solid proppants prevent the cracks from closing (i.e., hold the
fractures open) and allow petroleum to flow more freely into the wellbore as an aid to the
production recovery process.

A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons
can be as simple as methane (CH4), but many are highly complex molecules and can occur
as gases, liquids, or solids.

The extraction of additional petroleum, beyond primary recovery, from naturally occurring
reservoirs by supplementing the natural forces in the reservoir. It includes waterflooding and
gas injection for pressure maintenance, secondary processes, tertiary processes, and any
other means of supplementing natural reservoir recovery processes. Improved recovery
also includes thermal and chemical processes to improve the in-situ mobility of viscous
forms of petroleum (also called Enhanced Recovery).

Is the energy dissipated as heat when an electric current of one ampere passes through a
resistance of one ohm for one second.

A period from 201-145 million years ago

Kelly bushing. A hexagonal spline, the kelly drive slides though the kelly bushing and
permits a length of drill pipe to be drilled into the wellbore. When the kelly is fully
descended, the drillstring is lifted, the kelly disconnected and a new length of drillpipe
re-connected and the drilling process continues. The kelly bushing fits into the rotary
turntable fixed into the floor of the drill rig. Depth measurement is relative to the top of KB
(usually around one foot above the rig floor) but otherwise may be relative to the top of the
rotary table; RT.

Kilometres.

A square kilometre.

Liquefied natural gas.

Free on board (“FOB”) export price of LNG at the receiving terminal. The buyer is
responsible for shipping and transportation.

The measurement versus depth or time, or both, of one or more physical quantities in or
around a well. Logs are measured downhole and transmitted through a wireline for
recording at the surface. Common measurements include the background gamma radiation,
acoustic velocity, density, and resistance of rocks and the pressure, temperature, and flow
rates of petroleum fluids.

Metres

1,000

Millions 106

The thickness of reservoir considered to be gas or oil bearing and capable of contributing to
production into the wellbore. Usually there will be several cutoff parameters including a
porosity minimum, a shale maximum and a water saturation maximum.

Original gas (initially) in place. The estimated quantity of gas which may originally have
occurred in a reservoir.

Original oil (initially) in place. The estimated quantity of oil which may originally have
occurred in a reservoir.

Oil Shale

P&A

PEL
Permian
Permit Areas

Pool

Porosity

PRL

Reflectors

Reservoir

Resources

Risk

RTSTM

scf

scf/d

Seismic

Shale volume

Shale, siltstone and marl deposits highly saturated with kerogen. Whether extracted by
mining or in-situ processes, the material must be extensively processed to yield a
marketable product (synthetic crude oil). They are totally different from Shale Oil

Plugged and abandoned. Refers to the process of the final abandonment of petroleum wells
usually by spotting cement plugs at key intervals within the well to ensure the protection and
isolate of aquifers and depleted reservoirs. Any surface wellheads are removed and the
general location restored to a natural state.

Petroleum Exploration Licence as used in South Australia.

A period 299 to 252 million years ago.

The land subject of the Permits in which Vintage Energy has an interest from time to time.

Petajoule. A joule is a measure of heating value. 1 PJ is equal to 1 x 1015 joules

An individual and separate accumulation of petroleum in a reservoir.

The pore space in a reservoir which can contain fluids, either water, oil, or gas. (i.e., the
space between beach sand grains).

Petroleum Retention Licence as used in South Australia

As in seismic reflectors. Refer to Seismic.

A subsurface rock formation containing an individual and separate natural accumulation of
moveable petroleum that is confined by impermeable rocks/ formations and is characterised
by a single-pressure system.

The term “Resources” as used herein is intended to encompass all quantities of petroleum
(recoverable and unrecoverable) naturally occurring on or within the Earth’s crust,
discovered and undiscovered, plus those quantities already produced.

The probability of loss or failure. As “risk” is generally associated with the negative outcome,
the term “chance” is preferred for general usage to describe the probability of a discrete
event occurring.

Rotary Table. Refer to KB, kelly bushing.

Refers to a flow of gas recovered at the surface as a consequence of well testing but flows
at a rate too small to measure. There is sufficient flow to light a flare but insufficient pressure
to register on the gauge or enable the flow rate to be calculated.

Standard cubic feet. Usually referring to gas at standard conditions.

A flow rate in standard cubic feet per day.

A seismic survey measures at geophone locations the time for a shock wave propagated at
the surface to travel deep into the earth, strike rock strata and reflect back to the surface.
Dynamite as the historical source has almost entirely been replaced with vibroseis onshore
(i.e., truck mounted and weighted vibrator plates) or acoustic source offshore. A good
reflector is the interface between two rock strata of differing density and or acoustic velocity
e.g., between sandstone and shale or limestone and mudstone. Interbedded strata thinner
than ~10 metres are more difficult to resolve. A survey progresses along lines aligned in a
grid and with orthogonal cross lines. After suitable computer processing to “stack” the traces
of individual source points and geophones into seismic sections these provide a “picture” of
the structure of the subsurface reflectors.

This is the portion of rock which is occupied by “shales” (in fact, usually more correctly
called mudstone). For example, a “shaly” sandstone interval may contain 15% shale either
as thin laminations or clay minerals within the sandstone matrix. At a certain maxima, the
shale volume may preclude the occurrence of any effective porosity.

Standard conditions

Measurements of volumes at standard conditions means 14.7 psia and 60°F (US).

Sub-blocks

Petroleum tenements are often defined as blocks. In Queensland there are 25 (5 x 5)
sub-blocks within a block.

TCF

Tectonic

Tenement

TOC

Triassic

Unconventional oil and

gas

Water saturation

WTI

Trillion cubic feet of gas.

Total depth of the well.

Pertaining to forces and the geological architecture that results, such as faults, folds etc.

Ground granted for exploration or production purposes.

Terajoule; a joule is a measure of heating value. 1 TJ is equal to 1 x 1012 joules

Total organic carbon, a measure of the dry weight percent of organic carbon within rocks.

A period from 252-201 million years ago

Oil and gas produced by non-traditional sources, means or methods. This covers oil and
gas produced from shale formations and coal seams. The formation contains both the
hydrocarbon source and reservoir.

Vitrinite reflectance. It is a measure of light reflectance from organic matter in sediments. It
provides an indication of the organic maturity of source rocks and whether petroleum may
have been generated under heat and pressure and expulsed for potential capture and
preservation in reservoir traps.

Is the percentage of water occupying the pore space. For an aquifer the water saturation is
100%. For an oil or gas field a portion of the water is displaced and for example, SW of 25%
indicates 75% gas or oil within the porosity. Usually, reservoirs are water wet and therefore
there must be a layer of water coating the surface of the grains of the pore space. This is
the connate or irreducible water saturation.

The price of West Texas Intermediate crude oil as at the delivery point at Cushing,
Oklahoma. It is used as a benchmark for oil pricing but has declined in importance in recent
years. Refer to Brent.

CORPORATE DIRECTORY
Vintage Energy Ltd (ASX: VEN)

ABN 56 609 200 580

Chairman

Reg Nelson

Directors

Neil Gibbins | Managing Director

Nick Smart | Non-executive

Ian Howarth | Non-executive

Company Secretary

Simon Gray

Registered Office

58 King William Road

Goodwood SA 5034

P: +61 (0) 8 7477 7680

info@vintageenergy.com.au

www.vintageenergy.com.au

Share Registry

Automic Pty Ltd

Level 5

126 Phillip Street

Sydney NSW 2000

Contact:

P: 1300 288 664 (within Australia)

P: +61 (0) 2 9698 5414

www.automic.com.au

Auditor

Grant Thornton Audit Pty Ltd

Grant Thornton House

Level 3

170 Frome Street

Adelaide SA 5000