1
ANNUAL
REPORT
2024
Vintage Energy Ltd
ABN: 56 609 200 580
www.vintageenergy.com.au
info@vintageenergy.com.au
+61 8 7477 7680
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Contents
Chairman’s overview............................................................................................................................... 4
Note from the Managing Director .......................................................................................................... 6
Review of operations .............................................................................................................................. 9
Reserves & resources statement .......................................................................................................... 13
Climate change & risk management ..................................................................................................... 16
Directors’ report ................................................................................................................................... 18
Auditor’s independence declaration .................................................................................................... 29
Corporate governance statement ......................................................................................................... 30
Consolidated entity disclosure 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 ......................................................................................................................... 61
Information pursuant to the listing requirements of the ASX .............................................................. 62
Glossary ................................................................................................................................................. 64
Corporate directory .............................................................................................................................. 69
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.
Terms and abbreviations
This report uses terms and abbreviations commonly employed in the petroleum industry. A glossary of these terms
and abbreviations is provided in this report commencing on page 62.
The terms “the year”, “2024” or “FY24” refer to the 12 months ended 30 June 2024. Similarly references to “2025
financial year” and “FY25” refer to the 12 months to 30 June 2025.
4
Chairman’s overview
Fellow Shareholders,
Your company’s results for 2024 are typical of
young, emerging oil and gas companies: progress
in the cornerstones of value creation; accompanied
by frustrations from the testing inherent in new field
appraisal – but with valuable lessons learned.
These are not unusual, but weather impacts on
fledgling operations have been very vexatious.
The areas of progress are nevertheless significant.
Vintage has grown from a single-field, single-supply
contract and customer producer to a dual-field,
dual-supply contract and customer producer. Vali-1
completed its first full year of operation. The field,
and its facilities recorded exemplary reliability. The
Odin gas field was brought into production when
Odin-1 came online in September and was
successfully appraised by Odin-2 in June. Vintage
has maintained a 100% success rate in Cooper
Basin drilling operations. Odin’s supply contract
was extended to December 2026. Proved and
probable reserves have risen substantially.
The year’s frustrations resulted in lower production
than expected. As discussed by the Managing
Director in his subsequent report, Vali-2 and Vali-3
are yet to contribute gas production of any
significance, with both wells shut-in pending
remedial action at year-end.
The delay in establishing production from these
wells resulted in revenue and cash flow generation
being much lower than anticipated and necessitated
the capital raising conducted in April. Management
implemented initiatives which yielded a significant
reduction in cash expenditure on staff costs,
corporate costs and administration from the closing
months of the year. Directors elected to forego
directors’ fees for the latter portion of the year.
Your board of directors appreciates the impact of
these events on the value of shareholders’
investment and the demands placed on their
patience. We expect the confidence shown by
shareholders will be affirmed: initially, in the near
term, through increased gas production and sales
from the work at Odin and Vali; and in the longer
term, through the undeniably inherent value of
Vintage’s gas reserves and resources.
Building a substantial reserves and resources base
has been a long-standing feature of Vintage’s value
proposition and relevance. A founding premise in
forming the company was recognising the
impending supply shortfall and the opportunity to
create value by discovering and building a
substantial gas portfolio with access to east coast
Australian energy markets.
However, our foresight did not contemplate the
government policy response which heightened
uncertainty and – paradoxically - in fact has resulted
in higher prices. Some gas users were reported to
view the gas “cap” as “a misnomer” - and more like
a “floor”.
Superficially, these impacts would seem favourable
for Vintage. The potential value of our gas is greater
than we might otherwise have anticipated.
Moreover, the company qualifies for an exemption
from the $12/gigajoule price cap, positioning it to
realise prices now available in the current market.
However, the hasty intervention has had a dramatic
impact on investor confidence and availability of
investment capital. Smaller companies, such as
Vintage, have suffered de-rated share prices.
Notwithstanding the later modifications and
exemptions introduced, the damage remains. The
intervention has been poisonous to investment to
create new supply, to the capital raising capacity
and costs of small gas companies and to contracts
for long term supply.
The energy problem in Australia is complex: the
“solution” was to promulgate a price regulation
policy deemed to be clear and simple. But it is
doomed to be wrong. You might as well place a
picture of a glowing gas heater in a room to deal
with cold weather – a dramatic way to pursue net
zero emissions, but hardly conducive to wellbeing.
5
As if that were not enough, reporting obligations
have become even more demanding. We are a
small company working hard to minimise costs.
These are increasingly onerous impositions.
Yet, as I have noted, our gas is now more valuable
than ever. Realisation of the value of our Cooper
Basin gas is the company’s foremost priority. In the
near term, this goal will be advanced through
ongoing appraisal of, and increasing production
from, the Odin and Vali gas fields. Progress on
these fronts will enable development to be
expedited and other areas of potential in the
company’s portfolio, such as promising oil
exploration, to be addressed.
The signing, after year-end, of a Heads of
Agreement with the board of Galilee Energy Limited
for a merger of the two companies is an initiative
taken to strengthen Vintage’s capacity to prioritise
value creation at Odin and Vali and its long-term
prospects. The proposal is subject to conditions,
including approval by the shareholders of Galilee for
acquisition of their shares by Vintage in an all-scrip
offer.
The details of the transaction will be finalised and
detailed in a scheme implementation deed to be
provided after the date of this report. As such, it is
premature to make specific comment on the
initiative other than to say that both boards are
unanimous in their support for the proposal.
We believe this consolidation will result in a
company better equipped to generate value for its
shareholders; including greater financial strength,
holding significant gas reserves and resources and
a heightened equity market presence.
Your company has completed the year free of lost-
time-injuries and without reportable environmental
incidents. While this may seem simply the only
acceptable performance, the reality is results such
as these are not a default position which ‘just
happen’. Rather it is the result of planning,
vigilance and diligence across the company and its
various contractors on every day they are engaged
in its operations. On behalf of directors, I record our
appreciation for this achievement.
More generally, I also express our appreciation to
our Managing Director, Neil Gibbins, and his team
for their efforts throughout a strenuous year, and to
our shareholders, for their support. While 2024 was
a challenging year, the company enters the new
financial year with an expanded production base,
and gas reserves and resources with rising potential
value in a supply-short eastern Australian market.
Reg Nelson
Chairman
6
Note from the Managing Director
The 2024 financial year was the first full year of
production for Vintage.
Our first producing well, Vali-1, produced reliably
over the course of the year, having been brought
online in February 2023. A second well, Odin-1,
added production from the nearby Odin gas field in
September 2023 and, preparations to connect and
commission the recently drilled Odin-2 for supply
are currently underway.
These events are milestones for a young company
and I have chosen these highlights to open my
report as they are emblematic of its development
since floating on the ASX six years ago.
Safety and environment
At the outset, I am pleased to report Vintage has
completed the year free of lost-time-injuries and
reportable environmental incidents. Whilst safety,
whether it be for people or the environment, is the
first and greatest concern in the planning and
management of operations, its achievement is
entirely dependent on the vigilance of our
employees and contractors for every moment they
are engaged.
Appraisal production program
Our principal activity in 2024 was production
appraisal of the Odin and Vali gas fields.
The surest path to value maximisation of our gas
fields flows from an informed understanding of their
characteristics, limitations and opportunities. For
Odin and Vali, as in the Cooper Basin generally,
this entails assessing the performance of a number
of zones spread across a number of formations
during long term production.
Through this process we expect to identify the most
economic development plan and production profile
for the Odin and Vali fields which, with gross 2P
sales gas and ethane reserves of 142 PJ (Vintage
Energy share 71 PJ), we expect to be valuable,
long-term cash-generating assets. The realisation
of value from Odin and Vali for Vintage
shareholders remains our foremost priority.
Details of the appraisal production operations at
Odin and Vali are provided in the Review of
Operations which commences on page 9. I would
like to address the most significant outcomes and
status of the program for each field.
Vali
At Vali, the initial focus of production appraisal has
been the Patchawarra Formation, which was
fracture stimulated to enable gas flow from these
deeper, tighter, sands in the field’s three completed
wells. A gas sales agreement with AGL Energy
provided the commercial footing for facility
construction and pipeline connection and for
revenue generation.
It is now approximately 19 months since Vali-1 was
brought online and in this time the well and its
facilities, have proven reliable, producing total raw
gas of approximately 864 MMscf in the 305 days
the field was online from start-up in February 2023
to 30 June 2024. Facility performance has been
good, with availability of 93% days in this period.
Vali-1 has provided a data point for modelling on the
likely performance of the field’s Patchawarra
Formation. However, the delay in establishing
production from Vali-2 and Vali-3 prevented the
acquisition of a broader-based data set. The delay,
detailed in the 2023 Annual Report and
announcements to the ASX, meant the two wells
have been shut-in and are yet to establish gas flows
of any significance.
In summary, whilst Vali-1 and its facilities performed
steadily, the delay to Vali-2 and Vali-3 production has
meant the Vali program has, to date, produced less
gas, generated less cash and is less advanced than
originally expected. In the near term, this is to be
addressed by the initiation of production from the
unfractured Toolachee Formation, initially at Vali-2,
to establish gas flow from the well and to commence
appraisal of the formation’s productive capacity in the
field.
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Odin
At the nearby Odin gas field, production appraisal
has taken a different path, focussing initially on the
Epsilon and Toolachee formations. The field has
been online for approximately 12 months as at the
date of this report and averaged an online raw gas
production rate of 3.3 MMscf/d in 219 days to 30
June.
The production performance of Odin-1 and the
features of the field’s gas contract (negotiated
approximately 2 years after the Vali gas contract),
make expansion of its operations highly attractive.
To this end, Vintage has sought to expedite drilling
and the appraisal of the field.
The Odin-2 appraisal well drilled in May successfully
appraised the north-eastern extent of the field and is
expected to add gas production when it comes online
in the first half of the 2025 financial year. A planned
third well, Odin-3, was deferred pending joint venture
approval. Production appraisal is to enter a new
phase in the first half of FY25 with the opening of the
Patchawarra Formation in both Odin-1 and Odin-2 to
appraise unstimulated productivity of the formation.
Commercial: Odin gas supply contract
Contract coverage for the Odin gas field was
extended through the signing of an additional gas
sales agreement under the master gas supply
agreement for the Odin gas field with Pelican Point
Power Pty Limited. The additional agreement
provides for the supply of gas from the field from 1
January 2025 to 31 December 2026. Current gas
production from the Odin gas field is being supplied
to Pelican Point Power under a contract extending
from field start-up to December 2024.
Other activities
The Odin and Vali gas operations are the company’s
most valuable assets and our efforts and expenditure
were almost entirely directed to their maturation.
Vintage’s portfolio also includes other assets,
licences in proven and frontier hydrocarbon
provinces considered to possess the potential to add
materially to shareholder value in the longer term.
These assets and activity therein during the year are
detailed in the Review of Operations.
Two assets of particular significance are the Cooper
Basin oil exploration acreage and the Nangwarry
carbon dioxide resource.
Oil exploration
Notwithstanding Vintage’s focus on the east coast gas
supply opportunity, low risk oil exploration has been a
core element of the company’s strategy since inception.
The Cooper/Eromanga basins are particularly attractive,
offering a combination of proven prospectivity with
existing infrastructure which support cash generation
and return rapid payback for relatively small capital
investment.
Vintage has worked to avail itself of such
opportunities, through geological studies of its
existing acreage and by successfully bidding on an
exploration licence, PELA 679, adjacent to the
producing Worrior oil field. A description of the
licence is included in the Review of Operations.
Award of the licence is subject to negotiation of a
land access agreement.
The PELA 679 farm-in agreement signed with Sabre
Energy Pty Ltd during the year is a positive
development. The farmin, which is conditional on
licence award, will enable acquisition of a three-
dimensional seismic survey to identify drilling targets
without demand on Vintage’s capital and provide
reimbursement of costs to date.
Further analysis of our acreage in the southern flank
of the Nappamerri Trough during the year has
reiterated the prospect for oil exploration opportunity
in ATP 2021. Over 20 closures have been mapped
in the permit, with the lead prospect, Thaldra-1,
assessed as drill-ready and economically justifiable.
We are keen to address the oil opportunity in ATP
2021 and the funding of the necessary drilling, and or
seismic acquisition, is featuring in the company’s
capital management plans.
Nangwarry
Each passing year since the discovery of this gas
resource has reinforced the case for Nangwarry’s
strategic significance to users of food-grade CO2
and its latent value to Vintage shareholders. The
case for Nangwarry’s commerciality is strong, firmly
underpinned by broadly-based demand and supply
factors.
The company has continued to engage with
stakeholders across the value chain from
infrastructure operators to industrial gas
distributors, exporters and importers and end-users
with a view to identifying parties with an interest in
collaboration as a processing plant owner and
operator.
The engagement over the past 12 months has
been encouraging; it is clear interest in Nangwarry
as a source of food grade CO2 has broadened and
there is greater awareness of the prospect, and
implications of, shortages of this critical input.
I am conscious this status summary is essentially
unchanged from the previous Annual Report and
there have been no developments of significance.
Whilst the full impairment of this asset in the 2024
accounts recognises the absence of a near term
path to commercialisation, our assessment of the
long-term potential of Nangwarry is undiminished
and merits persistence and patience.
Reserves and resources
A statement of the company’s Reserves and
Resources is included in this report commencing on
page 13. The statement includes the most recent
independent estimates for the company’s Cooper
Basin gas operations.
Vintage has concluded the year having increased its
Proved and Probable (“2P”) Resources by 45%
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Total 2P Reserves of 12.6 million barrels of oil
equivalent includes over 70 PJ of sales gas and
ethane. The large majority of this is uncontracted,
an asset of rising value in a market where the
shortfall between expected supply from existing
supply sources and demand is expected to widen.
The increase in Reserves is attributable to the Odin
gas field, and the conversion of what was a
Contingent Resource to 2P Reserves.
Financial and capital management
The company’s financial statements, and
accompanying discussion are provided in the
Financial Report.
In respect of the profit and loss statement, I note the
company’s loss of $23.2 million for the 2024 financial
year was recorded after impairment expense of
$19.4 million. Comparison of this with the previous
year’s loss ($11.3 million after impairment expense of
$4.6 million) indicates an underlying improvement in
financial results.
The improvement is attributable to the increase in
revenue arising from a full year’s gas sales, although,
as noted at the outset of this report, only one well,
Vali-1 was online for the full year. This result, and a
similar improvement in cash outflow from operating
activities (which reduced by 54% compared with the
previous year) is encouraging for the prospect of
better financial results as the production initiatives in
train for FY25 are executed.
Vintage concluded the year with cash and cash
equivalents of $8.0 million which compares with the
previous corresponding figure of $7.5 million. The
company’s secured debt facility of $10 million was
fully drawn.
Capital raising and expenditure management
initiatives were undertaken during the year. The
raising of $8.0 million through a placement and
entitlement offer provided funds for the drilling,
completion and connection of the successful Odin-
2 appraisal well. The drilling of Odin-3 was to be
also funded by the raising but as noted above,
deferred on joint venture voting.
Corporate, administration and staffing cost
reduction measures were implemented in the latter
half of the year in recognition of cash generation
being lower than anticipated following the delay in
production from Vali-2 and Vali-3. Savings from
these measures emerged in the final quarter with a
27% reduction in staff costs. Administration and
corporate cost savings are expected to become
apparent in FY25.
Concluding summary and outlook
Our work in FY24 has taken Vintage forward,
completing our first year of production, and the
diversity of our gas sales. We are expecting gas
production to increase further in FY25, through
the contribution of Odin-2 and production
optimisation initiatives.
As outlined in this report, Vali did not advance to
the point expected in FY24. This has been
disappointing, frustrating for shareholders, and
impacted our capital management. Our
production appraisal plans for FY25 will provide
insight to the capabilities of the field’s Toolachee
Formation, an important input to the
determination of the optimal development plan for
the field.
It is appropriate to consider the context for the
company’s year-end position and new year plans.
Having identified emerging east coast energy
markets as an opportunity to build a business,
Vintage concludes the year substantially
increased Reserves, two producing fields and a
strong demand and price outlook for its gas.
The realisation of value for shareholders from
this position is our priority and drives our
planning and decisions for FY25 and beyond.
The proposed merger with Galilee has been
initiated principally to strengthen Vintage’s
capacity to advance value realisation from its
Cooper Basin gas projects.
In closing, I would like to acknowledge the
support and guidance the board of directors has
given the management team during the year,
thank shareholders for their ongoing patience
and support and also thank the company’s
employees.
The year had its challenges, and the team has
met these with unstinting effort, commitment and
I note, with sacrifice in their acceptance of salary
reductions to support the company whilst cash
generation was lower than anticipated. On
behalf of all shareholders, I record our gratitude
for their contribution.
Neil Gibbins
Managing Director
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Review of operations
Description of operations
Vintage Energy’s operations involve exploration,
appraisal, development and commercialisation of
hydrocarbon 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:
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the Cooper/Eromanga basins, South Australia
and Queensland;
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the Otway Basin, onshore South Australia and
Victoria;
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the Galilee Basin, Queensland; and
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the Bonaparte Basin, Northern Territory.
Cooper/Eromanga basins,
Queensland & South Australia
PRL 211, South Australia
ATP 2021, Queensland
Vintage 50% and Operator, Metgasco Ltd 25% and
Bridgeport (Cooper Basin) Pty Ltd 25%
The company’s operations in the Cooper Eromanga
basins are focussed on two neighbouring licences: PRL
211 in South Australia: and ATP 2021 in Queensland,
which share identical joint venture composition.
The licences are located in the Southern Flank of the
Nappamerri Trough, in close proximity to, and
connected with, the South Australian Cooper Basin
Joint Venture’s gas production infrastructure at the
Beckler, Bow and Dullingari fields.
Operations during the year were focussed on appraisal
production from the Vali and Odin gas fields. Vintage’s
share of production from these fields for FY24
comprised 458 TJ of sales gas and ethane, 56 tonnes
LPG and 1,180 bbls condensate.
Production was sourced from Vali-1 and Odin-1, which
came online in September 2023. Odin-1 was
completed and connected on schedule and free of lost-
time-injuries or environmental events of reportable
significance.
Vali-1 produced reliably over the financial year,
supplying gas to AGL under the gas sales agreement
extending to December 2026. The Vali-2 and Vali-3
wells were the subject of ongoing technical analysis,
having yet to establish gas flows of significance and
recording higher than anticipated fluid production. Both
wells were shut-in at year end. A remedial work
program for Vali-2 was resolved by the joint venture for
execution in the first quarter of FY25. The joint venture
is continuing to assess potential remediation options for
Vali-3.
Appraisal drilling and production opportunities at the
Odin gas field were analysed and identified, culminating
in the drilling of Odin-2. The well successfully
appraised the north-eastern extent of the field in June.
Completion and connection of Odin-2 is scheduled to
occur subsequent to year-end. Gas produced from
Odin-2 is to be supplied into the Odin field supply
contract with Pelican Point Power Limited, a joint
venture between ENGIE Australia and New Zealand
(72%) and Mitsui & Co Ltd (28%).
Technical analysis conducted during the year identified
opportunities for increased production and/or value
creation. These include: a perforating program planned
for Odin-1, to be conducted in the first quarter of FY25;
the drilling of Odin-3, situated to appraise the western
extent of the Odin gas field; and Thaldra, a drill-ready
oil prospect.
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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,
for which Vintage Energy is the successful bidder. The
licence is situated south-west of the Worrior oil field
which has produced in excess of 4.5 million barrels of
oil. Comprising a total area of 393 km2, the permit is
considered to hold Permian and Jurassic oil potential.
Award of PEL 679 to Vintage is contingent on
establishment of an appropriate land access
agreement, negotiations for which continued during the
year.
During the year Vintage signed a farmout agreement
under which Sabre Energy Pty Ltd (“Sabre”) will acquire
a 50% interest in the South Australian Cooper Basin
exploration licence PEL 679, once granted. Vintage will
retain operatorship and a 50% interest in the licence
following completion of the farmout.
Sabre will fund 100% of a 150 km2 3D seismic survey
and pay Vintage $200,000 as reimbursement of its
share of costs incurred to the time the permit is
granted.
Completion of the farmout work will satisfy the Year 1
work program for the permit and is expected to provide
the data for more accurate mapping of potential drilling
candidates.
The farmout agreement is subject to a number of
conditions precedent including, but not limited to,
regulatory approval, receipt of necessary consents and
authorisations.
11
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 CO2 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 (“MMscf/d”), measured
through a 48/64” choke at a flowing wellhead pressure
of 1,415 psi over a 36-hour period.
Vintage and Otway Energy are seeking an outcome
which will realise the economic value of Nangwarry.
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. 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.
The company is seeking to secure a collaborative wellhead-to-product delivery solution to enable commercialisation and,
to this end, continued to engage with participants along the value chain from infrastructure, industrial gas providers and
consumers.
In July 2021, ERCE independently certified recoverable hydrocarbon and CO2 sales gas at Nangwarry as displayed in the
following table:
Nangwarry Field
CO2
Hydrocarbon
Gross On-block Recoverable
Sales Gas (Bcf)
Gross Gas Contingent
Resources (Bcf)
Low
Best
High
1C
2C
3C
Pretty Hill Sandstone
9.0
25.9
64.4
0.5
1.6
4.1
Net On-block Recoverable
Sales Gas (Bcf)
Net Gas Contingent
Resources (Bcf)
Pretty Hill Sandstone
4.5
12.9
32.2
0.3
0.8
2.0
Notes to the table above:
1.
ERCE recoverable and resource estimates effective 7 July 2021. These resources were first announced to the ASX 12 July 2021.
2.
Gross volumes represent a 100% total of estimated recoverable volumes within PRL 249.
3.
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.
4.
Sales gas stream for Nangwarry is CO2 gas. Contingent Resources will be used as fuel for CO2 gas plant.
5.
These are unrisked Contingent Resources that have not been risked for Chance of Development and are sub-classified as Development
Unclarified.
6.
Hydrocarbon gas also includes minor volumes of nitrogen.
PEP 171 Victoria
Vintage 25% and operator, Somerton Energy Pty Ltd (a subsidiary of
Cooper Energy Limited) 75%
PEP 171 is located in the onshore Otway Basin and effectively encompasses the
entirety of the Victorian section of the Penola Trough. Exploration in the nearby
South Australia section has confirmed the prospectivity of the Penola Trough for
conventionally produced gas, most significantly at fields such as Haselgrove,
Katnook, Ladbroke Grove and Limestone Ridge.
Activity during the year consisted of execution of the licence Stakeholder
Engagement Plan and planning for 3D seismic survey.
12
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 previously acquired a
30% participation into the ‘Deeps’ sandstone
reservoir sequence of ATP 744, ATP 743 & ATP
1015 through a farmin agreement (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 scf/d 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.
Activity during the year was concentrated on joint
venture analyses and evaluation of the data
collected during the exploration activities.
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 in the basin offshore including
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, can be undertaken until the issue is
resolved.
13
Reserves & resources statement
Reserves at 30 June 2024
Net Proved (1P) Reserves MMboe
Movement from FY23 to FY24; FY24 Reserves by development status
Area
FY23
Production
Contingent Resources to
Reserves
Revisions
FY24
FY24
Developed
FY24
Undeveloped
Cooper Basin
4.06
(0.08)
1.7
0.7
6.3
0.4
5.9
Total
4.06
(0.08)
1.7
0.7
6.3
0.4
5.9
Net Proved and Probable (2P) Reserves MMboe
Movement from FY23 to FY24; FY24 Reserves by development status
Area
FY23
Production
Contingent Resources to
Reserves
Revisions
FY24
FY24
Developed
FY24
Undeveloped
Cooper Basin
8.66
(0.08)
3.3
0.7
12.6
0.5
12.1
Total
8.66
(0.08)
3.3
0.7
12.6
0.5
12.1
2P Reserves Net to Vintage by product at 30 June 2024
Area
Total
Sales gas
Ethane
LPG
Condensate
MMboe
PJ
PJ
kTonne
MMbbl
Cooper Basin
12.6
68.1
2.8
13.3
0.3
Total
12.6
68.1
2.8
13.3
0.3
Notes to the Cooper Basin 1P and 2P Reserve assessment:
1.
Net Reserves estimates reported here are CDRI estimates, effective 30 June 2024.
2.
CDRI 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.
3.
Reserves estimates have been made and classified in accordance with the Society of Petroleum Engineers (“SPE”)
Petroleum Resources Management System (“PRMS”) 2018.
4.
Probabilistic methods have been used for individual reservoir intervals and totals for each reservoir interval have been
summed arithmetically.
5.
Net Reserves attributable to Vintage constitute 50% of the Gross Reserves, in accordance with the licensing terms
governing the field. No deductions have been made for state or native title royalties in the reporting of Net Reserves,
as these royalties are paid in cash. No overriding royalties apply to the Vali and Odin fields. Net Reserves incorporate
deductions from the various product streams for which Vintage receives payment, namely methane, ethane, LPG,
and condensate, and deductions related to downstream fuel, flare and venting.
6.
The undeveloped resource is defined as Reserves in the sub-class “Justified for Development” on the basis that
Vintage has advised CDRI that it intends to fully exploit these Reserves. Under the Joint Operating Agreement,
Vintage is entitled to drill wells with or without the participation of other members of the Joint Venture.
7.
Ethane has been reported separately from Sales Gas as it is sold separately in the case of both the Vali and Odin
Fields.
8.
All quantities are subject to rounding to two decimal places for clarity purposes.
9.
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
14
Contingent Resources at 30 June 2024
2C Contingent Resource Net to Vintage (PJ)
Movement from FY23 to FY24; Gas share of FY24 2C Contingent Resource
Area
FY23
Acquisitions &
Divestments
Contingent Resources to
Reserves
Revisions
FY24
Gas
Galilee Basin
46
0
0
0
46
46
Cooper Basin
19
0
19
0
0
0
Otway* Basin
0.8
0
0
0
0.8
0.8
Total
66
0
19
0
47
47
*In the Otway Basin, the recoverable CO2 resource cannot be classified under PRMS as a Contingent Resource.
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).
1.
Probabilistic methods were used.
2.
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.
3.
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.
4.
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.
All Contingent Resources stated at end FY23 for ATP 2021 and PRL 211 previously announced to the ASX on 15
September 2021 have been converted to Reserves by CDRI effective June 30 2024.
2.
This conversion of Contingent Resources to Reserves were first disclosed in a release to the ASX on 30 September
2024.
Notes on Otway Basin Contingent Resource assessment:
1.
Nangwarry hydrocarbon Contingent 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.
2.
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.
3.
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.
4.
Probabalistic totals have been estimated using the Monte Carlo method.
5.
Volumes represent Vintage’s 50% working interest in PRL 249.
15
Qualified Petroleum Reserves
and Resources Evaluator
CDRI – Vali and Odin Reserves
CDRI is a specialist independent company that
provides evaluation, estimating, auditing, consultancy
services and due diligence services for upstream oil
and gas. CDRI is an affiliate of Chris Dykes
International Ltd (“CDIL”) which has provided
independent energy services since 2002.
The staff members who prepared this report possess
the appropriate professional and educational
qualifications and have the requisite experience and
expertise for the work performed. The work has been
supervised and reviewed by Mr. Brian Rhodes. Mr.
Brian Rhodes is a geologist with over 50 years’
experience in the upstream oil and gas industry,
including more than 10 years as a Reserves Estimator
and Auditor. He has a global knowledge of the oil and
gas basins of the world and has worked both in oil and
gas companies and as a consultant. He is a member of
the Society of Petroleum Engineers (SPE), a member
of the Energy Institute and a member of the
Geoscience Energy Society of Great Britain.
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 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 was supervised by Mr Adam Becis, formerly
Principal Reservoir Engineer of ERCE’s Asia Pacific
office who has over 16 years of experience. He is a
member of the Society of Petroleum Engineers and a
member of the Society of Petroleum Evaluation
Engineers.
16
Climate change & risk management
The Vintage board has a policy on climate change
which recognises the company has a role to play in
reducing carbon emissions.
We recognise that 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; and
•
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.
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.
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 contributing significantly to
emissions reductions around the globe and is
an essential energy source in a lower
emissions future. This 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 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.
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.
17
In particular, the company has exposure in the following risk areas:
RISK
DESCRIPTION
Funding
The company’s main activity is exploration and production of oil and gas. To continue its programme, the company may be
required to raise additional capital. There is no assurance 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.
Operating risk
The company’s operations are subject to operating risks that could result in increased costs & breaches of regulations. To
manage this risk, the company seeks to attract and retain high calibre employees and implement suitable systems and
processes to ensure targets are achieved.
Environmental
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 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).
Sustainability
risks
The company seeks to ensure 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) management system to drive the organisation’s continuous improvement in HSE performance which has standards that
include 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.
Climate change
The company operates within the oil & gas industry, which has committed to a set of Climate Change Policy Principles published
by the Australian Energy Producers (AEP) 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.
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 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”) covering each of the company’s JVs detail operating and voting
procedures for activities withing the relevant licences.
Changes to
restoration
obligations
provisions
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
balance sheet incorporates estimates for such decommissioning and abandonment activity, with those estimates included within
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.
18
Directors’ report
19
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 2024 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.
Committee memberships - Audit and risk committee,
Nomination committee and Remuneration committee.
Interest in shares and options
Ordinary shares
32,479,515
Options
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 (i)
32,121,440
Options
-
Employee incentive rights
-
(i) includes personal related parties.
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
6,936,821
Options
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
27,124,396
Options
2,000,000
Employee incentive rights
-
20
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.
Results for the year
Statement of profit or loss
The company incurred an operating loss of
$23,234,241 for the financial year ended 30 June 2024
(2023 $11,261,626).
The increased operating loss is attributable to
increased impairment expense, which rose from
$4,635,464 to $19,409,812. The factors involved in the
impairment expense are outlined in the discussion
below.
Significant features of the statement of profit or loss
include
-
increased revenue, which rose from $949,333 to
$5,152,471 due to higher gas sales. The 2024
financial year was the company’s first full year of
gas production (2023: approximately four
months). Gas sales also increased following the
commencement of production from the Odin gas
field in September 2023;
-
higher production-related expenses including
production costs, royalties, and depreciation
increased consistent with the 12 month of
production operations and commencement of
production from Odin;
-
a 49% reduction in director remuneration, which
was $416,740 compared with $821,980 in the
prior year;
-
lower employee benefits expense, which fell
from $4,342,473 to $3,139,604, chiefly through
salary reductions and lower share based
payments;
-
increased impairment expense. The total
impairment expense of $19,409,812 for the year
is comprised of three items;
o
full impairment of PRL 249 joint venture
costs of ($8,545,070) in recognition there
is presently no near term path to
commercialisation of the Nangwarry
carbon dioxide resource. The impairment
is not reflective of the latent long term
value of this asset, which is considered to
be positive given anticipated supply
availability of food-grade carbon dioxide,
a widely used input for a broad range of
manufacturing, healthcare and distribution
activities;
o
full impairment of Galilee Deeps Joint
Venture expenditure ($7,909,660). The
impairment has been made as no
exploration activities have been budgeted
in the near future; and
o
the full impairment of costs for EP 126
(Bonaparte Basin) at 31 December 2023.
-
financing costs of $1,887,738 were
unchanged.
Statement of financial position
Net assets at 30 June 2024 were $29,659,977,
compared with $45,534,420, with the movement
impacted by the $19,409,812 impairment of exploration
and evaluation assets.
Cash and cash equivalents rose from $7,507,716 to
$8,017,760, with the major factor in the movement
being:
-
reduced outflow from operating activities due to
increased receipts and lower payments. Net
cash used in operating activities of $3,420,078
was 54% lower than the corresponding outflow
of $7,493,587 in the previous year;
-
application of cash of $3,174,652 to investing
activities (2023: $8,667,502);
-
net inflow of $7,104,774 from financing activities,
principally being proceeds from the issue of
shares.
The statement of financial position recognises Vintage’s
share of contract liabilities arising from prepayment for
gas under the Vali gas sales agreement between the
ATP 2021 Joint Venture and AGL Energy. The total
value of the liability reduced from $7,302,340 to
$6,979,079 during the year.
Other financial liabilities of $8,716,787 at 30 June
comprise the fully-drawn $10 million debt facility net of
the fair value of warrants issued under the financing
agreement.
Dividends
No dividends were paid or proposed during the year.
21
Significant changes in the state of affairs
The company commenced gas supply to Pelican Point Power under the Odin gas supply contract announced 15 May
2023 and negotiated an additional gas sale agreement for supply from the field for the 2025 and 2026 calendar years.
Supply from the field was previously contracted from start-up to 31 December 2024. The agreement provides for supply
of all gas produced from the Odin gas field in the contract period. Pelican Point Power Station is a 497 MW combined
cycle gas power plant in South Australia. The plant is regarded as a critical infrastructure asset for energy security and
system stability in South Australia.
In April 2024, the company issued 217,044,204 new ordinary shares at $0.01 per share and in May 2024 issued
582,591,013 new ordinary shares at $0.01 per share, to complete a $7,996,352 (before costs) capital raise, as
announced 25 March 2024.
Subsequent events
On 15 August 2024, the Company announced that a Heads of Agreement had been signed with Galilee Energy Limited
(“Galilee”, ASX: GLL) with key terms for a merger via a scheme of arrangement. The proposed merger would be effected
by Vintage acquisition of 100% of Galilee via an all-scrip deal. The Galilee board has unanimously recommended the
proposal, in the absence of a superior proposal and subject to being satisfied with its due diligence enquiries and an
independent expert concluding (and continuing to conclude) that the scheme of arrangement is in the best interests of
Galilee shareholders. The Vintage board unanimously supports the proposal, subject to Vintage being satisfied with its
due diligence enquiries and in the absence of a superior proposal involving Vintage.
Also subsequent to period end, the following performance rights held by key management personnel and other
management personnel lapsed upon their performance conditions not being met:
•
2,739,000 short term incentive performance rights and 4,036,000 long term incentive performance rights held
by the Managing Director;
•
243,800 short term incentive performance rights held by an associate of the Managing Director;
•
1,598,600 short term incentive performance rights and 2,357,000 long term incentive performance rights held
by other key management personnel, and;
•
12,866,500 short term incentive performance rights and 9,363,600 long term incentive performance rights held
by other management personnel.
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
Meetings
Audit and Risk
Committee
Remuneration
Committee
Nomination
Committee
Board member
A
B
A
B
A
B
A
B
Reg Nelson
10
10
3
3
1
1
1
1
Ian Howarth
10
9
3
2
1
1
1
1
Neil Gibbins
10
10
3
3
1
1
1
1
Nick Smart
10
6
3
3
1
1
1
1
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.
22
Performance rights granted to management and directors during the year
Performance rights were granted to the Managing Director and a related party on 5 December 2023, as approved at the
company AGM held 29 November 2023, on the following terms:
•
2,739,000 short term incentives issued to the Managing Director – being employed by the company and
acceptable individual performance up to 1 July 2024, Odin production on-line (or available) over a period of 9
months during FY24; full field development plan finalised for the Vali gas field and approved by the joint venture;
and total capital expenditure for FY24 maintained within 110% of the approved corporate budget capital
expenditure.
•
243,800 short term incentives issued to an associate of the Managing Director – being employed by the
company and acceptable individual performance up to 1 July 2024, Odin production on-line (or available) over
a period of 9 months during FY24; full field development plan finalised for the Vali gas field and approved by
the joint venture; and total capital expenditure for FY24 maintained within 110% of the approved corporate
budget capital expenditure.
Performance rights were granted to other key management personnel on 1 August 2023 on the following terms:
•
1,598,600 short term incentives – being employed by the company and acceptable individual performance up
to 1 July 2024, Odin production on-line (or available) over a period of 9 months during FY24; full field
development plan finalised for the Vali gas field and approved by the joint venture; and total capital expenditure
for FY24 maintained within 110% of the approved corporate budget capital expenditure.
Performance rights were granted to other management and staff on 1 August 2023 on the following terms:
•
12,866,500 short term incentives – being employed by the company and acceptable individual performance up
to 1 July 2024, Odin production on-line (or available) over a period of 9 months during FY24; full field
development plan finalised for the Vali gas field and approved by the joint venture; and total capital expenditure
for FY24 maintained within 110% of the approved corporate budget capital expenditure.
Performance rights on issue
There are no performance rights to ordinary shares in the company at the date of this report.
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, 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 8,290,304 shares
were issued to management and staff on the exercise of Class STI performance rights upon satisfaction of performance
conditions.
23
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 the respective
joint operating agreements and is otherwise conducted using oil industry’s 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 of 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 2024:
Financial year
2020
2021
2022
2023
2024
Revenue
-
-
-
$949,333
$5,152,471
Loss for the year
(2,205,848)
($2,368,480)
($7,978,704)
($11,261,626)
($23,234,241)
Financial year
2020
2021
2022
2023
2024
Share price at
beginning of year
$0.11
$0.06
$0.07
$0.07
$0.05
Share price at
end of year
$0.06
$0.07
$0.07
$0.05
$0.01
Basic loss per
ordinary share
($0.0079)
($0.0044)
($0.0117)
($0.0149)
($0.0228)
Diluted loss per
ordinary share
($0.0079)
($0.0044)
($0.0117)
($0.0149)
($0.0228)
24
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 29 November 2023, 95.14% of eligible votes were cast in favour of the
remuneration report in the 2023 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
Date appointed
Position
Reg Nelson
10 February 2017
Chairman
Neil Gibbins
10 February 2017
Managing Director
Nick Smart
9 November 2015
Non-executive director
Ian Howarth
9 November 2015
Non-executive director
Simon Gray
9 November 2015
Company Secretary and Chief Financial Officer
Remuneration summary directors and other key management personnel
2024
Salary
& fees (1)
Share based
remuneration
Super-
annuation
Termination
benefits
Total
Share based
percentage
of total
Performance related
percentage
Non-executives
Reg Nelson
47,522
-
5,227
-
52,749
-
-
Ian Howarth
31,681
-
3,485
-
35,166
-
-
Nick Smart
31,681
-
3,485
-
35,166
-
-
Executives
Neil Gibbins
267,466
-
26,192
-
293,658
-
-
Simon Gray
109,022
-
12,095
-
121,117
-
-
487,372
-
50,484
-
537,856
25
2023
Salary
& fees (1)
Share based
remuneration
Super-
annuation
Termination
benefits
Total
Share based
percentage
of total
Performance
related percentage
Non-executives
Reg Nelson
71,283
-
7,485
-
78,768
-
-
Ian Howarth
47,522
-
4,990
-
52,512
-
-
Nick Smart
47,522
-
4,990
-
52,512
-
-
Executives
Neil Gibbins
400,008
174,386 (2)
27,492
-
601,886
29%
29%
Simon Gray
132,320
100,763 (2)
12,043
-
245,126
41%
41%
698,655
275,149
57,000
-
1,030,804
Notes to the two tables above:
(1) Executive salaries include leave entitlements.
(2) 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.
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 $348,525 (full time equivalent) inclusive of superannuation. The position is a 0.7 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 $271,226 (full time equivalent) inclusive of superannuation. The position is a 0.4 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 conditions were met) – 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 short term incentives (performance conditions were not met) – being employed by the company and
acceptable individual performance up to 1 July 2024, Odin production on-line (or available) over a period of 9
months during FY24; full field development plan finalised for the Vali gas field and approved by the joint venture;
and total capital expenditure for FY24 maintained within 110% of the approved corporate budget capital
expenditure.
•
Class long term incentives 1 – performance rights (performance conditions were not met) – 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 (performance conditions were not met) – continued employment
with Vintage at 30 June 2024 and the company reach a market capitalisation of $100million prior to 30 June 2024.
26
Employee
Class
Number of
rights granted
Grant Date
$ Value at
Grant date
Number
converted
Number
lapsed
Neil Gibbins
LT1
2,018,000
30 November 2021
113,815
-
-
Neil Gibbins
LT2
2,018,000
30 November 2021
141,260
-
-
Simon Gray
LT1
1,178,500
2 August 2021
42,426
-
-
Simon Gray
LT2
1,178,500
2 August 2021
9,428
-
-
Neil Gibbins
STI
1,845,300
25 November 2022
143,933
1,845,300
-
Neil Gibbins
STI
2,739,000
5 December 2023
82,170
-
-
Simon Gray
STI
1,077,700
1 August 2022
92,682
1,077,700
-
Simon Gray
STI
1,598,600
1 August 2023
63,944
-
-
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 are set out below:
Name
Balance
1 July 2023
Rights
Exercised
Options
Exercised
Net Change
Other
Balance
30 June 2024
Reg Nelson
18,357,986
-
-
14,121,528 (i)
32,479,515
Neil Gibbins
16,188,211
1,845,300
-
13,871,932 (i)
31,905,443
Ian Howarth
15,331,180
-
-
11,793,216 (i)
27,124,396
Nick Smart
6,436,821
-
-
500,000 (i)
6,936,821
Simon Gray
6,336,727
1,077,700
-
500,000 (i)
7,914,427
Notes to the table above:
(i)
Shares were acquired during the year as part of the capital raise announced on 27 March 2024.
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
Balance
1 July 2023
Options
granted
Options
lapsed
Balance
30 June 2024
Reg Nelson
2,000,000
-
-
2,000,000
Ian Howarth
2,000,000
-
-
2,000,000
Nick Smart
2,000,000
-
-
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
Balance
1 July 2023
Rights
lapsed
Rights
converted
Rights
granted
Balance
30 June 2024
Neil Gibbins
5,881,300
-
1,845,300
2,739,000
6,775,000
Simon Gray
3,434,700
-
1,077,700
1,598,600
3,955,600
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.
27
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 2024 are detailed at Note 18 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
28
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 auditor, 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 25 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
30 September 2024
29
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 2024, 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.
Adelaide, 30 September 2024
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.
GRANT THORNTON AUDIT PTY LTD
Chartered Accountants
B K Wundersitz
Partner – Audit & Assurance
30
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 2024 was approved and dated
by the board on 30 September 2024. The corporate governance statement is available on Vintage’s website at:
https://www.vintageenergy.com.au/governance-policies.html
31
Consolidated entity disclosure statement
For year ended 30 June 2024
Vintage Energy Limited does not have any controlled entities and therefore is not required by the Australian Accounting
Standards to prepare consolidated financial statements. As a result, Vintage Energy Limited has not prepared a
consolidated entity disclosure statement.
32
Statement of profit or loss and other
comprehensive income
For year ended 30 June 2024
Notes
30 June
2024
30 June
2023
$
$
Revenue from customers
5
5,152,471
949,333
Interest income
53,124
124,456
Joint operations recoveries
2,305,966
2,794,504
Other income
250
127,217
Total income
7,511,811
3,995,510
Production costs
(2,908,787)
(1,492,611)
Royalty expense
(384,478)
(77,517)
Restoration expense
(19,468)
-
Depreciation expense
11
(1,062,832)
(560,707)
Exploration and valuation expense
(79,848)
(30,010)
Director remuneration expense
6
(416,740)
(821,980)
Employee benefits expense
6
(3,139,604)
(4,342,473)
Impairment expense
12
(19,409,812)
(4,635,464)
Financing costs
6
(1,887,738)
(1,887,738)
Other expenses
6
(1,436,745)
(1,408,636)
(Loss) before income tax
(23,234,241)
(11,261,626)
Income tax benefit
-
-
(Loss) for the year
(23,234,241)
(11,261,626)
Other comprehensive income
-
-
Total comprehensive (loss) attributable to owners of the
(23,234,241)
(11,261,626)
company for the year
Earnings per share
Basic (loss) per share from continuing operations (dollars)
20
(0.0228)
(0.0149)
Diluted (loss) per share from continuing operations (dollars)
20
(0.0228)
(0.0149)
This statement should be read in conjunction with the notes to the financial statements
33
Statement of financial position
As at 30 June 2024
Notes
30 June
2024
30 June
2023
$
$
Current Assets
Cash and cash equivalents
8
8,017,760
7,507,716
Trade and other receivables
9
501,228
1,078,559
Total current assets
8,518,988
8,586,275
Non-Current Assets
Other financial assets
10
175,306
175,306
Property, plant and equipment
11
9,231,051
8,660,457
Exploration and evaluation assets
12
35,098,156
49,403,928
Total non-current assets
44,504,513
58,239,691
Total Assets
53,023,501
66,825,966
Current Liabilities
Trade and other payables
13
2,414,380
993,168
Provisions
14
725,995
908,945
Contract liabilities
15
335,458
1,210,633
Other financial liabilities
16
125,046
145,236
Total current liabilities
3,600,879
3,257,982
Non-Current Liabilities
Provisions
14
4,402,237
4,239,426
Contract liabilities
15
6,643,621
6,091,707
Other financial liabilities
16
8,716,787
7,702,431
Total non-current liabilities
19,762,645
18,033,564
Total Liabilities
23,363,524
21,291,546
Net Assets
29,659,977
45,534,420
Equity
Share capital
17
76,942,581
68,626,145
Reserves
2,816,842
3,974,757
Accumulated (losses)
(50,099,446)
(27,066,482)
Total Equity
29,659,977
45,534,420
This statement should be read in conjunction with the notes to the financial statements
34
Statement of changes in equity
For the year ended 30 June 2024
Notes
Share
capital
Accumulated
losses
Share
based
payments
reserve
Total equity
$
$
$
$
Balance at 1 July 2022
63,442,004
(16,202,947)
3,370,284
50,609,341
(Loss) for the year
-
(11,261,626)
-
(11,261,626)
Other comprehensive income
-
-
-
-
Total comprehensive (loss) for the year
-
(11,261,626)
-
(11,261,626)
Total transactions with owners
Issue of ordinary shares at $0.005
17
5,590,052
-
-
5,590,052
Issue of ordinary shares on conversion of rights
17
24,714
-
(24,714)
-
Fair value of performance rights issued
-
-
1,027,278
1,027,278
Fair value of performance rights lapsed
-
398,091
(398,091)
-
Transaction costs
17
(430,625)
-
-
(430,625)
Balance at 30 June 2023
68,626,145
(27,066,482)
3,974,757
45,534,420
Balance at 1 July 2023
68,626,145
(27,066,482)
3,974,757
45,534,420
(Loss) for the year
-
(23,234,241)
-
(23,234,241)
Other comprehensive income
-
-
-
-
Total comprehensive (loss) for the year
-
(23,234,241)
-
(23,234,241)
Total transactions with owners
Issue of ordinary shares at $0.01
17
7,996,352
-
-
7,996,352
Issue of ordinary shares on conversion of rights
17
966,566
-
(966,566)
-
Fair value of performance rights and options issued
-
-
9,928
9,928
Fair value of performance rights lapsed
-
201,277
(201,277)
-
Transaction costs
17
(646,482)
-
-
(646,482)
Balance at 30 June 2024
76,942,581
(50,099,446)
2,816,842
29,659,977
This statement should be read in conjunction with the notes to the financial statements
35
Statement of cash flows
For the year ended 30 June 2024
Notes
30 June
2024
30 June
2023
$
$
Cash flows from operating activities
Receipts from customers
4,338,158
658,407
Payments to suppliers and employees
(6,708,346)
(7,245,985)
Interest received
53,124
124,455
Financing costs
(1,103,014)
(1,109,042)
Other income – recoveries
-
78,578
Net cash (used in) / from operating activities
26
(3,420,078)
(7,493,587)
Cash flows from investing activities
Payments for exploration and evaluation assets
(3,163,121)
(8,450,755)
Payments for property, plant and equipment
(11,531)
(216,747)
Cash flows (used in) investing activities
(3,174,652)
(8,667,502)
Cash flows from financing activities
Proceeds from issues of shares
17
7,996,352
5,590,052
Payment for share issue costs
(672,859)
(404,249)
Payment of the principal portion of lease liabilities
(218,719)
(228,958)
Net cash from financing activities
7,104,774
4,956,845
Net change in cash and cash equivalents
510,044
(11,204,244)
Cash and cash equivalents at the beginning of year
7,507,716
18,711,960
Cash and cash equivalents at end of year
8
8,017,760
7,507,716
This statement should be read in conjunction with the notes to the financial statements
36
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 2024 were approved and authorised for issue by the board of directors on 30
September 2024.
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 material 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 material 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.
4.4
Income taxes
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.
37
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
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.
38
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.
4.10 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.
4.11 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:
i.
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
ii.
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.
4.12 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.
39
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.
4.13 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.
40
4.14 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.
4.15 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 in net of any directly attributable transaction costs are allocated
to share capital.
4.16 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.
41
4.17 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.
4.18 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 2024 the company recognised a loss of $23,234,241, had net cash outflows from
operating and investing activities of $6,594,730 and had accumulated losses of $50,099,446 as at 30 June 2024. 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.
4.19 Comparative figures
When required by Accounting Standards, comparative figures have been adjusted to conform to changes in presentation
for the current financial year.
4.20 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.
42
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.
Development costs
The costs of exploration and evaluation assets are reclassified as Development assets, to be amortised with reference
to estimated field reserves, only when the technical feasibility and commercial viability of an area of interest becomes
demonstrable. This requires, where applicable, a full field development plan to be approved by relevant joint venture
participants. At that time, subject to an impairment test, the accumulated costs of an area of interest are reclassified as
Development assets, with the exception of those asset costs which are classified separately as property, plant and
equipment.
Costs of goods sold
When recognising revenue from the sale of hydrocarbons, the company also recognises applicable costs of goods sold.
In doing so, judgement is made in considering the nature of costs as being-revenue related or capital in nature.
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.
4.21 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.
43
5
Revenue from customers
Sale of hydrocarbon products:
30 June
2024
30 June
2023
$
$
Natural gas (i)
5,013,646
949,333
Condensate and other liquids (i)
138,825
-
5,152,471
949,333
(i)
Sales are classed as point in time and generated from sales within
Australia.
6
Loss for the year
Loss for the year from continuing operations includes the following expenses:
30 June
2024
30 June
2023
$
$
Director remuneration expense
Director salary and fees
(378,351)
(566,334)
Director post-employment benefits
(38,389)
(44,957)
Share based payments
-
(210,689)
(416,740)
(821,980)
Employees benefit expense
Short-term employee benefits – salaries and fees
(2,788,628)
(2,687,513)
Post-employment benefits
(290,808)
(285,233)
Decrease / (Increase) in employee benefit provisions
170,139
(295,582)
Recharge of salaries and fees to exploration expenditure
86,927
84,952
Share based payments
(9,928)
(816,588)
Other staff costs
(307,306)
(342,509)
(3,139,604)
(4,342,473)
Financing expenses
Amortisation of borrowing costs
(787,738)
(787,738)
Interest expense – debt facility
(1,100,000)
(1,100,000)
(1,887,738)
(1,887,738)
Other expenses
Accounting and audit
(102,215)
(107,524)
Conferences
(15,714)
(33,300)
Consulting expenses
(84,004)
(154,203)
Computer expenses
(406,735)
(364,078)
Insurances
(147,269)
(140,400)
Marketing
(175,020)
(170,000)
Travel and accommodation
(20,049)
(29,482)
Legal fees
(163,737)
(100,703)
Share registry and exchange costs
(101,767)
(94,195)
Subscriptions and technical publications
(44,215)
(62,527)
Sundry
(176,020)
(152,224)
(1,436,745)
(1,408,636)
44
7
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:
30 June
2024
30 June
2023
$
$
Loss from operations
(23,234,241)
(11,261,626)
Income tax expense / (benefit) calculated at 25% (2023: 25%)
(5,808,560)
(2,815,407)
Non-deductible expenses
4,268
425,372
Unused tax losses and tax offsets not recognised as deferred tax assets
5,804,292
2,390,035
Tax expense/(benefit)
-
-
Tax expense/(benefit) comprises
Current tax expense
(5,804,292)
(2,390,035)
Tax losses not brought to account (1)
2,020,712
4,022,799
Deferred tax liability not brought to account (2)
3,783,580
(1,632,764)
Tax expense (benefit)
-
-
(1) Total tax losses not brought to account at 30 June 2024 total $20,692,320 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.
8
Cash and cash equivalents
Cash and cash equivalents consist of the following:
30 June
2024
30 June
2023
$
$
Cash on hand
9
9
Cash at bank (1)
7,672,531
7,055,408
Restricted cash (2)
345,220
452,299
8,017,760
7,507,716
(1) Includes amounts pledged as security for bank guarantees and credit facilities amounting
to $137,865 (2023 $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.
9
Trade and other receivables
30 June
2024
30 June
2023
$
$
Trade receivables
259,584
153,412
Joint operations receivables
167,341
663,033
GST receivables
609
43,172
Other receivables
73,694
218,942
501,228
1,078,559
45
10 Other financial assets
30 June
2024
30 June
2023
$
$
Financial surety payments (i)
175,306
175,306
175,306
175,306
(ii)
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.
11 Property, plant and equipment
Field plant &
equipment
Furniture and
fittings
Right of use asset
Total
$
$
Assets at cost
Balance at 30 June 2022
-
260,651
657,421
918,072
Additions
-
216,748
-
216,748
Reclassified (i)
8,598,361
-
-
8,598,361
Balance at 30 June 2023
8,598,361
477,399
657,421
9,733,181
Additions
-
11,531
398,014
409,545
Reclassified (i)
1,223,881
-
-
1,223,881
Disposal at end of lease
-
-
(657,421)
(657,421)
Balance at 30 June 2024
9,822,242
488,930
398,014
10,709,186
Accumulated depreciation
Balance at 30 June 2022
-
214,938
297,079
512,017
Depreciation expense
291,358
53,144
216,205
560,707
Balance at 30 June 2023
291,358
268,082
513,284
1,072,724
Depreciation expense
787,878
86,593
188,361
1,062,832
Disposal at end of lease
-
-
(657,421)
(657,421)
Balance at 30 June 2024
1,079,236
354,675
44,224
1,478,135
Net book value 30 June 2023
8,307,003
209,317
144,137
8,660,457
Net book value 30 June 2024
8,743,006
134,255
353,790
9,231,051
(i)
Reclassified from Exploration and Evaluation Assets
12 Exploration and evaluation assets
30 June
2024
30 June
2023
$
$
Exploration and evaluation
35,098,156
49,403,928
35,098,156
49,403,928
30 June
2024
30 June
2023
$
$
Balance at 1 July
49,403,928
49,167,004
Additions for the year (i)
6,327,920
13,470,749
Reclassified to Property, Plant & Equipment (ii)
(1,223,880)
(8,598,361)
Impairment (iii)
(19,409,812)
(4,635,464)
Balance at 30 June
35,098,156
49,403,928
46
(i)
The increase in exploration and evaluation assets during the year included expenditure on:
Opening
balance
$
Additions
$
Reclassifi-
cation
$
Impairment
$
Closing
balance
$
ATP 2021 Joint Venture (iv)
24,667,140
4,435,013
-
-
29,102,153
Galilee Deeps Joint Venture *
7,901,239
8,421
-
(7,909,660)
-
PRL 249 Joint Venture *
8,494,880
50,190
-
(8,545,070)
-
PRL 211 Joint Venture
4,712,822
1,695,424
(1,223,880)
-
5,184,366
EP 126, Bonaparte Basin
2,920,874
34,208
-
(2,955,082)
-
PEP 171 Joint Venture
573,296
88,860
-
-
662,156
GSEL 672
133,677
15,804
-
-
149,481
Total
49,403,928
6,327,920
(1,223,880)
(19,409,812)
35,098,156
*non-operated permit
(ii)
Reclassified to Property, Plant and Equipment during the year, upon completion of PRL 211 joint venture field
facility/pipeline works.
(iii)
Galilee Deeps Joint Venture costs were fully impaired at 31 December 2023, as no exploration activities in the Basin
have been budgeted for in the near future. Albany-2 well costs totalling $4,635,464 had previously been impaired at 30
June 2023, as no economic hydrocarbons were produced during the flowback period of the well and, after consideration,
it was determined there was a low likelihood of economic recovery of gas from the well.
EP 126 (Bonaparte Basin) costs were also fully impaired at 31 December 2023, as the company has concluded that
unfettered exploration access to the permit is not likely in the foreseeable future, due to the Northern Territory
government’s ongoing declaration of approximately 50% of the permit, including the Cullen-1 well site as a ‘Reserved
Area’.
PRL 249 (ex PEL 155) joint venture costs relating to the Nangwarry-1 well were impaired at 30 June 2024, as the
company has been unable to identify an immediate or near-term path to commercialisation for the asset.
(iv)
The ATP 2021 permit expired on 31 May 2024. The joint venture parties have unanimously voted to accept draft terms
and conditions offered by the Queensland regulator for the renewal of ATP 2021 for a period of 6 years from 1 June
2024, pending formal permit grant by the regulator.
13 Trade and other payables
Trade and other payables consist of the following:
30 June
2024
30 June
2023
Current
$
$
Trade payables
852,216
752,082
Joint Venture payable
1,415,767
-
Other payables
146,397
241,086
Total trade & other payables
2,414,380
993,168
14 Provisions
30 June
2024
30 June
2023
$
$
Current
Employee Benefits
725,995
908,945
725,995
908,945
47
Non-current
Employee benefits
259,737
246,926
Restoration provision
4,142,500
3,992,500
4,402,237
4,239,426
Movement in employee benefits
Opening balance
1,155,871
860,289
Movement for the year
(170,139)
295,582
Closing balance
985,732
1,155,871
Movement in restoration provision
Opening balance
3,992,500
970,000
Movement for the year
150,000
3,022,500
Closing balance
4,142,500
3,992,500
15 Contract liabilities
30 June
2024
30 June
2023
$
$
Deferred revenues
Current
335,458
1,210,633
Non-current
6,643,621
6,091,707
Total
6,979,079
7,302,340
In March 2022, 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.
16 Other financial liabilities
30 June
2024
30 June
2023
Current
$
$
Lease liability (i)
125,046
145,236
125,046
145,236
Non-current
Lease liability (i)
226,619
-
Loan facility – PURE Asset Management (ii)
8,490,168
7,702,431
8,716,787
7,702,431
(i)
Movement in lease liability
Opening balance
145,236
366,002
Lease liability recognised
398,014
-
Rent payments made during the year
(202,732)
(228,958)
Interest expense on lease liability recognised during the year
11,147
8,192
351,665
145,236
(ii)
Loan facility reconciliation
Financing facility (PURE Asset Management)
10,000,000
10,000,000
Net of transaction costs:
Fair value of warrants issued
(2,647,059)
(2,647,059)
Amortisation of warrants
1,378,676
716,912
Carrying amount of other financing facility establishment costs
(241,449)
(367,422)
8,490,168
7,702,431
48
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. Subsequent to draw down, Vintage’s capital raise activities have adjusted the exercise price of
the warrants to 1 cent per warrant, in keeping with the anti-dilution provisions of the debt facility.
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.
17 Issued capital
30 June
2024
30 June
2023
$
$
Ordinary shares
76,942,581
68,626,145
Balance at 30 June
76,942,581
68,626,145
30 June
2024
30 June
2024
30 June
2023
30 June
2023
Number
$
Number
$
Shares issued and fully paid
Ordinary Shares (i)
Beginning of the year
858,518,459
68,626,145
746,168,216
63,442,004
Shares allotted during the period
799,635,217
7,996,352
111,801,044
5,590,052
Conversion of performance rights
11,377,604
966,566
549,200
24,714
Share issue costs
-
(646,482)
-
(430,625)
Total ordinary shares
1,669,531,280
76,942,581
858,518,460
68,626,145
Total contributed equity at 30 June
1,669,531,280
76,942,581
858,518,460
68,626,145
(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:
•
217,044,204 ordinary shares via a capital placement at $0.01 per share
•
582,591,013 ordinary shares via an accelerated offer at $0.01 per share
•
11,377,604 ordinary shares on the conversion of performance rights
49
18 Share options and performance rights
Share options
In December 2021, 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
Non-executive
directors
6,000,000
-
$0.133
-
6,000,000
Total under option
6,000,000
-
-
6,000,000
Shares issued on exercise of remuneration performance rights
A total of 11,377,604 ordinary shares were issued to management and staff on exercise of performance rights, following
performance conditions being 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
Balance at
1 July 2023
Granted
during the
year
Exercised on
performance
condition met
Lapsed
Balance at
30 June
2024
Fair value
at grant
date
$
Class LT1
Aug/Nov
2021
7,878,300
-
-
-
7,878,300
324,786
Class LT2
Aug/Nov
2021
7,878,300
-
-
-
7,878,300
188,142
Class STI
Aug/Nov
2022
11,377,604
-
11,377,604
-
-
732,370
Class STI
Aug/Nov
2023
-
17,447,900
-
-
17,447,900
668,088
The Class STI rights have been valued using the Black-Scholes methodology at the grant date.
50
(i)
Refer table below for rights issued to the Managing Director
Performance rights issued under the employee incentive plan were issued under the following general performance
conditions:
Class STI performance rights – 11,377,604 rights issued August 2022/November 2022 – 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 STI performance rights – 17,447,900 rights issued August 2023/November 2023 – being employed by the
company and acceptable individual performance up to 1 July 2024, Odin production on-line (or available) over a period
of 9 months during FY24; full field development plan finalised for the Vali gas field and approved by the joint venture;
and total capital expenditure for FY24 maintained within 110% of the approved corporate budget capital expenditure.
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 29 November 2023:
Class of Performance Right
Maximum number of performance rights
Class ST1
2,739,000
19 Interest in joint operations
The company has an interest in the following unincorporated joint operations whose principal activities are oil and gas
exploration:
30 June
2024
30 June
2023
% Interest
% Interest
Galilee Basin ATP-743, ATP-744 (i)
30
30
Galilee Basin ATP-1015 (i)
30
30
Galilee Basin PCAs 319-324 (i)
30
30
Otway Basin PRL 249 (ex PEL 155) (ii)
50
50
Otway Basin PEP 171
25
25
ATP 2021
50
50
PRL 211
50
50
PELA 679 (iii)
-
-
i.
“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 and 1015 under the PCAs have been renewed for twelve years.
ii.
Petroleum Retention Licence (PRL) 249, covering the Nangwarry CO2 discovery area.
iii.
The company was successful in bidding for Block CO2019-E (now PELA 679) in the south-west of the Cooper Basin in South
Australia. Since then, the company has been successful in executing a farmout agreement with Sabre Energy Ltd (as
announced to the market on 22 April 2024), which means that once an appropriate land access agreement is in place with
the Dieri Aboriginal Corporation RNTBC and the South Australian government, the company will then have a 50% interest in
PEL 679 and Sabre will have a 50% interest and Sabre will fund the Year 1 3D seismic program (approximate cost to Sabre
$4.5million, which includes $200,000 of past costs).
51
20 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:
30 June
2024
30 June
2023
Number
Number
Weighted average number of shares used in basic earnings per share
1,020,208,215
755,988,402
Weighted average number of shares used in dilutive earnings per share
1,020,208,215
755,988,402
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.
21 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:
30 June
2024
$
30 June
2023
$
Exploration and evaluation
No longer than 1 year
5,006,000
4,371,000
Longer than 1 year but less than 5 years
2,448,000
683,500
7,454,000
5,054,500
22 Financial instruments
(a)
Capital risk management
The company manages its capital to ensure that it will be able to continue as a going concern. As at 30 June
2024 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 $6,979,079.
(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.
52
(c)
Categories of financial instruments
30 June
2024
$
30 June
2023
$
Categories of financial instruments
Financial assets
Cash and cash equivalents
8,017,760
7,507,716
Trade and other receivables
500,619
1,035,387
Other financial assets
175,306
175,306
Total financial assets
8,693,685
8,718,409
Financial liabilities
Trade and other payables
2,414,380
993,168
Other financial liabilities
8,841,833
7,847,667
Total financial liabilities
11,256,213
8,840,835
(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
Less than 1
month
1 to
3 months
3 months
to 1 year
1 to 5 years
5
plus
Total
2024
Financial assets:
Non-interest bearing
0.00%
9
500,619
-
175,306
-
675,934
Variable interest rate
0.75%
7,534,666
345,220
-
-
-
7,879,886
Fixed interest rate
3.55%
-
-
137,865
-
-
137,865
Financial
liabilities:
Non-interest bearing
-
(2,414,380)
(125,046)
(226,619)
-
(2,766,045)
Interest bearing (i)
11%
-
-
(10,000,000)
-
(10,000,000)
7,534,675
(1,568,541)
12,819
(10,051,313)
-
(4,072,360)
53
Weighted
average
effective
interest
rate
Less than 1
month
1 to 3
months
3 months to
1 year
1 to 5 years
5
plus
Total
2023
Financial assets:
Non-interest bearing
0.00%
9
1,035,387
-
175,306
-
1,210,702
Variable interest rate
0.75%
6,917,543
452,299
-
-
-
7,369,842
Fixed interest rate
3.05%
-
-
137,865
-
-
137,865
Financial
liabilities:
Non-interest bearing
-
(993,168)
(145,236)
-
-
(1,138,404)
Interest bearing (i)
11%
-
-
-
(10,000,000)
-
(10,000,000)
6,917,552
494,518
(7,371)
(9,824,694)
-
(2,419,995)
(i)
$10,000,000 interest bearing financial liabilities reported exclusive of transaction costs.
(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 $103,601.
(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 (2023: net fair value).
Financial assets and financial liabilities are recognised at amortised cost.
23 Contingent liabilities
No contingent liabilities exist as at the date of the financial report.
54
24 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:
30 June
2024
$
30 June
2023
$
Short-term employee benefits
487,373
698,655
Share based payments
-
275,150
Post-employment benefits
50,484
57,000
537,857
1,030,805
(b)
Transactions with affiliates
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 (2023 – nil).
25 Remuneration of auditors
30 June
2024
$
30 June
2023
$
Audit or review of the financial report
98,611
96,965
Other Services
3,605
7,990
102,216
104,955
Other services include fees for taxation services.
The company’s auditor is Grant Thornton Audit Pty Ltd.
55
26 Cash flow information
Reconciliation of cash flows from operating activities
30 June
2024
$
30 June
2023
$
Loss for the year
(23,234,241)
(11,261,626)
Depreciation
1,062,832
560,707
Shares options and performance rights expensed
9,927
1,027,277
Wages and salaries capitalised to exploration
(86,927)
(84,952)
Recoveries offset against exploration
(1,186,488)
(2,794,504)
Impairment
19,409,812
4,635,464
Changes in assets and liabilities
Increase / (decrease) in contract liabilities
(323,260)
(197,660)
(Increase) / decrease in trade and other receivables
133,159
1,362,240
Increase / (decrease) in provisions
(170,139)
295,582
Increase / (decrease) in trade and other payables
150,378
(1,825,087)
Increase / (decrease) in other liabilities
814,869
788,972
(3,420,078)
(7,493,587)
27 Company information
The principal place of business of the company is 58 King William Road, Goodwood, SA 5034.
56
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:
i.
Giving a true and fair view of its financial position as at 30 June 2024 and of its performance for the
financial year ended on that date;
ii.
Complying with Australian Accounting Standards (including the Australian Accounting Interpretations)
and the Corporations Regulations 2001;
iii.
The statement that a Consolidated Entity Disclosure Statement is not required is true and correct as at
30 June 2024.
2.
The Managing Director and the Chief Financial Officer have each declared that:
i.
the financial records of the company for the year ended have been properly maintained in accordance
with section 295A of the Corporations Act 2001;
ii.
the financial statements and notes for the financial year comply with the Accounting Standards; and
iii.
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
30 September 2024
57
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
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
Opinion
We have audited the financial report of Vintage Energy Limited (the Company), which comprises the statement of
financial position as at 30 June 2024, 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
material accounting policy information, the consolidated entity disclosure statement 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 2024 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 Company 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.
58
Material uncertainty related to going concern
We draw attention to Note 4.18 in the financial statements, which indicates that the Company incurred a loss of
$23,234,241 and had net cash outflows from operating and investing activities of $6,594,730 during the year
ended 30 June 2024, and as of that date, the Company’s accumulated losses were $50,099,446. As stated in
Note 4.18, these events or conditions, along with other matters as set forth in Note 4.18, 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 12
At 30 June 2024 the carrying value of exploration
and evaluation assets was $35,098,156.
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:
•
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.
59
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 2024, 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:
a the financial report that gives a true and fair view in accordance with Australian Accounting Standards and
the Corporations Act 2001 (other than the consolidated entity disclosure statement); and
b the consolidated entity disclosure statement that is true and correct in accordance with the Corporations
Act 2001, and
for such internal control as the directors determine is necessary to enable the preparation of:
i
the financial report that gives a true and fair view and is free from material misstatement, whether due
to fraud or error; and
ii
the consolidated entity disclosure statement that is true and correct and is free of misstatement,
whether due to fraud or error.
In preparing the financial report, the Directors are responsible for assessing the Company’s/Group’s ability to
continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern
basis of accounting unless the Directors either intend to liquidate the Company/Group or to cease operations, or
have no realistic alternative but to do so.
Auditor’s responsibilities for the audit of the financial report
Our objectives are to obtain reasonable assurance about whether the financial report as a whole is free from
material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion.
Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance
with the Australian Auditing Standards will always detect a material misstatement when it exists. Misstatements
can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably
be expected to influence the economic decisions of users taken on the basis of this financial report.
A further description of our responsibilities for the audit of the financial report is located at the Auditing and Assurance
Standards Board website at: http://www.auasb.gov.au/auditors_responsibilities/ar2_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 2024.
In our opinion, the Remuneration Report of Vintage Energy Limited, for the year ended 30 June 2024 complies
with section 300A of the Corporations Act 2001.
60
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.
Adelaide, 30 September 2024
GRANT THORNTON AUDIT PTY LTD
Chartered Accountants
B K Wundersitz
Partner – Audit & Assurance
61
Schedule of tenements
Tenement
Basin
Operator
Interest held
30 June 2024
Interest held
30 June 2023
Queensland
ATP 743 (1)
Galilee
Comet Ridge Ltd
30%
30%
ATP 744 (1)
Galilee
Comet Ridge Ltd
30%
30%
ATP 1015 (1)
Galilee
Comet Ridge Ltd
30%
30%
PCAs
319,320,321,322,323 &
324 (1)
Galilee
Comet Ridge Ltd
30%
30%
ATP 2021
Cooper/Eromanga
Vintage Energy Ltd
50%
50%
South Australia
PRL 211
Cooper/Eromanga
Vintage Energy Ltd
50%
50%
PRL 249 (ex PEL 155)
Otway
Otway Energy Pty Ltd
50%
50%
GSEL 672
Otway
Vintage Energy Ltd
100%
100%
PELA 679 (2)
Cooper/Eromanga
Vintage Energy Ltd
-
-
Victoria
PEP 171
Otway
Vintage Energy Ltd
25%
25%
Northern Territory
EP 126
Bonaparte
Vintage Energy Ltd
100%
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 and will
then transfer 50% to Sabre Energy Limited as per the executed farmout agreement.
62
Information pursuant to the listing
requirements of the ASX
Number of holders of equity securities
Ordinary shares
At 30 September 2024, the issued capital comprised of 1,669,531,280 ordinary shares held by 2,517 holders.
Employee performance rights
At 30 September 2024, there were zero performance rights on issue with a $nil exercise price.
Spread details as at 30 September 2024 for ordinary shares
Holding Ranges
Holders
Total Units
% Issued Share Capital
1 - 1,000
43
3,676
0.00%
1,001 - 5,000
59
238,414
0.01%
5,001 – 10,000
300
2,357,933
0.14%
10,001 – 100,000
1,129
49,308,997
2.95%
100,001 – 9,999,999,999
986
1,617,622,260
96.89%
Totals
2,517
1,669,531,280
100.00%
Holders less than a marketable parcel = 1,202
63
Substantial shareholders as at 30 September 2024
Number of shares
%
REGAL FUNDS MANAGEMENT PTY LIMITED
239,238,961
14.33%
Top twenty shareholders as at 30 September 2024
Position
Holder Name
Holding
%
1
JP MORGAN NOMINEES AUSTRALIA PTY LIMITED
195,596,452
11.72%
2
CITICORP NOMINEES PTY LIMITED
116,892,561
7.00%
3
VINTAGE UNDERWRITING INVESTMENTS PTY LTD
69,569,357
4.17%
4
ALLEGRO CAPITAL NOMINEES PTY LTD
59,855,960
3.59%
5
ITA VERO PTY LTD
34,846,154
2.09%
6
COOEE INVESTMENTS PTY LTD
32,762,231
1.96%
7
MR ANTONIOS SYRIANOS
30,000,000
1.80%
8
HOWZAT SERVICES PTY LTD
27,124,395
1.62%
9
VIEWADE PTY LIMITED
24,229,329
1.45%
10
LILLICRAP SUPER PTY LTD
22,896,924
1.37%
11
GEELLE PTY LTD
21,177,284
1.31%
12
N M GIBBINS
20,926,444
1.25%
13
UBS NOMINEES PTY LTD
20,357,462
1.22%
14
AURELIUS RESOURCES PTY LTD
17,621,818
1.06%
15
MR LYNDON EUGENE FLORANCE
15,000,000
0.90%
16
SERLETT PTY LTD
14,878,680
0.89%
17
MR REGINALD NELSON & MRS SUSAN NELSON
14,857,695
0.89%
18
MR MALCOLM JOHN MCCLURE
11,974,150
0.72%
19
MR BRIAN RAYMOND SMITH
11,641,226
0.70%
20
GP SECURITIES PTY LTD
11,571,646
0.69%
Total
774,479,768
46.39%
Total Issued Capital
1,669,531,280
100.00%
64
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
Low estimate of Prospective Resources. The abbreviation “1U” is an informal, alternative acronym
Best, 2U
Best estimate of Prospective Resources. The abbreviation “2U” is an informal, alternative acronym.
High, 3U
High estimate of Prospective Resources. The abbreviation “3U” is an informal, alternative acronym.
Play
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.
Lead
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.
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.
Chance of Discovery
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.
1C
Low estimate of Contingent Resources.
2C
Best estimate of Contingent Resources.
3C
High estimate of Contingent Resources.
Reserves
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
Possible
Proved plus Probable plus Possible reserves (deterministic or probabilistic).
65
Range of Uncertainty
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.
Deterministic
A deterministic estimate is a single discrete scenario within a range of outcomes. Each of the input
parameters is a single value.
Probabilistic
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.
P90
Probabilistic Estimate
From the probabilistic method there is a greater than 90% cumulative probability that quantities
estimated would ultimately be exceeded.
P50
Probabilistic Estimate
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.
P10
Probabilistic Estimate
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
Two dimensional; usually referring to a seismic survey with a coarse grid of orthogonal lines.
3D
Three dimensional; usually referring to a seismic survey with a fine grid of orthogonal lines.
ASX
Australian Securities Exchange.
ATP
Authority to Prospect which is an exploration licence in Queensland.
B
Billion 109, or 1,000 million.
bbl
One barrel of crude oil contains 42 US gallons (or 34.97 imperial gallons, or, 159 litres).
Bcf
Billion cubic feet.
Blooie Line
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.
Boe
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.
Bopd
A liquid flow rate expressed in barrels of oil per day.
Brent
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
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
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
A period from 145 to 66 million years ago.
CSG
Coal seam gas.
Devonian
A period from 419 to 359 million years ago.
DST
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.
EP
Exploration Permit for petroleum as in the Northern Territory.
66
Fault
A fracture in a rock mass, with the movement of one side past the other.
Gas Condensate
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.
GJ
Gigajoule. A joule is a measure of heating value. 1 GJ is equal to 1 x 109 joules.
Graben
Is a fault block, generally greater in length than its width that has been downfaulted relative to
the adjacent blocks.
Hydraulic fracturing
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.
Hydrocarbon
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.
Improved Recovery
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).
Joule
Is the energy dissipated as heat when an electric current of one ampere passes through a
resistance of one ohm for one second.
Jurassic
A period from 201-145 million years ago
KB
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.
Km
Kilometres.
Km2
A square kilometre.
LNG
Liquefied natural gas.
LNG Netback Price
Free on board (“FOB”) export price of LNG at the receiving terminal. The buyer is responsible
for shipping and transportation.
Logs
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.
m
Metres
M
1,000
MM
Millions 106
Net pay
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.
OGIP, OGIIP
Original gas (initially) in place. The estimated quantity of gas which may originally have
occurred in a reservoir.
OOIP, OOIIP
Original oil (initially) in place. The estimated quantity of oil which may originally have occurred
in a reservoir.
Oil Shale
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
P&A
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.
PEL
Petroleum Exploration Licence as used in South Australia.
Permian
A period 299 to 252 million years ago.
67
Permit Areas
The land subject of the Permits in which Vintage Energy has an interest from time to time.
PJ
Petajoule. A joule is a measure of heating value. 1 PJ is equal to 1 x 1015 joules
Pool
An individual and separate accumulation of petroleum in a reservoir.
Porosity
The pore space in a reservoir which can contain fluids, either water, oil, or gas. (i.e., the space
between beach sand grains).
PRL
Petroleum Retention Licence as used in South Australia
Reflectors
As in seismic reflectors. Refer to Seismic.
Reservoir
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.
Resources
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.
Risk
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.
RT
Rotary Table. Refer to KB, kelly bushing.
RTSTM
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.
scf
Standard cubic feet. Usually referring to gas at standard conditions.
scf/d
A flow rate in standard cubic feet per day.
Seismic
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.
Shale volume
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.
68
TCF
Trillion cubic feet of gas.
TD
Total depth of the well.
Tectonic
Pertaining to forces and the geological architecture that results, such as faults, folds etc.
Tenement
Ground granted for exploration or production purposes.
TJ
Terajoule; a joule is a measure of heating value. 1 TJ is equal to 1 x 1012 joules
TOC
Total organic carbon, a measure of the dry weight percent of organic carbon within rocks.
Triassic
A period from 252-201 million years ago
Unconventional oil and
gas
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.
VR
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.
Water saturation
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.
WTI
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.
69
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