ANNUAL
REPORT
FY24
CHAIRMAN’S FOREWORD
03
MANAGING DIRECTOR’S REPORT
07
OUR VALUES
11
OUR BUSINESS
12
OUR SOCIAL AND
ENVIRONMENTAL COMMITMENT
15
KEY RESULTS
17
Financial
17
Operations & Reserves
19
Equity
20
Gas & Oil Revenue
20
Capital Expenditure
20
RESERVES & CONTINGENT RESOURCES
21
Reserves
22
Contingent Resources
23
REVIEW OF OPERATIONS
25
Safety
25
Production
25
Gippsland Basin
26
Otway Basin (Offshore)
29
Otway Basin (Onshore)
31
Cooper Basin
32
PORTFOLIO
36
DIRECTORS
37
EXECUTIVE LEADERSHIP
41
KEY PERFORMANCE INDICATORS
45
PROUDLY
PART OF
AUSTRALIA’S
ENERGY
FUTURE.
We are proud to explore, develop and produce
domestic gas for Australians to deliver shareholder
value, support energy security and contribute to the
wealth of our nation.
CONTENTS
COOPER ENERGY LIMITED | ABN 93 096 170 295
The terms “the Company” and “Cooper Energy” are used in this Annual Report to refer to Cooper Energy
Limited and/or its subsidiaries. The terms “2024”, “FY24” and the “2024 financial year” refer to the 12 months
ended 30 June 2024 unless otherwise stated. References to 2023, FY23 or 2025, FY25 refer to the 12
months ending 30 June of that year. References to information and events that occurred after 30 June 2024
are current as at 31 August 2024 unless otherwise stated. This Annual Report uses terms and abbreviations
relevant to the company, its accounts and the petroleum industry. Information on abbreviations and terms,
rounding and reserves and resources reporting is provided at the back of this report.
ACKNOWLEDGEMENTS
Cooper Energy recognises and
acknowledges First Nations Peoples as
the Traditional Owners and Custodians
of the lands where we operate. We pay
respects to the Elders past and present
of the world’s oldest living culture.
02
01
CHAIRMAN’S
FOREWORD
SUMMARY
The 2024 financial year was a period of change for
Cooper Energy which saw operational successes,
project challenges and renewal of the Board and
management team. Our company is now on a strong
footing to increase exposure to the East Coast domestic
gas market and to execute its next phase of growth as a
consequence of the strategic focus being driven by our
Managing Director and her team.
Our Company continued its commendable health and
safety performance in FY24, with a total recordable
injury frequency rate (TRIFR) of 4.35 per million
hours worked. While we have a target rate of zero,
our TRIFR was well below the industry benchmark of
5.86, reflecting our unrelenting focus on a safe work
environment for our employees.
FY24 was the first full year of Jane Norman’s tenure as
your CEO and Managing Director. Within a few short
months of joining us, Jane reshaped the management
of our Company, with greater clarity around
accountabilities and responsibilities within the executive
team and a sharper focus on operational success. The
team working with Jane is well placed to deliver our new
strategy in the interests of shareholders.
Pleasingly, our team’s focus on improving operations
at the Orbost Gas Processing Plant started to deliver
production benefits through the year. Since July 2024,
hardly a week has gone by without a new production-
related record. Higher and more reliable production from
Orbost is allowing us to generate record revenue and
increased margins on greater volumes of spot gas sales
and reduced production costs. Maximising production at
Orbost remains a priority for FY25 and in September, for
the first time in the Orbost plant’s life, we recorded an
average of 68 TJ/day for a full week, much to the great
joy of the entire Company and all shareholders. I’m
confident the dedication and focus of our team will result
in further production improvements.
Completion of the Basker, Manta and Gummy wells
decommissioning project was a major milestone for
the company. Projects such as these carry serious
operational, environmental and safety risks, so I am
very pleased that no lost time injuries or significant
environmental incidents occurred despite the more than
360,000 hours worked on the project. The project’s cost
was within the Company’s revised guidance, although
it was above our initial budget, largely due to issues out
of the Company’s control. This impacted the Company’s
debt position and the Company is focused on growing
underlying cash generation to manage this in FY25 and
beyond.
Importantly, over FY24 our Company began
preparations for its next major growth project, the East
Coast Supply Project (ECSP). The ECSP features
low-risk exploration prospects and utilises our existing
infrastructure to offer highly attractive returns and an
accelerated development pathway. The Company’s
preferred three-well ECSP programme would provide
one of the largest sources of new gas supply from 2028
onwards for the tight Southeast Australian gas market.
The management team is working assiduously to
progress funding, partnering and approvals workstreams
to make this much-needed project a reality.
Our Company entered FY25 with a clear focus on
improving shareholder returns by increasing production
into a tight market, maximising our operational leverage
and de-risking growth.
Importance of new gas supply
When it comes to gas in Australia, it is encouraging to
see a change in the narrative from the media, regulators
and legislators. There is recognition that gas will play
a very important role through the energy transition
and beyond, and that the lack of new local supply into
Southeast Australia creates risks to that transition.
Without new local gas supply, Southeast Australian
consumers will be forced to rely on higher-cost and
higher-emissions gas diverted from Queensland and/or
imported as LNG.
Millions of Australians rely on affordable natural gas
every day in their homes and for their jobs. Gas is
essential in the production of everyday products like
bricks and glass and for reliable electricity supply. Our
Company is one of few able to help address looming
gas shortages in Southeastern Australia with low-cost,
local supply.
Higher and more
reliable production
from Orbost is
allowing us to
generate record
revenue and
increased margins
on greater volumes
of spot gas sales
and reduced
production costs.
04
03
Board renewal
I am delighted to welcome two new directors to your
Board with the appointments of Mr Gary Gray AO
and Mr Frank Tudor. Each is offering themselves to
shareholders for election at the Annual General Meeting
(AGM) in November and I commend them to you. Each
of them brings outstanding expertise and I am very
confident each will be effective in helping the company
to maximise shareholder value as we play our part in the
nation’s energy transition. Full details of the impressive
experience and accomplishments of Gary Gray and
Frank Tudor can be found in the AGM Notice of Meeting.
I acknowledge also Mr Jeff Schnieder, who recently
advised the Board that he will retire at our upcoming
AGM. Jeff is the Company’s longest serving board
member, having overseen a transformative period in
the Company’s history. At all times Jeff brought an
inquisitive mind and helpful insights to our discussions.
I thank Jeff most sincerely for his service and extend to
him and his wife our best wishes in his retirement.
Following Jeff’s retirement and the appointment of the
new directors, the average tenure of directors on the
Board will be less than four years. The Board will also
be genuinely diverse, not just in gender but also in
background, experience and thought.
Jeff’s departure will leave me as the longest-serving
director on the Board. My current term expires in
2025. While my enthusiasm for the company remains
undiminished, buoyed by the successes we have had
in various operational areas in the last 12 months,
the Board will continue to reflect on its composition to
ensure it remains contemporary in the best interests
of shareholders.
IN CONCLUSION
On behalf of the Board, I express my appreciation to
shareholders for their loyalty and look forward to the
Company’s delivering its promises in FY25. With your
Company having come through many challenges during
the past few years, we now look forward to realising
our potential. Maximising production from Orbost and
bringing new supply into the market via the ECSP
will maximise shareholder returns consistent with our
purpose of being part of Australia’s energy future. I
thank all Cooper Energy staff for their hard work and
persistence.
The Company’s long-term strategy is appropriate,
and we look forward to working in the interests of
shareholders in FY25 and beyond.
John Conde AO
Chairman
“Maximising
production from
Orbost and bringing
new supply into
the market via the
ECSP will maximise
shareholder returns
consistent with our
purpose of being
part of Australia’s
energy future.”
John Conde AO
Chairman
06
05
MANAGING
DIRECTOR’S
REPORT
Financial year 2024 has been a pivotal year
for our business: demonstrating delivery
against our commitments, refreshing the
Executive team and rolling out our new
Vision, Strategy, Purpose and Values.
Our new Purpose, “Proudly part of Australia’s Energy
Future”, is founded on the critical role that domestically
produced natural gas plays in the Australian economy.
Supported by our new Values: Think Differently, Deliver
Together and Act Responsibly, these changes articulate
the shift of our company culture to be more performance
and delivery focused.
The market opportunity for our business remains
stronger than ever. Gas is central to Australia’s way of
life. It is used for cooking and heating in our homes,
to firm variable renewables in power generation and
in the manufacturing of everyday, essential products,
such as food packaging, fertilisers and construction
materials. The Australian Government’s Future Gas
Strategy, released in May, recognises the criticality of
natural gas, and the importance of supporting the timely
development of gas supply in existing basins, such
as our positions in the Otway and Gippsland Basins.
The growing need for more gas supply is translating
into stronger market pricing. Combined with stronger
production in the Gippsland Basin, this resulted in the
company generating record revenue, record underlying
EBITDAX and record adjusted cash from operations.
FY24 IN REVIEW
Health, safety and environment
We have now been the operator of both the Athena
Gas Plant (AGP) and the Orbost Gas Processing Plant
(OGPP) for a full year and I am pleased to report that
we have maintained our strong health and safety record,
and exceptional environmental performance through
FY24. This is especially meaningful in a year when we
completed such a significant offshore decommissioning
project that tripled our normal worker hours during
execution. We improved slightly on FY23, with a Total
Recordable Injury Rate of 4.35 (FY23: 4.38), and
continue to track ahead of the industry benchmark
of 5.86 (FY23: 5.68). Disappointingly, we did have a
lost-time injury at OGPP, where one of our operators
injured his finger during a routine maintenance task.
We conducted a full investigation into the incident to
ensure that we learn from it, including putting measures
in place to prevent it from reoccurring. Thankfully, our
operator has made a full recovery. We will continue
to strive for continuous improvement in health, safety
and environmental performance, to ensure that all our
people go home safely from work.
07
08
In the past year, we have also progressed physical
emissions reduction across our operated assets,
delivering opportunities that reduce our emissions
by approximately 4,000 tonnes of carbon dioxide
equivalent. This has an additional benefit in reducing
the number of credits required to maintain our carbon
neutral position.
Plant performance improvement
We have delivered improved production performance
across both plants. OGPP production increased by
5.5% year-on-year, despite power generator reliability
issues and pipeline constraints that we faced in the last
quarter of the year. With these issues now resolved,
we have demonstrated our ability to push OGPP to its
nameplate capacity through early FY25, reflecting the
improvements we have made at the facility since taking
over as operator in May 2023.
At AGP, we have reduced reliability loss from 12% in
FY23 to 3% in FY24, with zero reliability loss in May and
June. As discussed at our Investor Briefing in June, we
are aiming to achieve less than 2% reliability loss across
both facilities by the end of FY26.
BMG wells decommissioning
As announced in May, we completed the
decommissioning of seven offshore oil wells in the
Basker, Manta and Gummy (BMG) fields in the
Gippsland Basin, clearing this liability from our balance
sheet. I am proud of the way the decommissioning
program was technically executed, and its success
is testament to the hard work and dedication of our
team and our service partners. The work program
was completed with an exemplary health, safety and
environmental record – with no lost-time injuries and
no reportable or notifiable environmental incidents
across more than 360,000 worker hours. The scale
of the BMG program was significant in the history of
decommissioning work in Australia, a reflection of the
first-class capability of our work force.
With this hurdle cleared, we can now turn our attention
to exploring the 1.3 trillion cubic feet (Tcf) of prospective
resources1 in the Gippsland to ensure we have backfill
and growth for OGPP into the 2030s and beyond.
Positioning for growth
In June 2024, we rolled out our refreshed Vision and
strategy, clearly defining our commitment to continue
delivering affordable, reliable, locally-sourced and lower-
emissions2 gas to Australians. Our tier 1 resources,
close to established infrastructure and the Southeast
Australian market, is a core element of our competitive
advantage. Over the last 10 years, we have shifted our
business into domestic gas, targeting these premium
domestic markets. Our growth strategy is to now
leverage the unique infrastructure position that we
have established, respecting the capital that has been
invested in the business by our shareholders, enabling
us to grow both value and volume. With stable, reliable
production as our foundation, we now look forward to
developing our East Coast Supply Project, a significant
opportunity to increase production through AGP by
more than four times. At a potential 90 terajoules a
day, it is one of the largest new sources of supply for
the Southeast domestic market and we have strong
customer support for this economically attractive project
As previously announced, we are participating in a rig
consortium which is expected to bring a rig into the
region around the middle of calendar year 2025, setting
the timeline for drilling. Our preferred programme is to
drill 3 wells on a 50% basis, targeting first gas by 2028.
This project could deliver more than 350 Bcf3 of mean,
unrisked resource potential, with a 98% chance of at
least one gas discovery at Elanora, Isabella or Juliet.
Cost out / Transformation
In FY24, we have realised more than $10 million
in annualised savings, with approximately 85% of
identified initiatives completed within the year. This
program has delivered our commitment to reduce
General & Administrative (G&A) costs by at least 10%,
achieving a 24% reduction in FY24 compared to FY23.
We aim to maintain this momentum through an ongoing
continuous improvement program through FY25,
focusing on streamlining business processes and
systems, reducing contractor services costs through
shorter OGPP absorber cleaning times and further
increasing the time between absorber cleans, and lower
waste management costs.
FY25 OUTLOOK
In FY25, our priority will be on further margin
enhancement, maximising cash generation and paying
down debt ahead of our major growth spending.
This will be driven by:
• Continued performance improvement at Orbost and
improving reliability across both OGPP and AGP.
• Increasing our realised gas prices through increasing
our exposure to the tight spot market and supplying
customers with gas when they need it most,
particularly during peak power generation
demand periods.
• Maintaining focus on the lower cost base that we have
delivered through our Transformation program and
driving a mindset of continuous improvement to keep
identifying opportunities to do things better, reduce
costs and improve productivity.
• Focusing on energy efficiency and reducing waste and
emissions at our plants. This not only maximises our
sales gas volumes but will help to position us as an
operator of choice for third-party gas volumes.
• Lastly, we will continue to progress the East Coast
Supply Project, with the aim of locking in a partner for
our preferred 3-well drilling program, in preparation
for arrival of the rig.
CONCLUDING REMARKS
As we have consistently said, we believe gas is not
just a transition fuel, it will increasingly be required to
support Australia’s net-zero targets and integration of
renewable energy in the future. Australian manufacturers,
businesses and homes continue to need access to
reliable, low emissions and affordable gas. Domestic gas
from existing basins, leveraging existing infrastructure,
is the lowest cost, lowest emission supply to meet this
demand. Over FY24, the need for more gas now and
in the longer term, especially in our target markets,
has become clearer to the Australian and State
Governments, the Australian Energy Market Operator
and other independent market analysts. Without gas,
Australia cannot ensure reliable and affordable energy
for householders and businesses or meet its climate
objectives and deliver the energy transition.
We at Cooper Energy are uniquely positioned to supply
affordable, reliable, locally-sourced and lower-emissions2
gas to Southeast Australia and through this, deliver
long-term, sustainable value to all shareholders,
stakeholders, customers and the communities in
which we live and work.
Thank you to our investors, the Board, the new Executive
team, our staff and contractors, lenders, customers and
suppliers for supporting our journey and success. I look
forward to further progress in financial year 2025.
Jane Norman
Managing Director and CEO
1The Low (P90), Mid (P50), Mean and High (P10) prospective
resource estimates, and net share of each prospect, were
announced to ASX on 15 May 2023 (Gummy Deep), 13 April 2022
(Wobbegong), and 4 May 2016 (Manta Deep and Chimaera East)
2Cooper Energy produces gas with lower Scope 1 and 2
emissions than alternative sources such as gas redirected from
Queensland or imported as LNG, with Scope 1 and 2 emissions
also fully offset using carbon credits
3The Low (P90), Mid (P50), Mean and High (P10) prospective
resource estimates, and the net share of each prospect,
were announced to ASX on 9 February 2022.
10
09
We innovate by
keeping it simple
while raising the
bar. Nothing stops
us from continually
learning how to do
things better and we
move with pace.
Our clarity of
purpose, can-do
mindset and respect
for each other
means that anything
is possible, and we
are accountable to
deliver our part.
We know how to
act responsibly and
why it is important
to work safely, keep
our promises and act
ethically with integrity
in everything we do.
PROUDLY PART
OF AUSTRALIA’S
ENERGY FUTURE
THINK
DIFFERENTLY
DELIVER
TOGETHER
ACT
RESPONSIBLY
OUR
BUSINESS
Market cap
$594.0 million
Net debt
$250.7 million
Issued shares
2,640.0 million
Employee headcount
128
Cooper Energy is an Australian company
providing energy exclusively for the domestic
market.
Our headquarters are in Adelaide, with regional offices in Perth and
Melbourne. We operate two gas processing facilities in regional Victoria,
which process gas from offshore fields in the Otway and Gippsland basins.
We have various non-operated interests in the South Australian Cooper Basin
and in the onshore Otway basin in regional South Australia and Victoria.
OTHER KEY STATISTICS AT 30 JUNE 2024
FY24 Production: 62.1 TJe/day
2P Proved & Probable reserves at 30 June 2024:
33.0 MMboe (201.6 PJe)
2C Contingent Resources at 30 June 2024:
48.4 MMboe (at 30 June 2024)
Gippsland Basin gas (49.5)
Otway Basin gas & gas liquids (10.5)
Cooper Basin oil (2.1)
Gippsland Basin (29.1 MMboe)
Otway Basin (3.0 MMboe)
Cooper Basin (0.9 MMboe)
Gippsland Basin (37.4 MMboe)
Otway Basin (10.7 MMboe)
Cooper Basin (0.3 MMboe)
11
12
Cooper Basin
Western Flank oil production, development
and exploration
25% Cooper Energy interest in PEL 92
Onshore Otway Basin
Gas exploration and development prospects,
including the Dombey gas discovery
30-75% Cooper Energy interest
OUR
OPERATIONS
Offshore Gippsland Basin
Gas and gas liquids production from the Sole field
Manta and Gummy gas and gas liquids resource and
multiple gas exploration prospects
100% Cooper Energy interest
Orbost Gas Processing Plan
Processing hub for offshore Gippsland Basin gas
100% Cooper Energy interest
68 TJ/day capacity
49.5 TJ/day average production FY24
A$500-550mm estimated replacement value
Offshore Otway Basin
Gas and gas liquids production from
the Casino, Henry and Netherby fields
Annie gas discovery and multiple
exploration prospects
Preparing for the East Coast Supply
Project
50% Cooper Energy interest in CHN
10% Cooper Energy interest in VIC/L21
(Minerva)
Athena Gas Plant
Processing hub for Otway Basin gas
50% Cooper Energy interest
150 TJ/day capacity
21 TJ/day average production FY24 YTD
A$450-500mm estimated
replacement value
13
14
SCOPE-1, SCOPE-2 &
RELEVANT SCOPE-3
EMISSIONS OFFSET4
>300
SUPPLIERS IN
SA & VICTORIA
100%
CARBON NEUTRAL
GENDER DIVERSITY
50%
43%
Female representation on the
Executive Leadership Team
OUR SOCIAL &
ENVIRONMENTAL
COMMITMENT
CARBON NEUTRAL
Maintaining Climate
Active Carbon
Neutral Organisation
certification5
HEALTH, SAFETY & ENVIRONMENT
0 FATALITIES
1 LOST TIME
INJURY
HEALTH, SAFETY & ENVIRONMENT
Ahead of industry
benchmark TRIFR1
HEALTH, SAFETY & ENVIRONMENT
No reportable2 or notifiable3
environmental incidents
during the period
~$60
MILLION
1 NOPSEMA industry 12-month
rolling average TRIFR for FY24
2 As defined by Offshore
Petroleum and Greenhouse
Gas Storage (Environment)
Regulations 2009
3 As defined by the Victorian
Environment Protection
Act 2017
4 Organisational carbon emissions
voluntarily offset according to
Climate Active’s scheme for
FY24. These consist of Scope-1
(direct), Scope-2 (purchased
electricity) and what Cooper
has defined as its relevant
Scope-3 emissions (embedded
energy and business travel).
Downstream Customer Scope-3
transportation and combustion
emissions are not included.
More information regarding
Scope definition is available
in the Cooper Energy 2024
Sustainability Report.
5 Cooper Energy has been
certified by Climate Active
as a Carbon Neutral organisation
for its Scope 1, Scope 2 and
what Cooper Energy defines as
its relevant Scope 3 emissions
(e.g. embedded energy and
business travel) for FY20-23.
It is in the process of seeking
FY24 certification. See the 2024
Sustainability Report for further
information.
in purchases from SA and
Victorian-based suppliers
Female representation
on the Board of Directors
KEY
RESULTS
FINANCIAL
Record production, up 4.2% to 62.1 TJe/d
(22.7 PJe for the year)
Record underlying EBITDAX, up 16.7%
to $127.5 million
Record underlying cash from operations,
up 19.8% to $114.8 million
FY20
FY21
FY22
FY23
FY24
FY20
FY21
FY22
FY23
FY24
FY20
FY21
FY22
FY23
FY24
FY20
FY21
FY22
FY23
FY24
SALES REVENUE ($ million)
UNDERLYING EBITDAX ($ million)
-6.6
-25.9
14.4
-5.6
1.4
UNDERLYING NET PROFIT ($ million)
UNDERLYING CASH
FROM OPERATIONS1 ($ million)
-97.8
-126.7
89
-80.9
-250.7
NET (DEBT)/CASH ($ million)
TOTAL EQUITY ($ million)
FY20
FY21
FY22
FY23
FY24
FY20
FY21
FY22
FY23
FY24
78.1
131.7
205.4
196.9
2196.0
1Operating Cash Flow excluding restoration spend and other non-recurring and non-underlying items
30.8
29.6
80.7
109.3
127.5
30.0
24.6
80.6
95.8
114.8
351.1
325.8
498.4
528.5
417.6
17
18
1.56
2.63
3.31
3.56
3.72
FY20
FY20
FY20
FY20
FY21
FY21
FY21
FY21
FY22
FY22
FY22
FY22
FY23
FY23
FY23
FY23
FY24
FY24
FY24
FY24
FY20
FY21
FY22
FY23
FY24
FY20
FY21
FY22
FY23
FY24
49.9
47.1
39.5
36.3
SAFETY (total recordable injury frequency rate)
PRODUCTION (MMboe)
PROVED AND PROBABLE
RESERVES (MMboe)1
3.53
6.92
0
4.38
4.35
1As announced to the ASX on 23 August 2024
OPERATIONS
& RESERVES
Fifth consecutive year of record
production
Excellent safety performance
given significant BMG wells
decommissioning project and
increase in hours worked
33.0
EQUITY
0.38
0.26
0.25
0.15
0.225
424.1
583.1
394.7
SHARE PRICE (dollars per share at 30 June)
BASIC EARNINGS PER SHARE
(cents per share at 30 June)
MARKET CAPITALISATION ($million at 30 June)
GAS &
OIL REVENUE
Gas
FY24
FY23
FY22
Total sales volume (PJ)
22.5
21.4
22.7
Average realised price ($/GJ)
8.83
8.59
8.29
Total revenue ($million)
198.5
184.0
188.1
2P Reserves (PJ)1
196.1
217.2
235.1
Oil and condensate
FY24
FY23
FY22
Total sales volume (kbbl)
146.8
91.5
126.6
Average realised price ($/bbl) 138.97
136.59
129.14
Total revenue ($million)
20.5
13.0
17.3
2P Reserves (MMbbl)1
0.9
0.8
1.1
CAPITAL
EXPENDITURE
By activity ($million)
FY24
FY23
FY22
Exploration & appraisal
14.6
23.9
4.9
Development
9.3
17.3
14.6
TOTAL
23.9
41.2
19.5
By basin ($million)
FY24
FY23
FY22
Gippsland Basin
6.5
18.3
0.4
Otway Basin
10.6
17.8
15.3
Cooper Basin
6.0
4.2
3.3
Other
0.8
0.9
0.5
TOTAL
23.9
41.2
19.5
-5.3
-1.8
-0.6
-2.3
-4.3
610.0
594.0
20
19
RESERVES &
CONTINGENT
RESOURCES
Cooper Energy’s 2P gas and oil
Reserves at 30 June 2024 are
assessed to be 33.0 MMboe
(201.6 PJe)1.
1The conversion factor of 1 PJ = 0.163417 MMboe has been used to
convert from sales gas (PJ) to oil equivalent (MMboe). The conversion
factor 1 MMbbls = 6.11932 PJe has been used to convert oil (MMbbls)
and condensate (MMbbls) to gas equivalent (PJe).
The key factors contributing to the reduction in
Reserves since 30 June 2023 include:
Production of 3.7 MMboe in FY24
Upward revisions of 0.2 MMboe (2P) in the offshore
Gippsland through updated history matching of the
Sole gas field subsurface model
Upwards revisions of 0.2 MMboe (2P) in the onshore
Cooper Basin through the FY24 Bangalee South
exploration discovery and revised field limits
RESERVES AT 30 JUNE 20241
Category
Unit
1P
Proved
2P
Proved and Probable
3P
Proved, Probable and Possible
Dev.
Undev.
Total
Dev.
Undev.
Total
Dev.
Undev.
Total
Sales gas
PJ
128.6
0.0
128.6
196.1
0.0
196.1
280.0
0.0
280.0
Oil + cond.
MMbbl
0.4
0.0
0.4
0.8
0.1
0.9
1.1
0.1
1.2
Total (2)
MMboe
21.4
0.0
21.4
32.9
0.1
33.0
46.9
0.1
47.0
1As announced to the ASX on 23 August 2024
2Reserves exclude Cooper Energy’s share of future fuel usage. Totals may not reflect arithmetic addition due to rounding. The Reserves information
displayed should be read in conjunction with the information in the Notes on calculation of Reserves and Contingent Resources provided in this
document. “Cond.” refers to condensate, “Dev.” refers to developed reserves and “Undev.” refers to undeveloped reserves
YEAR-ON-YEAR MOVEMENT IN 2P RESERVES
Category
Unit
Proved and Probable 2P Reserves
Cooper
Otway
Gippsland
Total
Reserves at 30 June 2023 (1)
MMboe
0.8
3.6
31.9
36.3
FY24 Production (2)
MMboe
-0.1
-0.6
-3.0
-3.7
Revisions/Acquisitions
MMboe
0.2
0.0
0.2
0.4
Reserves at 30 June 2024 (3)
MMboe
0.9
3.0
29.1
33.0
1As announced to the ASX on 25 August 2023
2Production from 1 July 2023 to 30 June 2024
3As announced to the ASX on 23 August 2024. Totals may not reflect arithmetic addition due to rounding.
RESERVES
21
22
CONTINGENT RESOURCES AT 30 JUNE 20241
1C
2C
3C
Category
Gas
Oil/Cond
Total
Gas
Oil/Cond
Total
Gas
Oil/Cond
Total
Basin
PJ
MMbbl
MMboe
PJ
MMbbl
MMboe
PJ
MMbbl
MMboe
Gippsland
100.9
2.5
19.0
198.9
4.9
37.4
365.0
9.7
69.3
Otway
43.9
0.0
7.2
64.7
0.1
10.7
83.9
0.1
13.8
Cooper
0.0
0.2
0.2
0.0
0.3
0.3
0.0
0.6
0.6
Total (2)
144.8
2.7
26.4
263.6
5.3
48.4
448.8
10.4
83.7
1As announced to the ASX on 23 August 2024
2 Totals may not reflect arithmetic addition due to rounding. The Contingent Resources information displayed should be read in conjunction
with the information in the Notes on calculation of Reserves and Contingent Resources provided in this document. “Oil/Cond” refers to oil +
condensate resources.
Cooper Energy’s 2C Contingent Resources at 30 June 2024
are 48.4 MMboe.1 No material changes have occurred to the
Contingent Resources since 30 June 2023.
1The conversion factor of 1 PJ = 0.163417 MMboe has been used to convert from sales gas (PJ) to oil equivalent (MMboe). The conversion
factor 1 MMbbls = 6.11932 PJe has been used to convert oil (MMbbls) and condensate (MMbbls) to gas equivalent (PJe).
YEAR-ON-YEAR MOVEMENT IN CONTINGENT RESOURCES
Category
Unit
1C
2C
3C
Contingent Resources at 30 June 2023 (1)
MMboe
26.4
48.4
83.7
Revisions
MMboe
0.0
0.0
0.0
Contingent Resources at 30 June 2024 (2)
MMboe
26.4
48.4
83.7
1 As announced to the ASX on 25 August 2023
2 As announced to the ASX on 23 August 2024. Totals may not reflect arithmetic addition due to rounding. The method of aggregation is by
arithmetic sum by category. As a result, the 1C estimate may be conservative and the 3C estimate may be optimistic due to the effects of
arithmetic summation.
CONTINGENT
RESOURCES
Notes on calculation of Reserves and Contingent
ResourcesCooper Energy prepares its petroleum
Reserves and Contingent Resources in accordance
with the definitions and guidelines in the Society
of Petroleum Engineers (SPE) 2018 Petroleum
Resources Management System (PRMS).
The estimates of petroleum Reserves and Contingent
Resources contained in this Reserves statement are
as at 30 June 2024. The Company is not aware of
any new information or data that materially affects the
estimates of reserves and contingent resources, and
the material assumptions and technical parameters
underpinning the estimates continue to apply and
have not materially changed.
Unless otherwise stated, all references to Reserves
and Contingent Resource quantities in this document
are net to Cooper Energy.
Cooper Energy has completed its own estimation of
Reserves and Contingent Resources for its operated
Otway and Gippsland Basin assets. Elsewhere,
Reserves and Contingent Resource estimations are
based on assessment and independent views of
information provided by the permit operators (Beach
Energy Limited for PEL 92).
Reference points for Cooper Energy’s petroleum
Reserves and Contingent Resources and production
are defined points where normal operations cease,
and petroleum products are measured under defined
conditions prior to custody transfer. Fuel, flare and vent
consumed prior to the reference point is excluded.
Petroleum Reserves and Contingent Resources
are prepared using deterministic, with support from
probabilistic, methods. The Reserves and Contingent
Resources estimate methodologies incorporate
a range of uncertainty relating to each of the key
reservoir input parameters to predict the likely range
of outcomes.
Project and field totals are aggregated by arithmetic
summation by category. Aggregated 1P and 1C
estimates may be conservative and aggregated 3P
and 3C estimates may be optimistic due to the effects
of arithmetic summation.
Throughout this announcement, totals may not
exactly reflect arithmetic addition due to rounding.
The conversion factor of 1 PJ = 0.163417 MMboe
has been used to convert from sales gas (PJ) to oil
equivalent (MMboe). Condensate and crude oil are
converted at 1bbl = 1 boe. The conversion factor
1 MMbbls = 6.11932 PJe has been used to convert
Oil (MMbbls) and condensate (MMbbls) to gas
equivalent (PJe).
Reserves
Under the SPE PRMS 2018, “Reserves are 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 Otway Basin totals comprise the arithmetically
aggregated project fields (Casino, Henry and
Netherby). The Cooper Basin totals comprise
the arithmetically aggregated PEL 92 fields. The
Gippsland Basin totals comprise Sole Reserves only.
Contingent Resources
Under the SPE PRMS 2018, “Contingent Resources
are those quantities of petroleum estimated, as
of a given date, to be potentially recoverable from
known accumulations by application of development
projects, but which are not currently considered to
be commercially recoverable owing to one or more
contingencies”.
The Contingent Resources assessment
includes resources in the Gippsland, Otway
and Cooper Basins.
Qualified petroleum Reserves and
Resources evaluator statement
The information contained in this report regarding
Cooper Energy’s Reserves and Contingent
Resources is based on, and fairly represents,
information and supporting documentation reviewed,
prepared by, or under the supervision of, Mr James
Clark who is a full-time employee of Cooper Energy
Limited holding the position of Manager, Exploration
& Subsurface. Mr Clark holds a Bachelor of Arts
(Hons), a Doctorate in Geology, is a member of the
American Association of Petroleum Geologists and
the Society of Petroleum Engineers, is qualified
in accordance with ASX listing rule 5.41, and has
consented to the inclusion of this information in the
form and context in which it appears.
24
23
SAFETY
Detailed information regarding
Cooper Energy’s safety
performance is provided in the
2024 Sustainability Report.
The 2024 Sustainability Report
was published at the time of
this Annual Report and can be
viewed and downloaded from
the Company’s website.
Safety metrics
FY24
FY23
Hours worked
689,398
228,482
Lost-time injuries (LTI)
1
0
Total recordable
injury frequency rate
(TRIFR)1
4.35
4.38
Industry TRIFR2
5.86
5.68
1 TRIFR is recordable injuries (medical treatment injuries + restricted work case
+ lost time injuries + fatalities) per million hours worked. Calculated on a rolling
12-month basis
2 Industry TRIFR is the NOPSEMA benchmark for offshore
Australian operations; data is updated 3-monthly; published at
www.nopsema.gov.au
REVIEW OF
OPERATIONS
PRODUCTION
Cooper Energy achieved record annual gas and oil production of
22.7 PJe in FY24, mainly due to increasing gas production from the
Sole field in the Gippsland Basin.
FY24
FY23
Gas
(PJ)
Oil & Cond.
(kbbl)
Total
(PJe)
Gas
(PJ)
Oil & Cond.
(kbbl)
Total
(PJe)
Gippsland Basin
18.1
-
18.1
17.2
-
17.2
Otway Basin
3.8
3.6
3.8
3.9
3.6
3.9
Cooper Basin
-
127.4
0.8
-
116.6
0.7
TOTAL
21.9
131.0
22.7
21.1
120.1
21.8
Cooper Energy is the operator and 100% interest
holder for all its Gippsland Basin interests.
As at 30 June 2024, these interests comprised:
VIC/L32, which contains the Sole gas field;
VIC/RL13, VIC/RL14 and VIC/RL15, which contains the
Basker, Manta and Gummy (BMG) gas and liquids field
(these retention leases also hold legacy infrastructure
associated with the BMG oil project);
VIC/RL16, which contains the shut-in Patricia-Baleen gas
field and infrastructure which connects to the OGPP; and
Exploration permits VIC/P72, VIC/P75 and VIC/P80.
Orbost Gas Processing Plant
OGPP delivered an average gas processing rate of
49.5 TJ/d during FY24 (+5.5% on 47.1 TJ/d produced
in FY23).
Production rates increased in H2 FY24 versus H1
FY24, largely due to the implementation of Orbost
Improvement Project initiatives. Subsequent to FY24
year end, over July-August 2024, multiple records for
Sole/OGPP production were set, including a record daily
rate of 68 TJ, a 30-day average of 65.7 TJ/d, a 60-day
average of 60.2 TJ/d and a 90-day average of 57.7 TJ/d.
The Sole gas field continues to perform in line with
expectations.
Orbost Improvement Project
Numerous initiatives were implemented over FY24,
focused on minimising foaming and fouling in the
absorbers, increasing the time between absorber
cleans and reducing the duration of cleans.
GIPPSLAND
BASIN
25
26
With the recent production records, a decision has been
made to no longer progress with the option to install a
third absorber.
BMG wells decommissioning
During FY24, Cooper Energy decommissioned the
former Basker, Manta and Gummy (BMG) wells. The
work was primarily undertaken by the Helix Q7000 semi-
submersible well intervention vessel.
Following delayed completion of the Tui field
abandonment programme in New Zealand, the vessel
departed New Zealand in late November 2023. BMG
wells decommissioning operations commenced in late
December 2023.
The late arrival of the Helix Q7000 at the BMG site
resulted in the Company incurring more than three
months of holding costs for the remaining contractor
spread on the BMG programme. This delayed start, and
additional time required for startup activities, consumed
the budgeted contingency.
On 22 January 2024, the Company revised its
mid-case cost estimate for the BMG wells
decommissioning to approximately A$240-280 million,
including a reasonable contingency for further
non-productive time and adverse weather.
The BMG wells decommissioning programme was
successfully completed in May. The programme incurred
more than 360,000 person-hours with no lost time
injuries and no significant environmental incidents. The
success of the wells decommissioning project highlights
the Company’s commitment to health, safety, and the
environment, as well as its strong engineering capability.
The total cost of the BMG wells decommissioning
programme is expected to be slightly less than $270
million, with the final value subject to remaining invoice
reconciliation. Decommissioning costs were funded from
cash on hand, organic cash generation and the existing
senior debt facility.
Cooper Energy continues to pursue its Victorian
Supreme Court claim against PT Pertamina Hulu
Energi (“Pertamina”) for Pertamina’s 10% share of the
BMG decommissioning costs. These costs relate to
decommissioning the seven wells as well as the related
subsea infrastructure of the BMG oil project. From 2009
until 2014, Pertamina Hulu Energi Australia Pty Limited
(“Pertamina Australia”), a wholly owned subsidiary
of Pertamina, held a 10% interest in the BMG joint
operating and production agreement (“JOA”).
Workstreams undertaken included:
• reinstatement of the polisher unit;
• installation of heat tracing and insulation around the
polisher unit;
• installation of an alternative spray distributor
configuration in the absorber beds;
• installation of a mist eliminator;
• optimisation of the anti-foam agent pumps;
• trials of alternative packing material in the absorbers;
and
• clean-in-place trials in the absorbers.
The polisher unit had a significant positive impact on
production during the year. In late December 2023,
a new type of polisher unit media was loaded and
achieved a record life of nearly five months, four times
longer than the previous record.
With the support of the polisher unit and other
improvement initiatives, a record absorber runtime of six
weeks between cleans was achieved over June - July
2024, compared to the previous typical absorber
runtime of 2 - 3 weeks.
Work continues on identifying the root cause of the
sulphur foaming and fouling issues in the sulphur
absorber units. While this work is ongoing, the success
of improvement programme initiatives to date, has
allowed the plant to operate more consistently and at
higher rates.
Further initiatives are being progressed to improve the
reliability of the plant and maximise production rates,
focusing on extending the time between absorber
cleans and minimising the duration of the cleans.
Gippsland Basin
Key
In February 2014, Pertamina Australia withdrew
from the JOA.
A claim against Pertamina was filed by Cooper
Energy in the Supreme Court of Victoria (the “Court”),
in December 2022, seeking payment of an amount
equal to 10% of the costs and expenses of the
decommissioning operations incurred and to be
incurred, pursuant to Pertamina Australia’s obligations
under the withdrawal and abandonment provisions of
the JOA. Pertamina has been ordered by the Court to
file its defence in September 2024.
Gippsland Basin farm-out
In May 2024, Cooper Energy commenced a process
to bring a partner into VIC/P80 and VIC/L13,14 & 15
(Cooper Energy 100%) for the next Gippsland gas
exploration and development phase.
The opportunity covers 185 PJ of 2C1 discovered
resource and more than 1.3 Tcf2 of prospective
resource. This brownfield project is expected to have a
low cost to develop, a clear commercialisation pathway
via existing infrastructure, and a relatively lower overall
emissions profile compared to alternate sources, such
as gas transported to Victoria from Queensland or
imported LNG.
Gippsland Basin gas storage
In Q4 FY24 Cooper Energy commenced studying the
potential repurpose of the shut-in Patricia Baleen field
in VIC/RL16 (Cooper Energy 100%) for gas storage.
Cooper Energy tested the existing equipment, and
the results of these tests are being integrated into the
Company’s assessment of gas storage potential.
1 Contingent Resources for Manta gas and liquids announced to ASX on 12 August 2019, Contingent Resources
for Gummy gas and liquids announced to ASX on 25 August 2023, 100% share
2The Low (P90), Mid (P50), Mean and High (P10) prospective resource estimates, and net share of each prospect, were announced to ASX on 15 May 2023
(Gummy Deep), 13 April 2022 (Wobbegong), and 4 May 2016 (Manta Deep and Chimaera East)
27
28
During Q4 FY24 AGP demonstrated stable operation
with zero reliability loss over the two months of May
and June.
East Coast Supply Project
Cooper Energy made significant progress on the East
Coast Supply Project (ECSP), formally referred to as the
Otway Phase 3 Development (OP3D), under which the
Company intends to maximise the use of existing Otway
Basin infrastructure to bring much-needed gas supply to
Southeast Australia.
The ECSP developments can be connected to Cooper
Energy’s existing gas processing infrastructure at the
AGP, which has ~150 TJ/d of total capacity (100%
gross), with first gas targeted for 2028.
In Q1 FY24, as part of a consortium agreement
with three other operators, the Company secured
the Transocean Equinox rig for its drilling campaign
in the Otway Basin. The Transocean Equinox is
estimated to arrive in the Otway Basin in circa
mid-CY2025. Within the consortium agreement, Cooper
Energy has committed to one firm well and has options
to drill additional development and/or exploration/
appraisal wells.
Cooper Energy has evaluated a number of alternatives
for the ECSP drilling and development campaign.
The Company has focused on identifying the optimal
campaign considering the size of prospects, the
development’s overall economic returns, scale of capital
expenditure required and risk.
While Cooper Energy continues to evaluate
ECSP alternatives, the Company is targeting a
three-well programme on a 50% basis. This includes
developing 64.8 PJ1 in gross 2C resource (32.4 PJ
net to Cooper Energy) through one well (Annie-2) and
a two well exploration programme, with one planned
geological sidetrack, targeting 358 Bcf2 (179 Bcf net
to Cooper Energy) of gross mean unrisked prospective
resource potential.
Discussions with Mitsui, Cooper Energy’s 50% joint
venture partner in the Otway Basin, regarding the
The Company’s interests in the offshore
Otway Basin as at 30 June 2024 comprised:
a 50% interest in and operatorship of production
licences VIC/L24 and VIC/L30 containing the producing
Casino, Henry and Netherby gas fields, with the
remaining 50% interest held by Mitsui E&P Australia
and its associated entities ("Mitsui");
a 50% interest in and operatorship of production
licences VIC/L33 and VIC/L34 containing part of the
Black Watch and Martha gas fields, with the remaining
50% interest in these production licences held by Mitsui;
a 50% interest in and operatorship of exploration
permit VIC/P44 containing the undeveloped Annie gas
discovery, with the remaining 50% interest held by Mitsui;
a 100% interest in and operatorship of exploration
permit VIC/P76;
a 50% interest in and operatorship of AGP (onshore
Victoria), which is jointly owned with Mitsui and
processes gas from the Casino, Henry and Netherby
gas fields; and
a 10% non-operated interest in production licence
VIC/L22, which holds the shut-in Minerva gas field, with
Woodside Energy the operator and 90% interest holder.
Athena Gas Plant (AGP)
The AGP achieved an average gas processing rate of
10.4 TJ/d during FY24 (FY23: 10.7 TJ/d), both net to
Cooper Energy’s 50% share. Notable improvements
in plant reliability were offset by natural decline in the
Casino, Henry and Netherby (CHN) gas fields.
Low inlet pressure operations were successfully
implemented in the beginning of CY2024, resulting in
a production uplift of approximately 1 TJ/d on average.
Well cycling operations continued to be implemented
throughout the financial year to optimise production
from the CHN fields.
Production in Q3 FY24 was impacted by a planned
maintenance shutdown and additional unplanned
compressor maintenance.
OTWAY BASIN
(OFFSHORE)
1 Indicative only, not guidance. Projects are preliminary in nature and not yet sanctioned. Annie 2C resource is included on a gross basis as part of the Otway Basin 2C number
in the FY24 Reserves and Contingent Resources ASX released on the 23 August 2024. See also Contingent Resource announcement: Annie Gas Field, 24 February 2020.
2The Low (P90), Mid (P50), Mean and High (P10) prospective resource estimates, and the net share of each prospect, were announced to ASX on 9 February 2022.
ECSP, are ongoing.
Cooper Energy expects to sanction the ECSP during
FY25, at which time it will confirm the identity, number
and timing of wells drilled as part of the programme.
The Transocean Equinox is expected to commence
drilling the first firm well of its campaign for Cooper
Energy later in FY26.
The ECSP is expected to be funded from a range of
sources including organic cash generation, the existing
secured bank debt facility as well as the accordion debt
facility of up to $120 million. Additionally, the Company
continues to engage with several gas customers to
support new domestic gas supply through a range of
funding options, which could include prepayments.
Minerva decommissioning
Woodside Energy, the Operator of VIC/L22 (Cooper
Energy share 10%), will commence decommissioning of
the Minerva gas field in late CY2024.
The subsea facilities (pipelines, umbilicals, etc.)
will be removed first, followed by the subsequent
decommissioning of the Minerva wells. The Transocean
Equinox rig is estimated to arrive in the offshore Otway
Basin region in circa mid-CY2025 and will commence
the Minerva wells decommissioning shortly thereafter.
29
30
The Company’s interests in the onshore Otway
Basin as at 30 June 2024 comprised:
a 30% interest in PEL 494, PRL 32 and PEL 680 in
South Australia, with the remaining interests held
by the operator, Beach Energy;
a 50% interest in PEP 168 in Victoria, with the remaining
interest held by the operator, Beach Energy; and
a 75% interest in PEP 171 in Victoria, with the
remainder held by operator Vintage Energy Limited.
Exploration activity
The PEL 494 Dombey 3D seismic survey was
processed during H1 FY24 and interpreted during H2
FY24. Analysis to delineate the resource potential of the
Dombey gas field and identify potential new exploration
opportunities is ongoing and expected to be completed
in H1 FY25.
Reprocessing of existing 3D seismic surveys within PEP
168 was conducted in H1 FY24, with several legacy 3D
seismic datasets across PEP 168 reprocessed into one
survey. Interpretation of this reprocessed seismic data
was undertaken during the H2 FY24 and is ongoing to
mature drilling prospects in the permit.
OTWAY BASIN
(ONSHORE)
The Company's interests in the Cooper Basin
as at 30 June 2024 comprised a 25% interest in
PRLs 85-104 (formerly PEL 92), with the remaining
interests held by the operator, Beach Energy.
Exploration and development activity
Cooper Energy took part in a four well exploration
drilling campaign in PRLs 85-104 (formerly PEL 92)
in the first half of FY24.
The first exploration well, Marion 1, was drilled in
September 2023 and was plugged and abandoned after
failing to encounter hydrocarbons in the primary Namur
Reservoir.
Bangalee South 1, located 630 metres southeast of
Bangalee 1, was drilled in October 2023 and intersected
2.9 metres of net oil pay in the Namur reservoir and 4.3
metres of net oil pay in the Birkhead reservoir. The well
COOPER
BASIN
was cased and suspended as a future oil producer.
The Birkhead zone was brought online in December
2023, with initial production above 350 bbls/d (gross).
In October 2023, Wooley Rock 1 intersected 1.2
metres of net oil pay and was plugged and abandoned
as a non-commercial discovery. Chadinga 1 was drilled
in December 2023, approximately three kilometres
northwest of the Wooley Rock discovery and was
plugged and abandoned, having failed to encounter
hydrocarbons.
31
32
TRANSFORMATION
PROGRAMME
One of the Company’s key
priorities for FY24 was the
execution of cost-out initiatives
under the transformation
programme, outlined during the
FY23 full year results.
The transformation programme
was all encompassing, targeting
savings and efficiency across
the entire business.
As at 30 June 2024, approximately $10.5 million
in annualised forward-looking net savings has
been realised, with over 100 initiatives identified
across the business. Around 85% of the identified
initiatives were completed or actioned by the end
of FY24, with the full effect of cost savings and
benefits realised into FY25 and beyond.
Significant savings in production costs were
achieved across the business, in particular at
OGPP. A large part of the savings related to
cost of cleaning of the absorber beds, including
renegotiating long standing contracts with third
party contractors, as well as reducing the time and
frequency of absorber cleans.
An additional focus area at OGPP was to reduce
costs arising from the removal and disposal of solid
sulphur and waste related to the treatment of gas.
The Company is investigating beneficial reuse
opportunities for the solid sulphur that is produced
as a by-product at the plant and currently classified
as waste. If successful, and in conjunction with
more efficient waste disposal, the Company
is targeting more than $2.0 million per year in
additional savings from this initiative.
A 24% reduction in net G&A costs was achieved in
FY24 vs FY23 on an annualised basis, or 36% net of
restructuring and other non-recurring costs incurred.
$10.5 MILLION
annualised net savings realised (approx)
>100
initiatives identified across the business
24% REDUCTION
in net G&A costs on an annualised basis
34
33
PORTFOLIO
GIPPSLAND BASIN
State
Tenement
Interest
Location
Area (km²)
Operator
Activity
Victoria
VIC/P72
100%
Offshore
271
Cooper Energy
Exploration
VIC/P75
100%
Offshore
808
Cooper Energy
Exploration
VIC/P80
100%
Offshore
676
Cooper Energy
Exploration
VIC/RL13 (Basker-Manta-Gummy) 100%
Offshore
67
Cooper Energy
Retention
VIC/RL14
100%
Offshore
67
Cooper Energy
Retention
VIC/RL15
100%
Offshore
67
Cooper Energy
Retention
VIC/RL16
100%
Offshore
135
Cooper Energy
Retention
VIC/L32
100%
Offshore
203
Cooper Energy
Production
OTWAY BASIN
State
Tenement
Interest
Location
Area (km²)
Operator
Activity
South Australia
PEL 494
30%
Onshore
1,277
Beach Energy
Exploration
PEL 680
30%
Onshore
1,929
Beach Energy
Exploration
PRL 32
30%
Onshore
37
Beach Energy
Retention
Victoria
PEP 168
50%
Onshore
795
Beach Energy
Exploration
PEP 171
75%
Onshore
1,974
Vintage Energy
Exploration
VIC/P44
50%
Offshore
603
Cooper Energy
Exploration
VIC/P76
100%
Offshore
162
Cooper Energy
Exploration
VIC/L22 (Minerva)
10%
Offshore
58
Woodside Energy
Production
VIC/L24 (Casino)
50%
Offshore
201
Cooper Energy
Production
VIC/L30
(Henry & Netherby)
50%
Offshore
201
Cooper Energy
Production
VIC/L33
50%
Offshore
128
Cooper Energy
Production
VIC/L34
50%
Offshore
6
Cooper Energy
Production
COOPER BASIN
State
Tenement
Interest
Location
Area (km²)
Operator
Activity
South Australia
PPL 204 (Sellicks)
25%
Onshore
2.0
Beach Energy
Production
PPL 205 (Christies-Silver Sands)
25%
Onshore
4.3
Beach Energy
Production
PPL 220 (Callawonga)
25%
Onshore
5.5
Beach Energy
Production
PPL 224 (Parsons)
25%
Onshore
1.8
Beach Energy
Production
PPL 245 (Butlers)
25%
Onshore
2.1
Beach Energy
Production
PPL 246 (Germein)
25%
Onshore
0.1
Beach Energy
Production
PPL 247 (Perlubie)
25%
Onshore
1.5
Beach Energy
Production
PPL 248 (Rincon)
25%
Onshore
2.0
Beach Energy
Production
PPL 249 (Ellison)
25%
Onshore
0.8
Beach Energy
Production
PPL 250 (Windmill)
25%
Onshore
0.6
Beach Energy
Production
PRL 85-1041 (formerly PEL 92)
25%
Onshore
1,899.3
Beach Energy
Exploration
1Includes associated PPLs
Cooper Energy Exploration & Production Tenements
36
35
DIRECTORS
Experience and expertise
Mr Conde has extensive experience in business and
commerce and in chairing high profile business, arts
and sporting organisations.
Previous positions include non-executive director of
BHP Billiton (ASX:BHP), Chairman of Bupa Australia,
Chairman of Pacific Power (the Electricity Commission
of NSW), Chairman of the Sydney Symphony Orchestra,
director of AFC Asian Cup, Chairman of Events NSW,
President of the National Heart Foundation, Chairman
of the Pymble Ladies’ College Council and director of
Dexus Property Group (ASX:DXS).
Current and other directorships in the last 3 years
Mr Conde is Chairman of The McGrath Foundation
(since 2013 and director since 2012) and Chairman of
Dexus Wholesale Property Fund (DWPF) (since 2020).
Mr Conde is a former President of the Commonwealth
Remuneration Tribunal (2003 – 2023) and Deputy
Chairman of Whitehaven Coal Limited (ASX:WHC)
(2007 – 2022)
Special responsibilities
Mr Conde is Chairman of the Board of Directors.
Effective 19 August 2021 he is also a member of the
People & Remuneration Committee and is the
Chairman of the Governance & Nomination Committee.
Experience and expertise
Jane has worked and studied in Australia and the UK
and brings 30 years of industry experience in the energy
markets. She began her career with Shell International
Exploration & Production as a Process Engineer
in operations and then as a Commercial Advisor in
The Hague, Aberdeen and London. Subsequently, in
London, Jane held corporate finance and equity capital
markets roles with Cazenove & Co (now JP Morgan
Cazenove) and Goldman Sachs.
Jane returned to Australia to join Santos where she held
senior commercial, corporate strategy and Executive
Committee roles. She led major strategic initiatives at
Santos and played a key role in Santos’ growth strategy,
in particular the merger with Oil Search.
During her time at Santos Jane helped drive the
transformation of company performance, helping
to establish the growth strategy focused on cash
generation and shareholder returns and, more recently,
the company’s energy transition strategy. Jane
holds a Bachelor of Science (Pure Mathematics and
Chemistry) and Bachelor of Chemical Engineering
(Hons) from the University of Sydney and a Graduate
Diploma in Management and Economics of Natural Gas
(Distinction) from the University of Oxford.
Jane is a Graduate of the Australian Institute of
Company Directors.
Current and other directorships in the last 3 years
Ms Norman is a director of the wholly owned subsidiaries
of Cooper Energy Limited and is on the Board of the
Australian Energy Producers (since 2023).
Special responsibilities
Ms Norman is Managing Director and CEO. She is
responsible for the day-to-day leadership of Cooper
Energy, and is the leader of the Executive
Leadership Team.
MS JANE
L. NORMAN
B.Sc.,B.Eng.(Hons)
PGDip, GAICD
Managing Director
and CEO
Appointed 20 March 2023
MR JOHN
C. CONDE AO
B.Sc. B.E(Hons), MBA
- Chairman
- Independent
Non-Executive Director
Appointed 25 Feb 2013
Experience and expertise
Mr Bednall is a highly experienced and respected
corporate lawyer and law firm manager. He is a partner
of King & Wood Mallesons (KWM), where he specialises
in mergers and acquisitions, capital markets and
corporate governance, representing public company
and government clients. Mr Bednall has advised
clients in the oil and gas and energy sectors
throughout his career.
Mr Bednall was the Chairman of the Australian
partnership of KWM from January 2010 to December
2012, during which time the merger of King & Wood
and Mallesons Stephen Jaques was negotiated and
implemented. He was also Managing Partner of
M&A and Tax for KWM Australia from 2013 to 2014,
and Managing Partner of KWM Europe and Middle
East from 2016 to 2017. He was General Counsel of
Southcorp Limited (which became the core of Treasury
Wine Estates Limited) from 2000 to 2001.
Current and other directorships in the last 3 years
Mr Bednall is a board member of the National Portrait
Gallery Foundation (since 2018) and a director of
Pooling Limited (since 2017).
Special responsibilities
Effective 19 August 2021 Mr Bednall is a member
of the Audit Committee, the People & Remuneration
Committee and the Governance & Nomination
Committee, and effective 9 November 2023 Mr Bednall
is a member of the Risk and Sustainability Committee.
MR TIMOTHY
G. BEDNALL
LLB (Hons)
Independent
Non-Executive Director
Appointed 31 March 2020
38
37
Experience and expertise
Ms Donaghey brings over 30 years’ experience in the
energy sector including technical, commercial and
executive roles in EnergyAustralia, Woodside Energy
and BHP Petroleum.
Ms Donaghey’s experience includes non-executive
director roles at Imdex Ltd (an ASX-listed provider of
drilling fluids and downhole instrumentation), St Barbara
Ltd (a gold explorer and producer), and the Australian
Renewable Energy Agency. She has performed
extensive committee roles in these appointments,
serving on audit and compliance, risk and audit,
technical and regulatory, remuneration and health and
safety committees.
Current and other directorships in the last 3 years
Ms Donaghey is currently a non-executive director of
the Australian Energy Market Operator (AEMO) (since
2017) and a non-executive director of Ampol Limited
(ASX: ALD) (since 2021).
Special responsibilities
Effective 19 August 2021 Ms Donaghey is a member
of the Risk & Sustainability Committee, the People
& Remuneration Committee and the Governance &
Nomination Committee. Effective 23 June 2023 Ms
Donaghey is the Chairman of the Risk & Sustainability
Committee.
MS ELIZABETH
A. DONAGHEY
B.Sc., M.Sc.
Independent
Non-Executive Director
Appointed 25 June 2018
Experience and expertise
Ms Collins has broad executive and director experience
across finance, treasury and property disciplines.
Ms Collins’ executive positions included General
Manager Property, Treasury and Tourism of NRMA,
Chief Executive Officer, Property and General Manager
Finance with the Hannan Group, and Senior Manager,
Audit Services with KPMG Switzerland. Ms Collins is
a former non-executive director and Chairman of the
following companies: Aon Superannuation (2016 –
2017), The Travelodge Hotel Group (2009 – 2013)
and The Heart Research Institute Limited (2003 – 2011).
Current and other directorships in the last 3 years
Ms Collins is Chairman of Hotel Property Investments
(ASX:HPI) since 2022, director since 2017 and recently
appointed as Chairman of Pacific Smiles Limited
(ASX:PSQ), director since 2023. Ms Collins is also
a non executive director of Generation Development
Group (ASX:GDG) since 2018 and Chairman of the
responsibility entity (RE) for AMP Limited’s managed
investment schemes since 2021.
Ms Collins is a former Chairman for Indigenous
Business Australia in the Darwin Hotel Pty Limited,
non-executive director of Generation Life
(2018 – 2021) and Peak Rare Earths Limited
(ASX:PEK) (2021 – 2023).
Special responsibilities
Effective 19 August 2021 Ms Collins is a member of
the Audit Committee and the Risk & Sustainability
Committee. Effective 9 November 2023 Ms Collins
is the Chairman of the Audit Committee and a member
of the Governance & Nomination Committee.
MS GISELLE
M. COLLINS
B. Ec, CA , GAICD
Independent
Non-Executive Director
Appointed 19 Aug 2021
Experience and expertise
Mr Schneider has over 30 years of experience in
senior management roles in the oil and gas industry,
including 24 years with Woodside Energy. He has
extensive corporate governance and board experience
as both a non-executive director and chairman in
resources companies.
Current and other directorships in the last 3 years
Mr Schneider does not currently hold any other
directorships.
Special responsibilities
Effective 19 August 2021 Mr Schneider is Chairman
of the People & Remuneration Committee. Effective 9
November 2023 Mr Schneider is also a member of the
Audit Committee.
MR JEFFREY
W. SCHNEIDER
B.Com
Independent
Non-Executive Director
Appointed 12 Oct 2011
Experience and expertise
Ms Binns has over 35 years’ experience in the global
resources and financial services sectors, including more
than 10 years in executive leadership roles at BHP and
15 years in financial services with Merrill Lynch Australia
and Macquarie Equities. During her career at BHP,
Ms Binns’ roles included Vice President Minerals
Marketing, leadership positions in the metals and coal
marketing business, Vice President of Market Analysis
and Economics and was a member of the first BHP
Global Inclusion and Diversity Council.
Prior to joining BHP, Ms Binns held a number of board
and senior management roles at Merrill Lynch Australia
including Managing Director and Head of Australian
Research, Head of Global Mining, Metals and Steel,
and Head of Australian Mining Research. She was
also co-founder and Chair of Women in Mining and
Resources Singapore.
Current and other directorships in the last 3 years
Ms Binns is a non-executive director of Evolution Mining
(ASX:EVN) (since 2020) and Sims Limited (ASX:SGM)
(since 2021). She is also a non-executive director of
the Carbon Market Institute and a member of the J.P.
Morgan Australia & NZ Advisory Council.
Special responsibilities
Prior to her retirement, Ms Binns was the Chairman of
the Audit Committee and was a member of the Risk
& Sustainability Committee.
MS VICTORIA
J. BINNS
B. Eng (Mining – Hons
1), Grad Dip SIA,
FAusIMM, GAICD
Independent
Non-Executive Director
Appointed 2 March 2020
Retired 9 Nov 2023
39
40
EXECUTIVE
LEADERSHIP
Ms Norman’s biography is shown in the Director’s
section of the report.
MR DANIEL
YOUNG
B. Com (Hons), MBA
(Hons), CA, CFA
Chief Financial Officer
Mr Young joined Cooper Energy in May 2022. Mr
Young is an energy professional with over 28 years of
experience in Australia, Asia and Europe. He joined
Cooper Energy from Jadestone Energy plc where he
held the role of Chief Financial Officer for over five
years. He also held the role of Executive Director
with Jadestone. Daniel played a key role in the
management team, charged with the funding, growth
and development of Jadestone. The compound annual
share price growth rate averaged 25% over this period.
Prior to Jadestone, Mr Young was Head of APAC
Consulting for Wood Mackenzie and earlier worked in
J.P. Morgan’s energy investment banking coverage/
mergers & acquisitions group, in Europe and in Asia.
During this time, he worked on a number of noteworthy
transactions in the energy sector.
After completing his undergraduate studies, Daniel
joined Deloitte where he qualified as a Chartered
Accountant. Daniel holds a Bachelor of Commerce with
Firsts in Accounting and Finance from the University of
Western Australia and an MBA with Honours from the
University of Chicago Booth School of Business.
He is also a CFA® charterholder.
MS JANE
L. NORMAN
B.Sc., B.Eng. (Hons)
PGDip, GAICD
Managing Director
and CEO
Mr Glavas joined Cooper Energy in August 2014
and has more than 25 years of experience in
business development, finance, commercial, portfolio
management and strategy, including 22 years in the
oil and gas sector. Prior to joining Cooper Energy,
he was employed by Santos as Manager Corporate
Development with responsibility for managing multi-
disciplinary teams tasked with mergers, acquisitions,
partnerships and divestitures.
Prior roles within Santos included: Finance Manager
WA and NT, where Mr Glavas was a member of
the leadership team that managed a large asset
portfolio; corporate roles in strategy and planning; and
operational, commercial and finance roles for Santos’
Cooper Basin assets.
MR EDDY
GLAVAS
B. Acc. FCPA, MBA
Chief Commercial
Officer
Mr Wilson joined Cooper Energy in October 2023
and has over two decades of experience in project
development, production operations and business
transformation.
He embarked on his professional journey as a Process
Engineer at a prominent Canadian mining firm. He later
joined Talisman Energy, where he held various roles in
engineering, development, and, finally, an operational
management role comprising five operating areas, six
sweet gas plants and one of Alberta’s major sour gas
processing plants.
Subsequently, he joined Santos in Australia, where
Chad was appointed Chief Production Engineer
and later Vice President of Cooper Basin. He was
instrumental in the transformation of the Cooper
Basin asset through 2015-16, ensuring the asset was
sustainably profitable in the low oil price environment.
After heading up development and operations of the
Cooper Basin for a further 4 years, he became Vice
President, Energy Solutions, where he oversaw the
development of the Moomba Carbon Capture and
Storage Project and emissions reduction strategy and
execution across Santos’s portfolio. Chad has a proven
track record of enhancing safety, production, and
profitability through applying lean systems thinking.
He holds a Bachelor of Science in Chemical
Engineering and a Bachelor of Science in Zoology/
Chemistry from the University of Alberta, Canada.
MR CHAD
WILSON
B. Sc. Chem. Eng.
(Distinction), B. Sc.
Zoology (Chemistry),
PEng, MIEAust
CPEng NER
Chief Operating Officer
41
42
MS YING LUO
B. Eng. (Hons), B. Sc.
(Hons), MBA, Grad Cert.
Chief Advisor &
General Manager
Strategy
Ms Luo has almost 15 years of experience working in
the energy sector in onshore gas, LNG and hydrogen.
She began her career as a Graduate Mechanical
Engineer with Santos. She progressed through several
roles over the following decade including Production
Engineer, and Operations Engineer where she
implemented solutions to design and operability issues
identified during the commissioning and start-up of the
GLNG Project upstream wells and facilities.
Ying also worked in the Corporate Strategy and
Planning team, providing oil, LNG and domestic gas
market analysis, supporting the development of
Santos’ 10-year strategic plan. Her last four years
with Santos were as the Project and Strategy Lead
for the Energy Solutions division. Ying developed,
implemented, and maintained the Energy Solutions
strategy and led a portfolio of emissions reduction,
renewable integration and hydrogen projects. Most
recently she worked as the Senior Adviser, Hydrogen
Development for the Australian Gas Infrastructure Group
where she led the development of Australia’s largest
renewable hydrogen production and blending project
in Albury-Wodonga, Victoria.
Ying has a Bachelor of Mechanical Engineering with
First Class Honours; Bachelor of Science (Mathematics,
Computer Science) with First Class Honours; Graduate
Certificate in Energy and Resources Policy and Practice
and an MBA. She was awarded the Sir John Monash
Scholarship for Excellence at Monash University and
the Exceptional Young Women in Resources from the
South Australian Chamber of Mines and Energy.
MR NATHAN
CHILDS
B. Chem. Eng. (Hons)
Chief Corporate
Services Officer
Mr Childs has over 25 years of experience in the gas
and oil industry, having held line, technical, engineering
and executive management roles.
Before joining Cooper Energy in October 2019 as Head
of Engineering and Planning, he was Santos's Vice
President of Production Mid stream. He worked through
several roles at Santos across plant and process
operations; engineering; production optimisation; asset
management; commercial business development;
integrity, and reliability.
While working for Santos, Nathan made several
strategic changes, including lowering operating costs,
improving asset performance, increasing production,
delivering $50 million of transformation initiatives to
improve free cash flow and implementing Operations
Discipline.
Nathan began his career with Rio Tinto in research
and technology development. He later worked at
ExxonMobil's refining and supply business after
graduating with first-class honours from Adelaide
University with a Bachelor of Engineering–Chemical.
Ms Ortigosa has over 15 years’ experience as a
corporate and commercial lawyer, specialising in the
energy and resources sector. Prior to joining Cooper
Energy she worked for top tier law firms across
Australia, including Clifford Chance and Minter Ellison.
Nicole’s experience covers all legal, corporate, and
commercial aspects of the business, including joint
ventures, gas sales, infrastructure, environment,
regulatory, procurement, mergers and acquisitions,
corporate governance and compliance.
Nicole started at Cooper Energy in 2017 and prior to
becoming General Counsel & Company Secretary
was the Legal Manager. Amongst other matters, she
has advised the company on the development of the
Sole gas field, the acquisition of the Athena Gas Plant
and associated infrastructure and the acquisition of the
Orbost Gas Processing Plant and associated onshore
and offshore pipeline infrastructure.
She holds a Bachelor of Laws with Honours from the
University of Adelaide, and a Graduate Diploma in Legal
Practice from the Law Society of South Australia.
MS NICOLE
ORTIGOSA
BA LLB (Hons), Grad Dip
Legal Practice
Company Secretary
& General Counsel
MR ANDREW
THOMAS
B. Sc. (Hons)
Chief Exploration &
Subsurface Officer
Ceased as Executive
KMP on 30 June 2024
Mr Thomas is a successful and experienced
geoscientist who has been involved with Australian and
international gas and oil exploration and development
projects for over 30 years. He has experience in a wide
range of onshore and offshore basins in Australia, Asia
and Africa.
Prior to joining Cooper Energy, Mr Thomas was
employed by Newfield Exploration in the roles of
Southeast Asia New Ventures Manager and Exploration
Manager for offshore Sarawak and was a key person in
the team that successfully negotiated Newfield’s entry
into Malaysia in 2004. Through the efforts of the teams
he led, Newfield built a substantial portfolio of permits
in Malaysia and made several significant oil and gas
discoveries before being divested to SapuraKencana
in 2014.
Mr Thomas’s previous employers include Santos
Limited, Gulf Canada and Geoscience Australia.
He is a member of the American Association of
Petroleum Geologists and a member of the Society
of Petroleum Engineers.
Mr. Thomas leaves Cooper Energy on 30 September
2024, after 12 years of dedicated service. Mr Thomas
ceased as Executive KMP on 30 June 2024.
43
44
KEY
PERFORMANCE
INDICATORS
FY20
FY21
FY22
FY23
FY24
OPERATIONAL
Production
PJe
9.2
16.1
20.3
21.8
22.7
2P Proved
and Probable
Reserves
MMboe
49.9
47.1
39.5
36.3
33.0
Wells drilled
#
18
1
2
2
4
Exploration wells
spudded
#
4
-
2
-
4
1P Reserves
replacement ratio1
%
-65%
17%
-65%
24%
-1%
FINANCIAL
Sales revenue
$ million
78.1
131.7
205.4
196.9
219.0
Other income
$ million
19.8
7.2
-
-
3.4
Underlying
EBITDAX
$ million
29.6
30.0
80.7
109.3
127.5
Net profit / (loss)
before tax
$ million
-110.0
-33.5
-22.7
-104.7
-125.1
Underlying profit /
(loss) after tax
$ million
-6.6
-25.9
14.4
-5.6
1.4
Cash and cash
equivalents
$ million
131.6
91.3
247.0
77.1
14.3
Underlying cash
from operations
$ million
30.8
24.6
80.6
95.8
114.8
Working capital
$ million
90.4
30.3
190.3
-121.8
-52.9
Accumulated profit
$ million
-136.0
-166.0
-177.5
-214.3
-328.4
Franking credits
$ million
42.9
42.9
42.9
42.9
42.9
Total Equity
$ million
351.1
325.8
498.4
528.5
417.6
Earnings per
share
cents
-5.3
-1.8
-0.6
-2.3
-4.3
Return on
shareholder funds
%
-21.9%
-8.9%
-2.6%
-11.8%
-24.1%
Total shareholder
return
%
-30.6%
-30.7%
-5.8%
-38.8%
+50.0%
CAPITAL AS AT 30 JUNE 2024
Share price
$
0.375
0.260
0.245
0.15
0.225
Issued shares
#
1,621.6
1,631.0
2,379.8
2,631.5
2,640.0
Market
capitalisation
$ million
608.1
424.1
583.1
394.7
594.0
¹The annual reserve replacement ratio is calculated based on the 1P Reserve revisions (excluding production)
divided by Financial Year production
30 June 2024
FINANCIAL
REPORT
COOPER ENERGY LIMITED
and its controlled entities.
ABN 93 096 170 295
45
46
APPENDIX 4E
PRELIMINARY
FINAL REPORT
CONTENTS
OPERATING AND FINANCIAL REVIEW
49
DIRECTORS’ STATUTORY REPORT
64
REMUNERATION REPORT
69
CONSOLIDATED STATEMENT OF
COMPREHENSIVE INCOME
97
CONSOLIDATED STATEMENT
OF FINANCIAL POSITION
98
CONSOLIDATED STATEMENT
OF CHANGES IN EQUITY
99
CONSOLIDATED STATEMENT
OF CASH FLOWS
100
NOTES TO THE CONSOLIDATED FINANCIAL
STATEMENTS
101
GROUP PERFORMANCE
1. Segment reporting
105
2. Revenues and expenses
107
3. Income tax
109
4. Earnings per share
112
WORKING CAPITAL
5. Cash and cash equivalents and term deposits
113
6. Trade and other receivables
114
7. Prepayments
114
8. Inventory
114
9. Trade and other payables
114
CAPITAL EMPLOYED
10. Property, plant and equipment
115
11. Intangible assets
115
12. Exploration and evaluation assets
116
13. Gas and oil assets
117
14. Impairment
118
15. Provisions
119
16. Leases
121
FUNDING AND RISK MANAGEMENT
17. Interest bearing loans and borrowings
123
18. Net finance costs
123
19. Contributed equity and reserves
124
20. Financial risk management
126
GROUP STRUCTURE
21. Interests In Joint Arrangements
130
22. Investments In Controlled Entities
131
23. Parent Entity Information
132
OTHER INFORMATION
24. Commitments For Expenditure
133
25. Contingent Liabilities
133
26. Share Based Payments
133
27. Related Party Disclosures
136
28. Remuneration Of Auditors
136
29. Events After The Reporting Period
136
CONSOLIDATED ENTITY
DISCLOSURE STATEMENT
137
DIRECTORS’ DECLARATION
138
INDEPENDENT AUDITOR’S
REPORT TO THE MEMBERS OF
COOPER ENERGY LIMITED
139
AUDITOR’S INDEPENDENCE
DECLARATION TO THE DIRECTORS
OF COOPER ENERGY LIMITED
149
SECURITIES EXCHANGE
& SHAREHOLDER INFORMATION
151
ABBREVIATIONS AND TERMS
154
47
48
For the year ended 30 June 2024
For the year ended 30 June 2024
OPERATIONS
Cooper Energy Limited and its controlled entities (“Cooper
Energy”, or the “Company”, or the “Group”) generates
revenue from the production of gas and condensate in the
Otway and Gippsland Basins, and from the production of
oil in the Cooper Basin.
The Company’s current operations and interests include:
§
offshore gas and gas liquids production in the
Gippsland Basin, Victoria, from the Sole gas field;
§
offshore gas and gas liquids production in the Otway
Basin, Victoria, from the Casino, Henry and Netherby
gas fields;
§
onshore oil production in the western flank of the
Cooper Basin, South Australia;
§
the Orbost Gas Processing Plant (“OGPP”) onshore
Gippsland Basin, Victoria;
§
the Athena Gas Plant (“AGP”) onshore Otway Basin,
Victoria;
§
the Annie gas discovery in the offshore Otway Basin
and the Dombey gas discovery in the onshore Otway
Basin;
§
the undeveloped Manta and Gummy gas and liquids
fields in the Gippsland Basin; and
§
exploration prospectivity in the onshore and offshore
Otway, offshore Gippsland and Cooper Basins.
The Company is the operator of all its offshore activities, as
well as the OGPP and AGP, and non-operator of all its
onshore activities.
Workforce
At 30 June 2024, the Company had 126.1 full time
equivalent (“FTE”) employees and 13.4 FTE contractors,
compared with 128.9 FTE employees and 24.4 FTE
contractors at 30 June 2023. This 9% reduction in both
employee and contractor numbers in FY24 is largely tied to
the completion of the BMG wells decommissioning
programme.
Contractors are engaged via third parties in South
Australia, Western Australia and Victoria, and numbers
fluctuated predominantly driven by the requirements of the
BMG wells decommissioning project. As of 30 June 2024,
all contractors engaged by Cooper Energy were contracted
via third party providers.
Health, safety and environment
For the twelve months to 30 June 2024 the Group recorded
zero fatalities, one lost time injury, one restricted work case
and one medical treatment injury.
The lost time injury occurred at the OGPP in November
2023; a Cooper Energy employee suffered a finger injury
requiring surgery and resulting in a lost time period of 3
days.
The restricted work case occurred at AGP in March 2024,
where a contractor suffered discomfort in the lower back
requiring restricted work duties to be assigned.
The medical treatment case occurred on the Helix Q7000
semi-submersible well intervention vessel during the BMG
wells decommissioning project in January 2024, where a
contractor suffered a lacerated ear requiring stitches.
The total recordable injury frequency rate (“TRIFR”) was
4.35 per million hours worked in the 12 months to 30 June
2024, well below the industry benchmark of 5.861 injuries
per million hours worked. The TRIFR declined from the
4.38 per million hours worked recorded in the previous 12
months to 30 June 2023, which was also below the
industry benchmark of 5.681.
There were no reportable2 or notifiable3 environmental
incidents during the period.
Sustainability
A mixture of Australian Carbon Credit Units and Climate
Active eligible international credits were retired at the end
of H1 FY24 and H2 FY24 to offset the Company’s
estimated FY24 scope 1, scope 2 and relevant scope 3
emissions4.
Carbon credit retirements in H2 FY24 were based on an
estimate of emissions and will be trued-up once FY24
emissions data is finalised.
1 NOPSEMA industry rolling 12-month TRIFR for 30 June 2023
and 30 June 2024
2 As defined by Offshore Petroleum and Greenhouse Gas Storage
(Environment) Regulations 2009
3 As defined by the Victorian Environment Protection Act 2017
4 See page 15 of Cooper Energy 2023 Sustainability Report for
scope definitions
OPERATING AND
FINANCIAL REVIEW
RESERVES AND CONTINGENT RESOURCES
Proved and Probable Reserves (2P) at 30 June 2024 are
assessed to be 33.0 MMboe, compared with 36.3 MMboe
at 30 June 2023.
Changes to 2P Reserves for FY24 include production of
-3.7 MMboe and 2P Reserves revisions of +0.4 MMboe.
Contingent Resources (2C) at 30 June 2024 are assessed
to be 48.4 MMboe compared with 48.4 MMboe at 30 June
2023.
Details of Reserves and Contingent Resources and the
movement from the previous year are available in the ASX
announcement titled ‘Reserves and Contingent Resources
at 30 June 2024’, released on 23 August 2024.
Proved and Probable Reserves (2P)
Contingent Resources (2C)
As at 30 June 20241
Gas
PJ
Oil &
condensate
MMbbl
Total
MMboe
Gas
PJ
Oil &
condensate
MMbbl
Total
MMboe
Gippsland Basin
178.1
0.0
29.1
198.9
4.9
37.4
Otway Basin
18.0
0.0
3.0
64.7
0.1
10.7
Cooper Basin
0.0
0.9
0.9
0.0
0.3
0.3
Total Cooper Energy
196.1
0.9
33.0
263.6
5.3
48.4
1 As announced on 23 August 2024. Totals may not reflect arithmetic addition due to rounding. The method of aggregation is by arithmetic sum
by category.
Production5
Gas and oil production for FY24 was 22.7 PJ-equivalent
(“PJe”), or 62.1 TJ-equivalent per day, 4.2% higher than
the prior year, mainly due to increased gas production from
Sole with the improved performance at OGPP.
Total gas production of 21.9 PJ, or 59.9 TJ/d, was 4.1%
higher than the prior year. In the Gippsland Basin,
increased Sole production and improved OGPP
performance resulted in a 5.5% increase in gas production
to 18.1 PJ, or 49.5 TJ/d. In the Otway Basin, natural field
decline at CHN contributed to a 2.0% decline in gas
production to 3.8 PJ, or 10.4 TJ/d (both net to Cooper
Energy’s 50% share).
Oil and condensate production was 131.0 kbbl, or 358
bbls/d (net to Cooper Energy’s 25% share), 9.1% higher
than the prior year due to the production uplift from three
new wells in PRLs 85-104 (formerly PEL 92) in the Cooper
Basin.
Production by product and basin is summarised in the following tables.
PRODUCTION BY PRODUCT
FY24
FY23
Change
Sales gas
PJ
21.9
21.1
4.1%
Oil and condensate1
kbbl
131.0
120.1
9.1%
Total production
PJe
22.7
21.8
4.2%
PRODUCTION BY BASIN
FY24
FY23
Change
Gippsland Basin
Sole: sales gas
PJ
18.1
17.2
5.5%
Otway Basin
Casino Henry: sales gas
PJ
3.8
3.9
(2.0%)
Casino Henry: condensate
kbbl
3.6
3.6
1.8%
Cooper Basin
Oil1
kbbl
127.4
116.6
9.2%
Total production
PJe
22.7
21.8
4.2%
1 FY23 oil production figures may vary compared to previously reported data as a result of production allocation reconciliations. Percentages
may not reflect arithmetic calculation due to rounding
5 Totals may not reflect arithmetic addition due to rounding
OPERATING AND
FINANCIAL REVIEW
49
50
For the year ended 30 June 2024
For the year ended 30 June 2024
Orbost Gas Processing Plant
OGPP delivered an average gas processing rate of 49.5
TJ/d during FY24 (FY23: 47.1 TJ/d).
Production rates increased in H2 FY24 versus H1 FY24,
largely due to the implementation of Orbost Improvement
Project initiatives. Multiple records for Sole/OGPP
production were set during Q3 FY24 including a record
daily rate of 67.3 TJ/d, a 30-day average of 58.2 TJ/d,
a 60-day average of 55.8 TJ/d and a 90-day average of
54.1 TJ/d.
However overall plant performance was below
expectations for large periods of FY24, particularly during
H1 FY24, with continued foaming and fouling issues in the
sulphur absorber units constraining production rates and
requiring absorber downtime for cleaning. Some of these
issues arose from unsuccessful trials during the Orbost
Improvement Project, with learnings applied to improve
system stability.
Production was also impacted by short-term issues, such
as unplanned generator maintenance in March 2024 and
pipeline restrictions in June 2024, which have since been
resolved.
The Sole gas field continues to perform in line with
expectations.
Orbost Improvement Project
Numerous initiatives were implemented over FY24,
focused on minimising foaming and fouling in the
absorbers, increasing the time between absorber cleans
and reducing the duration of cleans. Worksteams
undertaken included:
§
reinstatement of the polisher unit;
§
installation of heat tracing and insulation around the
polisher unit;
§
installation of an alternative spray distributor
configuration in the absorber beds;
§
installation of a mist eliminator in one absorber;
§
optimisation of the anti-foam agent pumps;
§
trials of alternative packing material in the absorbers;
and
§
trials of absorber clean-in-place.
The polisher unit had a significant positive impact on
production during the year. In late December 2023, a new
type of polisher unit media was loaded and achieved a
record life of nearly five months, four times longer than the
previous record.
With the support of the polisher unit and other improvement
initiatives, a record absorber runtime of 6 weeks between
cleans was achieved over June - July 2024, compared to
the previous typical absorber runtime of 2 - 3 weeks.
Work continues on identifying the root cause of the sulphur
foaming and fouling issues in the sulphur absorber units.
While this work is ongoing, the success of improvement
programme initiatives to date has allowed the OGPP to
operate more consistently and at higher rates.
Further Orbost Improvement Project initiatives are being
progressed to improve the reliability of the OGPP and
maximise production rates. With recent 30 day, 60 day,
and 90 day production records, a decision has been made
no longer to progress with the option to install a third
absorber bed.
Athena Gas Plant
The AGP achieved an average gas processing rate of 10.4
TJ/d during FY24 (FY23: 10.7 TJ/d), both net to Cooper
Energy’s 50% share. Notable improvements in plant
reliability were offset by natural decline in the CHN gas
fields.
Low inlet pressure operations were successfully
implemented in the beginning of 2024, resulting in a
production uplift of approximately 1 TJ/d on average. Well
cycling operations continued to be implemented throughout
the year to optimise production from the CHN fields.
Production in Q3 FY24 was impacted by a planned
maintenance shutdown and additional unplanned
compressor maintenance.
During Q4 FY24 AGP demonstrated stable operation with
zero reliability loss over the two months of May and June.
COMMERCIAL
Extended gas sales arrangements with key customers
On 6 November 2023, the Company signed an agreement
with EnergyAustralia to extend the supply term under their
existing Sole gas sales agreement (“GSA”). Under the
amended agreement, the Company will supply five
petajoules of natural gas annually, for three years, from
January 2026. The contract is priced reflective of current
market conditions for term contracts6.
During December 2023, the Company completed a price
review on a one petajoule per annum GSA. Cooper Energy
achieved a favourable outcome, with the revised base
contract price effective 1 January 2024 increasing by the
maximum extent possible under the GSA.
Bairnsdale Power Station gas sales agreement
On 3 June 2024, the Company entered into an agreement
with Alinta Energy to supply as-available gas to the
Bairnsdale Power Station. The Bairnsdale Power Station is
a 94 MW open cycle gas peaker, located approximately
100kms from the Orbost Gas Plant. Gas will be supplied
during times of elevated electricity demand. The agreement
highlights the growing opportunity for Cooper Energy to
provide shaped gas products, to support the reliability of
the electricity system, amidst growing variable renewables.
Gas Market Code
During the period the Company maintained its deemed
exemption to the price rules under the Gas Market Code,
noted as a small supplier supplying the domestic market.
Physical gas portfolio management
During the period the Company entered into a revised suite
of commercial arrangements with Jemena’s Eastern Gas
Pipeline. The arrangements deliver increased flexibility to
manage production variability experienced at the Orbost
Gas Plant and delivery obligations under the Company’s
gas sale agreements.
6 As an indication of current market conditions, please see the ACCC Gas Inquiry December 2023, interim update on east coast gas market, page 87
OPERATING AND
FINANCIAL REVIEW
DEVELOPMENT, EXPLORATION
AND ABANDONMENT
Gippsland Basin
Cooper Energy is the operator and 100% interest holder for
all its Gippsland Basin interests. As at 30 June 2024, these
interests comprised:
a) VIC/L32, which contains the Sole gas field;
b) VIC/RL13, VIC/RL14 and VIC/RL15, which contain the
Basker, Manta and Gummy (BMG) gas and liquids
fields (these retention leases also hold legacy
infrastructure associated with the BMG oil project);
c) VIC/RL16, which contains the shut-in Patricia-Baleen
gas field and infrastructure which connects to the
OGPP; and
d) exploration permits VIC/P72, VIC/P75 and VIC/P80.
BMG wells decommissioning
During FY24, Cooper Energy decommissioned the former
Basker and Manta wells in the offshore Basker-Manta-
Gummy (BMG) retention leases. The work was primarily
undertaken by the Helix Q7000 semi-submersible well
intervention vessel.
Following delayed completion of the Tui field
abandonment, the vessel departed New Zealand in late
November 2023. Equipment and fuel were loaded at
Geelong Port and Corner Inlet, adjacent to the Barry Beach
Marine Terminal in Victoria, prior to transiting to the
offshore BMG location. Well decommissioning operations
commenced in late December 2023.
The late arrival of the Helix Q7000 in Australia resulted in
the Company incurring more than three months of holding
costs for the remaining contractor spread on the BMG
programme. This delayed start and additional time required
for startup activities consumed the budgeted contingency.
On 22 January 2024, the Company revised its mid-case
cost estimate for the BMG wells decommissioning to
approximately A$240-280 million, including a reasonable
contingency for further non-productive time and adverse
weather.
The BMG wells decommissioning programme was
completed in May. The Helix Q7000 vessel went off-hire
and departed the BMG site on 28 May. The programme
incurred more than 360,000 person-hours with no lost time
injuries and no significant environmental incidents. The
success of the wells decommissioning project highlights
the Company's commitment to health, safety, and the
environment, as well as its strong engineering capability.
The total cost of the BMG wells decommissioning
programme is expected to be slightly less than A$270
million, with the final value subject to remaining invoice
reconciliation. Decommissioning costs were funded from
cash on hand, organic cash generation and the existing
senior debt facility.
Cooper Energy continues to pursue its Victorian Supreme
Court claim against PT Pertamina Hulu Energi
("Pertamina") for Pertamina's 10% share of the BMG
decommissioning costs. These costs relate to
decommissioning the seven wells and future removal of
related BMG subsea infrastructure.
Pertamina, via an Australian subsidiary, participated in the
BMG oil project during its production life. Cooper Energy's
claim against Pertamina arises from Pertamina’s
obligations under the withdrawal and abandonment
provisions of the BMG joint operating and production
agreement. Pertamina has been ordered by the Court to
file its defence in September 2024.
Gippsland Basin farm-out
In May 2024, Cooper Energy commenced a process to
bring a partner into VIC/P80 and VIC/L13,14 & 15 (Cooper
Energy 100%) for the next Gippsland gas exploration and
development phase.
The opportunity covers 185 PJ7 of 2C discovered resource
and > 1.3 Tcf8 of prospective resource. This brownfield
project is expected to have a low cost to develop, a clear
commercialisation pathway via existing infrastructure, and
a relatively lower overall emissions profile compared to
alternate sources, such as gas transported to Victoria from
Queensland or imported LNG.
Gippsland Basin gas storage
In Q4 FY24 Cooper Energy commenced studying potential
repurpose of the shut-in Patricia-Baleen field in VIC/RL16
(Cooper Energy 100%) for gas storage.
7 Contingent Resources for Manta gas and liquids announced to
ASX on 12 August 2019, Contingent Resources for Gummy gas
and liquids announced to ASX on 25 August 2023, 100% share
8 The Low (P90), Mid (P50), Mean and High (P10) prospective
resource estimates, and net share of each prospect, were
announced to ASX on 15 May 2023 (Gummy Deep), 13 April 2022
(Wobbegong), and 4 May 2016 (Manta Deep and Chimaera East)
OPERATING AND
FINANCIAL REVIEW
51
52
For the year ended 30 June 2024
For the year ended 30 June 2024
Cooper Energy tested the existing equipment, and the
results of these tests are being integrated into the
Company's assessment of gas storage potential.
Otway Basin (Offshore)
The Company's interests in the offshore Otway Basin as at
30 June 2024 comprised:
a) a 50% interest in and operatorship of production
licences VIC/L24 and VIC/L30 containing the producing
Casino, Henry and Netherby gas fields, with the
remaining 50% interest held by Mitsui E&P Australia
and its associated entities ("Mitsui");
b) a 50% interest in and operatorship of production
licences VIC/L33 and VIC/L34 containing part of the
Black Watch and Martha gas fields, with the remaining
50% interest in these production licences held by
Mitsui;
c) a 50% interest in and operatorship of exploration permit
VIC/P44 containing the undeveloped Annie gas
discovery, with the remaining 50% interest held by
Mitsui;
d) a 100% interest in and operatorship of exploration
permit VIC/P76;
e) a 50% interest in and operatorship of AGP (onshore
Victoria), which is jointly owned with Mitsui and
processes gas from the Casino, Henry and Netherby
gas fields; and
f) a 10% non-operated interest in production licence
VIC/L22, which holds the shut-in Minerva gas field, with
Woodside Energy the operator and 90% interest holder.
East Coast Supply Project
Cooper Energy made significant progress on the East
Coast Supply Project ("ECSP"), formerly referred to as the
Otway Phase 3 Development ("OP3D"), under which the
Company intends to maximise the use of existing Otway
Basin infrastructure to bring much-needed gas supply to
Southeast Australia.
The ECSP developments can be connected to Cooper
Energy's existing gas processing infrastructure at the AGP,
which has ~150 TJ/d of total capacity (100% gross), with
first gas targeted for 2028.
In Q1 FY24, as part of a consortium agreement with three
other operators, the Company secured the Transocean
Equinox rig for its drilling campaign in the Otway Basin.
The Transocean Equinox is estimated to arrive in the
Otway Basin in circa mid-CY2025. Within the consortium
agreement, Cooper Energy has committed to one firm well
and has options to drill additional subsea development
and/or exploration/appraisal wells.
Cooper Energy has evaluated a number of alternatives for
the ECSP drilling and development campaign. The
Company has focused on identifying the optimal campaign
considering the size of prospects, the development’s
overall economic returns, scale of capital expenditure
required and risk.
While Cooper Energy continues to evaluate ECSP
alternatives, the Company is targeting a three-well
programme. This includes developing 64.8 PJ9 in gross 2C
estimated resource (32.4 PJ net to Cooper Energy) through
one well (Annie-2) and a two well exploration programme,
with one planned geological sidetrack, targeting 358 Bcf10
(179 Bcf net to Cooper Energy) of gross mean unrisked
prospective resource potential.
Discussions with Mitsui, Cooper Energy's 50% joint venture
partner in the Otway Basin, regarding the ECSP, are
ongoing.
Cooper Energy expects to sanction the ECSP during FY25,
at which time it will confirm the identity, number and timing
of wells drilled as part of the programme. The Transocean
Equinox is expected to commence drilling the first firm well
of its campaign for Cooper Energy in FY26.
The ECSP is expected to be funded from a range of
sources including organic cash generation, the existing
secured bank debt facility as well as the accordion debt
facility of up to $120 million. Additionally, the Company
continues to engage with several gas customers to support
new domestic gas supply through a range of funding
options, which could include prepayments.
Minerva decommissioning
Woodside Energy, the Operator of VIC/L22 (Cooper
Energy share 10%), will commence decommissioning of
the Minerva gas field in late 2024. The subsea facilities
(pipelines, umbilicals, etc.) will be removed first, followed
by the subsequent decommissioning of three of the four
Minerva wells. The Transocean Equinox rig is estimated to
arrive in the offshore Otway Basin region in circa mid-
CY2025 and will commence the Minerva wells
decommissioning shortly thereafter.
Otway Basin (Onshore)
The Company's interests in the onshore Otway Basin as at
30 June 2024 comprised:
a) a 30% interest in PEL 494, PRL 32 and PEL 680 in
South Australia, with the remaining interests held by the
operator, Beach Energy;
b) a 50% interest in PEP 168 in Victoria, with the
remaining interest held by the operator, Beach Energy;
and
c) a 75% interest in PEP 171 in Victoria, with the
remainder held by operator Vintage Energy Limited.
9 Indicative only, not guidance. Projects are preliminary in nature and not yet
sanctioned. Annie 2C resource is included on a gross basis as part of the
Otway Basin 2C number in the FY23 Reserves and Contingent Resources
ASX released on the 23 August 2024. See also Contingent Resource
announcement: Annie Gas Field”, 24 February 2020.
10 The Low (P90), Mid (P50), Mean and High (P10) prospective resource
estimates, and the net share of each prospect, were announced to ASX on 9
February 2022.
OPERATING AND
FINANCIAL REVIEW
Exploration
The PEL 494 Dombey 3D seismic survey was processed
during H1 FY24 and interpreted during H2 FY24. Analysis
to delineate the resource potential of the Dombey gas field
and identify potential new exploration opportunities is
ongoing and expected to be completed in Q1 FY25.
Reprocessing of existing 3D seismic surveys within PEP
168 was conducted in H1 FY24, with several legacy 3D
seismic datasets across PEP 168 reprocessed into one
survey. Interpretation of this reprocessed seismic data was
undertaken during the H2 FY24 and is ongoing to mature
drilling prospects in the permit.
Cooper Basin
The Company's interests in the Cooper Basin as at 30
June 2024 comprised a 25% interest in PRLs 85-104
(formerly PEL 92), with the remaining interests held by the
operator, Beach Energy.
Exploration and development
Cooper Energy took part in a four well exploration drilling
campaign in PRLs 85-104 (formerly PEL 92) in the first half
of FY24.
The first exploration well, Marion 1, was drilled in
September 2023 and was plugged and abandoned after
failing to encounter hydrocarbons in the primary Namur
Reservoir.
Bangalee South 1, located 630 metres southeast of
Bangalee 1, was drilled in October 2023 and intersected
2.9 metres of net oil pay in the Namur reservoir and 4.3
metres of net oil pay in the Birkhead reservoir. The well
was cased and suspended as a future oil producer. The
Birkhead zone was brought online in December 2023, with
initial production above 350 bbls/d.
In October 2023, Wooley Rock 1 intersected 1.2 metres of
net oil pay and was plugged and abandoned as a non-
commercial discovery. Chadinga 1 was drilled in December
2023, approximately three kilometres northwest of the
Wooley Rock discovery and was plugged and abandoned,
having failed to encounter hydrocarbons.
TRANSFORMATION PROGRAMME
One of the Company’s key priorities for FY24 was the
execution of cost-out initiatives under the transformation
programme, outlined during the FY23 full year results in
August 2023.
The transformation programme is all encompassing,
targeting savings and efficiency across the entire business.
To date, approximately A$10.5 million in net savings has
been realised, with over 100 initiatives identified across the
business. Around 85% of the identified initiatives were
completed or actioned by the end of FY24, with the full
effect of cost savings and benefits realised into FY25 and
beyond.
Significant savings in production costs were achieved
across the business, in particular at OGPP. A large part of
the savings related to cleaning of the absorber beds,
including renegotiating long standing contracts with third
party contractors, as well as reducing the time and
frequency of absorber cleans. Successful implementation
of the in-situ absorber cleans has the potential to deliver
meaningful further savings.
An additional focus area at OGPP was to reduce costs
arising from the removal and disposal of solid sulphur and
process liquids related to the treatment of gas. The
Company is investigating beneficial reuse opportunities for
the solid sulphur that is produced as a by-product at OGPP
and currently classified as a waste. If successful, and in
conjunction with more efficient liquids disposal, the
Company is targeting more than A$2.0 million per year
additional saving from this initiative.
Within the Company’s gas commercial activities, the
company has removed A$0.4 million in costs related to
physical gas portfolio management, through cost saving
initiatives and renegotiation of key contracts.
To date, approximately A$4.6 million in annualised G&A
net savings has been realised, relative to FY23, as a result
of a freeze in general salary rises, reduction in the size of
the Board, reduction in the number of KMP, office
rationalisation, reduction in the use of advisory services,
and reductions to travel and entertainment wherever
possible. This savings number is net of A$2.2 million of
restructuring costs and other FY24 non-recurring items,
hence we expect to see a further significant reduction in
reported G&A in FY25.
OTHER ACTIVITIES
Orbost sulphur trial
In April 2024 the Company agreed with Gippsland
Agricultural Group to undertake a six-month trial to use
sulphur by-product from OGPP as an alternative to
commercially available fertiliser. A permit for the trial was
granted by the Victorian Environmental Protection Agency
and the trial is underway with preliminary results expected
in October 2024.
If successful, the trial will pave the way for the sulphur by-
product to be used in commercial agricultural applications
on an ongoing basis, eliminating the cost of disposal and
potentially generating revenue. This would both reduce
costs for the business, while contributing to the circular
economy and creating opportunities within the community
in which we operate.
OPERATING AND
FINANCIAL REVIEW
53
54
For the year ended 30 June 2024
For the year ended 30 June 2024
FINANCIAL PERFORMANCE
All numbers in tables in the Operating and Financial
Review have been rounded and are expressed in
Australian dollars, except where noted otherwise. Some
total figures may differ insignificantly from totals obtained
from the arithmetic addition of the rounded numbers
presented.
In order to provide a more meaningful comparison of
operating results between periods, the calculation of
underlying EBITDAX and of underlying net profit/(loss) after
tax includes adjustments for items which are considered
unrelated to the Company’s underlying operating
performance.
Underlying EBITDAX and underlying net profit/(loss) after
tax are not defined measures under International Financial
Reporting Standards and are not audited. For that reason,
reconciliations of underlying EBITDAX and of underlying
net profit/(loss) after tax are included at the end of this
review.
Cooper Energy recorded FY24 underlying EBITDAX of
A$127.5 million, 16.7% higher than FY23. There are
several drivers behind the change, which is summarised in
the following chart.
The principal factors which contributed to the movement in
underlying EBITDAX between the periods included:
§ higher gas sales revenue of A$14.6 million attributed to
higher sales volumes compared to the previous year
(22.47 PJ in FY24, versus 21.41 PJ in FY23), together
with higher realised gas prices across the portfolio
(A$8.83/GJ in FY24, versus A$8.59/GJ in FY23);
§ higher crude oil sales revenue of A$7.6 million, due to
higher volumes of lifted oil (143.2 kbbls in FY24 versus
87.7 kbbls in FY23); and
§ production expenses were lower by A$1.9 million in
FY24. Production expenses reflect a full year of
processing gas at OGPP with no toll payable to APA.
Whilst costs have been incurred in addressing the
sulphur depositional issues, savings have been realised
from the transformation programme;
§ third-party gas purchases and trading costs were higher
by A$1.8 million in FY24 due to the timing of purchases
to fulfill contracted sales (564.6 TJ gas purchased in
FY24 versus 346.7 TJ in FY23);
§ other opex was higher by A$2.3 million due to higher
royalties and the production costs associated with oil sold
from PEL 92 that was in inventory in FY23;
§ lower G&A of A$4.6 million linked to savings realised
from the transformation programme; and
§ other items were higher by A$6.4 million primarily due to
costs associated with care and maintenance work at
Patricia-Baleen, as well as the impact of underlying
adjustments.
109.3
127.5
FY23
underlying
EBITDAX
Higher
gas sales
volumes
Higher gas
price
realisations
Higher
crude oil
revenue
Lower
production
costs
Higher
third party
product
purchases
Higher
other opex
Lower G&A
Other
FY24
underlying
EBITDAX
A$ million
OPERATING AND
FINANCIAL REVIEW
Underlying profit after tax (exclusive of the items noted
below) was A$1.4 million, compared with an underlying
loss after tax of A$5.6 million in FY23. Factors driving the
change, in addition to those listed above for underlying
EBITDAX, included:
§ higher net finance costs of A$6.5 million, mostly
due to higher interest expense;
§ higher exploration expenses of A$3.7 million, due to
activity during the period; and
§ lower tax benefit of A$1.5 million.
The Company’s statutory loss after tax was A$114.1
million, which compares with a loss after tax of A$60.5
million recorded in FY23. The FY24 statutory loss included
a number of significant items considered to fall outside
underlying operating performance, which affected the result
by a total of A$115.5 million.
These items comprise:
§ non-cash restoration expense of A$110.3 million resulting
from a reassessment of the BMG, Patricia-Baleen, and
Minerva Field decommissioning provisions;
§ derecognition of the previously recognised deferred tax
asset in respect of the Sole gas field decommissioning of
A$33.3 million11;
§ business restructuring and transformation costs of A$3.4
million;
§ FX hedging costs of A$1.5 million;
§ a non-cash impairment expense of A$0.3 million in
relation to one of the Group’s exploration licences;
§ OGPP acquisition and integration costs of A$0.1 million;
§ other expense of A$1.8 million in respect of the National
Oil & Gas Australia Pty Ltd Commonwealth Government
levy; and
§ tax impact of the above items of A$35.2 million.
Financial performance
FY24
FY23
Change
%
Production volume
PJe
22.74
21.81
0.93
4.2%
Sales volume
PJe
23.37
21.97
1.40
6.4%
Revenue
A$ million
219.0
196.9
22.1
11.2%
Gross profit
A$ million
51.7
32.5
19.2
59.1%
Underlying EBITDAX1
A$ million
127.5
109.3
18.3
16.7%
Operating cash flow
A$ million
(99.8)
62.8
(162.6)
N/M
Underlying loss before tax
A$ million
(7.7)
(16.0)
8.3
51.9%
Underlying profit/(loss) after tax
A$ million
1.4
(5.6)
7.0
N/M
Reported loss after tax
A$ million
(114.1)
(60.5)
(53.6)
(88.6%)
Cash, other financial assets and
investments
A$ million
15.0
78.2
(63.2)
(80.8%)
1 Earnings before interest, tax, depreciation, amortisation, restoration, exploration and evaluation expense and impairment
Cash and cash equivalents decreased by A$62.8 million over the period, as summarised in the chart below.
11 Based on the current 2P profile of the business, and before the additional
production assumed from the ECSP and/or other future developments,
taxable profits may not be generated at the time that Sole decommissioning
is undertaken, hence there may be no taxable profits to be offset by the
deduction for decommissioning costs.
OPERATING AND
FINANCIAL REVIEW
(207.7)
(13.5)
(40.0)
(26.5)
55
56
For the year ended 30 June 2024
For the year ended 30 June 2024
Operating cash outflows for the period were A$99.8 million
in FY24 versus cash inflows of A$62.8 million in FY23.
The main line items for operating cashflow comprised:
§ cash generated from operations of A$121.2 million
(FY23: A$96.7 million). The major drivers of the increase
are explained above in relation to underlying EBITDAX,
while noting that changes in working capital are captured
in cash from operations whereas EBITDAX is reported on
an accruals basis;
§ restoration costs of A$207.7 million (FY23: A$19.6
million), up mostly due to the wells abandonment activity
at BMG in FY24;
§ petroleum resource rent tax (PRRT) refunds of A$0.2
million (FY23: A$6.2 million payments), impacted by
higher deductible expenditure in FY24; and
§ net interest paid of A$13.5 million (FY23: A$8.1 million).
Excluding restoration spend and other non-recurring and
non-underlying items, operating cash flow is A$114.8
million (FY23: A$95.8 million).
Financing, investing and other net cash inflows for the
period were A$37.0 million (FY23: A$232.6 million net cash
outflows) and primarily included:
§ debt drawdown of A$107.0 million (FY23: nil);
§ OGPP deferred acquisition payment of A$40.0 million
(FY23 net acquisition cost of: A$237.0 million12);
§ exploration, intangibles, development and property, plant
and equipment costs of A$26.5 million, comprised of a
number of different elements including order of the first
subsea tree for the ESCP, drilling in the Cooper Basin
and spend on the Orbost Improvement Project (FY23:
A$38.6 million);
§ nil proceeds from held for sale assets (FY23: A$0.7
million);
§ repayment of lease liability of A$1.5 million (FY23: A$1.3
million); and
§ other including foreign exchange revaluation A$2.1
million (FY23: A$1.0 million).
FINANCIAL POSITION
Financial Position
30 June 2024
30 Jun 2023
(Restated)
Change
%
Total assets
A$ million
1,223.2
1,365.0
(141.8)
(10.4%)
Total liabilities
A$ million
805.5
836.5
(31.0)
(3.7%)
Total equity
A$ million
417.6
528.5
(110.9)
(21.2%)
Net debt1
A$ million
(250.7)
(80.9)
(169.8)
209.9%
1 Net debt is based on drawn debt of A$265.0 million (FY23: A$158.0 million). Total debt per the statement of financial position is A$253.1
million (FY23: A$143.9 million), which includes A$11.9 million (FY23: A$14.1 million) of prepaid financing costs.
TOTAL ASSETS
Total assets decreased by A$141.8 million from A$1,365.0
million at 30 June 2023 to A$1,223.2 million at 30 June
2024.
At 30 June 2024, the Company held cash and cash
equivalents of A$14.3 million and investments of A$0.7
million.
Gas and oil assets decreased by A$60.7 million from
A$535.8 million to A$475.1 million, mainly as a result of
amortisation driven by production. Property, plant and
equipment decreased by A$34.1 million from A$380.4
million at 30 June 2023 to A$346.3 million at 30 June 2024,
mainly due to depreciation. Exploration and evaluation
assets increased by A$9.2 million from A$184.6 million to
A$193.8 million, due to PEL 92 exploration drilling and the
order of the first subsea tree for the ECSP.
TOTAL LIABILITIES
Total liabilities decreased by A$31.0 million from A$836.5
million at 30 June 2023 to A$805.5 million at 30 June 2024.
The sum of current and non-current trade and other
payables decreased by A$11.1 million year-on-year, from
A$87.9 million at 30 June 2023 to A$76.8 million.
Provisions decreased by A$117.0 million from A$583.6
million to A$466.6 million, primarily driven by the
completion of BMG abandonment in FY24 and the reset of
certain other provisions.
TOTAL EQUITY
Total equity decreased by A$110.9 million from A$528.5
million to A$417.6 million. In comparing equity at 30 June
2024 to 30 June 2023, the key movements were:
§ higher contributed equity of A$2.2 million due to vesting
of performance rights during the period;
§ higher reserves of A$1.1 million due to share-based
payments issued during the period offset by the transfer
to issued capital for the vested rights; and
§ higher accumulated losses of A$114.1 million due to the
statutory loss for the period.
12 OGPP upfront acquisition cost of A$210.0 million, plus other acquisition
and financing costs of A$27.0 million
OPERATING AND
FINANCIAL REVIEW
STRATEGY AND OUTLOOK
On 4 June 2024, the Company set out its updated 10-year
vision and strategy in an investor briefing presentation and
webcast.
Cooper Energy remains focused on playing a crucial role in
Australia’s energy future, by building on its core business
of producing domestic gas for Australian customers. Our
strategy aligns with the Australian Government’s Future
Gas Strategy, which underscores the importance of gas in
ensuring energy security, reliability and affordability, and
supports the broader energy transition.
At Cooper Energy, we are committed to delivering gas to
Australian consumers, including industrial manufacturers
and major energy generators and retailers. Our strategy
leverages our existing offshore and onshore infrastructure
across Victoria, where the industry and community have
coexisted for decades. This includes backfilling our
facilities by developing new supply from existing basins
that are close to market and opening our infrastructure for
third-party access to maximise utilisation.
Today, in our target markets of Southeastern Australia,
almost 40% of gas consumed is used by industrial
customers to make products that are the backbone of
Australia’s economy. This includes customers in the
construction, food processing and packaging sectors. As
highlighted by the Australian Energy Market Operator13,
gas also remains critical to providing fast-start, reliable,
dispatchable power to support the greater integration of
variable renewables into the electricity market.
As the way gas is used evolves in the future, the shape of
gas demand will change. We are investigating gas storage
and peaking gas opportunities to deliver gas to our
customers when they need it. Being able to supply gas
during peak demand periods, particularly when flexible
gas-powered generation is called upon, will enable us to
capture additional value and margin. Gas storage could be
provided through existing commercial arrangements that
allow us to use ‘line pack’ in transmission pipelines, or
using depleted reservoirs, such as our Patricia Baleen
fields.
In FY25, our business priorities are strong organic cash
generation, to de-risk our growth opportunities, and to
deliver superior shareholder returns. To achieve this our
objectives are to:
§ Reduce production loss at Orbost to deliver low 60s TJ/d
and group production >70 TJe/d by end-FY25;
§ Increase realised gas prices through increased exposure
to spot and peaking gas product opportunities;
§ Drive further cost and emissions reductions through
continuous improvement and efficiencies; and
§ Progress the preferred drilling program to deliver the East
Coast Supply Project and backfill AGP from 2028.
13 See the 2024 Step Change scenario under AEMO’s Gas Statement of
Opportunities, March 2024, which “forecasts the potential for a long-term
increase in gas-powered electricity generation consumption … due to an
increasing need for firming support as coal generators continue to retire and
electrical demand increases through electrification, particularly during winter
seasons when solar output is low” (p.22)
OPERATING AND
FINANCIAL REVIEW
57
58
For the year ended 30 June 2024
For the year ended 30 June 2024
FUNDING AND CAPITAL MANAGEMENT
At 30 June 2024, the Company had cash reserves of
A$14.3 million and drawn debt of A$265.0 million.
The Company has a reserves based loan facility with a
group of banks, with a committed available limit of A$400.0
million as at 30 June 2024 (excluding an up to A$120.0
million accordion facility), to be used for general corporate
purposes. Management plans to utilise the facility to part
fund the planned ECSP in the Otway Basin.
The Company has additional liquidity of A$20.0 million
through a working capital facility to be used for general
business purposes, of which around A$7.4 million has
been utilised in respect of bank guarantees as at 30 June
2024. The facility also includes an additional amount of up
to A$120.0 million, under an accordion facility available,
subject to certain terms and conditions. The Company’s
liquidity position as at 30 June 2024 is illustrated in the
following chart:
* Subject to terms and conditions
Further information is detailed in the basis of preparation and accounting policies section of the Financial Statements.
The Company continues to assess accretive funding options as it pursues growth opportunities.
14.3
161.9
281.9
400.0
265.0
20.0
7.4
120.0
Cash &
cash
equivalents
30/06/2024
RBL
committed
funding
Drawn portion
at 30/06/2024
Working
capital
facility
Utilisation
30/06/2024
Cash and
committed
undrawn
funding
30/06/2024
Additional
accordion*
Adjusted
subtotal
including
accordion
A$ million
OPERATING AND
FINANCIAL REVIEW
265.0
RISK MANAGEMENT
The Company has an established risk management
protocol that is applied at all organisational levels, and
serves to identify and manage risk within the Company’s
risk appetite.
The Company’s management system is being reviewed
and revised to provide effective management of operational
and business risks. The executive leadership team revises
risk assessments and reviews risk management actions for
corporate level risks on a regular basis.
The non-financial internal audit program supports the risk
management program by reviewing the effectiveness of
key risk controls and advising on improvements.
Corporate risk activities and internal audit outcomes are
reported to and discussed with the Risk & Sustainability
Committee of the Board. This Committee oversees the risk
and non-financial audit programs and provides guidance.
RISK
DESCRIPTION
Production
performance
The OGPP contributes around 80% of Cooper Energy group production. The plant has historically
encountered sulphur removal and general reliability issues and it produced below its nameplate
production capacity during FY24. Cooper Energy is progressing an improvement project targeting
sulphur deposition and fouling in the absorbers, as well as general reliability improvements. There is
a risk that the improvement project does not meet, or only partially meets, its objectives and that
overall OGPP performance does not meet Cooper Energy’s expectations in the future. Should OGPP
production fall from FY24 levels of 49.5 TJ/d on average, Group revenue and operating cashflows
will, all else held equal, likely decrease and impact Cooper Energy’s strategic planning.
Conversely, should the improvement project increase OGPP production towards its nameplate
capacity, Group revenue and operating cashflows will, all else held equal, likely increase from FY24
levels.
The Athena Gas Plant or AGP, formerly named the Minerva Gas plant, was built by BHP in 2009, and
was repurposed and renamed the Athena Gas Plant by Cooper Energy in 2020. Characterised as a
mature asset, there are inherent risks associated with aging equipment nearing end of life. Sales gas
and raw gas compression reliability, aging fixed equipment, and end of life control systems for the
offshore wells present ongoing production, revenue, and operating cashflow risks. Cooper Energy
has developed and is progressing strategies and actions to mitigate and minimise these risks.
Cooper Energy operates with a comprehensive range of operating and risk management plans and
an enterprise-wide integrated management system to ensure safe and sustainable operations. To the
extent that it is reasonable and possible to do so, Cooper Energy mitigates the risk of financial loss
associated with operating events through insurance.
Health safety and
environment
The nature of Cooper Energy’s operations poses inherent risks to the health and safety of employees
and contractors as well as posing a range of environmental risks.
A major safety or environmental incident could jeopardise Cooper Energy’s licence to operate,
leading to delays, disruption and a potential interruption of the company’s activities.
Cooper Energy has a comprehensive approach to the management of health, safety and
environmental risks. The company’s management systems integrate technical and engineering
requirements with management and mitigation of personal health and safety risks, process safety
risks and environmental risks.
JV partnership
alignment
Joint venture ownership and operation of assets is common in the gas and oil exploration and
production industry.
Joint ventures are structured to achieve a common goal to develop and operate an asset and are
used to mitigate exploration and development risks including sharing of costs.
The ability for Cooper Energy to execute growth activity in a joint venture (“JV”) can be impacted by a
change of circumstance and consequential divergent or misaligned strategy and appetite for capital
investment by its JV partner.
The joint operating agreement (“JOA”) that covers the Company’s JV in the offshore Otway contains
sole risk and voting provisions in scenarios where JV parties have different or misaligned objectives.
OPERATING AND
FINANCIAL REVIEW
59
60
For the year ended 30 June 2024
For the year ended 30 June 2024
Changes to
restoration
obligations/
provisions
Cooper Energy has certain restoration obligations with respect to its exploration and development
licences, including subsea wells, production facilities and related infrastructure.
These liabilities are derived from legislative and regulatory requirements, which are subject to change.
Cooper Energy’s balance sheet incorporates estimates for such decommissioning and abandonment
activity, with those estimates included within provisions.
Cooper Energy 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.
Gas and oil reserves and estimates of contingent resources are expressions of judgement based on
knowledge, experience and industry practice. Estimates may change and may change significantly, or
become uncertain, when new information becomes available and/or there are material changes to
circumstances which result in a change to plans. This may have a positive or negative effect on
estimated restoration provisions.
Changes to the estimate of restoration provisions are recognised in line with accounting standards.
Restoration provisions are informed estimates, but there can be no assurance that the future actual
costs associated with decommissioning and abandonment will not exceed the long-term provision
quantum recognised to cover this activity.
Positive cash
generation and
access to capital
Cooper Energy undertakes significant capital expenditure to fund exploration, appraisal,
development and restoration requirements.
While Cooper Energy generates positive operating cashflow to reinvest into the business, it may
also seek, from time to time, to access third-party capital to accelerate organic and/or inorganic
growth options.
Organic operating cashflow generation is dependent upon many variables, such as production
rates including uptime, prevailing spot prices for uncontracted gas and global oil price benchmarks,
operating costs, general and administration costs, taxation and foreign exchange rates.
Spot gas prices are subject to fluctuations and are affected by numerous factors beyond the control
of Cooper Energy. Cooper Energy monitors and analyses its gas and oil markets and seeks to
reduce price risk where reasonable and practical. Gas price risk is assessed within the context of
the Company’s ongoing modelling of the Southeast Australian energy market and through its gas
contracting strategy, which prioritises long term agreements and appropriate indexation and price
review clauses.
There can be no assurance that sufficient organic operating cashflow generation and/or access to
incremental third-party capital will be available on acceptable terms, or at all. Lower organic
operating cashflow generation and/or limitations on access to adequate incremental third-party
capital could have a material adverse effect on the business, including the ability to commercialise
discoveries and expand the Company’s operations, long term results from operations, financial
conditions and prospects, and compliance with covenants under the existing bank facility.
If Cooper Energy accesses further funding under the existing debt facility, Cooper Energy’s debt
levels will increase. Consequently, there is a risk that Cooper Energy may be more exposed to
risks associated with gearing and leverage.
Failure to comply with the covenants of the debt facility could limit financial flexibility. It may enable
the bank group to accelerate repayment of the Company’s debt obligations.
Lower organic operating cashflows, whether as a result of a decline in commodity prices or
otherwise, may also give rise to changes in the assumptions incorporated into the estimation of fair
market values used to test the carrying value of Cooper Energy’s gas and oil assets.
Market
intervention and
legislative
changes
Cooper Energy operates in a highly regulated environment and complies with the law.
Federal or State Government intervention, legislative, policy or guideline changes can impact
Cooper Energy's operations and share value.
Changes, and uncertainty with respect to future legislative changes, can prolong compliance,
delay approvals and escalate costs, impacting the company's financial position or expected
financial returns.
Cooper Energy engages with Federal and State governments and regulators on a regular basis to
maintain open channels of communication.
OPERATING AND
FINANCIAL REVIEW
Climate change &
energy transition
Cooper Energy recognises its activities may be impacted by climate change and the energy
transition.
Risks are identified and managed in two broad categories: physical climate change risks relating to
direct impacts on the Company’s operations, and energy transition risks arising from the move to a
net-zero energy system.
A comprehensive range of risks and opportunities associated with climate change is incorporated into
company policy, strategy and risk management processes. Cooper Energy has taken a proactive
stance, since 2020, to voluntarily offset its Scope-1 (direct), Scope-2 (purchased electricity) and
relevant Scope-3 emissions14 (e.g. embedded energy and business travel), with a blend of Australian
and international carbon credits. Cooper Energy also identifies and executes opportunities to reduce
physical emissions from its operated assets, including opportunities to reduce flaring and fuel gas
consumption, which also make more gas available to market.
The Company’s carbon neutral status15 is certified by Climate Active, an initiative of the Australian
Federal Government. For the avoidance of doubt, Cooper Energy does not offset downstream
customer “Scope-3” emissions which arise primarily from processing, transmission, distribution and
combustion of sold products.
Cooper Energy is also investigating opportunities to invest in carbon credit origination projects, both
in Australia and overseas. Investing in carbon credit origination projects aims to reduce the cost to
access credible credits for our carbon neutral16 certification.
Our proactive approach to emissions reduction and voluntary offsets may also help to mitigate risks
associated with climate activism. Cooper Energy is conscious of the risk of activism from some parts
of the community and certain other stakeholders, aimed at delaying new natural gas projects, such as
Cooper Energy’s East Coast Supply Project (ECSP). Cooper Energy’s project opportunities are in
existing basins, leveraging existing infrastructure, helping to minimise the environmental footprint.
The Australian Government’s Future Gas Strategy, released in May 2024, highlights the principle of
the need for new sources of gas supply, such as the ECSP, to meet demand during the economy-
wide transition.
On energy transition risk, the Company’s domestic gas assets are resilient to the threat of demand
loss from climate change. AEMO scenarios, including their central Step Change scenario, indicate
that although gas demand may reduce slightly in Cooper Energy’s target markets of Southeast
Australia, gas supply is declining even faster, creating a significant opportunity for additional domestic
gas supply. This underpins Cooper Energy’s long-term strategy to grow its business and to increase
market share.
Gas is expected to play a significant role through the energy transition in two key areas. First, as a
source for heating and industrial use by Australian manufacturers, where limited cost effective or
practical alternatives are available, and second, to provide firming of variable renewable power
generation as the electricity network continues to decarbonise.
The Company’s strategy continues to focus on conventional gas production, locally in Southeast
Australia, close to market. The Company measures and publicly reports its emissions and emissions
offsets to maintain its carbon neutral14 position. These results, together with detail on climate change
impacts, direct emissions reduction initiatives and its energy transition strategy, are described in
Cooper Energy’s annual Sustainability Report. Disclosures are aligned with the Taskforce on Climate
related Financial Disclosures. See page 18 of the 2023 Sustainability Report for further information.
14 Cooper Energy has been certified by Climate Active as a carbon neutral organisation for its Scope-1, Scope-2 and what Cooper Energy defines as its relevant
Scope-3 emissions for FY20-23. Cooper Energy is in the process of seeking FY24 certification. See page 15 of Cooper Energy 2023 Sustainability Report for further
information.
15 Refer to footnote 14 above.
16 Refer to footnote 14 above.
OPERATING AND
FINANCIAL REVIEW
61
62
For the year ended 30 June 2024
For the year ended 30 June 2024
Access to skills
and capabilities
Cooper Energy relies on the ability to attract and retain people with the right skills, behaviours and
capability to deliver both its base business and its growth opportunities. It also relies on skills and
expertise provided through industry service providers for both onshore and offshore operations.
Failure to access such capability and services may constrain the achievement of business objectives.
Cooper Energy has established employment conditions and practices, incentives and a workplace
culture designed to attract and retain the skills and experience needed to deliver business objectives.
The Company aims to appeal to a diverse group of individuals and ensure their inclusion in its ‘one
team’ ethos. Metrics are in place to monitor employee engagement, and these are regularly
reviewed by the executive leadership team and the Board.
The company has well-established relationships with service providers regionally, domestically and
globally. Cooper Energy collaborates with industry colleagues to partner in offshore campaigns, for
example, as a means to share access to skills and experience. This includes the engagement of
international providers with access to a global workforce. The company also has access to well-
known and highly skilled contract personnel engaged to meet the various project requirements.
OPERATING AND
FINANCIAL REVIEW
Cyber security
Cooper Energy’s operations are, and will continue to be, reliant on various computer systems, data
repositories and interfaces with networks and other systems. Failures or breaches of these systems
(including by way of virus and hacking attacks) have the potential to materially and negatively impact
Cooper Energy’s operations.
Cooper Energy has barriers, continuity plans and risk management systems in place, however there
are inherent limits to such plans and systems. Further, Cooper Energy has no control over the cyber
security plans and systems of third parties which may interface with Cooper Energy’s operations, or
upon whose services Cooper Energy’s operations are reliant.
RECONCILIATIONS FOR NET LOSS TO UNDERLYING NET LOSS
AND UNDERLYING EBITDAX
Reconciliation To Underlying EBITAX1
FY24
FY23
Change
%
Underlying profit/(loss)
A$ million
1.4
(5.6)
7.0
125.1%
Add back:
Net finance costs
A$ million
15.0
8.5
6.5
76.5%
Accretion expense
A$ million
17.7
18.0
(0.3)
(1.7%)
Tax benefit
A$ million
(11.0)
(36.2)
25.2
69.6%
Tax adjustments to generate underlying profit/(loss)
A$ million
1.9
25.8
(23.9)
(92.6%)
Depreciation
A$ million
40.1
38.7
1.4
3.6%
Amortisation
A$ million
58.7
60.1
(1.4)
(2.3%)
Exploration and evaluation expense
A$ million
3.7
-
3.7
N/M
Underlying EBITDAX
A$ million
127.5
109.3
18.2
16.7%
Reconciliation to Underlying Loss
FY24
FY23
Change
%
Net loss after income tax
A$ million (114.1)
(60.5)
(53.6)
(88.6%)
Adjusted for:
OGPP reconfiguration and commissioning works
A$ million
-
0.4
(0.4)
N/M
OGPP acquisition and integration costs
A$ million
0.1
5.8
(5.7)
(98.2%)
Hedging costs
A$ million
1.5
-
1.5
N/M
APA toll normalisation
A$ million
-
2.9
(2.9)
N/M
Business restructuring and transformation
A$ million
3.4
2.7
0.7
25.9%
Restoration expense and associated costs
A$ million
110.3
49.1
61.2
124.6%
NOGA levy
A$ million
1.8
1.7
0.1
5.9%
Impairment
A$ million
0.3
26.1
(25.8)
(98.9%)
Derecognition of deferred income tax asset
A$ million
33.3
-
33.3
N/M
AASB 112 retrospective change
A$ million
-
(8.0)
8.0
N/M
Tax impact of adjustments to underlying loss
A$ million
(35.2)
(25.8)
(9.4)
(36.4%)
Underlying profit/(loss)
A$ million
1.4
(5.6)
7.0
125.1%
1 Earnings before interest, tax, depreciation, amortisation, restoration, exploration and evaluation expense and impairment.
The Directors present their report together with the Consolidated
Financial Report of the Group, being Cooper Energy Limited (the
“parent entity” or “Cooper Energy” or “Company”) and its controlled
entities, for the financial year ended 30 June 2024, and the Independent
Auditor’s Report thereon.
1. DIRECTORS
The Directors of the parent entity at any time during or since the end of the financial year are:
MR JOHN C. CONDE AO
B.Sc. B.E(Hons), MBA
Chairman
Independent
Non-Executive Director
Appointed 25 February 2013
Experience and expertise
Mr Conde has extensive experience in business and commerce and in chairing high profile
business, arts and sporting organisations.
Previous positions include non-executive director of BHP Billiton (ASX:BHP), Chairman of
Bupa Australia, Chairman of Pacific Power (the Electricity Commission of NSW),
Chairman of the Sydney Symphony Orchestra, director of AFC Asian Cup, Chairman of
Events NSW, President of the National Heart Foundation, Chairman of the Pymble
Ladies’ College Council and director of Dexus Property Group (ASX:DXS).
Current and other directorships in the last 3 years
Mr Conde is Chairman of The McGrath Foundation (since 2013 and director since 2012)
and Chairman of Dexus Wholesale Property Fund (DWPF) (since 2020).
Mr Conde is a former President of the Commonwealth Remuneration Tribunal (2003 –
2023) and Deputy Chairman of Whitehaven Coal Limited (ASX:WHC) (2007 – 2022)
Special responsibilities
Mr Conde is Chairman of the Board of Directors. Effective 19 August 2021 he is also a
member of the People & Remuneration Committee and is the Chairman of the
Governance & Nomination Committee.
MS JANE L. NORMAN
B.Sc.,B.Eng.(Hons) PGDip
GAICD
Managing Director and CEO
Appointed 20 March 2023
Experience and expertise
Jane has worked and studied in Australia and the UK and brings 30 years of industry
experience in the energy markets. She began her career with Shell International
Exploration & Production as a Process Engineer in operations and then as a Commercial
Advisor in The Hague, Aberdeen and London. Subsequently, in London, Jane held
corporate finance and equity capital markets roles with Cazenove & Co (now JP Morgan
Cazenove) and Goldman Sachs.
Jane returned to Australia to join Santos where she held senior commercial, corporate
strategy and Executive Committee roles. She led major strategic initiatives at Santos and
played a key role in Santos’ growth strategy, in particular the merger with Oil Search.
During her time at Santos Jane helped drive the transformation of company performance,
helping to establish the growth strategy focused on cash generation and shareholder
returns and, more recently, the company’s energy transition strategy. Jane holds a
Bachelor of Science (Pure Mathematics and Chemistry) and Bachelor of Chemical
Engineering (Hons) from the University of Sydney and a Graduate Diploma in
Management and Economics of Natural Gas (Distinction) from the University of Oxford.
Jane is a Graduate of the Australian Institute of Company Directors.
Current and other directorships in the last 3 years
Ms Norman is a director of the wholly owned subsidiaries of Cooper Energy Limited and is
on the Board of the Australian Energy Producers (since 2023).
Special responsibilities
Ms Norman is Managing Director and CEO. She is responsible for the day-to-day
leadership of Cooper Energy, and is the leader of the Executive Leadership Team.
DIRECTORS’
STATUTORY REPORT
63
64
For the year ended 30 June 2024
For the year ended 30 June 2024
MR TIMOTHY
G. BEDNALL
LLB (Hons)
Independent Non-Executive
Director
Appointed 31 March 2020
Experience and expertise
Mr Bednall is a highly experienced and respected corporate lawyer and law firm manager.
He is a partner of King & Wood Mallesons (KWM), where he specialises in mergers and
acquisitions, capital markets and corporate governance, representing public company and
government clients. Mr Bednall has advised clients in the oil and gas and energy sectors
throughout his career.
Mr Bednall was the Chairman of the Australian partnership of KWM from January 2010 to
December 2012, during which time the merger of King & Wood and Mallesons Stephen
Jaques was negotiated and implemented. He was also Managing Partner of M&A and
Tax for KWM Australia from 2013 to 2014, and Managing Partner of KWM Europe and
Middle East from 2016 to 2017. He was General Counsel of Southcorp Limited (which
became the core of Treasury Wine Estates Limited) from 2000 to 2001.
Current and other directorships in the last 3 years
Mr Bednall is a board member of the National Portrait Gallery Foundation (since 2018)
and a director of Pooling Limited (since 2017).
Special responsibilities
Effective 19 August 2021 Mr Bednall is a member of the Audit Committee, the People &
Remuneration Committee and the Governance & Nomination Committee, and effective 9
November 2023 Mr Bednall is a member of the Risk and Sustainability Committee.
MS GISELLE
M. COLLINS
B. Ec, CA
GAICD
Independent
Non-Executive Director
Appointed 19 August 2021
Experience and expertise
Ms Collins has broad executive and director experience across finance, treasury and
property disciplines.
Ms Collins’ executive positions included General Manager Property, Treasury and
Tourism of NRMA, Chief Executive Officer, Property and General Manager Finance with
the Hannan Group, and Senior Manager, Audit Services with KPMG Switzerland. Ms
Collins is a former non-executive director and Chairman of the following companies: Aon
Superannuation (2016 – 2017), The Travelodge Hotel Group (2009 – 2013) and The
Heart Research Institute Limited (2003 – 2011).
Current and other directorships in the last 3 years
Ms Collins is Chairman of Hotel Property Investments (ASX:HPI) since 2022, director
since 2017 and recently appointed as Chairman of Pacific Smiles Limited (ASX:PSQ),
director since 2023. Ms Collins is also a non executive director of Generation
Development Group (ASX:GDG) since 2018 and Chairman of the responsibility entity
(RE) for AMP Limited’s managed investment schemes since 2021.
Ms Collins is a former Chairman for Indigenous Business Australia in the Darwin Hotel Pty
Limited, non-executive director of Generation Life (2018 – 2021) and Peak Rare Earths
Limited (ASX:PEK) (2021 – 2023).
Special responsibilities
Effective 19 August 2021 Ms Collins is a member of the Audit Committee and the Risk &
Sustainability Committee. Effective 9 November 2023 Ms Collins is the Chairman of the
Audit Committee and a member of the Governance & Nomination Committee.
DIRECTORS’
STATUTORY REPORT
MS ELIZABETH
A. DONAGHEY
B.Sc., M.Sc.
Independent
Non-Executive Director
Appointed 25 June 2018
Experience and expertise
Ms Donaghey brings over 30 years’ experience in the energy sector including technical,
commercial and executive roles in EnergyAustralia, Woodside Energy and BHP
Petroleum.
Ms Donaghey’s experience includes non-executive director roles at Imdex Ltd (an ASX-
listed provider of drilling fluids and downhole instrumentation), St Barbara Ltd (a gold
explorer and producer), and the Australian Renewable Energy Agency. She has
performed extensive committee roles in these appointments, serving on audit and
compliance, risk and audit, technical and regulatory, remuneration and health and safety
committees.
Current and other directorships in the last 3 years
Ms Donaghey is currently a non-executive director of the Australian Energy Market
Operator (AEMO) (since 2017) and a non-executive director of Ampol Limited (ASX: ALD)
(since 2021).
Special responsibilities
Effective 19 August 2021 Ms Donaghey is a member of the Risk & Sustainability
Committee, the People & Remuneration Committee and the Governance & Nomination
Committee. Effective 23 June 2023 Ms Donaghey is the Chairman of the Risk &
Sustainability Committee.
MR JEFFREY
W. SCHNEIDER
B.Com
Independent Non-Executive
Director
Appointed 12 October 2011
Experience and expertise
Mr Schneider has over 30 years of experience in senior management roles in the oil and
gas industry, including 24 years with Woodside Energy. He has extensive corporate
governance and board experience as both a non-executive director and chairman in
resources companies.
Current and other directorships in the last 3 years
Mr Schneider does not currently hold any other directorships.
Special responsibilities
Effective 19 August 2021 Mr Schneider is Chairman of the People & Remuneration
Committee. Effective 9 November 2023 Mr Schneider is also a member of the Audit
Committee.
MS VICTORIA J. BINNS
B. Eng (Mining – Hons 1),
Grad Dip SIA, FAusIMM, GAICD
Independent
Non-Executive Director
Appointed 2 March 2020
Retired 9 November 2023
Experience and expertise
Ms Binns has over 35 years’ experience in the global resources and financial services
sectors, including more than 10 years in executive leadership roles at BHP and 15 years
in financial services with Merrill Lynch Australia and Macquarie Equities. During her
career at BHP, Ms Binns’ roles included Vice President Minerals Marketing, leadership
positions in the metals and coal marketing business, Vice President of Market Analysis
and Economics and was a member of the first BHP Global Inclusion and Diversity
Council.
Prior to joining BHP, Ms Binns held a number of board and senior management roles at
Merrill Lynch Australia including Managing Director and Head of Australian Research,
Head of Global Mining, Metals and Steel, and Head of Australian Mining
Research. She was also co-founder and Chair of Women in Mining and Resources
Singapore.
Current and other directorships in the last 3 years
Ms Binns is a non-executive director of Evolution Mining (ASX:EVN) (since 2020) and
Sims Limited (ASX:SGM) (since 2021). She is also a non-executive director of the
Carbon Market Institute and a member of the J.P. Morgan Australia & NZ Advisory
Council.
Special responsibilities
Prior to her retirement, Ms Binns was the Chairman of the Audit Committee and was a
member of the Risk & Sustainability Committee.
DIRECTORS’
STATUTORY REPORT
65
66
For the year ended 30 June 2024
2. COMPANY SECRETARY
Ms Nicole Ortigosa B.A., LLB (Hons), Grad Dip Legal
Practice was appointed to the position of Company
Secretary and General Counsel effective from 21 April
2023.
Nicole has over 16 years experience as a corporate and
commercial lawyer, specialising in the energy and
resources sector. Prior to joining Cooper Energy she
worked for top tier law firms across Australia, including
Clifford Chance and Minter Ellison. Nicole’s experience
covers all legal, corporate, and commercial aspects of the
business, including joint ventures, gas sales, infrastructure,
environment, regulatory, procurement, mergers and
acquisitions, corporate governance and compliance.
Nicole started at Cooper Energy in 2017 and prior to
becoming General Counsel & Company Secretary was the
Legal Manager. Amongst other matters, she has advised
the company on the development of the Sole gas field, the
acquisition of AGP and associated infrastructure and the
acquisition of OGPP and associated onshore and offshore
pipeline infrastructure.
She holds a Bachelor of Laws with Honours from the
University of Adelaide and a Graduate Diploma in Legal
Practice from the Law Society of South Australia.
3. DIRECTORS’ MEETINGS
The number of Directors’ meetings (including meetings of committees of Directors) and number of meetings attended by each of
the Directors during the financial year were:
A = Number of meetings attended.
B = Number of meetings held during the time the Director held office, or was a
member of the Committee, during the year.
Director
Board
Meetings
Audit Committee
Meetings
Risk &
Sustainability
Committee
Meetings
People &
Remuneration
Committee
Meetings
Governance &
Nomination
Committee Meetings
A
B
A
B
A
B
A
B
A
B
Mr J. Conde
7
7
-
-
-
-
4
4
1
1
Mr J. Norman
7
7
-
-
-
-
-
-
-
-
Mr T. Bednall
7
7
4
4
2
2
4
4
1
1
Ms E. Donaghey
7
7
-
-
4
4
4
4
1
1
Mr J. Schneider
7
7
2
2
-
-
4
4
1
1
Ms G. Collins
7
7
4
4
4
4
-
-
-
-
Ms V. Binns1
4
4
2
2
2
2
-
-
-
-
DIRECTORS’
STATUTORY REPORT
1 Ms Binns retired effective 9 November 2023
68
67
For the year ended 30 June 2024
For the year ended 30 June 2024
4. REMUNERATION REPORT (AUDITED)
Information about the remuneration of the Company’s key management
personnel for the financial year ended 30 June 2024 is set out in the
Remuneration Report. The Remuneration Report forms part of the
Directors’ Report. It has been prepared in accordance with section
300A of the Corporations Act 2001 and has been audited as
required by that Act.
REMUNERATION REPORT
INTRODUCTION FROM THE
CHAIRMAN OF THE PEOPLE &
REMUNERATION COMMITTEE
Dear Shareholder,
The 2024 financial year (FY24) has seen notable
improvement in the performance of the business and the
achievement of a significant milestone with the completion
of the BMG wells decommissioning project. This, together
with the improving performance of the Orbost Gas
Processing Plant (OGPP), provides a positive business
setting which creates the opportunity for future growth.
The company has a clear strategy supported by a
refreshed Executive Leadership Team (ELT) established
by Jane Norman, Managing Director & Chief Executive
Officer since her commencement in March 2023.
This Remuneration Report reflects achievement levels in
FY24 and the associated remuneration outcomes for the
Key Management Personnel (KMP). The report
documents the Company’s remuneration framework and
guiding principles and illustrates clearly the impact of the
Company’s performance on the remuneration outcomes.
We will seek shareholders’ support for the Remuneration
Report at the 2024 Annual General Meeting.
The Board believes that the FY24 remuneration outcomes
are appropriate, taking into account the Company’s
performance, changes in the business, cost of living and
competition in the employment market for high quality staff.
Remuneration Report Context: 2024 Financial Year
The Company’s performance in the 12 months to 30 June
2024 is reported in the Operating and Financial Review of
the Financial Report. This performance and how it
compared with the specific targets of the Company
Scorecard provide the context of the Remuneration Report.
In FY24, the Company has been successful in maintaining
its strong performance in Health and Safety at industry
leading levels, together with no recordable environmental
incidents. The financial targets (cash OPEX, net G&A and
SIB Capex) were largely achieved. However, production
levels are yet to reach target levels despite significant
improvements and the commitment of the operations team
under the new leadership of our Chief Operating Officer,
Chad Wilson.
Our Projects & Growth scorecard dimension was
predominately weighted to the successful completion of the
BMG wells decommissioning project. The completion of
this project demonstrated the strength of our engineering
capability which was able to meet the many challenges of
this large scale and complex task. It was also delivered
without any significant safety or environmental incident.
Whilst recognising the major efforts of the BMG project
team, delays in the project and increased costs have
meant that the minimum level for reward (above Threshold)
was not achieved.
Full details of the scoring of the Company Scorecard for
FY24 are captured in 4.6.2. The Board determined that a
FY24 short-term incentive plan (STIP) payment be
awarded that reflected a Company Scorecard result of
56.1%. STIP relating to individual performance will also be
awarded to Executive KMP and Staff based on
achievement against individual objectives. The FY24 STIP
outcomes for the KMP are included in this report 4.6.3.
REMUNERATION DEVELOPMENTS
As foreshadowed in last years’ report, the company’s
Executive KMP numbers have reduced. For FY25, there
will be four Executive KMP roles namely the Managing
Director and Chief Executive Officer, Chief Financial
Officer, Chief Operating Officer and Chief Commercial
Officer. In FY25 the Exploration and Subsurface function
will come under the leadership of the Chief Operating
Officer, Chad Wilson. Andrew Thomas, previously Chief
Exploration and Subsurface Officer, leaves Cooper Energy
after 12 years of dedicated service.
Other executive roles shown in this report continue to be
part of the Cooper Energy Executive Leadership Team
(ELT). The revised Executive KMP group better reflects
those directly responsible for planning, directing and
controlling the activities of Cooper Energy and the size of
the business. The revised number of Executive KMP also
better aligns with our industry peers.
Last year I also indicated that there would be a review of
some aspects of our remuneration framework to ensure it
is meeting its intended objectives of providing incentives to
deliver superior performance to our shareholders, as well
as attracting and retaining high calibre employees. As a
result of this review, there have been some changes to the
STIP and LTIP as it applies to the Executive KMP and
broader ELT. These are described in 4.4.2 of this report.
The changes are intended to strengthen the connection
between the shareholder experience and remuneration
outcomes of our executives.
REMUNERATION
REPORT
REMUNERATION OUTCOMES
Fixed annual remuneration (FAR): planned increases to
the Executive KMP FAR were communicated in last year’s
report. However, given the company’s financial and
business performance these increases did not proceed in
FY24 (other than the statutory change to superannuation).
This was true for the ELT and for Staff not covered by an
enterprise agreement. The only exception was the small
number of employees who took on additional
responsibilities during FY24. This included the Chief
Financial Officer. The decision not to proceed with general
increases in FY24 was consistent with our cost
containment objectives of FY24.
As a consequence, there has not been a general salary
increase for ELT and Staff (excluding those covered by an
enterprise agreement) since 1 July 2022. Statutory
increases to the superannuation rate have been passed on
to all employees. The Board determined that an increase
will be applied to ELT and Staff effective 1 July 2024
including the increase in statutory superannuation. For the
Executive KMP, these increases range from 1.8% to
4.42%. The overall increase for the whole of the ELT was
3.33%. Increases to base salaries are seen as comparable
to our relevant peer companies and industry generally.
The next general review of base salaries will be 1 October
2025.
Short term incentive plan (STIP): the FY24 STIP
outcomes for the Executive KMP are included in this report
in 4.6.3. These reflect the Company Scorecard result and
achievement against FY24 individual objectives.
For FY25, a deferred equity component will be included in
STIP for the ELT. To date, any STIP reward for the ELT
has resulted in a cash payment. An equity opportunity has
only existed in the LTIP. For the Managing Director &
Chief Executive Officer (MD & CEO) and the Chief
Operating Officer their existing maximum STIP opportunity
will be adjusted to reduce the cash component and include
the equity component. For example, in the case of the MD
& CEO, the existing cash maximum opportunity of 125% of
FAR, will become a maximum of 105% rewarded in cash
and a maximum of 20% rewarded in equity (performance
rights) with a deferral period of 12 months. Other ELT
members will have their maximum STIP opportunity
increased from 50% to 60% of FAR with the additional
amount becoming an opportunity to earn performance
rights (with a 12-month deferral period for vesting). This
change is intended to strengthen the connection between
the shareholder experience and remuneration outcomes of
the ELT. Full details are described in 4.4.4.
Shareholders should note that if the FY25 STIP results in
an eligible grant of performance rights (equity) for the MD &
CEO, approval of shareholders will be sought at the 2025
Annual General Meeting (AGM).
Long term incentive plan (LTIP): our remuneration
framework is also designed to reward superior
performance over the long term and align executive
performance with shareholder value. The Board has
resolved to revise the structure of LTIP to include a second
measurement resulting in two evenly weighted measures
being relative total shareholder return (RTSR) and absolute
total shareholder return (ATSR). Under the revised
structure approved by the Board, grants will be solely in
performance rights; share appreciation rights do not form
part of the revised LTIP offer. The LTIP offer to the ELT in
December 2023 (3-year plan) reflected this structure. The
details of these measures are described in 4.4.5. For the
MD & CEO, shareholders approved the revised LTIP
structure at the 2023 AGM.
LTIP grants from December 2021 and 2022 will be tested
in December 2024 and 2025 respectively. The structure of
these plans remains as performance rights and share
appreciation rights, with any vesting subject to actual
performance against the nominated peer group (RTSR).
There has been no vesting from the LTIP since December
2020, due to the underperformance of the business.
The revised LTIP will continue to rely on strong business
performance, including growth in the company’s share
price, to deliver any level of vesting.
Directors fees: non-executive director fee remuneration
was last increased on 1 July 2019. Since that time statutory
increases to superannuation have also been absorbed
within the total fee. Effective 1 July 2024, the Board
resolved that the Company would pay the increase to the
superannuation rate (from 11% to 11.5%) but that there
would be no other increase in directors fees. This is
reflected in the Board Fees shown in 4.9.1.
The level of energy and commitment to succeed in the
Company is very strong, at all locations and levels.
The Board recognises the gains made in FY24 and is very
appreciative of the efforts of all staff in this regard. Under
Jane Norman’s leadership we are confident we will realise
the company’s potential and we look forward to FY25 and
beyond.
Yours sincerely
Mr Jeffrey Schneider
Chairman of the People & Remuneration Committee
REMUNERATION
REPORT
69
70
For the year ended 30 June 2024
For the year ended 30 June 2024
4.1 INTRODUCTION
This Remuneration Report (Report) details the approach to
remuneration frameworks, outcomes and performance for
Cooper Energy. The Remuneration Report forms part of
the Directors’ Report and provides shareholders with an
understanding of the remuneration principles and practices
in place for Key Management Personnel (KMP) for the
reporting period.
4.2 KEY MANAGEMENT PERSONNEL
COVERED IN THIS REPORT
In this Report, KMP are the people who have the authority
and responsibility for planning, directing and controlling the
activities of the Group, either directly or indirectly. They are:
§ the Non-Executive Directors;
§ the Managing Director and Chief Executive Officer; and
§ selected executives on the Executive Leadership Team.
The Managing Director and Chief Executive Officer and
select executives on the Executive Leadership Team are
referred to in this Report as “Executive KMP”. The following
table sets out the KMP of the Group during the reporting
period and the period they were KMP:
Name
Position
Period As KMP
Non-Executive Directors
John Conde AO
Chairman
Full Year
Timothy Bednall
Non-Executive Director
Full Year
Giselle Collins
Non-Executive Director
Full Year
Elizabeth Donaghey
Non-Executive Director
Full Year
Jeffrey Schneider
Non-Executive Director
Full Year
Former Non-Executive KMP
Vicky Binns1
Non-Executive Director
Part Year1
Executive KMP
Jane Norman
Managing Director & Chief Executive Officer
Full Year
Chad Wilson2
Chief Operating Officer
Part Year2
Dan Young
Chief Financial Officer
Full Year
Eddy Glavas
Chief Commercial Officer
Full Year
Andrew Thomas3
Chief Exploration & Subsurface Officer
Full Year3
1 Vicky Binns retired from the Board effective 9 November 2023.
2 Chad Wilson commenced effective 23 October 2023.
3 Andrew Thomas ceased as Executive KMP on 30 June 2024. Andrew leaves Cooper Energy on 30 September 2024.
CONTENTS
4.1
Introduction
71
4.2
Key Management Personnel Covered in this Report
71
4.3
Remuneration Governance
72
4.4
Nature & Structure of Executive KMP Remuneration
72
4.5
Cooper Energy’s Five-Year Performance and Link to Remuneration
78
4.6
2024 Executive KMP Performance and Remuneration Outcomes
79
4.7
Executive KMP Employment Contracts
83
4.8
2024 Remuneration Outcomes for Executive KMP
84
4.9
Nature of Non-Executive Director Remuneration
91
REMUNERATION
REPORT
4.3 REMUNERATION GOVERNANCE
4.3.1 PHILOSOPHY AND OBJECTIVES
The Company is committed to a remuneration philosophy
that aligns with its business strategy and encourages
superior performance and shareholder returns. Cooper
Energy’s approach towards remuneration is aimed at
ensuring that an appropriate balance is achieved between:
§ maximising sustainable growth in shareholder returns;
§ operational and strategic requirements; and
§ providing attractive and appropriate remuneration
packages.
The primary objectives of the Company’s remuneration
policy are to:
§ attract and retain high calibre employees;
§ ensure that remuneration is fair and competitive with both
peers and competitor employers;
§ provide significant incentive to deliver superior
performance (when compared to peers), against Cooper
Energy’s strategy and key business goals without
rewarding conduct that is contrary to the Cooper Energy
values or risk appetite;
§ achieve the most effective returns (employee
productivity), for total employee spend; and
§ ensure remuneration transparency and credibility for all
employees and in particular for Executive KMP.
Cooper Energy’s policy is to pay fixed annual remuneration
(FAR) at the median level, compared to resource industry
benchmark data and supplement this with “at risk”
remuneration to bring total remuneration within the upper
quartile when outstanding performance is achieved.
4.3.2 PEOPLE & REMUNERATION COMMITTEE
The People & Remuneration Committee (which, as at the
date of this report, is comprised of four non-executive
directors, all of whom are independent) makes
recommendations to the Board about remuneration
strategies and policies for the executive KMP and
considers matters related to organisational structure and
operating model, company culture and values, diversity,
succession for senior executives, and executive
development and talent management. The ultimate
responsibility for, and power to make company decisions
with respect to these matters, remains with the full Board.
On an annual basis, the People & Remuneration
Committee makes recommendations to the Board about
the form of payment and incentives to executive KMP, and
the amount. This is done with reference to Company
performance and individual performance of the executive
KMP, relevant employment market conditions, current
industry practices and independent remuneration
benchmark reports.
4.3.3 EXTERNAL REMUNERATION ADVISERS
The People & Remuneration Committee may consider
advice from external advisors who are engaged by and
report directly to the Committee. Such advice will typically
cover non-executive director fees, executive KMP
remuneration and advice in relation to equity plans.
The Corporations Act 2001 requires companies to disclose
specific details regarding the use of remuneration
consultants. The mandatory disclosure requirements only
apply to those advisors who provide a “remuneration
recommendation” as defined in the Corporations Act 2001.
The Committee did not receive any remuneration
recommendations during the FY24 reporting period.
4.4 NATURE & STRUCTURE OF
EXECUTIVE KMP REMUNERATION
Executive KMP remuneration during the reporting period
consisted of a mix of:
§ Fixed annual remuneration (FAR);
§ Short term incentive plan (STIP) participation;
§ Benefits such as, internet allowance and car parking; and
§ Long term incentive plan (LTIP) participation under the
Company’s amended equity incentive plan (EIP)
approved by shareholders at the 2022 AGM.
It is the Company’s policy that performance-based (or at-
risk) pay forms a significant portion of the executive KMPs’
total remuneration. The Company aims to achieve an
appropriate balance between rewarding operational
performance (through the STIP reward) and rewarding
long-term sustainable performance (through the LTIP).
REMUNERATION
REPORT
71
72
For the year ended 30 June 2024
For the year ended 30 June 2024
The Company’s current remuneration profile for executive KMP (at maximum performance) is as follows:
MANAGING DIRECTOR & CEO
The above split of fixed and at risk pay reflects the ongoing remuneration for the Managing Director & CEO. For the first year
the Managing Director’s remuneration split was 28.57% FAR, 35.71% STIP and 35.71% LTIP. A higher LTIP applied to the
first-year invitation was due to the timing of commencement with the Company, being 9 months into FY23. This was disclosed
in our ASX announcement of 19 December 2022, and the share rights issue approved by shareholders at the 2023 Annual
General Meeting.
CHIEF OPERATING OFFICER
OTHER EXECUTIVE KMP
4.4.1 REMUNERATION STRATEGY AND FRAMEWORK - LINKING REWARD TO PERFORMANCE
The remuneration strategy sets the remuneration framework and drives the design and application of remuneration for the
Company, including executive KMP.
The remuneration strategy:
§ encourages a strong focus on financial and operational performance, and motivates executive KMP to deliver sustainable
business results and returns to the Company’s shareholders, over the short and long term;
§ attracts, motivates and retains appropriately qualified and experienced talent; and
§ aligns executive and shareholder interests, through well designed performance incentives and equity linked plans.
The Board believes that remuneration should include a fixed component and at-risk or performance-related components,
including both short term and long-term incentives.
This remuneration framework is shown in the table following, including how performance outcomes will impact remuneration
outcomes for executive KMP. The Board will continue to review the remuneration framework to ensure it continues to align with
the Company’s strategic objectives and ensure shareholder alignment.
4.4.2 REMUNERATION STRATEGY AND FRAMEWORK – OVERVIEW
This current remuneration framework overview includes changes made to the STIP and LTIP during FY24. The inclusion of
equity (performance rights) in STIP is effective from FY25 (performance year commencing 1 July 2024). Changes to LTIP were
made in the December 2023 LTIP invitation. Testing of this LTIP invitation, for the purposes of vesting, will be in December
2026. Details of the STIP and LTIP that operated in FY24 are shown in 4.4.4 and 4.4.5 respectively.
30.77%
38.46%
30.77%
FAR
STIP
LTIP
41.67%
29.17%
29.17%
FAR
STIP
LTIP
43.48%
26.09%
30.43%
FAR
STIP
LTIP
The Board believes that remuneration should include a fixed
component and at-risk or performance-related components,
including both short term and long-term incentives.
This remuneration framework is shown in the table following,
including how performance outcomes will impact
remuneration outcomes for executive KMP. The Board will
continue to review the remuneration framework to ensure it
continues to align with the Company’s strategic objectives
and ensure shareholder alignment.
4.4.2 REMUNERATION STRATEGY
AND FRAMEWORK – OVERVIEW
This current remuneration framework overview includes
changes made to the STIP and LTIP during FY24. The
inclusion of equity (performance rights) in STIP is effective
from FY25 (performance year commencing 1 July
2024). Changes to LTIP were made in the December 2023
LTIP invitation. Testing of this LTIP invitation, for the
purposes of vesting, will be in December 2026. Details of the
STIP and LTIP that operated in FY24 are shown in 4.4.4 and
4.4.5 respectively.
4.4.1 REMUNERATION STRATEGY AND
FRAMEWORK - LINKING REWARD TO
PERFORMANCE
The remuneration strategy sets the remuneration framework
and drives the design and application of remuneration for the
Company, including executive KMP.
The remuneration strategy:
§ encourages a strong focus on financial and operational
performance, and motivates executive KMP to deliver
sustainable business results and returns to the
Company’s shareholders, over the short and long term;
§ attracts, motivates and retains appropriately qualified and
experienced talent; and
§ aligns executive and shareholder interests, through well
designed performance incentives and equity linked plans.
REMUNERATION
REPORT
Performance Conditions
Remuneration
Strategy/Performance Link
Fixed Annual
Remuneration
(FAR)
Salary and
other benefits
(including
statutory
superannuation)
Key Considerations
§
Scope of individual’s role.
§
Individual’s level of knowledge, skills
and expertise.
§
Individual performance.
§
Market benchmarking.
FAR is set to attract, retain and motivate the right talent to
deliver the strategy and deliver the Company’s financial and
operational targets.
For executives new to their role, the aim is to set FAR at
relatively modest levels, compared to their peers, and to
progressively increase as they gain experience and perform
at higher levels. This links fixed remuneration to individual
performance.
Short Term
Incentive Plan
(STIP)
Annual
incentive
opportunity,
delivered in
cash and
equity, based
on Company
and individual
performance
Company Performance
There are four key dimensions for which
company performance is measured:
§
Health, Safety, Environment,
Sustainability and People & Culture.
§
Production.
§
Financial.
§
Projects and Growth.
The targets that were established for FY24
and the achievement level against these
targets are outlined in 4.6.2 of this report.
Individual performance KPIs
Individual performance measures are
agreed each year. The measures include
key business objectives, while also being
role-specific, i.e. related to individual and
team specific responsibilities.
STIP performance conditions are designed to support the
financial, operational and strategic direction of the Company
and are clearly defined and measurable. The achievement
of these conditions will in turn create shareholder value.
A large proportion of outcomes are subject to the
operational and financial targets of the Company or
business unit, depending on the role of the executive, to
ensure clear line of sight to outcomes that will create
shareholder value. Strategy and project targets ensure that
continued focus on future opportunities is maintained.
Non-financial targets are aligned to core values (including
safety and sustainability) and key strategic and growth
objectives.
Threshold, Target, and Stretch targets for each measure are
set by the Board to ensure that a challenging performance-
based incentive is provided.
The Board has discretion to adjust STIP outcomes up or
down to ensure appropriate company and individual
outcomes are aligned with the shareholder experience and
Cooper Energy values.
Long Term
Incentive Plan
(LTIP)
Three-year
incentive
opportunity
delivered
through
performance
rights.
LTIP can reward executives subject to
performance hurdles being met, with the
allocation of performance rights.
Performance Measures
There are two equally weighted
performance measures:
§
Relative total shareholder return
(RTSR), where performance requires
a sustained superior share price
performance of the Company
compared to a peer group of
companies. The peer group
companies are ASX-listed companies
in the oil and gas sector, with a range
of market capitalisation.
§
Absolute total shareholder return
(ATSR). This measures the
compound average growth rate
(CAGR) over a three-year period.
Allocation of performance rights encourages executives to
‘behave like shareholders’ from the grant date.
The performance rights are restricted and subject to risk of
forfeiture at the end of the three-year performance period.
The Company believes that encouraging its employees to
become shareholders is the best way of aligning employee
interests with those of the Company’s shareholders. The
LTIP can also act as a retention incentive for key talent (due
to the three-year vesting period).
RTSR and ATSR measures are designed to encourage
executives to focus on the key performance drivers which
underpin sustainable growth in shareholder value.
The performance conditions are designed to ensure vesting
can only occur where shareholders have enjoyed superior
share price performance in relative (against peers) and
absolute terms.
Total remuneration: The combination of these elements is designed to attract, retain and motivate appropriately qualified
and experienced individuals, encourage a strong focus on performance, support the delivery of outstanding returns to
shareholders, and align executive and shareholder interests through share ownership.
REMUNERATION
REPORT
73
74
For the year ended 30 June 2024
For the year ended 30 June 2024
4.4.3 FIXED ANNUAL REMUNERATION (FAR)
FAR includes base salary (paid in cash) and statutory
superannuation. Executives are paid FAR which is
competitive in the markets in which the Company operates
and is consistent with the responsibilities, accountabilities
and complexities of the respective roles.
The Company benchmarks FAR for its executive KMP
against resource industry market surveys (and, in
particular, oil and gas companies) which are published
annually. Additionally, the pay levels of executive KMP
positions in the Company may be benchmarked against
national market executive remuneration surveys. It is the
Company’s policy to position itself at the median level of
the market when benchmarking FAR.
4.4.4 SHORT TERM INCENTIVE
PLAN (STIP) - OVERVIEW
The STIP is an annual incentive opportunity delivered in
cash (for FY24) based on a mix of Company and individual
performance. The individual measures are a mixture of
business unit and employee-specific goals. The key
features of the STIP for FY24 were as follows:
STIP FY24 Plan Features
Details
What is the purpose
of the STIP?
Motivate and reward individuals for their contribution to the annual performance of the
Company.
How does the STIP align
with the interests of
Cooper Energy’s
shareholders?
The STIP is aligned to shareholder interests by encouraging individuals to achieve operational
and business milestones in a balanced and sustainable manner whilst growing assets and total
company value.
What is the vehicle
of the STIP award?
The STIP award in FY24 is delivered in the form of a cash payment, payable in October.
From FY25 an equity component will be included in STIP where the opportunity to receive
performance rights under a deferred STIP award will be included. The deferred STIP element
will mean that any grant of performance rights will vest 12 months after the initial grant date,
provided the service conditions of current employment is met. Such rights are subject to
forfeiture under certain conditions of the EIP rules. If the FY25 STIP results in an eligible grant
of performance rights (equity) for the MD & CEO, prior to any such allocation, final approval of
the shareholders will be sought at the 2025 AGM, consistent with ASX requirements.
What is the maximum
award opportunity
(% of FAR)?
Changes made during the FY24 performance period are as follows:
Managing Director & CEO
Maximum STIP (% of FAR)
FY24
FY25
Cash
125%
105%
Equity
0%
20%
Maximum STIP
125%
125%
Chief Operating Officer
Maximum STIP (% of FAR)
FY24
FY25
Cash
70%
60%
Equity
0%
10%
Maximum STIP
70%
70%
Other executive KMP
Maximum STIP (% of FAR)
FY24
FY25
Cash
50%
50%
Equity
0%
10%
Maximum STIP
50%
60%
What is the
performance period?
Each year, the Board reviews and approves the performance criteria for the year ahead by
approving a Company scorecard and individual performance contracts which are agreed with
each executive KMP. The Company’s STIP operates over a 12-month performance period
from 1 July to 30 June.
REMUNERATION
REPORT
How are the performance
measures determined
and what are their
relative weightings?
The measurement of Company performance is based on the achievement of KPIs set out
in the Company scorecard. See section 4.6.2 for the Company scorecard measures used
for FY24.
The KPIs focus on the core elements the Board believes are needed to successfully
deliver the Company strategy and maximise sustainable shareholder returns. For each
KPI in the scorecard, a base or threshold performance level is established as well as a
Target and Stretch goal (Stretch being the maximum). Personal performance measures
are agreed between each executive KMP and Cooper Energy each year.
The relative weighting of Company scorecard and individual performance is as follows:
KMP
Company
Scorecard
Individual
Performance
Managing Director & CEO
75%
25%
Other Executive KMP
70%
30%
Performance measures are challenging, and maximum award opportunities are only
achieved by outstanding performance. 50% of the maximum award opportunity will be
awarded if the Company meets target level performance.
0% STIP will be awarded for performance achievement below a Threshold level.
0% STIP will be awarded if during any measurement period the Company sustains a
fatality or major environmental incident.
Irrespective of the scorecard outcome, payment of any STIP is entirely at the discretion of
the Board.
4.4.5 LONG TERM INCENTIVE PLAN (LTIP) - OVERVIEW
The key features of the grants made in the 2024 financial year (granted December 2023) are set out in the following table:
FY24 LTIP Plan Features
Details
What is the purpose
of the LTIP?
The Company believes that encouraging its employees, including executive KMP, to become
shareholders is the best way of aligning their interests with those of the Company’s
shareholders. Having a LTIP is also intended to be a retention incentive, with a vesting period
of at least three years before securities under the plan are available to employees.
How is the LTIP aligned
to shareholder interests?
Employees only benefit from the LTIP when there is sustained superior share price
performance of the Company, including when compared to relevant peer group companies.
This aligns the LTIP with the interests of shareholders.
What is the vehicle
of the LTIP?
LTIP grants during the reporting period were entirely in the form of performance rights.
A performance right is a right to acquire one fully paid share in the Company, provided
specified performance hurdles are met.
What is the maximum
annual LTIP grant (% of
Fixed Remuneration)?
KMP
% of FAR
Managing Director & CEO*
100%
Other Executive KMP
70%
* The first LTIP invitation for the Managing Director & CEO that was issued in December 2023
was 125% of FAR due to the timing of the appointment. This was disclosed in our ASX
announcement dated 19 December 2022.
What is the LTIP
performance period?
The performance period is three years.
What are the
performance measures?
There are two equally weighted performance measures:
§ Relative total shareholder return (RTSR) (50%). Performance requires a sustained superior
share price performance of the Company compared to a peer group of companies. The peer
group companies are ASX-listed companies in the oil and gas sector, with a range of market
capitalisation.
REMUNERATION
REPORT
75
76
For the year ended 30 June 2024
For the year ended 30 June 2024
§ Absolute total shareholder return (ATSR) (50%). ATSR is calculated as the compound
average growth rate (CAGR) of the Company’s share price over a 3-year period, and is
expressed as a percentage.
RTSR and ATSR are common long-term incentive measures across ASX-listed companies and
are aligned with shareholder returns. Relative measures ensure that maximum incentives are
only achieved if Cooper Energy’s performance exceeds that of its peers and therefore supports
competitive returns against other comparable organisations. Absolute measurement rewards
share price growth over a 3-year period.
Which companies make
up the RTSR peer group?
The RTSR is measured as a percentile ranking compared to the following comparator group of
listed entities: Beach Energy (BPT), Carnarvon Energy (CVN), Comet Ridge (COI), Empire
Energy (EEG), Horizon Oil (HZN), Melbana Energy (MAY), Pancontinental Energy (PCL),
Strike Energy (STX) and Tamboran Resources (TBN).
What is the
vesting schedule?
RTSR (tranche 1) 50% of performance rights
The vesting criteria for performance rights (PRs) is based on the Company’s RTSR
performance, with the percentage of PRs which vest at the end of the performance period
determined by the Company's RTSR percentile ranking as assessed against the peer group of
companies.
Subject to the plan rules, the number of incentives which are achieved and will vest at the end
of the performance period as a result of the Tranche 1 PRs will be the number which
corresponds to the Company’s RTSR as set out below:
RTSR percentile ranking
Percentage of tranche 1 performance
rights to vest
Below 50th percentile
No performance rights
At 50th percentile
50% of performance rights
Between 50th percentile
and 75th percentile
50% of performance rights plus 2% for each additional
percentile
At or above 75th percentile
100% of performance rights
ATSR (tranche 2) 50% of performance rights
Subject to the plan rules, the number of PRs which are achieved and will vest at the end of the
performance period as a result of the tranche 2 PRs will be the number which corresponds to
the CAGR as set out below:
3-year CAGR
Percentage of tranche 2 performance rights to vest
Less than 10%
No performance rights
At 10%
50% of performance rights
Between 10% and 20%
50% of performance rights plus 5% for each additional
percentile
20% or above
100% of performance rights
The vesting schedule reflects the Board’s requirement that performance measures are
challenging, and maximum award opportunities are only achieved by outstanding performance.
What happens on
cessation
of employment?
Generally, if an employee ceases employment prior to the vesting date (e.g., to take a position
with another company), they will forfeit all awards. In the case of “qualifying leavers” as defined
(examples of which include redundancy, retirement or incapacity), awards may be retained,
unless the Board determines otherwise. The Board also has the discretion to determine that
some or all awards may be retained upon cessation of employment.
What happens if there is
a change of control?
In the event of a change of control, unless the Board determines otherwise, pro-rata vesting
will occur on the basis of the proportion of the relevant performance period that has elapsed.
Who can participate in
the LTIP?
Eligibility is generally restricted to executive KMP and members of the executive leadership
team (ELT).
Will the Company make
any changes to the LTIP
for the grant to be made
in the 2025 financial year
(FY25)?
As indicated earlier in this Remuneration Report, a review of remuneration structure was
undertaken in FY24. The Board is satisfied that the revised LTIP aligns executive and
shareholder interests through the equity linked plan. No further changes are envisaged to the
LTIP grant to be made in FY25.
REMUNERATION
REPORT
4.5 COOPER ENERGY’S FIVE-YEAR PERFORMANCE AND LINK TO REMUNERATION
The following graphs illustrate the Company’s five-year performance, which link to the remuneration strategy and framework:
SAFETY - TOTAL RECORDABLE
INCIDENT FREQUENCY RATE
(events per hours worked, where a lower value is better)
SALES REVENUE
($ MILLION)
Links directly to Company STIP reward outcome as a
HSEC & Sustainability KPI.
Links indirectly to Company STIP reward outcome as a
Production & Financial KPI.
ANNUAL PRODUCTION
(PJE)
PROVED & PROBABLE NATURAL
GAS & OIL RESERVES (MMBOE)
Links directly to Company STIP reward outcomes as a
Production & Financial KPI.
Links directly to Company STIP reward outcome as a
Growth & Portfolio Management KPI.
FINANCIAL – UNDERLYING PROFIT
AFTER TAX ($ MILLION)
FINANCIAL – UNDERLYING
EBITDAX ($ MILLION)
Links indirectly to Company STIP reward outcomes via
Production & Financial KPIs.
Links indirectly to Company STIP reward outcome as a
Financial KPI.
FINANCIAL –
TOTAL SHAREHOLDER RETURN (%)
SHARE PRICE –
AS AT 30 JUNE ($ PER SHARE)
Links directly to Company LTIP reward outcome by
increasing shareholder value.
Links directly to Company LTIP reward outcome by
increasing shareholder value compared to peers.
MARKET CAPITALISATION -
AS AT 30 JUNE ($ MILLION)
In FY24, and in the past 5 years, dividends were not paid
by the Company to its shareholders, nor was there a
return of capital to shareholders, consistent with the
growth reinvestment objectives of the Company.
Links directly to Company LTIP reward outcome by
increasing shareholder value compared to peers.
3.53
6.92
0.00
4.38
4.35
FY20
FY21
FY22
FY23
FY24
78.1
131.7
205.4
196.9
219.0
FY20
FY21
FY22
FY23
FY24
9.18
16.11
20.25
21.81
22.74
FY20
FY21
FY22
FY23
FY24
49.9
47.1
39.5
36.3
33.0
FY20
FY21
FY22
FY23
FY24
(6.6)
(25.9)
14.4
(5.6)
1.4
FY20
FY21
FY22
FY23
FY24
29.6
30.0
80.7
109.3
127.5
FY20
FY21
FY22
FY23
FY24
(30.6)
(30.7)
(5.8)
(38.8)
50.0
FY20
FY21
FY22
FY23
FY24
0.38
0.26
0.25
0.15
0.23
FY20
FY21
FY22
FY23
FY24
610.0
424.1
583.1
394.7
594.0
FY20
FY21
FY22
FY23
FY24
REMUNERATION
REPORT
77
78
For the year ended 30 June 2024
For the year ended 30 June 2024
4.6 2024 EXECUTIVE KMP PERFORMANCE AND REMUNERATION OUTCOMES
4.6.1 FIXED ANNUAL
REMUNERATION OUTCOME
Planned increases to the executive KMP remuneration
were communicated in last year’s report.
However, these did not proceed in FY24 other than the
statutory change to superannuation. The only exception
was the Chief Financial Officer who took on additional
responsibilities. The decision not to proceed with general
increases for executive KMP in FY24 was consistent with
the business conditions faced by the Company including
cost containment objectives.
There has not been a general salary increase for executive
KMP since 1 July 2022 other than for increases in statutory
superannuation benefits. The Board determined that an
increase to FAR would be applied effective 1 July 2024
including the increase in statutory superannuation. For the
executive KMP, these increases range from 1.8% to 4.42%
and are seen as comparable to our relevant peer
companies and industry generally.
Fixed annual remuneration (FAR) effective 1 July 2024 is
as follows:
Executive KMP
Position
Base
Salary $
Superannuation $
Fixed Annual
Remuneration $
Jane Norman
Managing Director & CEO
804,068
29,932
834,000
Chad Wilson
Chief Operating Officer
573,068
29,932
603,000
Dan Young
Chief Financial Officer
535,068
29,932
565,000
Eddy Glavas
Chief Commercial Officer
440,068
29,932
470,000
Andrew Thomas1
Chief Exploration & Subsurface Officer
469,708
29,932
499,640
1 Andrew Thomas ceased as Executive KMP 30 June 2024. Andrew leaves Cooper Energy on 30 September 2024.
The next general review of base salaries will be 1 October 2025.
REMUNERATION
REPORT
4.6.2 STIP PERFORMANCE OUTCOMES – COMPANY RESULTS
The Board determined a FY24 scorecard assessment result of 56.1/100 (56.1/%)
Performance
Measure
(FY24
Weighting)
Performance Measure Outcome
Result
Threshold Target Stretch
HSE,
sustainability,
people &
culture (25%)
Result:
21.3/25.0
§
No LTIs > 3 days off work
§
No high potential incidents
§
No tier 1 or 2 process safety events
§
1 medical treatment case
§
No environmental incidents > level 1
§
Maintained Climate Active net zero certification
§
Three decarbonization projects implemented
§
New Company strategy released
§
Record employee survey participation
§
Voluntary turnover below industry benchmark
§
Stakeholder engagement to support project approvals
Production
(25%)
Result: 2.5/25.0
§
Sole/OGPP production of 50.1 TJ/d (excluding
shutdown)
§
CHN/AGP production of 10.8 TJ/d (excluding
shutdown)
§
PEL92 production of 360 bbls/d
Financial (25%)
Result:
22.3/25.0
§
Production expenses of $59.6mm
§
Net G&A of $14.5mm
§
SIB capex below stretch
Projects &
growth (25%)
Result:
10.0/25.0
§
BMG wells decommissioning delivered safely, but
costs exceeded threshold
§
Gas marketing contracting equal to or above market
price indicators, including ‘as available’ gas agreement
to supply peaking power when required, capturing the
value of firming renewables
§
Planning and long lead items advanced for ECSP,
but no overall FID
FY24 performance
56.1/ 100
4.6.3 STIP PERFORMANCE OUTCOMES – INDIVIDUAL RESULTS
When the Company Scorecard result and individual performance outcomes were combined, the Board determined the FY24
STIP outcomes for the Executive KMP as follows:
KMP Short Term Incentive (STIP) For The Year Ended 30 June 2024
Executive KMP
STIP - % Of FAR
at Target
STIP- % Of FAR
at Maximum
Cash STIP
$
% Earned of
Maximum STIP
Opportunity
% Forfeited of Maximum
STIP Opportunity
Jane Norman
62.5%
125%
642,438
64.08%
35.92%
Chad Wilson1
35.0%
70%
180,606
44.48%
55.52%
Dan Young
25.0%
50%
178,072
64.17%
35.83%
Eddy Glavas
25.0%
50%
141,716
62.97%
37.03%
Andrew Thomas2
25.0%
50%
154,277
62.07%
37.93%
1 Chad Wilson commenced on 23 October 2023. STIP projected to a full year would represent $261,748 gross or 64.47% of his maximum annual STIP opportunity.
2 Andrew Thomas ceased as Executive KMP 30 June 2024. STIP represents payment for the full financial year. Andrew leaves Cooper Energy on 30 September 2024.
Managing Director & CEO individual performance
Jane Norman, the Managing Director and CEO, received a FY24 STIP payment of $642,438 gross. The calculation of this
payment was as follows:
Jane Norman
Maximum
Eligibility % FAR
Maximum
Eligibility $
FY24
Result
FY24 STIP
Gross Payment
Company Scorecard (75%)
93.75%
751,975
56 %
421,858
Individual performance (25%) *
31.25%
250,658
88 %
220,580
Total
125.00%
1,002,633
642,438
REMUNERATION
REPORT
79
80
For the year ended 30 June 2024
For the year ended 30 June 2024
* The Managing Director & CEO’s Individual performance was assessed by the Board as follows:
Performance Measure
(Fy24 Weighting)
Performance Measure Outcome
Result
Threshold Target Maximum
Deliver improved
performance of the
Orbost Gas Processing
Plant (OGPP) to
achieve step change to
company performance.
Weighting: 40%
§
Creation of a focused engineering group to
drive plant performance.
§
Appointment of new Chief Operating Officer
(Chad Wilson); commenced October 2023.
§
Appointment of new Plant Superintendent.
§
Achieved average production rate ~50.1
TJ/d; higher than FY23 ~47 TJ/d. Includes
production records set in Jan - Feb 2024
with instantaneous rates > 70 TJ/d achieved.
§
Significant improvement project milestones
delivered, including new media for polisher,
polisher trace heating and insulation, 4-
nozzel spray distributor, in-situ chemical
clean trial.
Successful completion
of BMG
decommissioning
project to complete
regulatory obligations.
Weighting: 20%
§
Seven well BMG decommissioning project
delivered within the revised cost range as
outlined in January 2024.
§
Completion cost reflected in the ‘below
target outcome on the company scorecard.
Technically the project was a success, and
all seven wells were decommissioned.
§
Project completed with no lost-time injuries
and no significant environmental costs.
Deliver organisational
design and culture
goals to increase
strength of business
leadership and
accountability and
improve staff
engagement levels.
Weighting: 10%
§
Implementation of new organisational
structure complete, including changes to
ELT.
§
Organisational capability has been improved
and reset to a high performing culture to
deliver on what is promised.
§
Significant progress on cost out with ~$10m
of annual costs removed, including a
reduction in G&A and production expenses
(Production Expense guidance revised down
during the year).
§
New company Vision, Values, Purpose and
Strategy launched.
Build investor
relationships and
deliver clear messaging
to the market and other
stakeholders to restore
confidence in the future
of COE.
Enhance Shareholder
returns including share
price performance year
on year, M&A activity,
share buy backs and
other activities to
generate positive
returns.
Weighting: 30%
§
Share price performance up 53% from
$0.15/share to $0.23/share year-on year.
§
Several new institutional investors brought
into top 20 on register in past 6 months.
§
Compliance with gas market regulations
achieved including the Mandatory Gas Code
of Conduct.
§
Proactive engagement with Governments of
all levels, with regulators such as
NOPSEMA and industry bodies.
FY24 Performance
88 / 100
REMUNERATION
REPORT
Other Executive Key Management Personnel Individual Performance
STIP for other executive KMP has a 70% weighting on the company scorecard and 30% individual performance weighting.
Commentary on individual performance and FY24 STIP outcomes follow:
Chad Wilson
Chief Operating Officer
Dan Young
Chief Financial Officer
§
Commenced on 23 October 2023.
§
Systematically advanced the OGPP Improvement
Project, prioritising activities which delivered incremental
performance improvements.
§
Plant throughput improvements executed at both assets.
§
Operations systems and processes were refined, adding
greater discipline and rigour.
§
Increased focus on production loss and plant reliability.
§
Achieved significant reduction in production expenses
through reduced contract services and improved waste
management.
§
Company safety and environment targets achieved.
§
Company safety and environment targets achieved.
§
Leadership growth included an expended portfolio
including Contracts & Procurement and IT.
§
Lead role in company Transformation to reduce cost
base and drive efficiency.
§
Maintained strong relations with all capital providers.
§
Progressing funding options for ECSP including
existing lenders and potential gas customer
prepayments.
Company performance
56.1%
Company performance
56.1%
Individual performance
84%
Individual performance
83%
FY24 STIP as % of maximum1
64%1
FY24 STIP as % of maximum
64%
1 FY24 STIP pro-rated on basis of commencement date.
Andrew Thomas
Chief Exploration & Subsurface Officer
Eddy Glavas
Chief Commercial Officer
§
ELT oversight of the BMG wells decommissioning project
with successful, safe completion of the program.
§
Delivered value through subsurface review and selective
approach to PEL 92 Cooper exploration and
development projects.
§
Supported corporate development activities including
assessing, enhancing and maintaining growth
opportunities.
§
Company safety and environment targets achieved.
§
Maintained strong relationships with gas customers,
successfully completed gas contract extensions and
price reviews and originated new peak gas products.
§
Ongoing leadership in progressing growth
opportunities.
§
Successful stakeholder engagement with
government agencies and industry regarding the
Mandatory Gas Code of Conduct raising awareness
of Cooper Energy’s objectives and commitments to
domestic gas supply.
§
Robust economic modelling to support Commercial
decisions and Treasury activity.
§
Company safety and environment targets achieved.
Company performance
56.1% Company performance
56.1%
Individual performance
76%
Individual performance
79%
FY24 STIP as % of maximum
62%
FY24 STIP as % of maximum
63%
FORMER EXECUTIVE KEY MANAGEMENT PERSONNEL INDIVIDUAL PERFORMANCE
Ashley Haren
Former General Manager People & Remuneration
Iain Macdougall
Former General Manager HSE, Tech. Services & IT
§
Strong contribution to organisational change, including at
ELT level.
§
Lead change to leadership at both operated sites.
§
Delivered cost-out initiatives and focus on ensuring
recruitment activities lift organisational capability.
§
Supported transition to new Head of People & Culture.
§
Company safety and environment targets achieved.
§
Lead preparation of FY23 Sustainability Report and
narrative.
§
Completed successful handover of Environment and
Safety team responsibilities to new Chief Corporate
Services Officer.
§
Supported transition to new ELT.
§
Company safety and environment targets achieved.
Company performance
56.1% Company performance
56.1%
Individual performance
84%
Individual performance
50%
FY24 STIP as % of maximum
64%
FY24 STIP as % of maximum
54%
REMUNERATION
REPORT
81
82
For the year ended 30 June 2024
For the year ended 30 June 2024
4.6.4 LTIP OUTCOME
LTIP grants issued in December 2020 and tested in
December 2023 (during FY24) had a percentile ranking of
below 50th percentile and therefore no shares vested as a
result of this testing.
This nil vesting outcome was as a result of the
performance of the Company’s share price against its
peers over the measurement period. Over the three-year
measurement period Cooper Energy’s total shareholder
return was -69% and it achieved a RTSR percentile rank of
0%. This resulted in a nil vesting outcome for all
performance rights and share appreciation rights that were
granted in December 2020.
LTIP grants issued in December 2021 (to be tested in
December 2024) and December 2022 (to be tested in
December 2025) involve grants of performance rights
(50%) and share appreciation rights (50%). These plans
will be tested against their respective peer groups. Vesting
will rely on relative total shareholder return (RTSR)
percentile rankings, as previously disclosed.
Details, including performance hurdles, of the LTIP grants
issued in December 2023 (to be tested in December 2026)
are included under 4.4.5 Long term incentive plan (LTIP) –
overview.
There has been no vesting for the past three years of any LTIP
All performance rights and share appreciation rights granted in 2018, 2019 and 2020 have lapsed unvested
4.7 EXECUTIVE KMP EMPLOYMENT CONTRACTS
Each executive KMP has an ongoing employment contract. All executive KMP have termination benefits that are within the
allowed limits under the Corporations Act 2001, without shareholder approval. Contracts include the treatment of entitlements
on termination in the event of resignation, with notice or for cause.
Key terms for each Executive KMP are set out below:
Executive KMP
Notice by
Cooper
Energy
Notice by
Executive
KMP
Indemnity
Agreement
Treatment on Termination
by Cooper Energy
Jane Norman
6 months
6 months
Company provides
indemnity
agreement, Directors
and Officers
indemnity insurance
and access to
Company records.
Where the Managing Director is not employed
for the full period of notice, a payment in lieu
may be made. A payment in lieu of notice is
based on fixed remuneration (base salary and
superannuation). Upon termination,
superannuation is not paid on accrued annual
leave or long service leave. Unused personal
leave is not paid out and is forfeited.
Other
Executive KMP
6 months
3 months
Company provides
indemnity
agreement, Directors
and Officers
indemnity insurance
and access to
Company records.
Where an Executive KMP is not employed for
the full period of notice, a payment in lieu may
be made. Upon termination, superannuation is
not paid on accrued annual leave or long service
leave. Unused personal leave is not paid out and
is forfeited.
Under the rules of the STIP and the EIP, if an executive KMP ceases employment prior to the vesting date of an incentive
award (STIP and LTIP) (e.g., to take a position with another company), they will forfeit all awards.
In the case of “qualifying leavers” as defined (examples of which include redundancy, retirement or incapacity), awards may be
retained, unless the Board determines otherwise. The Board also has a discretion to determine that some or all awards may be
retained upon cessation of employment.
REMUNERATION
REPORT
4.8 2024 REMUNERATION OUTCOMES FOR EXECUTIVE KMP
4.8.1 REMUNERATION REALISED BY
EXECUTIVE KMP IN FY24 AND FY23 (NOT AUDITED)
The Company believes that providing details of the
remuneration actually realised by current executive KMP is
useful to shareholders. It provides clear and transparent
disclosure of remuneration provided by the Company.
The table set out below shows amounts paid, and the cash
value of any equity awards which vested, during the
reporting period. It serves to answer the question: what
was actually paid as compensation including salary, STIP
and LTIP realised in the financial year and any other
awards.
This information is a non-IFRS measure and is in addition
to and different from the disclosures required by the
Corporations Act 2001 and Accounting Standards in the
rest of the Remuneration Report including the tables in
sections 4.8.2 and 4.9.2. The information in section 4.8.1
is not audited.
The total benefits delivered during the reporting period and
set out in the table below comprise the following elements:
§
FAR is base salary and superannuation
(statutory and salary sacrifice).
§
STIP cash payment made in October each year.
The STIP payments shown here correspond to the
combined company scorecard and individual
performance outcomes from the prior financial year.
Currently, STIP awards are assessed and finalised in
August and paid in October, in arrears, for the
previous financial year. As a result, the amounts
shown in the 2024 row, relate to STIP payments in
respect of FY23. These amounts were assessed and
approved by the Board in August 2023 and disclosed
in 4.6.3 of the remuneration report for the year ended
30 June 2023. The STIP payments shown here align
to the financial year when they were actually paid,
while the table in section 4.8.2 aligns STIP payments
to the financial year to which they relate.
§
LTIP has not realised any vesting in the period stated,
as none of the partial or full vesting thresholds were
met (refer section 4.6.4).
\Executive KMP
Financial
year
FAR
$
STIP
$
LTIP
$
Other
$
Total
$
Jane Norman1
2024
802,105
57,144
-
407,684
1,266,933
2023
231,017
-
-
401,801
632,818
Chad Wilson2
2024
403,602
-
-
290,212
693,814
2023
-
-
-
-
-
Dan Young3
2024
555,000
72,128
-
6,741
633,869
2023
516,065
-
-
66,299
582,364
Eddy Glavas
2024
450,106
45,360
-
6,741
502,207
2023
448,000
175,552
-
6,462
630,014
Andrew Thomas4
2024
497,106
50,490
-
6,741
554,337
2023
495,000
190,519
-
6,462
691,981
1Jane Norman commenced as Managing Director & CEO on 20 March 2023 and her entitlements for 2023 are prorated. “Other” remuneration realised in 2023
includes $400,000 which represents 50% of a sign on bonus. The remaining 50% ($400,000) was payable on the first anniversary of company service and shown in
the 2024 “Other” figure. The Company considered this sign on bonus to be a reasonable assessment for the value of incentives forgone from her previous
employment. These contractual arrangements were disclosed in an ASX announcement dated 19 December 2022.
2Chad Wilson commenced as Chief Operating Officer on 23 October 2023. His entitlements for 2024 are prorated. “Other” remuneration realised includes $290,000
which represents 50% of a sign on bonus. The remaining 50% is payable on the first anniversary of company service. The Company considered this sign on bonus
to be a reasonable assessment for the value of incentives forgone from his previous employment.
3 Dan Young’s “Other” remuneration realised included sign on and relocation costs in FY2023. The Company considered this sign on bonus to be a reasonable
assessment for the value of incentives forgone from his previous employment.
4 Andrew Thomas ceased as Executive KMP 30 June 2024. 2024 payments are for the full year. Andrew leaves Cooper Energy on 30 September 2024.
REMUNERATION
REPORT
83
84
For the year ended 30 June 2024
Short-term
Long-term
Base salary
STIP1
Other short-
term
benefits2
Long
service
leave
Executive KMP
FY
$
$
$
$
Jane Norman8
2024
774,707
642,438
407,684
-
2023
221,747
57,144
401,801
-
Chad Wilson9
2024
383,053
180,606
290,212
-
2023
-
-
-
-
Dan Young10
2024
527,601
178,072
6,741
-
2023
490,773
61,824
76,603
-
Eddy Glavas
2024
422,708
141,716
6,741
11,090
2023
422,708
45,360
6,462
14,654
Andrew Thomas11
2024
469,708
154,277
6,741
12,323
2023
469,708
50,490
6,462
17,940
Former Executive KMP
FY
Ashley Haren12
2024
-
-
-
-
2023
289,708
34,020
6,462
-
Iain MacDougall13
2024
-
-
-
-
2023
454,708
37,440
6,462
13,850
David Maxwell14
2024
-
-
-
-
2023
666,573
150,000
47,316
33,656
Mike Jacobsen15
2024
-
-
-
-
2023
395,590
38,250
410
9,211
Amelia Jalleh16
2024
-
-
-
-
2023
375,229
-
5,934
-
Totals
2024
2,577,777
1,297,109
718,119
23,413
2023
3,786,744
474,528
557,912
89,311
REMUNERATION
REPORT
4.8.2 TABLE OF EXECUTIVE KMP STATUTORY REMUNERATION
DISCLOSURE FOR FY24 AND FY23
The following table provides IFRS aligned disclosures on KMP remuneration required by the Corporations Act 2001
and Accounting Standards and is audited. By contrast with the table in section 4.8.1, which discloses amounts
paid in respect of Executive KMP and the cash value of equity awards which vested during the reporting period, the
disclosures provided in the following table present the KMP remuneration costs incurred and accrued during the
reporting period. Amounts included as STIP and LTIP in section 4.8.1 represent realised benefits to Executive KMP
during the reporting period, whilst the amounts shown in the table below as STIP and LTIP represent benefits
incurred during the reporting period (LTIP grants are subject to vesting conditions described in section 4.4.5).
Benefits
Post-
employment
Share based
remuneration4
Post KMP Payments5
Total
Superannuation3
LTIP
Base salary6
Severance
LTIP7
$
$
$
$
$
$
27,398
114,038
-
-
-
1,966,265
9,270
-
-
-
-
689,962
20,549
46,178
-
-
-
920,598
-
-
-
-
-
-
27,399
238,676
-
-
-
978,489
25,292
237,800
-
-
-
892,292
27,399
236,144
-
-
-
845,798
25,292
257,322
-
-
-
771,798
27,399
260,984
133,943
379,379
309,992
1,754,746
25,292
284,486
-
-
-
854,378
-
-
-
-
-
-
25,292
97,702
-
-
-
453,184
-
-
-
-
-
25,292
278,072
-
-
-
815,824
-
-
-
-
-
-
17,530
566,677
293,034
-
1,239,071
3,013,857
-
-
-
-
-
-
21,077
230,335
262,852
319,515
420,132
1,697,372
-
-
-
-
-
-
23,185
241,148
-
-
-
645,496
130,144
896,020
133,943
379,379
309,992
6,465,896
197,522
2,193,542
555,886
319,515
1,659,203
9,834,163
86
85
For the year ended 30 June 2024
REMUNERATION
REPORT
1 Refer to 4.6.3 for STIP amount earned in FY24 which will be paid in FY25.
2 Other short-term benefits include fringe benefits, car parking, sign on bonuses, relocation and other benefits. Other short-term benefits
such as short-term compensated absences, short-term cash profit-sharing and other bonuses are not applicable to executive KMP in FY24.
3 Superannuation is the only applicable post-employment benefit i.e., no pension or similar benefits for executive KMP. Superannuation in-
cludes the amounts required to be contributed by the Company and does not include amounts salary sacrificed.
4 In accordance with the requirements of the Accounting Standards, remuneration includes a proportion of the value of the equity-linked
compensation determined as at the grant date of the PRs and progressively expensed over the vesting period. The amount allocated as re-
muneration is not relative to or indicative of the actual benefit, if any, that may ultimately be realised should the equity instruments vest. The
value of the PRs was determined in accordance with AASB 2 Share-based Payments and is discussed in Section 4.8.3 below and in more
detail in Note 26 of the Notes to the Financial Statements.
5 Base salary and severance are termination benefits and have been accounted for as such.
6 Includes base salary, other short-term benefits and superannuation.
7 Relate to LTIP awards made in December 2021, 2022 and 2023 which have not yet been fully expensed as the three-year testing period has
not finished. These are non-cash expenses for LTIP grants that have not yet vested. These rights remain on foot for qualifying leavers and
vesting of these grants remain contingent on the performance hurdles noted in section 4.4.5.
8 Jane Norman commenced as Managing Director & CEO on 20 March 2023 and her entitlements for 2023 are prorated. “Other short term
benefits” remuneration realised in 2023 includes $400,000 which represents 50% of a sign on bonus. The remaining 50% ($400,000) was
payable on the first anniversary of company service and shown in the 2024 “Other short term benefits” figure. The Company considered this
sign on bonus to be a reasonable assessment for the value of incentives forgone from her previous employment.
9 Chad Wilson commenced as Chief Operating Officer on 23 October 2023. His entitlements for 2024 are prorated. “Other short term bene-
fits” remuneration realised in 2024 includes $290,000 which represents 50% of a sign on bonus. The remaining 50% is payable on the first
anniversary of company service. The Company considered this sign on bonus to be a reasonable assessment for the value of incentives
forgone from his previous employment.
10 Dan Young’s “Other short term benefits” remuneration realised included sign on and relocation costs in 2023. The Company considered
this sign on bonus to be a reasonable assessment for the value of incentives forgone from his previous employment.
11 Andrew Thomas ceased as an executive KMP effective 30 June 2024 but entitlements reflect the full period until his leaving date on
30 September 2024.
12 Ashley Haren ceased as an executive KMP effective 30 June 2023 but entitlements reflect the full period until his retirement effective
5 July 2024.
13 Iain MacDougall ceased as an executive KMP effective 30 June 2023 but entitlements reflect the full period until his leaving date on
5 February 2024.
14 David Maxwell ceased as an executive KMP effective from 20 March 2023, but entitlements reflect the full period until his retirement
on 3 July 2023. Other includes accommodation costs.
15 Mr Jacobsen ceased as an executive KMP effective from 24 April 2023, but entitlements reflect the full period until his leaving date
of 23 October 2023.
16 Ms Jalleh ceased as an executive KMP effective from 19 May 2023, and her entitlements for 2023 are prorated.
No cash-settled share-based payment transactions or other forms of share-based payment compensa-
tion (including hybrids) were made by the Company. As noted in section 4.6.4, none of the PRs or SARs
scheduled for potential vesting in either FY23 or FY24 – namely PRs and SARs granted in December
2019 and December 2020 – met any partial or full vesting thresholds. As such, all of these PRs and
SARs lapsed unvested.
88
87
For the year ended 30 June 2024
For the year ended 30 June 2024
4.8.3 PERFORMANCE RIGHTS ACCOUNTING
FOR THE REPORTING PERIOD
The value of the performance rights (PRs) issued under the
EIP is recognised as share based payments in the
Company’s statement of comprehensive income and
amortised over the vesting period. PRs were granted
under the EIP on 11 December 2023.
PRs are granted for no consideration and employees
receive no cash benefit at the time of receiving the rights.
The cash benefit, if any, will be received by the employee
following the sale of the resultant shares, but this can only
be achieved after the rights have vested and the shares
are issued. Further, the rights can only vest when the
relative total shareholder return (RTSR) and absolute total
shareholder return (ATSR) thresholds described in section
4.4.5 have been achieved.
PRs granted under the EIP were valued by an independent
consultant applying a Monte Carlo simulation model to
determine the probability of achievement of the RTSR and
ATSR against performance conditions.
The value of PRs shown in the tables below are the
accounting fair values for grants in the reporting period:
Performance rights (equity incentive plan)
No. of rights
granted
during period
Fair value of
rights at grant date
($)
No. of rights vested
during period
% of all rights
vested from first
award to 30 June
2024
Directors
Jane Norman
8,378,307
586,481
-
0%
Executive KMP
Chad Wilson
3,392,657
237,486
-
0%
Dan Young
3,064,101
214,487
-
0%
Eddy Glavas
2,632,860
184,300
-
14%
Andrew Thomas1
2,907,782
203,545
-
17%
1 Andrew Thomas ceased as executive KMP 30 June 2024. Andrew leaves Cooper Energy on 30 September 2024.
The vesting date of the PRs granted on 11 December 2023 is 11 December 2026. The estimated fair value of these rights is
$0.07 per right and the share price on grant date was $0.10. The performance period for these PRs commenced on 11
December 2023.
4.8.4 MOVEMENT IN INCENTIVE RIGHTS
The movement during the reporting period in the number of PRs granted but not exercisable over ordinary shares in Cooper
Energy held, directly, indirectly or beneficially, by each executive KMP, including their related parties, is as follows:
Performance rights
(equity incentive plan)
Held at
1 July 2023
Granted
Lapsed
Vested &
exercised
Held at
30 June 2024
Directors
Jane Norman1
-
8,378,307
-
-
8,378,307
Executive KMP
Chad Wilson1
-
3,392,657
-
-
3,392,657
Dan Young
1,556,935
3,064,101
-
-
4,621,036
Eddy Glavas
1,731,917
2,632,860
426,217
-
3,938,560
Andrew Thomas2
1,914,372
2,907,782
471,346
-
4,350,808
No share appreciation rights were granted in FY24. The revised LTIP described in 4.4.5 means that only PRs will be awarded
from the LTIP invitation of 11 December 2023, and provided that performance hurdles described in 4.4.5 are satisfied.
REMUNERATION
REPORT
From previous LTIP grants (those granted in December 2021 and 2022), share appreciation rights represent the right to receive
a quantity of shares based on an amount equal to the difference in share price at grant date and test date. The movement
during the reporting period in the number of SARs granted but not exercisable over ordinary shares in Cooper Energy held,
directly, indirectly or beneficially, by each executive KMP, including their related parties, is as follows:
Share Appreciation Rights
(Equity Incentive Plan)
Held at
1 July 2023
Granted
Lapsed
Vested &
Exercised
Held at
30 June 2024
Directors
Jane Norman1
-
-
-
-
-
Executive KMP
Chad Wilson1
-
-
-
-
-
Dan Young
4,542,590
-
-
-
4,542,590
Eddy Glavas
5,167,133
-
1,364,678
-
3,802,455
Andrew Thomas2
5,711,629
-
1,509,174
-
4,202,455
1 Jane Norman and Chad Wilson were included in LTIP for the first time in December 2023. Jane’s Norman’s allocation of PRs were approved by shareholders in
the AGM in November 2023.
2 Andrew Thomas ceased as an executive KMP effective 30 June 2024. Vesting of the balance held at 30 June 2024 remains subject to meeting market conditions
of the award.
4.8.5 DIRECTORS & EXECUTIVES MOVEMENT IN SHARES
The movement during the reporting period in the number of ordinary shares in Cooper Energy held, directly, indirectly or
beneficially, by each KMP, including their related parties, is as follows:
Ordinary shares
Held at
1 July 2023
Purchases
Received on vesting
of PRs & SARs
Sales
Held at
30 June 2024
Directors
John Conde AO
1,904,254
-
-
1,904,254
Jane Norman
-
-
-
-
-
Timothy Bednall
270,499
50,000
-
-
320,499
Giselle Collins
160,000
-
-
-
160,000
Elizabeth Donaghey
879,000
300,000
-
-
1,179,000
Jeffrey Schneider
2,423,232
-
-
-
2,423,232
Executive KMP
Chad Wilson1
-
-
-
-
-
Dan Young
-
-
-
-
-
Eddy Glavas
1,424,203
-
-
1,346,461
77,742
Andrew Thomas2
5,963,633
-
-
-
5,963,633
1 Chad Wilson commenced as an executive KMP effective 23 October 2023.
2Andrew Thomas ceased as an executive KMP effective 30 June 2024.
Options
No options were issued (or forfeited) during the year.
REMUNERATION
REPORT
89
90
For the year ended 30 June 2024
For the year ended 30 June 2024
4.9 NATURE OF NON-EXECUTIVE DIRECTOR REMUNERATION
Non-executive directors are remunerated solely by way of
fees and statutory superannuation. Their remuneration is
reviewed annually to ensure that the fees reflect their
responsibilities and the demands placed on them. Non-
executive directors do not receive any performance-related
remuneration.
4.9.1 NON-EXECUTIVE DIRECTOR FEE
STRUCTURE
The maximum aggregate remuneration pool for non-
executive directors, as approved by shareholders at the
Company’s 2018 AGM, is $1.25 million. The non-executive
directors’ fee structure for the reporting period (FY24) was
as follows:
Role
Board Fee
Audit Committee
Risk & Sustainability
Committee
People &
Remuneration
Committee
Governance &
Nomination Committee
Chairman*
$240,000
$20,000
$20,000
$20,000
$0
Member
$115,000
$10,000
$10,000
$10,000
$10,000
Effective from 1 July 2024 (FY25), the Board resolved to adjust the fee structure to reflect the increase to the statutory
superannuation rate from 11.00% to 11.50%. This is the first increase in directors fees since July 2019. The table below shows
this adjustment to take effective 1 July 2024.
Role
Board Fee
Audit Committee
Risk & Sustainability
Committee
People &
Remuneration
Committee
Governance &
Nomination Committee
Chairman*
$240,081
$20,090
$20,090
$20,090
$0
Member
$115,518
$10,045
$10,045
$10,045
$10,045
*Where the Chairman of the Board is a member of a committee, they will not receive any additional committee fees.
Remuneration paid to the non-executive directors for the
reporting period and for the previous reporting period is
shown in the table in Section 4.9.2. The fees paid in 2024
were reduced slightly to recognise a minor over payment in
2023 relating to superannuation. By the completion of
2024 this minor over payment was recovered in full.
The Company has entered into written letters of
appointment with its non-executive directors. The term of
the appointment of a non-executive director is determined
in accordance with the Company’s Constitution and is
subject to the provisions of the Constitution dealing with
retirement, re-election and removal of non-executive
directors. The Constitution provides that all non-executive
directors of the Company are subject to re-election by
shareholders by rotation every three years. The Company
has entered into indemnity, insurance and access
agreements with each of the non-executive directors under
which the Company will, on the terms set out in the
agreement, provide an indemnity, maintain an appropriate
level of Directors’ and Officers’ indemnity insurance and
provide access to Company records.
REMUNERATION
REPORT
4.9.2 TABLE OF NON-EXECUTIVE KMP REMUNERATION FOR 2024 AND 2023 FINANCIAL YEARS
Current non-executive
directors (NED)1
Benefits
Short term
Long term
Post-employ-ment
Share based
remuneration
Fees
STIP2
Other
short-term
benefits
Long
service
leave
Super-annuation3
LTIP
Total
$
$
$
$
$
$
$
John Conde AO
2024
215,233
-
-
-
23,676
-
238,909
2023
218,182
-
-
-
22,909
-
241,091
Tim Bednall
2024
136,043
-
-
-
14,965
-
151,008
2023
131,818
-
-
-
13,841
-
145,659
Giselle Collins
2024
133,081
-
-
-
14,639
-
147,720
2023
122,727
-
-
-
12,886
-
135,613
Elizabeth Donaghey 2024
136,043
-
-
-
14,965
-
151,008
2023
131,818
-
-
-
13,841
-
145,659
Jeffrey Schneider
2024
130,037
-
-
-
14,304
-
144,341
2023
131,818
-
-
-
13,841
-
145,659
Vicky Binns4
2024
47,221
-
-
-
5,194
-
52,415
2023
136,818
-
-
-
14,366
-
151,184
Hector Gordon5
2024
-
-
-
-
-
-
-
2023
136,818
-
-
-
14,366
-
151,184
Totals
2024
797,658
-
-
-
87,743
-
885,401
2023
1,009,999
-
-
-
106,050
-
1,116,049
1 Non-executive directors do not participate in the LTIP.
2 Non-executive directors are not eligible for STIP payments.
3 Superannuation includes the amounts required to be contributed by the Company and does not include amounts salary sacrificed.
4 Vicky Binns retired from the Board effective 9 November 2023
5 Hector Gordon retired from the Board effective 23 June 2023.
End of remuneration report.
REMUNERATION
REPORT
91
92
For the year ended 30 June 2024
For the year ended 30 June 2024
5.
PRINCIPAL ACTIVITIES
Cooper Energy is an upstream gas and oil exploration and
production company whose primary purpose is to secure,
find, develop, produce and sell hydrocarbons. These
activities are undertaken either solely or via unincorporated
joint ventures. There was no significant change in the
nature of these activities during the year.
6.
OPERATING AND
FINANCIAL REVIEW
Information on the operations and financial position of
Cooper Energy and its business strategy and prospects is
set out in the Operating and Financial Review.
7.
DIVIDENDS
The Directors do not recommend the payment of a
dividend and no amount has been paid or declared by way
of dividends since the end of the previous financial year, or
to the date of this report.
8.
ENVIRONMENTAL REGULATION
The Company is a party to various exploration,
development and production licences or permits. In most
cases, the licence or permit terms specify the
environmental regulations applicable to gas and oil
operations in the respective jurisdiction. The Group aims
to ensure that it complies with the identified regulatory
requirements in each jurisdiction in which it operates.
There have been no significant known breaches of the
environmental obligations of the Group’s licences or
permits.
9.
LIKELY DEVELOPMENTS
Other than disclosed elsewhere in the Financial Report
(including the Operating and Financial Review under the
heading “Outlook”), further information about likely
developments in the operations of the Group and the
expected results of those operations in future financial
years has not been included in this report because
disclosure of the information would likely result in
unreasonable prejudice to the consolidated entity.
10. DIRECTORS’ INTERESTS
The relevant interest of each Director in ordinary shares and options over shares issued by the parent entity as notified by the
Directors to the Australian Stock Exchange in accordance with S205G(1) of the Corporations Act 2001, at the date of this
reports is as follows:
Ordinary Shares
Performance Rights
Share Appreciation Rights
Mr J. Conde AO
1,904,254
Nil
Nil
Ms J. Norman
Nil
8,378,307
Nil
Mr T. Bednall
320,499
Nil
Nil
Ms G. Collins
160,000
Nil
Nil
Ms E. Donaghey
1,179,000
Nil
Nil
Mr J. Schneider
2,423,232
Nil
Nil
11. SHARE OPTIONS AND RIGHTS
At the date of this report, there are no unissued ordinary
shares of the parent entity under option. At the date of this
report, there are 62,738,389 outstanding PRs and
43,758,208 SARs under the EIP approved by shareholders
at the 2022 AGM.
During the financial year 8,506,969 shares were issued as
a result of PRs exercised, none of these shares was issued
under the EIP to KMPs. At the date of this report, no PRs
have vested and been exercised subsequent to 30 June
2024.
12. EVENTS AFTER FINANCIAL
REPORTING DATE
Refer to Note 29 of the Notes to the Financial Statements.
13. PROCEEDINGS ON 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 the proceedings.
DIRECTORS’
STATUTORY REPORT
14. INDEMNIFICATION AND
INSURANCE OF DIRECTORS AND
OFFICERS
14.1 Indemnification
The parent entity has agreed to indemnify the current
Directors and Officers, and past Directors and Officers, of
the parent entity and its subsidiaries, where applicable,
against all liabilities (subject to certain limited exclusions) to
persons (other than the parent entity and its subsidiaries)
which arise out of the performance of their normal duties as
a Director or Officer, unless the liability relates to conduct
involving a lack of good faith. The parent entity has agreed
to indemnify the Directors and Officers against all costs
and expenses (other than certain excluded legal costs)
incurred in defending an action that falls within the scope of
the indemnity and any resulting payments.
14.2 Insurance premiums
During the financial year, the parent entity has paid
insurance premiums in respect of Directors’ and Officers’
liability and legal insurance contracts for current and former
Directors and Officers of the parent entity. The insurance
contracts relate to costs and expenses incurred by the
relevant Directors and Officers in defending proceedings,
whether civil or criminal and whatever their outcome and
other liabilities that may arise from their position, with
exceptions including conduct involving a wilful breach of
duty or improper use of information or position to gain a
personal advantage. The insurance contracts outlined
above do not contain details of premiums paid in respect of
individual Directors or Officers of the parent entity.
15.
INDEMNIFICATION OF AUDITORS
To the extent permitted by law, the Company has agreed to
indemnify its auditors, Ernst & Young, as part of the terms
of its audit engagement agreement against claims by third
parties arising from the audit (for an unspecified amount)
except in the case where the claim arises because of Ernst
& Young's negligent, wrongful or wilful acts or omissions.
No payment has been made to indemnify Ernst & Young
during or since the financial year.
16.
AUDITOR’S INDEPENDENCE
DECLARATION
The auditor’s independence declaration is set out on
page 149 and forms part of the Directors’ report for the
financial year ended 30 June 2024.
17.
NON-AUDIT SERVICES
The amounts paid and payable to the auditor of the Group,
Ernst & Young and its related practices for non-audit
services provided during the year was $62,000 (2023:
$49,500). The directors are satisfied that the provision of
non-audit services is compatible with the general standard
of independence for auditors imposed by the Corporations
Act 2001. The nature and scope of each type of non-audit
service provided means that auditor independence was not
compromised.
18.
AUDIT TENDER
As noted in last year’s annual report, the Directors elected
to put the Group’s audit out to tender, with effect from the
financial year commencing 1 July 2024.
Ernst & Young have been the Group’s auditor for over ten
years. The tender was designed to assist the Audit
Committee in continuing to assess the quality and
effectiveness of the external audit process. The evaluation
criteria for the audit tender comprised:
§ Firm qualifications in serving clients in the upstream gas
& oil industry
§ Engagement team experience & expertise, including the
involvement of other specialists
§ Audit service process overview, tailored to Cooper
Energy’s business
§ Quality assurance, including internal processes and
results of external inspections
§ Internal practices to ensure compliance with
independence requirements
§ Fee and other key terms & conditions
The tender was undertaken, as foreshadowed, in the
course of H2 FY24. Following a review of, and discussions
with, a number of the audit firms, a request for proposal
(RFP) was sent to each of Deloitte Touche Tohmatsu
Limited, Ernst & Young, KPMG and
PricewaterhouseCoopers.
Each firm was given access to a data room containing
select financial, operational and ESG related matters.
Additionally, each firm met with the Chair of the Audit
Committee, and separately with management including the
Managing Director & CEO, the CFO, and the Group
Finance Manager.
These meetings enabled each firm to ask questions
regarding the critical business issues, the tender evaluation
criteria, the Group’s approach to sustainability generally
including climate related financial disclosures specifically,
and other matters important to the Directors and
management as it pertains to the audit.
Written responses to the RFP were submitted to a steering
committee which comprised the Chair of the Audit
Committee along with senior members of management.
Together with the submission of each firm’s proposal, the
firms were also invited to present their capabilities for both
the audit, as well as in areas that complement the audit,
including climate related financial disclosures and
sustainability, and in IT/technology. These capabilities were
presented at face-to-face meetings with the Chair of the
Board, the Chair of the Audit Committee, the Managing
Director & CEO, the CFO, the Group Finance Manager and
the Environment & Sustainability Manager.
DIRECTORS’
STATUTORY REPORT
93
94
For the year ended 30 June 2024
The relative scores/results of the evaluation are summarized in the following chart.
The Audit Committee recommended to the Board to
continue the appointment of Ernst & Young as the Group’s
external auditor, while identifying certain opportunities for
improvement by them. The Board approved the Audit
Committee’s recommendation, and resolved to continue
the appointment Ernst & Young for the financial year
ending 30 June 2025.
Ernst & Young are required to rotate the audit partner
responsible for the Group’s audit every five years and, as a
result, the current lead audit partner, Darryn Hall, having
served since the financial year ending 30 June 2021, will
rotate after the financial year ending 30 June 2025.
19.
ROUNDING
The Group is of a kind referred to in ASIC Corporations
(Rounding in Financial/Directors’ Reports) Instrument
2016/191 dated 24 March 2016 and in accordance with
that Legislative Instrument, amounts in the financial report
have been rounded to the nearest thousand dollars,
unless otherwise stated.
This report is made in accordance with a resolution
of the Directors.
Mr John C. Conde AO
Ms Jane L. Norman
Chairman
Managing Director & CEO
Dated at Adelaide 27 August 2024
Ernst & Young
Firm 2
Firm 3
Firm 4
Key terms & conditions including fees
Independence
Quality assurance
Process overview
Engagement team experience & expertise
Firm qualifications
DIRECTORS’
STATUTORY REPORT
96
95
As at 30 June 2024
98
For the year ended 30 June 2024
Notes
2024
$’000
2023
(restated)
$’000
Revenue from gas and oil sales
2
219,047
196,885
Cost of sales
2
(167,321)
(164,379)
Gross profit
51,726
32,506
Other income
2
3,355
-
Other expenses
2
(147,440)
(110,722)
Finance income
18
3,484
3,019
Finance costs
18
(36,219)
(29,496)
Loss before tax
(125,094)
(104,693)
Income tax (expense)/benefit
3
(915)
19,185
Petroleum resource rent tax benefit
3
11,900
25,016
Total tax benefit
10,985
44,201
Loss after tax for the period attributable to shareholders
(114,109)
(60,492)
Other comprehensive income/(expenditure)
Items that will not be reclassified subsequently to profit or loss
Net gain/(loss) on equity instruments recorded at fair value through other
comprehensive income
19
(412)
648
Other comprehensive income/(expenditure) for the period net of tax
(412)
648
Total comprehensive loss for the period attributable to shareholders
(114,521)
(59,844)
Cents
Cents
Basic loss per share
4
(4.3)
(2.3)
Diluted loss per share
4
(4.3)
(2.3)
The above Consolidated Statement of Comprehensive Income should be read in conjunction with the accompanying notes.
CONSOLIDATED STATEMENT
OF COMPREHENSIVE INCOME
Notes
2024
$’000
2023
(restated)
$’000
1 July 2022
(restated)
$’000
ASSETS
Current Assets
Cash and cash equivalents
5
14,332
77,134
247,012
Trade and other receivables
6
35,209
28,797
30,467
Prepayments
7
6,064
6,303
12,854
Inventory
8
2,044
2,182
841
Total Current Assets
57,649
114,416
291,174
NON-CURRENT ASSETS
Other financial assets
20
718
1,131
484
Contract asset
2
2,069
2,323
2,062
Property, plant and equipment
10
346,320
380,375
59,232
Intangible assets
11
466
967
1,360
Right-of-use assets
16
1,380
7,448
7,520
Exploration and evaluation assets
12
193,805
184,569
164,909
Gas and oil assets
13
475,152
535,842
595,347
Deferred tax asset
3
83,818
84,733
64,530
Deferred petroleum resource rent tax asset
3
61,809
53,167
39,685
Total Non-Current Assets
1,165,537
1,250,555
935,129
Exploration assets classified as held for sale
-
-
1,558
Total Assets
1,223,186
1,364,971
1,227,861
LIABILITIES
Current Liabilities
Trade and other payables
9
76,773
68,679
32,752
Provisions
15
32,920
166,098
29,867
Lease liabilities
16
847
1,467
1,251
Interest bearing loans and borrowings
-
-
37,000
Total Current Liabilities
110,540
236,244
100,870
NON-CURRENT LIABILITIES
Trade and other payables
9
-
19,262
-
Provisions
15
433,720
417,509
446,754
Lease liabilities
16
927
9,182
9,612
Interest bearing loans and borrowings
17
253,147
143,956
121,000
Other financial liabilities
20
2,830
2,853
3,285
Deferred petroleum resource rent tax liability
3
4,376
7,479
23,365
Total Non-Current Liabilities
695,000
600,241
604,016
Liabilities directly associated with assets held for sale
-
-
908
Total Liabilities
805,540
836,485
705,794
Net Assets
417,646
528,486
522,067
CONSOLIDATED STATEMENT
FINANCIAL POSITION
EQUITY
Contributed equity
19
718,881
716,726
478,261
Reserves
19
27,185
26,071
197,625
Accumulated losses
(328,420)
(214,311)
(153,819)
Total Equity
417,646
528,486
522,067
The above Consolidated Statement of Financial Position should be read in conjunction with the accompanying notes.
97
For the year ended 30 June 2024
For the year ended 30 June 2024
CONSOLIDATED STATEMENT
OF CHANGES IN EQUITY
Issued
Capital
Reserves
Accumulated
Losses
Total
Equity
Notes
$’000
$’000
$’000
$’000
Balance at 1 July 2023 (restated)
716,726
26,071
(214,311)
528,486
Loss for the period
-
-
(114,109)
(114,109)
Other comprehensive expenditure
-
(412)
-
(412)
Total comprehensive loss for the period
-
(412)
(114,109)
(114,521)
Transactions with owners in their capacity as owners:
Share based payments
19
-
3,681
-
3,681
Transferred to issued capital
19
2,155
(2,155)
-
-
Balance as at 30 June 2024
718,881
27,185
(328,420)
417,646
Balance at 1 July 2022
478,261
197,625
(177,461)
498,425
Impact of adoption of amendments to AASB 112 (page 103)
-
-
23,642
23,642
Balance at 1 July 2022 (restated)
478,261
197,625
(153,819)
522,067
Loss for the period (restated)
-
-
(60,492)
(60,492)
Other comprehensive expenditure
-
648
-
648
Total comprehensive gain/(loss) for the period (restated)
-
648
(60,492)
(59,844)
Transactions with owners in their capacity as owners:
Equity issue
19
58,596
-
-
58,596
Share based payments
19
-
7,667
-
7,667
Transferred to retained earnings
19
-
-
-
-
Transferred to issued capital
19
179,869
(179,869)
-
-
Balance as at 30 June 2023 (restated)
716,726
26,071
(214,311)
528,486
The above Consolidated Statement of Changes in Equity should be read in conjunction with the accompanying notes.
Notes
2024
$’000
2023
$’000
CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from customers
214,079
198,265
Payments to suppliers and employees
(92,844)
(101,632)
Payments for restoration
(207,723)
(19,580)
Petroleum resource rent tax refund/(paid)
195
(6,225)
Interest received
3,603
2,910
Interest paid
(17,073)
(10,974)
Net cash from operating activities
5
(99,763)
62,764
CASH FLOWS FROM INVESTING ACTIVITIES
Payments for property, plant and equipment
(46,846)
(245,370)
Payments for intangibles
(34)
(1,092)
Payments for exploration and evaluation
(15,045)
(23,248)
Payments for gas and oil assets
(4,555)
(5,858)
Proceeds from held for sale assets
-
650
Net cash flows used in investing activities
(66,480)
(274,918)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayment of principal portion of lease liabilities
(1,457)
(1,262)
Proceeds from equity issue
-
57,579
Proceeds from borrowings
5
107,000
158,000
Repayment of borrowings
5
-
(158,000)
Transaction costs associated with borrowings
5
-
(15,142)
Net cash flow from financing activities
105,543
41,175
Net (decrease)/increase in cash held
(60,700)
(170,979)
Net foreign exchange differences
(2,102)
1,101
Cash and cash equivalents at 1 July
77,134
247,012
Cash and cash equivalents at 30 June
5
14,332
77,134
The above Consolidated Statement of Cash Flows should be read in conjunction with the accompanying notes.
CONSOLIDATED STATEMENT
OF CASH FLOWS
99
100
For the year ended 30 June 2024
CORPORATE INFORMATION
The consolidated financial report of Cooper Energy Limited
and its controlled entities (“Cooper Energy”, “the Group”, or
“the Company”), for the year ended 30 June 2024, was
authorised for issue on 27 August 2024 in accordance with
a resolution of the Directors.
Cooper Energy Limited is a for profit company limited by
shares, incorporated and domiciled in Australia, and whose
shares are publicly traded on the Australian Securities
Exchange.
The nature of the operations and principal activities of the
Group are described in the Directors’ Statutory Report and
Note 1.
BASIS OF PREPARATION
The financial report is a general-purpose financial report,
which has 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”) and International Financial Reporting
Standards (“IFRS”) as issued by the International
Accounting Standards Board.
The financial report has also been prepared on a historical
cost basis, except for equity instruments measured at fair
value through other comprehensive income and other
items as set out in the notes indicated as measured at fair
value through profit and loss.
The financial report is presented in Australian dollars.
Under the option available to the Group under ASIC
Corporations (Rounding in Financial/Directors’ Reports)
Instrument 2016/191, all values are rounded to the nearest
thousand dollars ($’000), unless otherwise stated.
Australian dollars is the functional currency of Cooper
Energy Limited and all of its subsidiaries. Transactions in
foreign currencies are initially recorded in the functional
currency of the transacting entity at the exchange rates
ruling at the date of the transaction. Monetary assets and
liabilities denominated in foreign currencies at the reporting
date are translated at the rates of exchange prevailing at
that date. Exchange differences in the consolidated
financial statements are taken to the income statement.
Funding overview
The Group holds cash balances of $14.3 million and has
drawn debt of $265.0 million as at the end of the reporting
period with a further $135.0 million committed, available
and undrawn as at 30 June 2024, under a senior secured
reserve based loan facility with an expected maturity date
of September 2027. The Company also has a further $12.6
million availability under the Company’s working capital
facility. All debt covenants have been complied with to the
date of this report.
GOING CONCERN BASIS
The consolidated financial statements have been prepared
on the basis that the Group is a going concern, which
contemplates continuity of normal operations and the
realisation of assets and settlement of liabilities in the
ordinary course of business. The directors have formed the
view that there are reasonable grounds to believe that the
Group will continue as a going concern.
BASIS OF CONSOLIDATION
The consolidated financial statements are those of the
consolidated entity, comprising Cooper Energy Limited
(“the parent entity”) and its controlled entities (“Cooper
Energy” or “the Group”).
The financial statements of subsidiaries are prepared for
the same reporting period as the parent entity, using
consistent accounting policies. All inter-company balances
and transactions, income and expenses and profit and
losses arising from intra-group transactions, have been
eliminated in full. Subsidiaries are consolidated from the
date on which the Group gains control of the subsidiary
and cease to be consolidated from the date on which the
Group ceases to control the subsidiary.
SIGNIFICANT ACCOUNTING
JUDGEMENTS, ESTIMATES AND
ASSUMPTIONS
In the process of applying the Group’s accounting policies,
management is required to make judgements, estimates
and assumptions that affect the reported amounts in the
financial statements. Judgements, estimates and
assumptions which are material to specific notes of the
financial statements are below:
Note 3
Income tax
Note 16
Leases
Note 13
Gas and
oil assets
Note 21
Interests in joint
arrangements
Note 14
Impairment
Note 26
Share based
payments
Note 15
Provisions
Judgements, estimates and assumptions which are
material to the overall financial statements are below:
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
COOPER ENERGY FINANCIAL REPORT 2024
NOTES
TO THE
CONSOLIDATED
FINANCIAL
STATEMENTS
102
101
For the year ended 30 June 2024
For the year ended 30 June 2024
NEW ACCOUNTING STANDARDS
AND INTERPRETATIONS
New standards, interpretations and amendments
thereof, adopted by the Group
The Group applied the following amendment to AASB 112
for the first time for the period commencing 1 July 2023:
AASB 2021-5 Amendments to Australian Accounting
Standards – Deferred Tax related to Assets and Liabilities
arising from a Single Transaction (AASB 112).
At 1 July 2023 the Group adopted narrow-scope
amendments to AASB 112 Income Taxes and have
restated comparative periods in accordance with the
transition requirements.
Under AASB 112, a deferred tax liability is recognised for
all taxable temporary differences and a deferred tax asset
is recognised for all deductible temporary differences (to
the extent it is probable that taxable profit will be available,
against which the deductible temporary difference can be
utilised), unless there is an exemption in AASB 112. One of
these circumstances, known as the initial recognition
exemption, applies when a transaction affects neither
accounting profit nor taxable profit, and is not a business
combination. The scope of this exemption has now been
narrowed, such that it no longer applies, on initial
recognition of an asset and liability in a single transaction
that gives rise to equal taxable and deductible temporary
differences.
The Group’s previous accounting policy applied this initial
recognition exemption, where the initial recognition of an
asset and liability from a single transaction gave rise to
equal taxable and deductible temporary differences. The
most significant impact of implementing this new
amendment comes from temporary differences arising from
the Group’s restoration provisions and corresponding
amounts recognised as part of the cost of the related asset.
Adjustments to deferred tax assets and liabilities arising
from this amendment have been recognised as at 1 July
2022, being the beginning of the earliest comparative
period presented in the financial statements for the year
ended 30 June 2024, with the cumulative effect recognised
as an adjustment to accumulated losses at that date.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
SIGNIFICANT ACCOUNTING JUDGEMENTS, ESTIMATES AND ASSUMPTIONS
Determination of recoverable hydrocarbons
Estimates of recoverable hydrocarbons impact the asset impairment assessment, depreciation and amortisation rates and
decommissioning and restoration provisions.
Estimates of recoverable hydrocarbons are evaluated and reported by qualified petroleum reserves and resources evaluators
in accordance with the ASX Listing Rules and definitions and guidelines in the Society of Petroleum Engineers (SPE) 2018
Petroleum Resources Management System (PRMS).
Recoverable hydrocarbon estimates may change, from time to time, if any of the forecast assumptions are revised.
Climate change
In preparing the financial report, management has considered the impact of climate change and current climate-related
legislation.
The focus of the Company’s strategy on conventional gas production, located close to market in Southeast Australia,
is conducive to the supply of lower emissions intensity gas. The Company measures and reports its emissions and
emissions offsets to maintain its carbon neutral position as certified by Climate Active, a partnership between the Australian
Government and Australian businesses to drive voluntary climate action, whilst also seeking to reduce its gross emissions.
These results are published annually in the Company’s Sustainability Report and are aligned with the Financial Stability
Board’s Task Force on Climate-Related Financial Disclosures recommendations on climate-related financial disclosures.
The Company continues to monitor climate-related policy and its impact on the financial report. The current impacts of
climate change include estimates of a range of economic and climate-related scenarios. This includes market supply and
demand profiles, carbon emissions profiles, legal impacts and technological impacts. These are factored into discount rates,
commodity price forecasts, and demand and supply profiles, all of which are impacted by the global demand profile of the
economy as a whole. The estimates and forecasts used by the Company are in accordance with current climate-related
legislation and policy.
The impact of climate change is considered in the significant judgements and key estimates in a number of areas in the
Company’s financial report including:
• asset carrying values (exploration and evaluation assets, gas and oil assets) through determination of valuations considered
for impairment – refer note 14;
• restoration obligations, including the timing of such activities – refer note 15; and
•deferred taxes, primarily related to asset carrying values and restoration obligations – refer note 3.
The Group continues to monitor climate-related policy and its impact on the Financial Report.
On initial adoption of the standard as at 1 July 2023, the impacts of the transition are the following:
Impact on the Consolidated Statement of Financial Position as at 1 July 2022
1 July 2022
(Previously
reported)
$’000
Impact of
AASB 112
amendments
$’000
1 July 2022
(Restated)
$’000
Assets: Deferred tax asset
63,563
967
64,530
Assets: Deferred petroleum resource rent tax asset
12,763
26,922
39,685
Liabilities: Deferred petroleum resource rent tax liability
(19,118)
(4,247)
(23,365)
Equity: Accumulated losses
(177,461)
23,642
(153,819)
Impact on the comparative reporting date is as follows:
30 June 2023
(Previously
reported)
$’000
Impact of
AASB 112
amendments
$’000
30 June 2023
(Restated)
$’000
Consolidated Statement of Financial Position
Assets: Deferred tax asset
92,642
(7,909)
84,733
Assets: Deferred petroleum resource rent tax asset
24,659
28,508
53,167
Liabilities: Deferred petroleum resource rent tax liability
(18,494)
11,015
(7,479)
Equity: Accumulated losses
(245,924)
31,613
(214,311)
Consolidated Statement of Comprehensive Income
Income tax benefit
28,063
(8,878)
19,185
Petroleum resource rent tax benefit
8,167
16,849
25,016
Basic loss per share
(2.6)
-
(2.3)
Diluted loss per share
(2.6)
-
(2.3)
There was no material impact on the Consolidated Statement of Cash Flows and other comprehensive income.
NOTES TO THE FINANCIAL STATEMENTS
The notes include information which is required to understand the financial statements and is material and relevant to the
operations, financial position and performance of the Group. They include applicable accounting policies applied and significant
judgements, estimates and assumptions made. Specific accounting policies are disclosed in the respective notes to the
financial statements. The notes are organised into the following sections:
Group performance Provides additional information regarding financial statement lines that are most relevant to explaining
the Group’s operating performance during the period.
Working capital
Provides additional information regarding financial statement lines that are most relevant to explaining
the working capital assets used to contribute to generating the Group’s operating performance during
the period.
Capital employed
Provides additional information regarding financial statement lines that are most relevant to explaining
the capital investments made that contribute to the ability for the Group to generate its operating result
during the period and liabilities incurred as a result.
Funding and risk
management
Provides additional information regarding financial statement lines that are most relevant to explaining
the Group’s funding sources. This section also provides information relating to the Group’s exposure to
various financial risks, its impact on the financial position and performance of the Group and how these
risks are managed.
Group structure
Summarises how the group structure affects the financial position and performance of the Group
as a whole.
Other information
Includes other information that is disclosed to comply with relevant accounting standards and other
pronouncements, but is not directly related to the individual line items in the financial statement.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
103
104
For the year ended 30 June 2024
For the year ended 30 June 2024
GROUP PERFORMANCE
1. SEGMENT REPORTING
Identification of reportable segments and types of
activities
The Group has identified its reportable segments to be
Southeast Australia, Cooper Basin (both based on the
nature and geographic location of its assets) and Corporate
and Other. This forms the basis of internal Group reporting
to the CEO & Managing Director who is the chief operating
decision maker for the purpose of assessing performance
and allocating resources between each segment. Revenue
and expenses are allocated by way of their natural
expense and income category. Other prospective
opportunities are also considered from time to time and, if
they are secured, will then be attributed to the segment
where they are located, or a new segment will be
established.
The following are reportable segments:
Southeast Australia
The Southeast Australia segment primarily consists of the
operated Sole producing gas assets and the OGPP, the
operated Casino Henry producing gas assets and the
operated Athena Gas Plant. Revenue is derived from the
sale of gas and condensate to six contracted customers
and via spot sales. The segment also includes exploration
and evaluation and care and maintenance activities
ongoing in the Gippsland and Otway basins.
Cooper Basin
This segment comprises production and sale of crude oil in
the Group’s permits within the Cooper Basin, along with
exploration and evaluation of additional oil targets.
Revenue is derived from the sale of crude oil to Santos
Limited and Beach Energy (Operations) Limited, the two
participants in the South Australia Cooper Basin joint
venture.
Corporate and Other
The Corporate residual component includes the revenue
and costs associated with the running of the business and
includes items which are not directly allocable to the other
segments.
Accounting policies and inter-segment transactions
The accounting policies used by the Group in reporting segments internally is the same as those contained in the financial
statements.
Southeast
Australia
$’000
Cooper
Basin
$’000
Corporate and
Other
$’000
Consolidated
$’000
30 June 2024
Revenue from gas and oil sales to external customers
199,142
19,905
-
219,047
Total revenue
199,142
19,905
-
219,047
Segment result before interest, tax, depreciation,
amortisation and restoration, exploration and evaluation
expense and impairment
102,049
11,300
(16,198)
97,151
Restoration expense
(86,790)
-
-
(86,790)
Depreciation and amortisation
(92,837)
(3,601)
(2,361)
(98,799)
Exploration and evaluation expense
(1,605)
(2,047)
-
(3,652)
Impairment
(269)
-
-
(269)
Net finance costs
(17,407)
(248)
(15,080)
(32,735)
Profit/(loss) before tax
(96,859)
5,404
(33,639)
(125,094)
Income tax expense
-
-
(915)
(915)
Petroleum resource rent tax benefit
11,900
-
-
11,900
Net profit/(loss) after tax
(84,959)
5,404
(34,554)
(114,109)
Segment assets
467,825
32,263
723,098
1,223,186
Segment liabilities
707,559
4,634
93,347
805,540
Additions of non-current assets1
Exploration and evaluation assets
11,318
3,002
-
14,320
Gas and oil assets
(6,508)
2,869
-
(3,639)
Property, plant and equipment
4,379
-
354
4,733
Intangibles
-
-
482
482
Total additions of non-current assets
9,189
5,871
836
15,896
1Additions include the movement in the restoration assets
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
1. SEGMENT REPORTING CONTINUED
Southeast
Australia
$’000
Cooper
Basin
$’000
Corporate and
Other
$’000
Consolidated
$’000
30 June 2023 (restated)1
Revenue from gas and oil sales to external customers
184,542
12,343
-
196,885
Total revenue
184,542
12,343
-
196,885
Segment result before interest, tax, depreciation,
amortisation and restoration, exploration and evaluation
expense and impairment
113,656
6,484
(27,071)
93,069
Restoration expense
(46,343)
-
-
(46,343)
Depreciation and amortisation
(93,450)
(2,066)
(3,308)
(98,824)
Impairment
(26,118)
-
-
(26,118)
Net finance costs
(18,764)
(160)
(7,553)
(26,477)
Profit/(loss) before tax
(71,019)
4,258
(37,932)
(104,693)
Income tax benefit
-
-
19,185
19,185
Petroleum resource rent tax benefit
25,016
-
-
25,016
Net profit/(loss) after tax (restated)
(46,003)
4,258
(18,747)
(60,492)
Segment assets
608,133
27,470
729,368
1,364,971
Segment liabilities
665,317
5,244
165,924
836,485
Additions of non-current assets2
Exploration and evaluation assets
23,835
986
-
24,821
Gas and oil assets
10,981
3,181
-
14,162
Property, plant and equipment
(9,765)
-
402
(9,363)
Intangibles
-
-
1,092
1,092
Total additions of non-current assets
25,051
4,167
1,494
30,712
1 Comparative information has been restated to reflect the adoption of narrow scope amendments to AASB 112 Income Taxes, refer to page 103 for details
2 Additions include the movement in the restoration assets
In 2024, contracted revenue from three customers amounted to $79.0 million, $42.5 million and $21.7 million respectively in the
Southeast Australia segment. In 2023, contracted revenue from three customers amounted to $88.6 million, $43.4 million and
$22.0 million respectively in the Southeast Australia segment.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
105
106
For the year ended 30 June 2024
For the year ended 30 June 2024
2. REVENUES AND EXPENSES
REVENUES
Revenue from gas and oil sales
Notes
2024
$’000
2023
$’000
Revenue from contracts with customers
Gas revenue from contracts with customers
199,154
184,542
Oil revenue from contracts with customers
19,893
12,403
Total revenue from contracts with customers
219,047
196,945
Other revenue
Fair value movement on crude oil receivables
-
(60)
Total other revenue
-
(60)
Total revenue from gas and oil sales
219,047
196,885
Other income
Lease adjustment
2,614
-
Other income
741
-
Total other income
3,355
-
Contract assets related to contracts with customers
The Group has recognised the following assets related to contracts with customers.
Opening balance
2,323
2,062
Contract assets recognised during the year
-
492
Unwind of contract asset
(254)
(231)
Closing balance
2,069
2,323
EXPENSES
Cost of sales
Production expenses
(59,212)
(61,081)
Royalties
(1,558)
(1,118)
Third-party product purchases and trading costs
(9,389)
(7,604)
Amortisation of gas and oil assets
(58,214)
(58,654)
Depreciation of property, plant and equipment
(38,043)
(36,853)
Inventory movement
(905)
931
Total cost of sales
(167,321)
(164,379)
Other expenses
Selling expense
(1,100)
(402)
General administration
(14,472)
(19,063)
Depreciation of property, plant and equipment
(745)
(713)
Amortisation of intangibles
(534)
(1,485)
Depreciation of right-of-use assets
(1,263)
(1,119)
Care and maintenance
(8,102)
(2,612)
Restoration expense
(86,790)
(46,343)
Exploration and evaluation expense
(3,652)
-
Impairment expense
14
(269)
(26,118)
Expected credit losses of trade and other receivables
20
(23,546)
(2,815)
Other (including new ventures)
(6,967)
(9,606)
OGPP reconfiguration and commissioning works
-
(446)
Total other expenses
(147,440)
(110,722)
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
2. REVENUES AND EXPENSES CONTINUED
Employee benefits expense included in general administration
2024
$’000
2023
$’000
Director and employee benefits
(37,246)
(28,960)
Share based payments
(3,681)
(7,667)
Superannuation expense
(2,823)
(2,365)
Total employee benefits expense (gross)
(43,750)
(38,992)
The increase in employee benefits in 2024, compared to 2023, is largely due to a full year’s recognition of the employee costs at
the Orbost Gas Processing Plant; Cooper Energy took over operatorship of the plant on 22 May 2023.
ACCOUNTING POLICY
Revenue from contracts with customers
Revenue from contracts with customers is recognised at the point in time when control of the natural gas, liquids or crude oil is
transferred to the customer, at an amount that reflects the consideration to which the Group expects to be entitled in exchange
for those goods. This is generally when the product is transferred to the delivery point specified in the individual customer
contract. The Group’s performance obligations are considered to relate only to the sale of the natural gas, liquids or crude oil,
with each GJ of natural gas or barrel of liquids or crude oil considered to be a separate performance obligation under the
contractual arrangements in place.
The Group has concluded that it is the principal in all of its revenue arrangements since it controls the goods before transferring
them to the customer. Under the terms of the relevant joint operating arrangements, the Group is entitled to its participating
share in the natural gas, liquids or crude oil, based on the Group’s entitlement interest. Revenue from contracts with customers
is recognised based on the actual volumes sold to customers.
The Group’s sales of natural gas are predominantly based on contracted prices, while crude oil and liquids transactions are
priced based on crude oil market prices, adjusted for a quality differential.
In the prior period, crude oil sales contained provisional pricing. Revenue from contracts with customers was recognised based
on the provisional pricing at the date of delivery, with the price estimate based on the forward curve. The difference between
the estimated price and the price ultimately achieved for the sale of the crude oil transaction was recognised as a movement in
the fair value of the receivable in accordance with AASB 9 Financial Instruments. This amount is presented as other revenue in
Note 2 as these movements are not within the scope of AASB 15 Revenue from Contracts with Customers.
Contract assets
A contract asset is recognised for gas contracts that have variable selling prices, which are allocated proportionately to all the
performance obligations over the life of the contract. Contract assets unwind as “revenue from contracts with customers” with
reference to the performance obligation over the life of the contract.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
ACCOUNTING POLICY
Revenue from contracts with customers
Revenue from contracts with customers is recognised at the point in time when control of the natural gas, liquids or crude
oil is transferred to the customer, at an amount that reflects the consideration to which the Group expects to be entitled in
exchange for those goods. This is generally when the product is transferred to the delivery point specified in the individual
customer contract. The Group’s performance obligations are considered to relate only to the sale of the natural gas, liquids
or crude oil, with each GJ of natural gas or barrel of liquids or crude oil considered to be a separate performance obligation
under the contractual arrangements in place.
The Group has concluded that it is the principal in all of its revenue arrangements since it controls the goods before
transferring them to the customer. Under the terms of the relevant joint operating arrangements, the Group is entitled to its
participating share in the natural gas, liquids or crude oil, based on the Group’s entitlement interest. Revenue from contracts
with customers is recognised based on the actual volumes sold to customers.
The Group’s sales of natural gas are predominantly based on contracted prices, while crude oil and liquids transactions are
priced based on crude oil market prices, adjusted for a quality differential.
In the prior period, crude oil sales contained provisional pricing. Revenue from contracts with customers was recognised
based on the provisional pricing at the date of delivery, with the price estimate based on the forward curve. The difference
between the estimated price and the price ultimately achieved for the sale of the crude oil transaction was recognised as a
movement in the fair value of the receivable in accordance with AASB 9 Financial Instruments. This amount is presented as
other revenue in Note 2 as these movements are not within the scope of AASB 15 Revenue from Contracts with Customers.
Contract assets
A contract asset is recognised for gas contracts that have variable selling prices, which are allocated proportionately to all
the performance obligations over the life of the contract. Contract assets unwind as “revenue from contracts with customers”
with reference to the performance obligation over the life of the contract.
107
108
For the year ended 30 June 2024
For the year ended 30 June 2024
3. INCOME TAX
2024
$’000
2023
(restated)
$’000
Consolidated Statement of Comprehensive Income
Current income tax
Current year
-
-
-
-
Deferred income tax
Origination and reversal of temporary differences
(66,835)
7,814
Recognition of tax losses
65,920
11,371
(915)
19,185
Income tax (expense)/benefit
(915)
19,185
Current petroleum resource rent tax
Current year
155
(4,184)
155
(4,184)
Deferred petroleum resource rent tax
Origination and reversal of temporary differences
11,745
29,200
11,745
29,200
Petroleum resource rent tax benefit
11,900
25,016
Total tax benefit
10,985
44,201
Reconciliation between tax expense and pre-tax net profit
Accounting loss before tax from continuing operations
(125,094)
(104,693)
Income tax based on the domestic corporation tax rate of 30% (2023: 30%)
37,528
31,408
(Increase)/decrease in income tax expense due to:
Non-deductible expenditure
(1,478)
(2,744)
Recognition of royalty related income tax benefits
(3,512)
(9,575)
Derecognition of deferred tax asset
(33,285)
-
Other
(168)
96
Income tax benefit
(915)
19,185
Petroleum resource rent tax benefit
11,900
25,016
Total tax benefit
10,985
44,201
TAX CONSOLIDATION
Cooper Energy Limited and its 100% owned Australian
resident subsidiaries are consolidated for Australian
income tax purposes, with Cooper Energy Limited being
the head entity of the tax consolidated group. Members of
the Group entered into a tax sharing arrangement in order
to allocate income tax expense to the wholly-owned
subsidiaries. In addition, the agreement provides for the
allocation of income tax liabilities between the entities
should the head entity default on its tax payment
obligations.
Members of the tax consolidated group have entered into a
tax funding agreement. The tax funding agreement
requires members of the tax consolidated group to make
contributions to the head company for tax liabilities and
deferred tax balances arising from transactions occurring
after the implementation of tax consolidation. Contributions
are payable following the payment of the liabilities by
Cooper Energy Limited. The assets and liabilities arising
under the tax funding agreement are recognised as inter-
company assets and liabilities with a consequential
adjustment to income tax expense or benefit. In addition,
the agreement provides for the allocation of income tax
liabilities between the entities should the head entity default
on its tax payment obligations or upon leaving the Group.
The current and deferred tax amounts are measured in a
systematic manner that is consistent with the broad
principles in AASB 112 Income Taxes.
UNRECOGNISED TEMPORARY DIFFERENCES
At 30 June 2024, there are no unrecognised temporary
differences associated with the Group’s investments in
subsidiaries, as the Group has no liability for additional
taxation should unremitted earnings be remitted
(2023: $nil).
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
3. INCOME TAX CONTINUED
FRANKING TAX CREDITS
At 30 June 2024 the parent entity had franking tax credits
of $42.9 million (2023: $42.9 million). The fully franked
dividend equivalent is $142.9 million (2023: $142.9 million).
PETROLEUM RESOURCE RENT TAX
Cooper Energy Limited has recognised a deferred tax
asset for PRRT of $61.8 million (2023 restated: $53.2
million) and a deferred tax liability for PRRT of $4.4 million
(2023 restated: $7.5 million).
INCOME TAX LOSSES
(a) Revenue Losses
A deferred tax asset has been recognised for the year
ended 30 June 2024 of $161.6 million (2023: $96.2 million).
(b) Capital Losses
Cooper Energy has not recognised a deferred tax asset for
Australian income tax capital losses of $15.5 million (2023:
$15.5 million) on the basis that it is not probable that the
carried forward capital losses will be utilised against future
assessable capital profits.
Consolidated Statement of
Financial Position
Consolidated Statement of
Comprehensive Income
2024
$’000
2023
(restated)
$’000
2024
$’000
2023
(restated)
$’000
Deferred corporate income tax
Deferred income tax at 30 June relates to:
Deferred tax liabilities
Trade and other receivables
21
57
(36)
(5,937)
Gas and oil assets
90,321
97,773
(7,452)
(3,188)
Exploration and evaluation
53,069
48,640
4,429
6,436
Property, plant and equipment
36,845
32,440
4,405
24,203
Other
18,083
16,469
1,614
13,594
198,339
195,379
2,960
35,108
Deferred tax assets
Leases
532
3,195
(2,663)
(64)
Provisions
117,252
178,290
(61,038)
30,575
Tax losses
161,577
96,205
65,372
19,610
Other
2,796
2,422
374
4,172
282,157
280,112
2,045
54,293
Deferred tax (expense) / benefit
(915)
19,185
Deferred tax asset from corporate tax
83,818
84,733
Deferred tax from PRRT
Deferred PRRT at 30 June relates to:
Deferred tax liabilities
Gas and oil assets
4,376
7,479
(3,103)
(7,392)
Deferred tax liability from PRRT
4,376
7,479
Deferred tax assets
Gas and oil assets
61,809
53,167
8,642
13,482
Deferred tax asset from PRRT
61,809
53,167
Total PRRT deferred tax benefit
5,539
6,090
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
109
110
For the year ended 30 June 2024
For the year ended 30 June 2024
3. INCOME TAX CONTINUED
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
ACCOUNTING POLICY
Current tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered
from or paid to the taxation authorities, based on tax rates and tax laws that are enacted, or substantively enacted, by the
reporting date.
Deferred tax is recognised on all temporary differences, except for:
• when deferred tax arises from the initial recognition of an asset or liability in a transaction that is not a business combination
and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss and does not give rise to
equal taxable and deductible temporary differences; and
• the taxable temporary difference is associated with investments in subsidiaries, associates or interests in joint ventures, and
the timing of the reversal of the temporary difference can be controlled and it is probable that the temporary difference will
not reverse in the foreseeable future.
Deferred income tax assets are recognised for all deductible temporary differences, carry-forward of unused tax assets and
unused tax losses, to the extent that it is probable that future taxable profit will be available against which the deductible
temporary differences and the carry-forward of unused tax credits and unused tax losses can be utilised.
The carrying amount of deferred income tax assets is reviewed at each reporting date and reduced to the extent that it is no
longer probable that sufficient taxable profit will be available to allow all or part of the deferred income tax asset to be utilised.
Unrecognised deferred income tax assets are reassessed at each reporting date and are recognised to the extent that it has
become probable that future taxable profit will allow the deferred tax asset to be recovered.
Deferred income tax assets and liabilities are measured at the tax rates that were expected to apply to the year when the
asset is realised or the liability is settled, based on tax rates and tax laws that have been enacted or substantively enacted by
the reporting date.
Income taxes relating to items recognised directly in equity are recognised in equity and not in profit or loss.
Deferred tax assets and deferred tax liabilities are offset only if a legally enforceable right exists to offset current tax assets
against current tax liabilities and the deferred tax asset and liabilities relate to the same taxable entity and the same taxation
authority.
Petroleum Resource Rent Tax
For PRRT purposes, the impact of future augmentation on expenditure is included in the determination of future taxable
profits when assessing the extent to which a deferred tax asset can be recognised in the statement of financial position.
Deferred tax assets are reduced to the extent that it is no longer probable that the related tax benefit will be realised.
Goods and Services Taxes (“GST”)
Revenues, expenses and assets are recognised net of the amount of GST. Receivables and payables are stated inclusive
of the amount of GST receivable or payable. The net amount of GST recoverable from, or payable to, the taxation authority
is included as part of receivables or payables in the Consolidated Statement of Financial Position. Commitments and
contingencies are disclosed net of the amount of GST recoverable from, or payable to, the taxation authority.
Cash flows are included in the Cash Flow Statement on a net basis and the net GST component of cash flows arising from
investing and financing activities, which is recoverable from, or payable to, the taxation authority, are classified as operating
cash flows.
SIGNIFICANT ACCOUNTING JUDGEMENTS, ESTIMATES AND ASSUMPTIONS
The Group has a Tax Risk Management Framework which outlines how the direct and indirect tax obligations of Cooper
Energy Limited are met from an operational, governance and tax risk management perspective.
Management judgements are made in relation to the types of arrangements considered to be a tax on income, including
PRRT, in contrast to an operating cost.
Judgement is also made in assessing whether deferred tax assets and certain deferred tax liabilities are recognised on the
Consolidated Statement of Financial Position. Deferred tax assets, including those arising from un-recouped tax losses,
capital losses, and temporary differences arising from the PRRT legislation, are recognised only where it is considered more
probable they will be recovered, which is dependent on the generation of sufficient future taxable profits. Future taxable
profits are estimated by using Board approved internal budgets and forecasts.
Judgements are also required about the application of income tax legislation. These judgements and assumptions are
subject to risk and uncertainty, hence there is a possibility changes in circumstances will alter expectation, which may impact
the amount of deferred tax assets and deferred tax liabilities recognised on the Consolidated Statement of Financial Position
and the amount of other tax losses and temporary differences not yet recognised.
In such circumstances, some or all of the carrying amounts of recognised deferred tax assets and liabilities may require
adjustment, resulting in a corresponding credit or charge to the Consolidated Statement of Comprehensive Income.
4. EARNINGS PER SHARE
The following reflects the net loss and share data used in the calculations of earnings per share:
2024
$’000
2023
(restated)
$’000
Net loss after tax attributable to shareholders
(114,109)
(60,492)
2024
Thousands
2023
Thousands
Weighted average number of ordinary shares used in calculating basic earnings per
share
2,636,076
2,621,292
Dilutive performance rights and share appreciation rights1
-
-
Weighted average number of ordinary shares used in calculating dilutive earnings per
share
2,636,076
2,621,292
Basic loss per share for the period (cents per share)
(4.3)
(2.3)
Diluted loss per share for the period (cents per share)
(4.3)
(2.3)
1 The weighted average number of potentially dilutive shares at 30 June 2024 is 47.3 million (2023: 28.9 million)
At 30 June 2024 there exist performance rights and share appreciation rights that if vested, would result in the issue of
additional ordinary shares over the next three years. In the current period, these potential ordinary shares are considered
antidilutive as their conversion to ordinary shares would reduce the loss per share. Accordingly, they have been excluded from
the dilutive earnings per share calculation. There have been no other transactions involving ordinary shares, or potential
ordinary shares, between the reporting date and the date of completion of these financial statements.
ACCOUNTING POLICY
Basic earnings per share are calculated as net profit attributable to shareholders divided by the weighted average number of
ordinary shares. Diluted earnings per share is calculated as net profit attributable to shareholders divided by the weighted
average number of ordinary shares and dilutive potential ordinary shares.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
ACCOUNTING POLICY
Basic earnings per share are calculated as net profit attributable to shareholders divided by the weighted average number
of ordinary shares. Diluted earnings per share is calculated as net profit attributable to shareholders divided by the weighted
average number of ordinary shares and dilutive potential ordinary shares.
111
112
For the year ended 30 June 2024
For the year ended 30 June 2024
WORKING CAPITAL
5. CASH AND CASH EQUIVALENTS AND TERM DEPOSITS
2024
$’000
2023
(restated)
$’000
Current Assets
Cash at bank and in hand
14,332
77,134
Cash and cash equivalents
14,332
77,134
Reconciliation of net profit to net cash flows from operating activities
2024
$’000
2023
$’000
Net loss after tax
(114,109)
(60,492)
Add/(deduct) non-cash items:
Amortisation of gas and oil assets
58,214
58,654
Depreciation of property, plant and equipment
38,788
37,566
Amortisation of intangibles
534
1,485
Depreciation of right-of-use assets
1,263
1,119
Impairment expense
269
26,118
Exploration and evaluation expense
3,652
-
Restoration (income)/expense
86,790
46,343
Share based payments
3,681
7,667
Finance costs
19,174
16,850
Foreign exchange (gain)/loss
2,102
(705)
Other non-cash movements
23,408
(532)
Net cash from operating activities before changes in assets or liabilities
123,766
134,073
Add/(deduct) changes in operating assets or liabilities:
Increase in trade and other receivables
(29,707)
(1,406)
Decrease/(increase) in inventories
138
(1,340)
(Increase)/decrease in prepayments
(305)
6,527
Increase in deferred taxes
(10,830)
(45,527)
Increase/(decrease) in trade and other payables
29,778
(6,331)
Decrease in provisions
(212,603)
(23,232)
Net cash from operating activities
(99,763)
62,764
Reconciliation of liabilities arising from financing activities
Borrowings
Lease Liabilities
2024
$’000
2023
$’000
2024
$’000
2023
$’000
Balance at beginning of period
143,956
158,000
10,649
10,863
Financing cash flows1
107,000
(15,142)
(1,457)
(1,262)
Other
2,191
1,098
(7,418)
1,048
Balance at end of period
253,147
143,956
1,774
10,649
1 Financing cash flows consist of: for borrowings, the net amount of proceeds from borrowings and transaction costs associated with borrowings, and for lease
liabilities, repayment of lease liabilities in the statement of cash flows.
ACCOUNTING POLICY
Cash and cash equivalents in the Consolidated Statement of Financial Position comprise cash at bank and short-term deposits
for periods of up to three months or subject to insignificant changes in value. For the purposes of the Statement of Cash Flows,
cash and cash equivalents includes cash and term deposits as defined above, net of outstanding bank overdrafts.
Cash held in escrow with associated restrictions, whereby the Group cannot use that cash for operational purposes as it deems
appropriate, is not included in cash and cash equivalents.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
ACCOUNTING POLICY
Cash and cash equivalents in the Consolidated Statement of Financial Position comprise cash at bank and short-term deposits for
periods of up to three months or subject to insignificant changes in value. For the purposes of the Statement of Cash Flows, cash
and cash equivalents includes cash and term deposits as defined above, net of outstanding bank overdrafts.
Cash held in escrow with associated restrictions, whereby the Group cannot use that cash for operational purposes as it
deems appropriate, is not included in cash and cash equivalents.
6. TRADE AND OTHER RECEIVABLES
2024
$’000
2023
$’000
Current Assets
Trade and other receivables
13,243
11,360
Accrued revenue
21,895
17,247
Interest receivable
71
190
35,209
28,797
Expected credit losses in respect of trade and other receivables is set out in Note 20.
ACCOUNTING POLICY
Trade receivables are non-interest bearing and generally have an average of 35 day terms. Trade receivables are initially
recognised at the transaction price as defined by AASB 15 Revenue from Contracts with Customers and subsequently carried
at amortised cost less any allowances for expected credit loss. An allowance for expected credit loss is recognised using the
simplified approach which permits the use of the lifetime expected loss provision for all trade receivables. Bad debts are written
off when identified.
7.
PREPAYMENTS
2024
$’000
2023
$’000
Insurance
3,752
4,229
Prepaid cash calls to joint arrangements
1,747
1,970
Other prepayments
565
104
6,064
6,303
8.
INVENTORY
2024
$’000
2023
$’000
Petroleum products
426
966
Spares and parts
1,618
1,216
2,044
2,182
All inventory items are carried at cost in the current and previous financial years.
ACCOUNTING POLICY
Inventories are carried at the lower of their cost or net realisable value. Inventories held by the Group are in respect of unsold
oil and spares and parts involved in drilling operations. Items held as insurance or capital spares are treated as part of property,
plant and equipment.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
ACCOUNTING POLICY
Inventories are carried at the lower of their cost or net realisable value. Inventories held by the Group are in respect of unsold oil
and spares and parts involved in drilling operations. Items held as insurance or capital spares are treated as part of property,
plant and equipment.
ACCOUNTING POLICY
Trade payables are non-interest bearing and carried at amortised cost. The amounts represent liabilities for goods and services
provided during the financial year, but not yet settled at the balance sheet date. Accruals represent unbilled goods or services.
ACCOUNTING POLICY
Trade receivables are non-interest bearing and generally have an average of 35 day terms. Trade receivables are initially recognised
at the transaction price as defined by AASB 15 Revenue from Contracts with Customers and subsequently carried at amortised cost
less any allowances for expected credit loss. An allowance for expected credit loss is recognised using the simplified approach
which permits the use of the lifetime expected loss provision for all trade receivables. Bad debts are written off when identified.
9.
TRADE AND OTHER PAYABLES
2024
$’000
2023
$’000
Current
Trade payables
29,531
6,411
Accruals (capital and operating expenditure)
27,242
22,268
Deferred consideration1
20,000
40,000
76,773
68,679
Non-Current
Deferred consideration1
-
19,262
1 Deferred consideration represents the fixed payments due 12 and 24 months after the 28 July 2022 financial close of the OGPP acquisition. The Group records
deferred consideration at the present value of consideration payments.
113
114
For the year ended 30 June 2024
For the year ended 30 June 2024
CAPITAL EMPLOYED
10.
PROPERTY, PLANT AND EQUIPMENT
Production assets
Corporate assets
Total
2024
$’000
2023
$’000
2024
$’000
2023
$’000
2024
$’000
2023
$’000
Reconciliation of carrying amounts at beginning
and end of period:
Carrying amount at beginning of period
377,382
55,928
2,993
3,304
380,375
59,232
Assets acquired1
-
374,016
-
-
-
374,016
Additions
5,607
10,724
354
402
5,961
11,126
Restoration
(1,228)
(20,489)
-
-
(1,228)
(20,489)
Impairment
-
(5,944)
-
-
-
(5,944)
Depreciation
(38,043)
(36,853)
(745)
(713)
(38,788)
(37,566)
Carrying amount at end of period
343,718
377,382
2,602
2,993
346,320
380,375
Cost
423,996
419,617
8,468
8,114
432,464
427,731
Accumulated depreciation
(80,278)
(42,235)
(5,866)
(5,121)
(86,144)
(47,356)
Carrying amount at end of period
343,718
377,382
2,602
2,993
346,320
380,375
1 The acquisition of OGPP includes $210.0 million of upfront consideration, $58.1 million deferred consideration (discounted at the acquisition date from the
undiscounted, or nominal, total of $60.0 million), $27.0 million capitalised acquisition and transaction costs and $78.9 million in relation to the restoration obligations
acquired. $40.0 million of the undiscounted deferred consideration was paid in July 2023 (on the 12-month anniversary following the 28 July 2022 financial close)
and is included within payments for property, plant and equipment in the Consolidated Statement of Cash Flows.
ACCOUNTING POLICY
Property, plant and equipment comprises office and IT equipment, leasehold improvements, the OGPP and the Athena Gas
Plant, and are stated at historical cost less accumulated depreciation and any accumulated impairment losses (refer to Note 14
for a description of the Company’s impairment policy). Historical cost includes expenditure that is directly attributable to the
acquisition of the items. 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 Group and the cost of
the item can be measured reliably. Repairs and maintenance are recognised in the Consolidated Statement of Comprehensive
Income, as incurred.
Depreciation on property plant and equipment is calculated at between 7.5% and 37.5% per annum using the diminishing value
method over the respective asset’s estimated useful live. Production assets are depreciated on a units of production basis. The
assets’ residual values and useful lives are reviewed and adjusted, if appropriate, at each reporting date.
An item of property, plant and equipment is derecognised upon disposal, or when no further future economic benefits are
expected from its use. Any gains or losses arising on derecognition of the asset (calculated as the difference between the net
disposal proceeds and the net carrying amount of the asset) is included in the Consolidated Statement of Comprehensive
Income.
11.
INTANGIBLE ASSETS
2024
$’000
2023
$’000
Reconciliation of carrying amounts at beginning and end of period:
Carrying amount at beginning of period
967
1,360
Additions
482
1,092
Disposals
(449)
-
Amortisation
(534)
(1,485)
Carrying amount at end of period
466
967
Cost
4,427
4,394
Accumulated amortisation
(3,961)
(3,427)
Carrying amount at end of period
466
967
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
ACCOUNTING POLICY
Property, plant and equipment comprises office and IT equipment, leasehold improvements, the OGPP and the Athena Gas Plant,
and are stated at historical cost less accumulated depreciation and any accumulated impairment losses (refer to Note 14 for a
description of the Company’s impairment policy). Historical cost includes expenditure that is directly attributable to the acquisition
of the items. 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 Group and the cost of the item can
be measured reliably. Repairs and maintenance are recognised in the Consolidated Statement of Comprehensive Income, as
incurred.
Depreciation on property plant and equipment is calculated at between 7.5% and 37.5% per annum using the diminishing value
method over the respective asset’s estimated useful live. Production assets are depreciated on a units of production basis. The
assets’ residual values and useful lives are reviewed and adjusted, if appropriate, at each reporting date.
An item of property, plant and equipment is derecognised upon disposal, or when no further future economic benefits are expected
from its use. Any gains or losses arising on derecognition of the asset (calculated as the difference between the net disposal
proceeds and the net carrying amount of the asset) is included in the Consolidated Statement of Comprehensive Income.
11. INTANGIBLE ASSETS CONTINUED
ACCOUNTING POLICY
Intangible assets comprise software and carbon credits, and are stated at historical cost less accumulated amortisation and any
accumulated impairment losses where applicable. Historical cost includes expenditure that is directly attributable to the
acquisition of the items. Intangible assets are determined to have a finite useful life and are amortised over their useful lives
and tested for impairment whenever there is an indicator of impairment. Amortisation on intangibles is calculated at 20% per
annum using the straight line method. The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at
each reporting date.
12.
EXPLORATION AND EVALUATION ASSETS
Notes
2024
$’000
2023
$’000
Reconciliation of carrying amounts at beginning and end of period
Carrying amount at beginning of period
184,569
164,909
Additions1
14,545
25,088
Restoration
(225)
(267)
Impairment
14
(269)
(5,161)
Exploration and evaluation expense
(3,652)
-
Transfer to gas and oil assets
(1,163)
-
Carrying amount at end of period2
193,805
184,569
1Additions in 2024 predominantly relate to PEL 92 exploration drilling and the order of the first subsea tree for the East Coast Supply Project (ECSP). Additions in
2023 relate to ECSP and licensing and interpretation of 3D seismic data in Gippsland Basin.
2 Recoverability is dependent on the successful development and commercial exploration or sale of the respective areas of interest.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
ACCOUNTING POLICY
Exploration and evaluation expenditure include costs incurred in the search for hydrocarbon resources and determining the
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 Group 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:
a. reached a stage which permits a reasonable assessment of the existence or otherwise of economically recoverable
reserves; and
b. 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 a natural gas or an oil field is considered
favourable or has been proven to exist and, in most cases, comprises an individual prospective gas or oil 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 Consolidated Statement of Financial Position as long as sufficient progress is being made in assessing the reserves
and the economic and operating viability of the project. Any appraisal costs relating to determining commercial feasibility are
also capitalised as exploration and evaluation assets. 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 facts and circumstances suggest that the carrying amount exceeds the recoverable amount, or where one of the specific
factors set out in i-iii above are no longer met, the Group will test for impairment in accordance with the impairment policy
stated in Note 14.
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 gas or oil field enters the development phase, the accumulated exploration and evaluation expenditure is tested for
impairment and then transferred to gas and oil assets.
ACCOUNTING POLICY
Intangible assets comprise software and carbon credits, and are stated at historical cost less accumulated amortisation and any
accumulated impairment losses where applicable. Historical cost includes expenditure that is directly attributable to the acquisition
of the items. Intangible assets are determined to have a finite useful life and are amortised over their useful lives and tested for
impairment whenever there is an indicator of impairment. Amortisation on intangibles is calculated at 20% per annum using the
straight line method. The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at each reporting date.
115
116
For the year ended 30 June 2024
For the year ended 30 June 2024
13.
GAS AND OIL ASSETS
Notes
2024
$’000
2023
$’000
Reconciliation of carrying amounts at beginning and end of period:
Carrying amount at beginning of period
535,842
595,347
Additions
2,932
4,675
Restoration1
(6,571)
9,487
Transferred from exploration and evaluation
1,163
-
Amortisation
(58,214)
(58,654)
Impairment
14
-
(15,013)
Carrying amount at end of period
475,152
535,842
Cost
837,422
839,898
Accumulated amortisation & impairment
(362,270)
(304,056)
Carrying amount at end of period
475,152
535,842
1 Updates to restoration provisions have resulted in a reduction in oil and gas assets in 2024
ACCOUNTING POLICY
Gas and oil assets are carried at cost including construction, installation of infrastructure such as roads, pipelines or umbilicals,
and the cost of development of wells.
Any restoration assets arising as a result of recognition of a restoration provision are also included in the carrying amount of gas
and oil assets. 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 Group and the cost of the item can
be measured reliably. All other repairs and maintenance are charged to the Consolidated Statement of Comprehensive Income
as incurred.
Gas and oil assets are amortised on a units-of-production basis, using the latest approved estimate of reserves and future
development cost estimates. Amortisation is charged only once production has commenced. No amortisation is charged on
areas under development where production has not commenced. Gas and oil assets are subject to impairment testing, refer to
Note 14.
SIGNIFICANT ACCOUNTING JUDGEMENTS, ESTIMATES AND ASSUMPTIONS
Estimation of gas and oil asset expenditure
Capitalised gas and oil assets for the construction of major projects or ongoing well construction activities include accruals in
relation to the value of work done. These remain estimates until the contractual arrangement is finalised, including any rebates,
credits and variations as part of the standard contractual process.
Amortisation of gas and oil assets
The amortisation of gas and oil assets is impacted by management’s estimates of reserves and future development costs.
Refer to the significant accounting judgements, estimates and assumptions section on page 51 in relation to reserves. Future
development cost estimates are costs necessary to develop an assets’ undeveloped 2P reserves. These costs are subject to
changes in technology, regulation and other external factors.
Significant accounting judgements, estimates and assumptions are also made in relation to the impairment of gas and oil assets
and recognition of restoration assets, refer to Note 14 and Note 15 respectively.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
ACCOUNTING POLICY
Gas and oil assets are carried at cost including construction, installation of infrastructure such as roads, pipelines or umbilicals,
and the cost of development of wells.
Any restoration assets arising as a result of recognition of a restoration provision are also included in the carrying amount of
gas and oil assets. 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 Group and the
cost of the item can be measured reliably. All other repairs and maintenance are charged to the Consolidated Statement of
Comprehensive Income as incurred.
Gas and oil assets are amortised on a units-of-production basis, using the latest approved estimate of reserves and future
development cost estimates. Amortisation is charged only once production has commenced. No amortisation is charged on areas
under development where production has not commenced. Gas and oil assets are subject to impairment testing, refer to Note 14.
SIGNIFICANT ACCOUNTING JUDGEMENTS, ESTIMATES AND ASSUMPTIONS
Estimation of gas and oil asset expenditure
Capitalised gas and oil assets for the construction of major projects or ongoing well construction activities include accruals in
relation to the value of work done. These remain estimates until the contractual arrangement is finalised, including any rebates,
credits and variations as part of the standard contractual process.
Amortisation of gas and oil assets
The amortisation of gas and oil assets is impacted by management’s estimates of reserves and future development costs.
Refer to the significant accounting judgements, estimates and assumptions section on page 102-103 in relation to reserves.
Future development cost estimates are costs necessary to develop an assets’ undeveloped 2P reserves. These costs are subject
to changes in technology, regulation and other external factors.
Significant accounting judgements, estimates and assumptions are also made in relation to the impairment of gas and oil assets
and recognition of restoration assets, refer to Note 14 and Note 15 respectively.
14.
IMPAIRMENT
2024
$’000
2023
$’000
Exploration and evaluation assets
269
5,161
Property, plant & equipment
-
5,944
Gas and oil assets
-
15,013
Total impairment recognised
269
26,118
The impairment losses recognised in the 2024 financial
year relate to one of the Group’s exploration licences being
fully impaired in accordance with AASB 6 Exploration
for and Evaluation of Mineral Resources (refer also
to Note 12).
During the year, the Group’s gas and oil assets and
property, plant and equipment were assessed for
impairment indicators in accordance with AASB 136
Impairment of Assets. There were no impairment indicators
present, therefore no impairment was recognised.
In the previous financial year, indicators of impairment
were present for the Casino Henry Netherby cash
generating unit (“CGU”), resulting in a non-cash impairment
loss recognised at June 2023.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
ACCOUNTING POLICY
The carrying values of non-current assets, including, property, plant and equipment, capitalised exploration and evaluation assets,
and gas and oil assets, are assessed for indicators of impairment at each reporting date (every six months). Where indicators of
impairment are present, an impairment test is performed.
An impairment loss is recognised for the amount by which the asset or CGU’s carrying amount exceeds its recoverable amount.
The recoverable amount of a non-current asset or CGU is the higher of value in use (“VIU”) and fair value less cost of disposal
(“FVLCD”). For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately
identifiable cash flows. In assessing VIU, the estimated future cash flows are discounted to their present value using a pre-tax rate
that reflects the risks specific to the asset. Where the recoverable amount is based on FVLCD, a discounted cash flow model is also
used and the inputs are consistent with level 3 on the fair value hierarchy. The estimated future cash flows are prepared on a real (no
estimates for future inflation) basis and discounted to their present value using a pre-tax rate that reflects current market assessments
of the time value of money and the risks specific to the asset that would be taken into account by an independent market participant.
SIGNIFICANT ACCOUNTING JUDGEMENTS, ESTIMATES AND ASSUMPTIONS
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 Group 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.
Impairment of exploration and evaluation assets and gas and oil assets
The Group reviews the carrying amount of gas and oil assets at each reporting date (every six months), starting with an analysis
of any indicators of impairment. Where relevant this may involve the preparation of trigger test modelling, for certain CGUs, to
determine if any indicators of impairment are present. Where indicators of impairment are present, the Group will test whether
the CGU’s recoverable amount exceeds its carrying amount, with reference to formal impairment models where discounted cash
flow models are used to assess the recoverable amount. Relevant items of working capital and property, plant and equipment are
allocated to CGUs when testing for impairment.
The estimated expected cash flows used in the discounted cash flow model are based on management’s best estimate of the
future production of reserves and sales volumes, commodity prices, foreign exchange rates, development expenditure in order to
access the reserves, and operating expenditure. Estimates of future commodity prices are based on the Group’s best estimate of
future market prices with reference to external brokers, market data and futures prices. Future commodity prices are reviewed at
least annually. Where volumes are contracted, future prices are based on the contracted price.
117
118
For the year ended 30 June 2024
For the year ended 30 June 2024
15. PROVISIONS
2024
$’000
2023
$’000
Current Liabilities
Employee benefits
4,265
4,547
Restoration provisions
28,655
161,551
32,920
166,098
Non-Current Liabilities
Employee benefits
1,207
763
Restoration provisions
432,513
416,746
433,720
417,509
2024
$’000
2023
$’000
Movement in carrying amount of the current restoration provision:
Carrying amount at beginning of period
161,551
26,957
Restoration expenditure incurred1
(212,764)
(25,720)
Changes in provisions2
55,710
33,600
Transferred from non-current provisions
24,158
126,714
Carrying amount at end of period
28,655
161,551
Movement in carrying amount of the non-current restoration provision:
Carrying amount at beginning of period
416,746
446,359
Provisions acquired
-
78,887
Changes in provisions2
23,055
1,474
Transferred to current provisions
(24,158)
(126,714)
Increase through accretion
16,870
16,740
Carrying amount at end of period
432,513
416,746
1 Majority of the expenditure incurred in 2024 relates to the BMG wells decommissioning programme.
2 Changes in provisions arise from a combination of changes to estimates of the cost to undertake restoration activities, changes to the estimated time periods
during which restoration activity is forecast to occur, changes to assumed future rates of inflation to forecast future expected costs and changes to assumed discount
rates to discount future expected costs to derive the present value included here within the restoration provision. Changes to estimates of the costs to undertake
restoration activities arise from changes to the assumed scope of activity based on current planning for abandonment and remediation work, changes in the
regulatory requirements and also arise from the current cost environment which, in some cases, have led to an increase to service costs.
The discount rate used in the calculation of the provisions
as at 30 June 2024 ranged from 4.10% to 4.31% (2023:
3.49% to 5.65%) reflecting a risk-free rate that aligns to the
timing of restoration obligations. The movement in the risk-
free rate reflects the change in Australian and US
government bond rates since the last assessment. Inflation
rate assumptions applied in the calculation of the provision
as at 30 June 2024 ranged from 2.0% to 3.15% (2023:
2.0% to 3.75%).
From 2009 until 2014, Pertamina Hulu Energi Australia Pty
Limited (“Pertamina Australia”), a wholly owned subsidiary
of PT Pertamina Hulu Energi (“Pertamina”), held a 10%
interest in the BMG joint operating and production
agreement (“JOA”). In October 2013, Pertamina Australia
withdrew from the JOA. A claim against Pertamina was
filed by Cooper Energy in the Supreme Court of Victoria
(the “Court”), in December 2022, seeking payment of an
amount equal to 10% of the costs and expenses of the
decommissioning operations incurred and to be incurred,
pursuant to Pertamina Australia’s obligations under the
withdrawal and abandonment provisions of the JOA.
Pertamina has been ordered by the Court to file its defence
in September 2024.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
ACCOUNTING POLICY
Provisions are recognised when the Group has a legal or constructive obligation, as a result of past transactions or other past
events, and it is probable that a future sacrifice of economic benefits will be required and that a reliable estimate can be made of
the amount of the obligation.
Employee benefits
Liabilities for wages and salaries, including non-monetary benefits and annual leave are recognised in respect of employees’
services up to the reporting date and are measured at the amount expected to be paid when the liabilities are settled. Expenses
for non-accumulating sick leave are recognised when the leave is taken and are measured at the rates paid or payable.
The provision for long service leave is recognised and measured as the present value of expected future payments to be made,
in respect of services provided by employees up to the reporting date, using the projected unit credit method. Consideration is
given to expected future wage and salary levels, years of experience of departed employees, and periods of service.
15. PROVISIONS CONTINUED
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
SIGNIFICANT ACCOUNTING JUDGEMENTS, ESTIMATES AND ASSUMPTIONS
Provisions for restoration costs
Decommissioning and restoration costs are a normal consequence of gas and oil extraction and the majority of this expenditure
is incurred at the end of a field’s life, many years in the future. In determining an appropriate level of provision, assumptions are
made as to the expected future costs to be incurred, the timing of these expected future costs (largely dependent on the life of the
field), and the estimated future level of inflation.
The ultimate cost of decommissioning and restoration is uncertain and these costs can vary in response to many factors. These
factors include the extent of restoration required due to changes to the relevant legal or regulatory requirements, the emergence of
new restoration techniques or experience at other fields, and prevailing service costs.
The expected timing of expenditure can also change, for example in response to changes in gas and oil reserves or to
production rates.
Provisions for restoration costs are based on the Company’s best estimates based on the information available at the time.
Changes to any of the estimates could result in significant changes to the amount of the provision recognised, which would in turn
impact future financial results.
The Group’s restoration provision includes the following costs:
• for onshore projects, provision has been made for the demolition and removal of all onshore production facilities, removal of
contaminated soil, and revegetation of the affected area. Other plant and equipment restoration may include estimates for
compensating landowners and the acquisition of land, in line with the requirements of the relevant regulatory authority;
• for offshore assets, provision has been made for the removal of subsea trees and manifolds and removal of flowlines and
umbilicals to a certain distance from shore and at a certain depth of water. This includes an assumption that all offshore materials
that are constructed using plastics are to be fully removed; and
• offshore pipelines that are constructed from steel and concrete are assumed to remain in-situ, where it can be demonstrated
that this will result in a net environmental benefit compared to full removal and where regulatory approval is anticipated to be
obtained. Offshore pipelines that are constructed from steel and concrete have previously been accepted by the Australian
regulator to be decommissioned in-situ, where it has been demonstrated that this will result in a net environmental benefit,
compared to full removal.
Expected future payments are discounted using market yields at the reporting date based on high quality corporate bonds with
terms of maturity and currencies that match, as closely as possible, the estimated future cash outflows.
Employees’ accumulated long service leave is ascribed to individual employees at the rates payable as and when they become
entitled to long service leave.
A provision for bonus is recognised and measured based upon the current wage and salary level and forms part of the employee
short term incentive plan. The basis for the bonus relating to Key Management Personnel is set out in the Remuneration Report.
Restoration
The Group records a restoration provision for the present value of its share of the estimated cost to restore its sites. The nature of
restoration activities includes the obligations relating to the reclamation, waste site closure, plant closure, production facility removal
and other costs associated with the restoration of the site. Risks associated with climate change are factored into forecast timing of
restoration activities and will continue to be monitored.
A restoration provision is recognised upon commencement of construction and then reviewed every six months at each reporting
date. When the liability is recorded, the carrying amount of the production or exploration asset is increased by the same amount
and is depreciated over the remaining producing life of the asset. The movement is recorded as a restoration expense when there
is no asset recorded. Over time, the liability is increased for the change in the present value based on a risk-free discount rate and
the discount unwind is recorded as an accretion charge within finance costs.
Any changes in the estimate of the provision for restoration arising from changes in the gross cost estimate or changes in the
discount rate of the restoration provision are recorded by adjusting the provision and the carrying amount of the production or
exploration asset, to the extent that it is appropriate to recognise an asset under accounting standards, and then depreciated over
the remaining producing life of the asset. Where it is not appropriate to recognise an asset, changes will immediately be recorded
through profit or loss. Any change in assumptions is applied prospectively. These estimated costs are based on current technology
available, State, Federal and international legislation, and industry practice.
119
120
For the year ended 30 June 2024
For the year ended 30 June 2024
15. PROVISIONS CONTINUED
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
No assumption is made regarding the potential residual value for the onshore production facilities, nor regarding the potential to
repurpose any of the onshore and offshore infrastructure and wells (e.g. potential to convert to gas storage and processing, or for
carbon capture and storage).
The Group estimates the future abandonment and restoration costs at different phases in an asset’s lifecycle, which in many
instances occurs many years into the future. The provisions reflect the Group’s best estimate based on current knowledge and
information, however further planning and technical analysis of the restoration activities for individual assets will be performed near
the end of field life and/or when detailed decommissioning plans are required to be submitted to the relevant regulatory authorities.
Actual abandonment and restoration costs can materially differ from the current estimate as a result of changes in regulations and
their application, service costs, site conditions, timing of restoration and changes in removal technology. These uncertainties may
result in abandonment and restoration costs differing from amounts included in the provision recognised as at 30 June 2024.
In the event that the removal of all pipelines was required, the Group estimates the additional cost would lead to an increase to the
provision of approximately $20.0 - $50.0 million. The Group’s provision in respect of the Sole Gas Project is based on estimated
cessation of production of the fields and timing of abandonment activities is linked to NOPSEMA’s restoration guidance. It is
intended that existing infrastructure at Sole will be utilised in a future Manta development. This has not been factored into the
provision calculations and would therefore extend the timing of these abandonment activities.
16. LEASES
THE GROUP AS A LESSEE
The Group has lease contracts for properties with remaining lease terms of between 1 month to 6 years and fixed monthly
payments. The Group also has certain leases with lease terms of 12 months or less and low value leases.
RIGHT-OF-USE ASSETS
2024
$’000
2023
$’000
Reconciliation of carrying amounts at beginning and end of period:
Carrying amount at beginning of period
7,448
7,520
Addition
-
1,047
Reset1
(4,805)
-
Depreciation
(1,263)
(1,119)
Carrying amount at end of period
1,380
7,448
Cost
7,101
11,905
Accumulated depreciation
(5,721)
(4,457)
Carrying amount at end of period
1,380
7,448
1 Adjustment due to change in lease term of the corporate offices
LEASE LIABILITIES
2024
$’000
2023
$’000
Reconciliation of carrying amounts at beginning and end of period:
Carrying amount at beginning of period
10,649
10,863
Addition
-
1,047
Reset1
(7,418)
-
Accretion of interest
523
495
Payments
(1,980)
(1,756)
Carrying amount at end of period
1,774
10,649
1 Adjustment due to change in lease term of the corporate offices
Current
847
1,467
Non-Current
927
9,182
16. LEASES CONTINUED
Short-term and low-value lease asset exemptions
For the year ending 30 June 2024, the following expense has been recognised in the Statement of Comprehensive Income for
lease arrangements that have been classified as short-term leases or low-value assets.
2024
$’000
2023
$’000
Short-term leases
41,441
9,238
Leases for low-value assets
28
176
Total expense recognised
41,469
9,414
The Group had total cash outflows for leases of $43.5 million (2023: $11.2 million), inclusive of short-term leases and leases for
low-value assets.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
ACCOUNTING POLICY
The Group recognises right-of-use assets, and corresponding lease liabilities, at the commencement date of the lease (the date the
underlying asset is available for use).
Right-of-use assets are initially measured at a value equal to the respective lease liability, adjusted for any initial direct costs
incurred, and lease payments made at or before the commencement date, less any lease incentives received. Subsequently,
right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any
remeasurement of lease liabilities. Property right-of-use assets are depreciated on a straight-line basis over the shorter of
estimated useful life and the respective lease term. Right-of-use assets are also allocated to CGUs when testing for impairment
(refer to Note 14). Lease liabilities are excluded from the carrying amount of a CGU.
At the commencement date of the lease, the Group recognises lease liabilities measured as the present value of lease payments
to be made over the lease term. In calculating the present value of lease payments, the Group uses the incremental borrowing
rate at the lease commencement date, if the interest rate implicit in the lease is not readily determinable. Subsequent to initial
measurement, the amount of lease liabilities is increased to reflect the accretion of interest and reduced for the lease payments
made. The carrying amount of lease liabilities is remeasured if there is a modification, a change in the lease term, a change in the
fixed lease payments, or a change in the assessment to purchase the underlying asset.
The Group applies the short-term lease recognition exemption to its short-term leases (those leases that have a lease term of 12
months or less, from the commencement date, and do not contain a purchase option). It also applies the lease of low-value assets
recognition exemption to leases of office equipment that are considered of low value (below $10,000). Lease payments on short-
term leases and leases of low-value assets are recognised as an expense on a straight-line basis over the lease term.
SIGNIFICANT ACCOUNTING JUDGEMENTS, ESTIMATES AND ASSUMPTIONS
Lease term of contracts with renewal options
The Group determines the lease term as the non-cancellable term of the lease, together with any periods covered by an option to
extend the lease, if the option is reasonably certain to be exercised. The Group has the option, under some of its leases, to lease
the assets for additional terms of three to five years. The Group applies judgement in evaluating whether it is reasonably certain to
exercise the option to renew. The Group continues to reassess the lease over its term to determine if there is a significant event or
change in circumstances that would impact the renewal decision. The Group has included the renewal period as part of the lease
term for its property leases, where relevant.
121
122
For the year ended 30 June 2024
For the year ended 30 June 2024
FUNDING AND RISK MANAGEMENT
17.
INTEREST BEARING LOANS AND BORROWINGS
2024
$’000
2023
$’000
Non-current bank debt1
253,147
143,956
1 Net of capitalised transaction costs of $11.9 million (2023: $14.0 million).
Cooper Energy has a $400.0 million senior secured reserve-based lending facility, secured across a portfolio of producing
assets, and a senior secured $20.0 million working capital facility. It is expected that the facility will be utilised to part fund the
planned ECSP project in the Otway Basin. Cooper Energy is in compliance with all covenants at 30 June 2024. A summary of
the Group’s secured facilities is included below.
Facility
Senior secured reserve based lending facility
Working Capital Facility
Currency
Australian dollars
Australian Dollars
Limit
$400.0 million1 (2023: $400.0 million)
$20.0 million (2023: $20.0 million)
Utilised amount
$265.0 million (2023: $158.0 million)
$7.4 million4 (2023: $7.7 million)
Accounting balance
$253.1 million (2023: $144.0 million)
Nil (2023: Nil)
Effective interest rate2
9.46% floating
Nil
Maturity3
30 September 20273
10 August 2025
1 As at 30 June 2024, $135.0 million of the facility limit of $400.0 million remains available. Availability of funds under the facility remains subject to an annual
redetermination, and a facility reduction schedule commencing in FY25 (reducing to $180.0 million at 30 September 2027).
2 Effective interest rate is the rate that discounts the estimated future drawdowns and repayments through the expected life of the facility, including the upfront
capitalised transaction costs.
3 Based on the facility reduction schedule, the reserves profile of the borrowing base assets and the facility maturity date.
4 As at 30 June 2024, no cash amounts have been drawn, $7.4 million has been utilised by way of bank guarantees.
ACCOUNTING POLICY
Borrowings are recognised initially at fair value net of directly attributable transaction costs. Subsequent to initial recognition,
borrowings are stated at amortised cost, with any difference between cost and redemption value being recognised in profit or
loss over the period of the borrowings on an effective interest basis. Transaction costs are capitalised initially and included in
the effective interest rate calculation and unwound over the expected term of the facility.
Borrowings are classified as current liabilities unless the Group has a right to defer the settlement of the liability for at least 12
months after the end of the reporting period. Interest expense is recognised as interest accrues, using the effective interest rate
and if not paid at balance date, is reflected in the balance sheet as a payable.
18.
NET FINANCE COSTS
2024
$’000
2023
$’000
Finance Income
Interest income
3,484
3,019
Finance Costs
Unwind discount on liabilities
(17,721)
(17,974)
Finance costs associated with lease liabilities
(523)
(495)
Interest expense
(17,975)
(11,027)
Total finance costs
(36,219)
(29,496)
Net finance costs
(32,735)
(26,477)
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
ACCOUNTING POLICY
Borrowings are recognised initially at fair value net of directly attributable transaction costs. Subsequent to initial recognition,
borrowings are stated at amortised cost, with any difference between cost and redemption value being recognised in profit or
loss over the period of the borrowings on an effective interest basis. Transaction costs are capitalised initially and included in the
effective interest rate calculation and unwound over the expected term of the facility.
Borrowings are classified as current liabilities unless the Group has a right to defer the settlement of the liability for at least 12
months after the end of the reporting period. Interest expense is recognised as interest accrues, using the effective interest rate
and if not paid at balance date, is reflected in the balance sheet as a payable.
ACCOUNTING POLICY
Interest earned is recognised in the Consolidated Statement of Comprehensive Income as finance income and is recognised as
interest accrues, using the effective interest rate. This is the rate that exactly discounts estimated future cash receipts through the
expected life of the financial instrument to the net carrying amount of the financial asset. Interest expense is capitalised to the cost
of a qualifying asset during the development phase.
19.
CONTRIBUTED EQUITY AND RESERVES
For the purposes of Group capital management, capital
includes issued capital and all other equity reserves
attributable to the equity holders of the parent entity.
The primary objective of the Group’s capital management
strategy is to maintain an appropriate capital profile to
support its business activities and to maximise
shareholder value.
At 30 June 2024, the Group has utilised $265.0 million of
its reserves based lending facility.
The Group manages its capital structure and makes
adjustments in light of economic conditions and within the
requirements of financial covenants. To maintain or adjust
the capital structure, the Group may adjust its dividend
policy, return capital to shareholders, issue new shares or
draw on debt. No changes were made in the objectives,
policies or processes during the current and prior period.
SHARE CAPITAL
2024
$’000
2023
$’000
Ordinary shares issued and fully paid
718,881
716,726
2024
2023
Thousands
$’000
Thousands
$’000
Movement in ordinary shares on issue
At 1 July
2,631,530
716,726
1,632,734
478,261
Equity issue1
-
-
248,855
58,596
Transfer from reserves2
-
-
747,097
179,508
Issuance of shares for performance rights
and share appreciation rights
8,507
2,155
2,844
361
At 30 June
2,640,037
718,881
2,631,530
716,726
1In July 2022, the group raised $58.6 million (net of $2.4 million after tax costs) via the retail portion of the ANREO, being the second component of the 2022 equity
raising. The first component comprised the institutional portion of the ANREO plus an institutional placement, with the combined cash from this first component
received in June 2022. The retail portion of the ANREO resulted in the issuance of 248.9 million shares on 14 July 2022.
2At the end of June 2022, the group raised $179.5 million (net of $3.5 million after tax costs) via the institutional portion of the ANREO plus an institutional
placement, being the first component of the 2022 equity raising. The second component comprised the retail portion of the ANREO which completed in July.
While the total cash from the combination of the institutional portion of the ANREO and the institutional placement was received at the end of June 2022, the
resulting 747.1 million shares were issued on 1 July 2022. As a result, the institutional component of the 2022 equity raising was recorded within reserves at 30 June
2022 and subsequently transferred from reserves to equity in July 2022.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
ACCOUNTING POLICY
Issued and paid up capital is recognised as the fair value of the consideration received by the Group. The shares issued do not
have a par value and there is no limit on the authorised share capital of the Group. Fully paid ordinary shares carry one vote per
share, which entitles the holder to participate in the proceeds on winding up of the Company in proportion to the number of, and
amounts paid on, the shares held.
Any transaction costs arising on the issue of ordinary shares that would not have been incurred had ordinary shares not been
issued, are recognised directly in equity as a reduction of the share proceeds received.
123
124
For the year ended 30 June 2024
For the year ended 30 June 2024
19. CONTRIBUTED EQUITY AND RESERVES CONTINUED
RESERVES
Share
capital
reserve
$’000
Consol.
Reserve
$’000
Share
based
payment
reserve
$’000
Option
premium
reserve
$’000
Equity
instruments
reserve
$’000
Total
$’000
Consolidated
At 30 June 2022
179,508
(541)
18,505
25
128
197,625
Other comprehensive income
-
-
-
-
648
648
Transferred to issued capital
(179,508)
-
(361)
-
-
(179,869)
Share-based payments
-
-
7,667
-
-
7,667
At 30 June 2023
-
(541)
25,811
25
776
26,071
Other comprehensive expenditure
-
-
-
-
(412)
(412)
Transferred to issued capital
-
-
(2,155)
-
-
(2,155)
Share-based payments
-
-
3,681
-
-
3,681
At 30 June 2024
-
(541)
27,337
25
364
27,185
NATURE AND PURPOSE OF RESERVES
Share capital reserve
This reserve is used to record receipts from equity
issuance, where the shares have not been formally issued.
This will be reclassified to share capital upon formal
share issue.
Consolidation reserve
This reserve comprises the premium paid on acquisition
of minority shareholdings in a controlled entity.
Share based payment reserve
This reserve is used to record the value of equity benefits
provided to employees, contractors and executive directors
as part of their remuneration.
Option premium reserve
This reserve is used to accumulate amounts received
from the issue of options. The reserve can be used to
pay dividends or issue bonus shares.
Equity instruments reserve
This reserve is used to capture the fair value movement
in the value of equity instruments designated at fair value
through Other Comprehensive Income. Items in this
reserve are never recycled through profit or loss.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
19.
20.
FINANCIAL RISK MANAGEMENT
The Group’s principal financial instruments comprise cash and short-term deposits (Note 5), receivables (Note 6), payables
(Note 9), borrowings (Note 17) and other financial assets and liabilities as disclosed in the table below.
2024
$’000
2023
$’000
Other financial assets – Non-Current
Equity instruments
718
1,131
718
1,131
Other financial liabilities – Non-Current
Success fee financial liability
2,830
2,853
2,830
2,853
Movement in carrying amount of the success fee financial liability:
Carrying amount at 1 July
2,853
3,285
Accretion of success fee liability
114
110
Fair value adjustment
(137)
(542)
Carrying amount at 30 June
2,830
2,853
FAIR VALUE HIERARCHY
Fair value is the price that would be received to sell an
asset, or the price that would be paid to transfer a liability,
in an orderly transaction between market participants at the
measurement date. All financial instruments for which fair
value is recognised, or disclosed, are categorised within
the fair value hierarchy, described as follows, and based on
the lowest level input that is significant to the fair value
measurement as a whole:
LEVEL 1
Quoted market prices in an active market (that are
unadjusted) for identical assets or liabilities
LEVEL 2 Valuation techniques for which the lowest level
input that is significant to the fair value measurement is
directly or indirectly observable
LEVEL 3 Valuation techniques for which the lowest level
input that is significant to the fair value
measurement is unobservable
For financial instruments that are recognised at fair value
on a recurring basis, the Group determines whether
transfers have occurred between levels in the hierarchy by
re-assessing categorisation (based on the lowest level
input that is significant to the fair value measurement as a
whole) at the end of each reporting period. Set out below
are the carrying amounts and fair values of financial
instruments held by the Group:
Carrying amount
Fair value
Level
2024
$’000
2023
$’000
2024
$’000
2023
$’000
Financial assets
Trade and other receivables
2
35,209
28,797
35,209
28,797
Equity instruments
1
718
1,131
718
1,131
Financial liabilities
Trade and other payables
2
76,773
87,941
76,773
87,941
Success fee financial liability
3
2,830
2,853
2,830
2,853
Interest bearing loans and borrowings
2
253,147
143,956
264,847
158,257
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
125
126
For the year ended 30 June 2024
For the year ended 30 June 2024
20. FINANCIAL RISK MANAGEMENT
CONTINUED
The following summarises the significant methods and
assumptions used in estimating the fair values of financial
instruments.
EQUITY INSTRUMENTS
Equity instruments are not held for trading, and are
measured at fair value through other comprehensive
income based on an irrevocable election made at inception
on an instrument basis.
They are initially recognised at fair value plus any directly
attributable transaction costs. After initial recognition,
investments are remeasured to fair value, determined by
reference to their quoted market price on a prescribed
equity stock exchange at the reporting date. Hence they
are a Level 1 fair value measurement.
Changes in the fair value of equity investments are
recognised as a separate component of equity and not
recycled to profit and loss at any stage. Any dividends
received are reflected in profit or loss.
SUCCESS FEE FINANCIAL LIABILITY
The success fee liability is the fair value of the Group’s
liability to pay a $5.0 million success fee upon the
commencement of commercial production of hydrocarbons
on the Group’s VIC/RL 13-15 assets, which includes the
Manta gas field, acquired on 7 May 2014.
The significant unobservable level 3 valuation inputs for the
success fee financial liability include: a probability of 33%
that no payment is made and a probability of 67% the
payment is made in 2032. The discount rate used in the
calculation of the liability as at 30 June 2024 equalled
4.31% (30 June 2023: 4.03%), reflecting a risk-free rate
that aligns to the timing of payment. The financial liability is
measured at fair value through profit and loss and valued
using a discounted cash flow model. The value is sensitive
to changes in discount rate and probability of payment.
Significant changes in any of the key unobservable inputs
would result in significantly higher or lower fair value
measurement.
RISK MANAGEMENT
The Group manages its exposure to key financial risks in
accordance with its risk management policy, with the
objective to ensure that the financial risks inherent in gas
and oil production and exploration activities are identified
and then managed, or kept as low as reasonably
practicable. The Group has a separate Risk &
Sustainability Committee.
The main financial risks that arise in the normal course of
business for the Group’s financial instruments are foreign
currency risk, commodity price risk, share price risk, credit
risk, liquidity risk and interest rate risk. The Group uses
different methods to measure and manage different types
of risks to which it is exposed. These include monitoring
exposure to foreign exchange risk and assessments of
market forecasts for interest rates, foreign exchange rates
and commodity prices. Liquidity risk is monitored through
the development of future rolling cash flow forecasts.
The Board’s policy is that no speculative trading in financial
instruments be undertaken. The primary responsibility for
the identification and control of financial risks rests with the
Managing Director and the Chief Financial Officer, under
the authority of the Board. The Board is apprised of these
and other risks at Board meetings and agrees any policies
that may be implemented to manage any of the risks
identified below.
MARKET RISK
Market risk is the risk that the fair value of future cash flows
of a financial instrument will fluctuate because of changes
in market prices. Market risk comprises four types of risk:
foreign currency risk, commodity price risk, interest rate risk
and share price risk. Financial instruments affected by
market risk include deposits, trade receivables, trade
payables, accrued liabilities and borrowings.
The sensitivity analyses in the following sections relate to
the position as at 30 June 2024 and 30 June 2023. The
sensitivity analyses are intended to illustrate the sensitivity
to changes in market variables on the Group’s financial
instruments and show the impact on profit or loss and
shareholders’ equity, where applicable.
When calculating the sensitivity analyses, it is assumed
that the sensitivity of the relevant profit before tax item
and/or equity, is the effect of the assumed changes in
respective market risks, with all other variables held
constant.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
20.
FINANCIAL RISK MANAGEMENT
CONTINUED
The Group has transactional currency exposure arising
from oil sales which are denominated in United States
dollars, whilst the great majority of costs are denominated
in Australian dollars, with some costs incurred in United
States dollars and Great British pounds. Transaction
exposures, where possible, are netted off across the
Group, to reduce volatility and provide a natural hedge.
a) Foreign currency risk
The Group may from time to time have cash denominated
in United States (“US”) dollars.
At 30 June 2024, the Group has no foreign exchange
hedge programmes in place. The Group manages the
purchase of foreign currency to meet expenditure
requirements, which cannot be netted off against US dollar
receivables.
The financial instruments which are denominated in US
dollars are as follows:
2024
$’000
2023
$’000
Financial assets
Cash
171
29,956
Trade and other receivables
2,274
-
b) Commodity price risk
Commodity price risk arises from the sale of oil
denominated in US dollars. From time to time, the Group
may use oil price options to manage some of its oil price
exposures.
The Group is exposed to changes in Southeast Australian
gas spot prices, with respect to gas production in excess of
contracted volumes. Spot gas trades at year end were
executed with reference to the prevailing intraday price
marker, i.e., at known settlement prices on the day.
c) Interest rate risk
The Group has borrowings of $265.0 million at 30 June
2024 (2023: $158.0 million). Interest on borrowings is at
variable rates (refer to Note 17).
The Group has fixed rate term deposits that are not
impacted by changes in the interest rate at the balance
date.
d) Share price risk
Share price risk arises from the movement of share prices
on a prescribed stock exchange. The Group has equity
instruments measured at fair value through Other
Comprehensive Income the fair value of which fluctuates,
due to movements in the share price.
The following table summarises the sensitivity of financial
instruments held at the year end, to the market risks above,
with all other variables held constant.
2024
$’000
2023
$’000
Foreign currency risk
Impact on after tax profit
If the Australian dollar were 10% higher at the balance date
(222)
(2,723)
If the Australian dollar were 10% lower at the balance date
272
3,328
Interest rate risk
If the interest rates were 100 basis points higher at the balance date
(2,650)
(1,580)
If the interest rates were 100 basis points lower at the balance date
2,650
1,580
Share price risk
Impact on reserve
If the share price were 10% higher at the balance date
72
113
If the share price were 10% lower at the balance date
(72)
(113)
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
127
128
For the year ended 30 June 2024
For the year ended 30 June 2024
20. FINANCIAL RISK MANAGEMENT
CONTINUED
Credit risk
Credit risk arises from the financial assets of the Group,
which comprise cash and cash equivalents and trade and
other receivables including hedge settlement receivables,
escrow proceeds receivable (disclosed as other financial
assets), and certain prepayments. The Group’s exposure
to credit risk arises from potential default of the
counterparty, with a maximum exposure equal to the
carrying amount of these instruments.
The Group trades only with recognised creditworthy third
parties and has a concentration of credit risk with trade
receivables due from a small number of entities which have
traded with the Group since 2003. Trade receivables are
settled on a 35 day average term. The Group has some
exposure to credit loss from other receivables and an
amount of $30.8 million calculated on lifetime expected
credit loss has been recognised in respect of credit-
impaired joint venture related receivables.
Cash and cash equivalents are held at two financial
institutions that each have a Standard & Poor’s credit rating
of AA- (stable).
Liquidity risk
Liquidity risk is the risk that the Group will not be able to
meet its financial obligations as they fall due. The liquidity
position of the Group is managed to ensure sufficient liquid
funds are available to meet all financial commitments in a
timely and cost-effective manner. The Managing Director
and Chief Financial Officer review the liquidity position on a
regular basis, including cash flow forecasts, to determine
the forecast liquidity position and maintain appropriate
liquidity levels.
Any fluctuation of the interest rate either up or down will
have only a limited impact on the principal amount of the
cash on term deposit at the banks. The Group does not
invest in financial instruments that are traded on any
secondary market.
The table below summarises the maturity profile of the Group’s financial liabilities based on contractual undiscounted payments:
Less than 3
months
3 to 12
months
1 to 5
years
Greater
than 5 years
Total
$’000
$’000
$’000
$’000
$’000
At 30 June 2024
Trade and other payables
76,773
-
-
-
76,773
Lease liabilities
367
554
1,021
32
1,974
Interest bearing loans and borrowings
5,131
15,394
308,470
-
328,995
Success fee financial liability
-
-
-
5,000
5,000
82,271
15,948
309,491
5,032
412,742
At 30 June 2023
Trade and other payables
68,679
-
19,262
-
87,941
Lease liabilities
495
1,428
9,284
1,056
12,263
Interest bearing loans and borrowings
3,022
9,066
197,286
-
209,374
Success fee financial liability
-
-
-
5,000
5,000
72,196
10,494
225,832
6,056
314,578
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
GROUP STRUCTURE
21.
INTERESTS IN JOINT ARRANGEMENTS
The Group has the following interests in joint arrangements involved in the exploration and/or production of gas and oil in
Australia:
Ownership Interest
2024
2023
Joint Arrangements in Australia in which Cooper Energy Limited is the operator/manager
VIC/L24 & 30
Gas exploration and production
50%
50%
VIC/P44
Gas exploration
50%
50%
Athena Processing Plant
Gas processing services
50%
50%
Joint Arrangements in Australia in which Cooper Energy Limited is not the operator/manager
PEL 494
Gas and oil exploration
30%
30%
PEP 168
Gas and oil exploration
50%
50%
PEP 171
Gas and oil exploration
75%
75%
PRL 32
Gas and oil exploration
30%
30%
PEL 680
Gas and oil exploration
30%
30%
PRL 85-1041 (Formerly PEL 92)
Oil and gas exploration and production
25%
25%
1 Includes associated PPLs.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
ACCOUNTING POLICY
The Group has interests in arrangements that are controlled jointly. 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. A joint arrangement is either a joint operation or a joint venture. The Group has several joint arrangements which are
classified as 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.
In relation to its interests in joint operations, the Group recognises its share of:
• Assets, including its share of any assets held jointly
• Liabilities, including its share of any liabilities incurred jointly
• Revenue from the sale of its share of the output arising from the joint operation
• Expenses, including its share of any expenses incurred jointly
SIGNIFICANT ACCOUNTING JUDGEMENTS, ESTIMATES AND ASSUMPTIONS
Joint arrangements
Judgement is required to determine when the Group has joint control over an arrangement, which requires an assessment of the
relevant activities and when the decisions in relation to those activities require unanimous consent. The Group has determined that
the relevant activities for its joint arrangements are those relating to the operating and capital decisions of the arrangement, such
as approval of the capital expenditure program for each year and appointing, remunerating and terminating the key management
personnel or service providers of the joint arrangement. Where joint control does not exist, the relationship is not accounted for as
a joint arrangement. The considerations made in determining joint control are similar to those necessary to determine control over
subsidiaries.
Judgement is also required to classify a joint arrangement. Classifying the arrangement requires the Group to assess their rights
and obligations arising from the arrangement. Specifically, the Group considers:
• the structure of the joint arrangement – whether it is structured through a separate vehicle; and
• when the arrangement is structured through a separate vehicle, the rights and obligations arising from the legal form of the
separate vehicle, the terms of the contractual arrangement, and other facts and circumstances (when relevant).
This assessment often requires significant judgement. A different conclusion on joint control, and also whether the arrangement is
a joint operation or a joint venture, may materially impact the accounting.
129
130
For the year ended 30 June 2024
For the year ended 30 June 2024
22.
INVESTMENTS IN CONTROLLED ENTITIES
(a) Deed of Cross Guarantee
Pursuant to ASIC Corporations (Wholly-owned Companies)
Instrument 2016/785 dated 29 September 2016, relief has
been granted to certain controlled entities of Cooper
Energy Limited from the Corporations Act 2001 for
preparation, audit and lodgement of financial reports, and
directors’ reports. As a condition of the Class Order,
Cooper Energy Limited, and the controlled entities subject
to the Class Order, entered into a Deed of Cross
Guarantee.
The effect of the deed is that Cooper Energy Limited has
guaranteed to pay any deficiency in the event of the
winding up of any member of the Closed Group, and each
member of the Closed Group has given a guarantee to pay
any deficiency, in the event that Cooper Energy Limited or
any other member of the Closed Group is wound up.
(b) Schedule of controlled entities
The Group’s consolidated financial statements include the
financial statements of Cooper Energy Limited and the
subsidiaries listed in the following table.
Ownership Interest
Name
Country of incorporation
Note
2024
2023
Somerton Energy Limited
Australia
(a)
100%
100%
Essential Petroleum Exploration Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (Australia) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (PBF) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (PB Pipelines) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (CH) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (TC) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (MF) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (MGP) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (IC) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (HC) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (EA) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (Sole) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (VO) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (Marketing) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (BMG) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (CB) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (Finance) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (AGP) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (CS) Pty Ltd
Australia
(a)
100%
100%
Cooper Energy (MS) Pty Ltd
Australia
(a)
100%
100%
The parties that comprise the Closed Group are denoted by (a).
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
22. INVESTMENTS IN CONTROLLED ENTITIES CONTINUED
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
ACCOUNTING POLICY
Business combinations are accounted for using the acquisition method. The consideration for an acquisition is measured as the
aggregate of the consideration transferred, measured at acquisition date fair value and the amount of any non-controlling interest
in the acquiree. For each business combination, the Group elects whether it measures the non-controlling interest in the acquiree
at fair value, or at the proportionate share of the acquiree’s identifiable net assets. Acquisition costs incurred are expensed and
included in administrative expenses.
When the Group acquires a business, it assesses the financial assets and liabilities acquired for appropriate classification and
designation per AASB 9 Financial Instruments (AASB 9), in accordance with the contractual terms, economic circumstances and
pertinent conditions, as at the acquisition date. If the business combination is achieved in stages, the acquisition date fair value of
the acquirers previously held equity interest in the acquiree is remeasured to fair value at the acquisition date, through profit or loss.
Any contingent consideration to be transferred by the acquirer will be recognised at fair value at the acquisition date. Subsequent
changes to the fair value of the contingent consideration that is deemed to be an asset or liability will be recognised in accordance
with AASB 9 and measured at fair value, through profit and loss. If the contingent consideration is classified as equity, it will not be
remeasured. Subsequent settlement is accounted for within equity. In instances where the contingent consideration does not fall
within the scope of AASB 9, it is measured in accordance with the appropriate AASB.
An asset or group of assets that do not meet the definition of a business are accounted for as asset acquisitions. Under this
method, assets are initially recognised at cost based on their relative fair value at the date of acquisition. Under this method
transaction costs are capitalised to the asset and not expensed.
23.
PARENT ENTITY INFORMATION
Information relating to the parent entity, Cooper Energy Limited
2024
$’000
2023
(restated)
$’000
Current Assets
126,135
144,598
Total Assets
460,395
712,281
Current Liabilities
57,694
186,501
Total Liabilities
118,601
223,784
Issued capital
718,881
716,726
Accumulated loss
(404,449)
(254,064)
Option premium reserve
25
25
Share based payment reserve
27,337
25,810
Total shareholders’ equity
341,794
488,497
Loss of the parent entity
(150,385)
(161,481)
Total comprehensive loss of the parent entity
(150,385)
(161,481)
131
132
For the year ended 30 June 2024
For the year ended 30 June 2024
OTHER INFORMATION
24.
COMMITMENTS FOR EXPENDITURE
The Group has the following commitments for exploration expenditure for which no liabilities have been record in the financial
statements as the goods or services have not been received.
2024
$’000
2023
$’000
Due within 1 year
32,403
32,263
Due within 1-5 years
33,878
478
66,281
32,741
From time to time through the ordinary course of business,
Cooper Energy enters into contractual arrangements that
may give rise to negotiated outcomes.
Cooper Energy has executed a number of material
contracts to the value of $44.6 million at 30 June 2024
relating to the East Coast Supply Project. The minimum
payment under these contracts at 30 June 2024 is $23.5
million.
As at 30 June 2024 the parent entity has bank guarantees
for $7.4 million (2023: $7.7 million), see also Note 17.
These guarantees are in relation to credit support for gas
purchases and guarantees on office leases.
25.
CONTINGENT LIABILITIES
Contingent liabilities arise in the ordinary course of
business through commercial disputes or claims, including
contractual or third-party claims. These contingent
liabilities are possible obligations whose existence will only
be confirmed by the occurrence or non-occurrence of
uncertain future events. Because it is not probable that a
future sacrifice of economic benefits will be required, or the
amount of the obligation cannot be measured with
sufficient reliability, the Group has not provided for these
amounts in the financial statements.
26.
SHARE BASED PAYMENTS
The Company’s amended EIP was approved by
shareholders at the 2022 AGM. The EIP applies only to
Executive KMPs and a small number of senior staff.
Performance rights were issued for no consideration under
the EIP under two tranches:
§
Tranche 1 – relative total shareholder return (RTSR)
§
Tranche 2 – absolute total shareholder return (ATSR).
No share appreciation rights were issued in the financial
year. Those share appreciation rights issued in previous
financial year remain on foot and subject to testing.
Issued rights vest as shares in the parent entity, subject to
performance hurdles being met.
A performance right is the right to acquire one fully paid
share in the Company, provided a specified hurdle is met.
Share appreciation rights are rights to acquire shares in the
Company to the value of the difference in the Company
share price between the grant date and vesting date.
Testing of the performance rights and historical share
appreciation rights occur at the end of the three year
performance period.
The vesting of tranche 1 performance rights is based on a
comparison of the Company’s RTSR percentile ranking
against the RTSR of a peer group of nine other companies.
Subject to the plan rules, the number of tranche 1
performance rights that will vest at the end of the
performance period is as follows:
§
Below 50th percentile – no tranche 1 performance
rights will vest
§
At 50th percentile – 50% of tranche 1 performance
rights will vest
§
Between 50th and 75th percentile – 50% of tranche 1
performance rights plus 2% for each additional
percentile
§
75th percentile or greater – 100% of tranche 1
performance rights will vest
The vesting of tranche 2 performance rights takes account
only of the Company’s ATSR, calculated as the compound
average growth rate (CAGR) of the Company’s share price
over a 3 year period. Subject to the plan rules, the number
of tranche 2 performance rights that will vest at the end of
the performance period is as follows:
§
Less than 10% CAGR – no tranche 2 performance
right will vest
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
26. SHARE BASED PAYMENTS
CONTINUED
§
At 10% CAGR – 50% of tranche 2 performance rights
will vest
§
Between 10% and 20% CAGR – 50% of tranche 2
performance rights will vest, plus 5% for each
additional percentile
§
20% or above – 100% of tranche 2 performance
rights will vest
Performance rights are also granted as part of deferred
awards under the short-term incentive plan (“STIP”).
Testing of these rights will occur at the end of a 12-month
performance period. Rights granted will vest if the
employee remains employed by the Company at the end of
the performance period.
There are no participating rights or entitlements inherent in
the rights and holders will not be entitled to participate in
new issues of capital offered to shareholders during the
period of the rights. All rights are settled by physical
delivery of shares.
Information with respect to the number of performance
rights and share appreciation rights granted to employees
is as follows:
Date Granted
Number of share
appreciation
rights (SARs)
granted
Number of
performance
rights granted
Average share
price at
commencement
date of grant
Average
contractual life of
rights at grant
date in years
Remaining
life of rights
in years
9 December 2021
28,449,812
9,043,984
$0.270
3
0.5
9 December 2022
20,636,373
7,608,195
$0.195
3
1.5
23 November 2023
1,084,611
407,814
$0.105
3
1.5
23 November 2023
-
9,547,387
$0.105
3
2.4
11 December 2023
-
29,249,252
$0.100
3
2.5
11 December 2023
-
9,231,865
$0.100
1
0.5
The number of performance rights and share appreciation rights held by employees is as follows:
Number of Share
Appreciation Rights
Number of Performance
Rights1
2024
2023
2024
2023
Balance at beginning of year
60,807,624
71,695,778
28,694,792
26,086,626
- granted
1,084,611
20,636,373
48,436,318
16,249,700
- vested
-
-
(8,506,969)
(2,844,324)
- expired and not exercised
(16,796,442)
(25,781,761)
(5,460,544)
(8,772,365)
- forfeited
(1,337,585)
(5,742,766)
(425,208)
(2,024,845)
Balance at end of year
43,758,208
60,807,624
62,738,389
28,694,792
Achieved at end of year
-
-
-
-
1 The Performance Rights, which vested in 2023 and 2024, are Deferred STIP that applies to staff generally and does not include any PRs having vested under the
EIP for Executive KMP.
The fair value of services received in return for the performance rights granted are measured by reference to the fair value of
performance rights granted. The estimate of the fair value of the services received is measured based on the Black-Scholes
methodology and a Monte-Carlo simulation model that allows for the incorporation of market-based performance hurdles that
must be met before the shares vest to the holder.
Fair value assumptions on LTIP grants
10 December
2021
9 December
2022
11 December
2023
Fair value of share appreciation rights at measurement date
8.3 cents
6.4 cents
N/A
Fair value of performance rights at measurement date
18.5 cents
13.4 cents
7.0 cents
Share price
27.0 cents
19.5 cents
10.0 cents
Risk free interest rate
0.97%
3.02%
3.80%
Expected volatility
48%
52%
53%
Dividend yield
0%
0%
0%
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
133
134
For the year ended 30 June 2024
For the year ended 30 June 2024
26. SHARE BASED PAYMENTS CONTINUED
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
ACCOUNTING POLICY
The Group provides benefits to employees of the Group in the form of share-based payment transactions, whereby employees
render services in exchange for rights over shares (“equity-settled transactions”).
The cost of these equity-settled transactions with employees is measured by reference to the fair value at the date at which they
are granted and are recorded as an expense, with a corresponding increase in reserves, on a straight-line basis over the vesting
period of the related instrument.
The fair value is determined using the Black-Scholes methodology and a Monte-Carlo simulation model that takes into account the
exercise price, the vesting period, the vesting and performance criteria, the non-tradable nature of the performance right or share
appreciation right, the share price at grant date, the expected volatility of the price of the underlying share, the expected dividend
yield and the risk-free interest rate for the term of the vesting period.
There are no non-market vesting conditions (e.g., profitability, or sales growth targets), and as such the estimation of the fair value
of the performance rights and share appreciation rights granted is based solely on the results of the Black-Scholes based Monte-
Carlo simulation model.
The volatility assumption is based on the actual volatility of Cooper Energy’s daily closing share price over the three-year period to
the valuation date.
The cost of equity-settled transactions is recognised, together with a corresponding increase in equity, over the period in which the
performance and/or service conditions are fulfilled, ending on the date on which the relevant employees become fully entitled to the
award (the vesting period).
The cumulative expense recognised for equity-settled transactions at each reporting date until vesting date reflects:
• the extent to which the vesting period has expired; and
• the Group’s best estimate of the number of equity instruments that will ultimately vest.
No adjustment is made for the likelihood of market performance conditions being met as the effect of these conditions is included in
the determination of fair value at grant date. The Consolidated Statement of Comprehensive Income charge or credit, for a period,
represents the movement in cumulative expense recognised as at the beginning and end of that period.
No expense is recognised for awards that do not ultimately vest, except for awards where vesting is only conditional
upon a market condition.
If the terms of an equity-settled award are modified, as a minimum an expense is recognised as if the terms had not been
modified. In addition, an expense is recognised for any modification that increases the total fair value of the share-based payment
arrangement, or is otherwise beneficial to the employees as measured at the date of modification.
If an equity-settled award is cancelled, it is treated as if it had vested on the date of cancellation, and any expense not yet
recognised for the award is recognised immediately. However, if a new award is substituted for the cancelled award and
designated as a replacement award on the date that it is granted, the cancelled and new award are treated as if they were a
modification of the original award, as described in the previous paragraph.
The dilutive effect, if any, of outstanding performance rights and share appreciation rights is reflected as additional share dilution in
the computation of diluted earnings per share.
SIGNIFICANT ACCOUNTING JUDGEMENTS, ESTIMATES AND ASSUMPTIONS
The Group measures the cost of equity-settled transactions with employees by reference to the fair value of the equity instruments
at the date at which they are granted. The fair value is determined by an external valuation expert using the calculation criteria.
27.
RELATED PARTY DISCLOSURES
The Group has a related party relationship with its joint arrangements (Note 21), its subsidiaries (Note 22), and its key
management personnel (disclosure below).
The key management personnel’s remuneration included in General Administration (see Note 2) is as follows:
2024
$
2023
$
Short-term benefits
5,390,663
5,829,184
Other long-term benefits
23,413
89,311
Post-employment benefits
217,887
303,572
Performance rights and share appreciation rights
896,020
2,193,542
Termination benefits
823,314
2,534,604
7,351,297
10,950,213
28.
REMUNERATION OF AUDITORS
2024
$
2023
$
The auditor of Cooper Energy Limited is Ernst & Young
Audit services
Amounts received or due and receivable by Ernst & Young Australia for:
Audit of statutory report of Cooper Energy Limited
463,800
486,380
463,800
486,380
Other services
Taxation and other services
62,000
49,500
62,000
49,500
Total fees to Ernst & Young
525,800
535,880
29.
EVENTS AFTER THE REPORTING PERIOD
There are no significant events subsequent to 30 June 2024 at the date of this report.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
135
136
For the year ended 30 June 2024
As at 30 June 2024
Entity name
Entity type
Body corporate
country of
incorporation
Body corporate %
of share capital
held
Country of tax
residence
Cooper Energy Limited
Body corporate
Australia
100%
Australia
Somerton Energy Limited
Body corporate
Australia
100%
Australia
Essential Petroleum Exploration Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (Australia) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (PBF) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (PB Pipelines) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (CH) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (TC) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (MF) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (MGP) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (IC) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (HC) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (EA) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (Sole) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (VO) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (Marketing) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (BMG) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (CB) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (Finance) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (AGP) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (CS) Pty Ltd
Body corporate
Australia
100%
Australia
Cooper Energy (MS) Pty Ltd
Body corporate
Australia
100%
Australia
CONSOLIDATED ENTITY
DISCLOSURE STATEMENT
In accordance with a resolution of the Directors of Cooper Energy Limited, I state that:
In the opinion of the Directors:
(a) the financial statements and notes of the consolidated entity are in accordance with the Corporations Act 2001,
including:
(i) giving a true and fair view of the consolidated entity’s financial position as at 30 June 2024 and of its performance for
the year ended on that date; and
(ii) complying with Australian Accounting Standards and the Corporations Regulations 2001;
(b) the financial statements and notes also comply with International Financial Reporting Standards as disclosed in the
Basis of Preparation;
(c) the consolidated entity disclosure statement required by section 295(3A) of the Corporations Act is true and correct; and
(d) there are reasonable grounds to believe that the Company will be able to pay its debts as and when they become due
and payable.
This declaration has been made after receiving the declarations required to be made to the Directors in accordance with section
295A of the Corporations Act 2001 for the financial year ended 30 June 2024.
In the opinion of the Directors, as at the date of this declaration, there are reasonable grounds to believe that the members of
the closed group identified in Note 22 will be able to meet any obligations or liabilities to which they are, or may become subject,
by virtue of the Deed of Cross Guarantee between the Company and those members of the Closed Group pursuant to ASIC
Corporations (Wholly-owned Companies) Instrument 2016/785.
Signed in accordance with a resolution of the Directors.
Mr John C. Conde AO
Ms Jane L. Norman
Chairman
Managing Director and CEO
27 August 2024
DIRECTORS’
DECLARATION
138
137
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Ernst & Young
121 King William Street
Adelaide SA 5000 Australia
GPO Box 1271 Adelaide SA 5001
Tel: +61 8 8417 1600
Fax: +61 8 8417 1775
ey.com/au
Independent auditor’s report to the members of Cooper Energy Limited
Report on the audit of the financial report
Opinion
We have audited the financial report of Cooper Energy Limited (the Company) and its subsidiaries
(collectively the Group), which comprises the consolidated statement of financial position as at 30
June 2024, the consolidated statement of comprehensive income, consolidated statement of changes
in equity and consolidated statement of cash flows for the year then ended, 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 Group is in accordance with the Corporations
Act 2001, including:
a.
Giving a true and fair view of the consolidated financial position of the Group as at 30 June 2024
and of its consolidated financial performance for the year ended on that date; and
b.
Complying with Australian Accounting Standards and the Corporations Regulations 2001.
Basis for opinion
We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under
those standards are further described in the Auditor’s responsibilities for the audit of the financial
report section of our report. We are independent of the Group in accordance with the auditor
independence requirements of the Corporations Act 2001 and the ethical requirements of the
Accounting Professional and Ethical Standards Board’s APES 110 Code of Ethics for Professional
Accountants (including Independence Standards) (the Code) that are relevant to our audit of the
financial report in Australia. We have also fulfilled our other ethical responsibilities in accordance with
the Code.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis
for our opinion.
Key audit matters
Key audit matters are those matters that, in our professional judgment, were of most significance in
our audit of the financial report of the current year. These matters were addressed in the context of
our audit of the financial report as a whole, and in forming our opinion thereon, but we do not provide
a separate opinion on these matters. For each matter below, our description of how our audit
addressed the matter is provided in that context.
We have fulfilled the responsibilities described in the Auditor’s responsibilities for the audit of the
financial report section of our report, including in relation to these matters. Accordingly, our audit
included the performance of procedures designed to respond to our assessment of the risks of
material misstatement of the financial report. The results of our audit procedures, including the
procedures performed to address the matters below, provide the basis for our audit opinion on the
accompanying financial report.
COOPER ENERGY FINANCIAL REPORT 2024
INDEPENDENT
AUDITOR’S
REPORT
TO THE MEMBERS
OF COOPER
ENERGY LIMITED
140
139
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1. Carrying value of gas and oil assets and exploration and evaluation assets
Why significant
How our audit addressed the key audit matter
At 30 June 2024, the Group’s Gas and Oil assets and
Exploration and Evaluation assets are valued at $475
million and $194 million respectively. At year-end, the
Group identified an indicator of impairment in respect of
a single Exploration and Evaluation asset, for which an
impairment charge of $0.3m was recognised, as
disclosed in Note 14 of the financial report.
In accordance with the requirements of Australian
Accounting Standards, the Group is required to assess in
respect of the reporting period, whether there is any
indication that an asset may be impaired, or conversely
whether reversal of a previously recognised impairment
may be required. If any impairment indicators exist, an
entity shall estimate the recoverable amount of the asset
or cash generating unit (‘CGU’).
The assessments for indicators of impairment and
reversals of impairment are judgmental and include
assessing a range of external and internal factors,
including the determination of preliminary recoverable
amounts for CGUs where relevant.
Where impairment indicators are identified throughout
the period, forecasting cash flows for the purpose of
determining the recoverable amount of a CGU, including
a preliminary recoverable amount, involves accounting
estimates and judgements and is affected by expected
future performance and market conditions. Key forecast
assumptions, such as discount rates, foreign exchange
rates, commodity prices and recoverable hydrocarbon
reserves used in the Group’s impairment assessment are
disclosed in Note 14.
We considered the impairment testing of the Group’s
CGUs and its exploration and evaluation assets
throughout the period, and the related disclosures in the
financial report, to be a key audit matter.
Assessing indicators of impairment
We evaluated whether there had been significant
changes to the external or internal factors considered by
the Group, in assessing whether indicators of impairment
or reversal of impairment existed throughout the period.
Those indicators included specific matters related to the
Group, CGUs, and industry as well as broader market-
based indicators.
Impairment testing of CGUs for which triggers were
identified and the determination of preliminary
recoverable amounts when assessing indicators of
impairment of CGUs
We assessed the composition of the forecast cash flows
and the reasonableness of key inputs used to formulate
recoverable amounts. Depending on the CGU, our audit
procedures included:
► Reconciling future production profiles to the latest
hydrocarbon reserves and resources estimates
(discussed further below), current sanctioned
development budgets, long-term asset plans and
historical operations.
► Developing a reasonable range of forecast oil and
gas prices, based upon external data. We compared
this range to the Group’s forecast oil and gas price
assumptions to challenge whether the Group’s
assumptions were reasonable. In developing our
ranges, we obtained a variety of reputable third-
party forecasts, peer information and market data
(which contemplate forecast oil and gas demand in a
decarbonising global economy).
► Evaluating discount rates used by the Group for
impairment tests (which contemplate costs of
capital considerations in light of a decarbonising
global economy).
► Evaluating the reasonableness of inflation rates,
foreign exchange rates and carbon costs used by
the Group for impairment tests.
► Understanding the operational performance of the
CGUs relative to plan, comparing future operating
and development expenditure within the impairment
assessments to current sanctioned budgets,
historical expenditures and future project plans, and
ensuring variations were in accordance with our
expectations.
► Testing the mathematical accuracy of the Group’s
discounted cash flow models.
Future production profiles
A key input to impairment assessments is the Group’s
production forecast, which is closely related to the
Group’s hydrocarbon reserves and resource estimates
and development plans. Our audit procedures on the
work of the Group’s internal and external experts
included:
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Why significant
How our audit addressed the key audit matter
► Assessing the processes and controls associated
with estimating reserves and resources.
► Reading reports provided by internal and external
experts and assessing their scopes of work and
findings.
► Assessing the qualifications, competence and
objectivity of the Group’s internal and external
experts involved in the estimation process.
► Understanding the reasons for reserve changes or
the absence of reserves changes, for consistency
with other information that we obtained throughout
the audit.
Impact of Sustainability and Climate Change Risks
In undertaking our impairment audit procedures, we
incorporated consideration of sustainability and climate
change related risks by:
► Performing sensitivity analysis of recoverable
amounts across a range of key inputs which have been
formulated to incorporate uncertainty risk associated
with climate change, such as the inclusion of
premiums in discount rates and alternative price
forecasts which contemplate varied climate change
assumptions and scenarios.
► Reviewing the recoverable amount for the appropriate
inclusion of carbon costs.
► Assessing the audit results of procedures carried out
over restoration and rehabilitation obligations and
their impact on impairment risk (refer to the
‘Accounting for Restoration Obligations’ Key Audit
Matter below).
► Inquiring of management and reading the Group’s
communication and publicly stated climate
commitments regarding sustainability and climate-
related risks where relevant and their impact on
financial reporting.
► Assessing whether the ‘other information’ presented
by the Group, including their publicly stated climate
commitments present a current period impairment
indicator for any CGUs at reporting date.
Exploration and Evaluation Assets
For exploration and evaluation assets, we assessed
whether any impairment indicators, per the requirements
of AASB 6: Exploration for and Evaluation of Mineral
Resources, were present, and performed audit
procedures in respect of the conclusions reached by
management, including:
► Assessing whether the Group’s right to explore was
current, which included obtaining and assessing
supporting documentation such as licenses, permits
and agreements.
141
142
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Why significant
How our audit addressed the key audit matter
► Assessing the Group’s intention to carry out
significant ongoing exploration and evaluation
activities in the relevant areas of interest and
enquiring of senior management as to their intentions
and the strategy of the Group as it relates to
particular areas of interest.
► Assessing whether exploration and evaluation data or
other information existed to indicate that the carrying
value of capitalised exploration and evaluation assets
was unlikely to be recovered through successful
evaluation and development or sale.
We also assessed the adequacy of the disclosures
included in the Notes to the financial statements.
2. Restoration obligations
Why significant
How our audit addressed the key audit matter
At 30 June 2024, the Group has recognised provisions
for restoration obligations relating to onshore and
offshore assets of $461 million. As disclosed in Note 15,
the calculation of restoration provisions is conducted by
specialist engineers and requires significant judgements,
assumptions and estimates to be made by the Group
regarding removal date, compliance with environmental
legislation and regulations, the extent of restoration
activities required, the engineering methodology for
estimating costs, future removal technologies in
determining the removal costs and liability-specific
discount rates to determine the present value of these
cash flows.
The judgements and estimates in respect of restoration
provisions are based upon conditions existing at 30 June
2024, including key assumptions related to certain items
remaining in-situ. Australian regulatory approval for
these items remaining in-situ will only be sought towards
the end of the respective asset’s field life and
accordingly, at 30 June 2024, there is uncertainty
whether the Australian regulator will approve plans for
these items to be decommissioned in-situ.
Changes to these significant judgements, assumptions
and estimates can lead to changes in the restoration
provisions.
Accordingly, the restoration provision calculation and the
related disclosures in the financial report are a key audit
matter.
We assessed the restoration obligation provisions
prepared by the Group, evaluating the assumptions and
methodologies used and the estimates made. Our audit
procedures included the following:
► Evaluating the Group’s process for identifying its
legal and regulatory obligations for restoration and
decommissioning and testing the completeness of
operating locations.
► Understanding and documenting the controls over
the Group’s internal methodology for determining
and approving gross cost estimates used to
calculate the Group’s restoration provisions.
► In conjunction with our environmental specialists,
assessing the reasonableness and completeness of
restoration cost estimates based on the relevant
current legal and regulatory requirements.
► Assessing the qualifications, competence and
objectivity of the Group’s internal and external
experts engaged to carry out the gross restoration
cost estimations as a basis for our reliance on the
output of their work.
► Comparing current year cost estimates to those of
the prior year and explanations from management
and both internal and external experts for observed
changes.
► Comparing the timing of the future cash outflows
against the anticipated end-of-field lives, cross-
checking that these dates were consistent with the
Group’s reserve estimates, impairment calculations
and regulatory notices.
► Evaluating the appropriateness of the discount
rates, inflation rates and foreign exchange rates
used to calculate the present value of each of the
provisions.
A member firm of Ernst & Young Global Limited
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Why significant
How our audit addressed the key audit matter
► Testing the mathematical accuracy of the
restoration provision calculations.
Impact of Sustainability and Climate Change Risks
In undertaking our audit procedures for restoration, we
incorporated consideration of sustainability and climate
change related risks by:
►
Understanding the regulatory framework in which
each project operates to ensure compliance with the
regulatory requirements of the various jurisdictions
as they relate to restoration obligations.
►
Evaluating the assumptions associated with the
form and extent of abandonment activities,
including conformity with regulation and industry
practice, and the nature of the items expected to be
left in-situ in abandonment activities.
►
Reviewing litigation registers, correspondence with
solicitors and regulators to confirm the
completeness of liabilities recognised.
►
Considering the estimated dates for the
commencement of restoration and rehabilitation
activities, possible impacts of physical risks of
climate change and performing sensitivity analyses
aligned with a range of scenarios associated with
the Group’s net zero climate targets.
We also assessed the adequacy of the disclosures
included in the Notes to the financial report.
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 30 June 2024 annual report other than the financial report
and our auditor’s report thereon. We obtained the directors’ report and the Overall Financial Review
that are to be included in the annual report, prior to the date of this auditor’s report, and we expect to
obtain the remaining sections of the annual report after the date of this auditor’s report.
Our opinion on the financial report does not cover the other information and we do not and will not
express any form of assurance conclusion thereon, with the exception of the Remuneration Report
and our related assurance opinion.
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 on the other information obtained prior to the date of this
auditor’s report, 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.
143
144
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
Responsibilities of the directors for the financial report
The directors of the Company are responsible for the preparation of:
►
The financial report (other than the consolidated entity disclosure statement) that gives a true
and fair view in accordance with Australian Accounting Standards and the Corporations Act
2001; and
►
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:
►
The financial report (other than the consolidated entity disclosure statement) that gives a true
and fair view and is free from material misstatement, whether due to fraud or error; and
►
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 Group’s ability to
continue as a going concern, disclosing, as applicable, matters relating to going concern and using the
going concern basis of accounting unless the directors either intend to liquidate the Group or to cease
operations, or have no realistic alternative but to do so.
Auditor’s responsibilities for the audit of the financial report
Our objectives are to obtain reasonable assurance about whether the financial report as a whole is
free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that
includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an
audit conducted in accordance with the Australian Auditing Standards will always detect a material
misstatement when it exists. Misstatements can arise from fraud or error and are considered material
if, individually or in the aggregate, they could reasonably be expected to influence the economic
decisions of users taken on the basis of this financial report.
As part of an audit in accordance with the Australian Auditing Standards, we exercise professional
judgment and maintain professional scepticism throughout the audit. We also:
►
Identify and assess the risks of material misstatement of the financial report, whether due to
fraud or error, design and perform audit procedures responsive to those risks, and obtain audit
evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not
detecting a material misstatement resulting from fraud is higher than for one resulting from
error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the
override of internal control.
►
Obtain an understanding of internal control relevant to the audit in order to design audit
procedures that are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Group’s internal control.
►
Evaluate the appropriateness of accounting policies used and the reasonableness of accounting
estimates and related disclosures made by the directors.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
►
Conclude on the appropriateness of the directors’ use of the going concern basis of accounting
and, based on the audit evidence obtained, whether a material uncertainty exists related to
events or conditions that may cast significant doubt on the Group’s ability to continue as a going
concern. If we conclude that a material uncertainty exists, we are required to draw attention in
our auditor’s report to the related disclosures in the financial report or, if such disclosures are
inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up
to the date of our auditor’s report. However, future events or conditions may cause the Group to
cease to continue as a going concern.
►
Evaluate the overall presentation, structure and content of the financial report, including the
disclosures, and whether the financial report represents the underlying transactions and events
in a manner that achieves fair presentation.
►
Obtain sufficient appropriate audit evidence regarding the financial information of the entities or
business activities within the Group to express an opinion on the financial report. We are
responsible for the direction, supervision and performance of the Group audit. We remain solely
responsible for our audit opinion.
We communicate with the directors regarding, among other matters, the planned scope and timing of
the audit and significant audit findings, including any significant deficiencies in internal control that we
identify during our audit.
We also provide the directors with a statement that we have complied with relevant ethical
requirements regarding independence, and to communicate with them all relationships and other
matters that may reasonably be thought to bear on our independence, and where applicable, actions
taken to eliminate threats or safeguards applied.
From the matters communicated to the directors, we determine those matters that were of most
significance in the audit of the financial report of the current year and are therefore the key audit
matters. We describe these matters in our auditor’s report unless law or regulation precludes public
disclosure about the matter or when, in extremely rare circumstances, we determine that a matter
should not be communicated in our report because the adverse consequences of doing so would
reasonably be expected to outweigh the public interest benefits of such communication.
Report on the audit of the Remuneration Report
Opinion on the Remuneration Report
We have audited the Remuneration Report included in pages 69 to 92 of the directors’ report for the
year ended 30 June 2024.
In our opinion, the Remuneration Report of Cooper Energy Limited for the year ended 30 June 2024,
complies with section 300A of the Corporations Act 2001.
145
146
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
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.
Ernst & Young
D Hall
Partner
Adelaide
27 August 2024
148
147
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
Ernst & Young
121 King William Street
Adelaide SA 5000 Australia
GPO Box 1271 Adelaide SA 5001
Tel: +61 8 8417 1600
Fax: +61 8 8417 1775
ey.com/au
Auditor’s Independence Declaration to the Directors of Cooper Energy
Limited
As lead auditor for the audit of the financial report of Cooper Energy Limited for the financial year
ended 30 June 2024, I declare 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;
b.
No contraventions of any applicable code of professional conduct in relation to the audit; and
c.
No non-audit services provided that contravene any applicable code of professional conduct in
relation to the audit.
This declaration is in respect of Cooper Energy Limited and the entities it controlled during the
financial year.
Ernst & Young
D Hall
Partner
Adelaide
27 August 2024
COOPER ENERGY FINANCIAL REPORT 2024
AUDITOR’S
INDEPENDENCE
DECLARATION
TO THE DIRECTORS
OF COOPER ENERGY
LIMITED
150
149
SECURITIES
EXCHANGE AND
SHAREHOLDER
INFORMATION
LISTING
The Company’s shares are quoted on the Australian
Securities Exchange under the code of “COE”.
NUMBER OF SHAREHOLDERS
There were 8,066 shareholders as at 31 August 2024.
All issued shares carry voting rights. On a show of
hands every member at a meeting of shareholders
shall have one vote and upon a poll each share shall
have one vote.
DISTRIBUTION OF SHAREHOLDING
(AT 31 AUGUST 2024)
Range
Total
holders
Shares
% of
Total
Shares
1-1,000
974
249,592
0.01
1,001 - 5,000
2,030
5,825,015
0.22
5,001 - 10,000
1,250
10,190,857
0.39
10,001 -
100,000
3,968
109,533,881
4.15
>100,001
844
2,514,238,884
95.23
Total
8,066
2,640,038,229
100.00
UNQUOTED OPTIONS
ON ISSUE
Nil
UNQUOTED
PERFORMANCE RIGHTS
Number of Holders
of Performance Rights
Total Rights
103
62,647,935
Performance Rights
13
43,758,208
Share Appreciation Rights
UNMARKETABLE PARCELS
At 31 August 2024 there were 1,973 shareholders,
representing 2,065,995 shares, holding less than a
marketable parcel of 2,565 shares in the company.
As at 31 August 2024
TWENTY LARGEST SHAREHOLDERS
Rank
Shareholder Name
Shares
%
1
CITICORP NOMINEES PTY LIMITED
539,276,586
20.43
2
HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED
492,937,325
18.67
3
HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED - A/C 2
352,010,888
13.33
4
J P MORGAN NOMINEES AUSTRALIA PTY LIMITED
344,905,904
13.06
5
HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED-GSCO ECA
93,604,725
3.55
6
MCCUSKER HOLDINGS PTY LTD
70,000,000
2.65
7
UBS NOMINEES PTY LTD
52,623,935
1.99
8
NATIONAL NOMINEES LIMITED
31,494,393
1.19
9
BNP PARIBAS NOMS PTY LTD
29,344,642
1.11
10
HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED
23,403,710
0.89
11
BNP PARIBAS NOMINEES PTY LTD
21,157,513
0.80
12
WARNEET SUPER PTY LTD
17,500,000
0.66
13
BOND STREET CUSTODIANS LIMITED
16,911,110
0.64
14
INVIA CUSTODIAN PTY LIMITED
13,095,442
0.50
15
MR SIMON HANNES + MRS MIGNON CATHERINE BOOTH
9,895,323
0.37
16
AUDANT INVESTMENTS PTY LIMITED
9,050,000
0.34
17
BNP PARIBAS NOMS PTY LTD
8,258,940
0.31
18
WANNA QUICKIE PTY LTD
7,984,607
0.30
19
SRGG PTY LTD
7,892,158
0.30
20
INVIA CUSTODIAN PTY LIMITED
7,175,387
0.27
Total Top 20 holders
2,148,522,588
81.38
Total Remaining Holders Balance
491,515,641
18.62
SUBSTANTIAL SHAREHOLDERS
The following were substantial holders in the company as at 31 August 2024, as disclosed in substantial holding
notices given to the Company as required by section 671B of the Corporations
Name of entity
Number of securities in which
substantial shareholder has a relevant
interest as at date of last notice
Voting power as at
date of last notice
L1 Capital Pty Limited
416,802,185
15.79%
Challenger Limited and Apollo Global
Management, Inc. and their associated entities
175,681,366
6.65%
Greencape Capital Pty Ltd
175,681,366
6.65%
Yarra Capital Management and
its associated entities
135,326,636
5.13%
The Vanguard Group, Inc and
its associated entities
132,315,772
5.17%
152
151
INVESTOR INFORMATION
Information about the Company is available from
a number of sources:
Website cooperenergy.com.au
E-news Shareholders can nominate to receive
Company information electronically. This service is
hosted by Computershare and can be accessed via
Computershare’s website.
Publications The Annual Report is the major printed
source of Company information. Other publications
include the Sustainability Report, half-yearly and
quarterly reports, company press releases and investor
presentations. All publications can be obtained either
through the Company’s website or by contacting the
Company.
Telephone or email enquiry
Tom Fraczek
Investor Relations & Treasurer
+61 439 555 165
tom.fraczek@cooperenergy.com.au
This Annual Report has been prepared to provide
Shareholders with an overview of Cooper Energy
Limited’s performance for the 2024 financial year and
its outlook. The Annual Report is mailed to shareholders
who elect to receive a copy and is available free of
charge on request (see Shareholder Information printed
in this Annual Report). This Annual Report and other
information about the company can be accessed via the
Company’s website at www.cooperenergy.com.au
ANNUAL GENERAL MEETING
Date of meeting Thursday, 7 November 2024
Time of meeting: 10:30 am (ACDT)
Place of meeting U City, Level 1,
43 Franklin Street, Adelaide SA 5000
The Notice of Meeting has been mailed to Shareholders.
Additional copies can be obtained from the Company’s
registered office or downloaded from our website at
www.cooperenergy.com.au
ENQUIRIES AND
SHARE REGISTRY ADDRESS
Shareholders with enquiries about their shareholdings
should contact the Company’s share registry,
Computershare Investor Services Pty Ltd, via the contact
details in the Corporate Directory of this Annual Report.
ONLINE SHAREHOLDER
INFORMATION
Shareholders can obtain information about their
holdings or view their account instructions online, as
well as download forms to update their holder details.
For identification and security purposes, you will need
to know your Holder Identification Number (HIN/
SRN), Surname/Company Name and Post/Country
Code to access. This service is accessible via the
Computershare website.
CHANGE OF ADDRESS
Shareholders who have changed their address should
advise Computershare in writing or online via the
Computershare website. Written notification can be mailed
or faxed to Computershare and must include both old and
new addresses and the security holder reference number
(SRN) of the holding. Change of address forms are
available for download from the Computershare website.
Shareholders who have broker sponsored holdings should
contact their broker to update these details.
ANNUAL REPORT MAILING LIST
Shareholders who wish to vary their annual report
mailing arrangements should advise Computershare
online via the Computershare website. Electronic
versions of the report are available to all via the
Company’s website. Annual Reports will be mailed to
all shareholders who have elected to be placed on the
mailing list for this document.
FORMS FOR DOWNLOAD
All forms relating to amendment of holding details and
holder instructions to the Company are available for
download from the Computershare website.
ABBREVIATIONS AND TERMS
This Report uses terms and abbreviations relevant to
the Group, its accounts and the petroleum industry.
The terms “the Company” and “Cooper Energy” and “the
Group” are used in the report to refer to Cooper Energy
Limited and/or its subsidiaries. The terms “2024”, or “2024
financial year” refer to the 12 months ended 30 June 2024
unless otherwise stated. References to “2023”, or other years
refer to the 12 months ended 30 June of that year.
$: Australian dollars unless specified otherwise
AASB: Australian Accounting Standards Board
ACCC: Australia Competition and Consumer Commission
AEMO: Australian Energy Market Operator
AGP: Athena gas plant
ANREO: accelerated, non-renounceable entitlement offer
bbls: barrels of oil
bbls/d: barrels of oil per day
CGU: cash generating unit
EBITDAX: earnings before interest, tax, depreciation,
amortisation, restoration, exploration and evaluation expense
and impairment
EIP: equity incentive plan
FTE: full time equivalent
FVLCD: fair value less cost of disposal
GSA: gas sales agreement
GST: goods and services taxes
HSE: health, safety and environment
HSEC: health, safety, environment and community
IFRS: International Financial Reporting Standards
JV: joint venture
JOA: joint operating agreement
kbbl: thousand barrels of oil
LNG: liquified natural gas
LTI: lost time injury
Mitsui: Mitsui E&P Australia and its associated entities
MMbbl: million barrels of oil
MMboe: million barrels of oil equivalent
OGPP: Orbost gas processing plant
Pertamina: PT Pertamina Hulu Energi
PJ: petajoules
PJe: petajoules-equivalent
PRRT: Petroleum resource rent tax
STIP: short-term incentive plan
TJ: terajoules
TJ/d: terajoules per day
TRIFR: total recordable injury frequency rate
US: United States
2P: best estimate of reserves.
The sum of proved plus probable reserves
2C: best estimate of contingent resources
153
154
CORPORATE
DIRECTORY
DIRECTORS
John C Conde AO, Chairman
Jane L Norman, Managing Director
Timothy G Bednall
Giselle M Collins
Elizabeth A Donaghey
Jeffrey W Schneider
COMPANY SECRETARY
Nicole Ortigosa
REGISTERED OFFICE
AND BUSINESS ADDRESS
Level 8, 70 Franklin Street
Adelaide, South Australia 5000
Telephone: +618 8100 4900
Facsimile: +618 8100 4997
Email: customerservice@cooperenergy.com.au
Website: www.cooperenergy.com.au
AUDITORS
Ernst & Young
121 King William Street
Adelaide, South Australia 5000
SHARE REGISTRY
Computershare Investor Services Pty Limited
Level 5,115 Grenfell Street
Adelaide, South Australia 5000
Website: investorcentre.com/au
Telephone
Australia 1300 556 161
International +61 3 9415 4000
Facsimile +61 3 9473 2500