Annual Report
Acknowledgement of Country
Cooper Energy recognises and acknowledges the First Peoples of this nation as the Traditional Owners of the
lands where we operate. We pay respects to their Elders past, present and emerging.
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 “2023”, “FY23” and the “2023 financial year” refer to the 12 months ended 30 June 2023 unless
otherwise stated. References to 2022, FY22 or 2024, FY24 refer to the 12 months ending 30 June of that year. References
to $ are Australian dollars unless specified otherwise. 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.
2
COOPER ENERGY ANNUAL REPORT 2023
Our Purpose
We find, develop and commercialise
Australian gas and oil for domestic
markets. We work to deliver a stable
and secure supply of domestic gas into
markets along the east coast at the low
end of the cost curve.
We operate with an emphasis on
health and safety, environment
and sustainability, reliability and
shareholder value.
Table of Contents
Acknowledgement of Country ................................ 2
Reserves & Contingent Resources ..................... 19
Our Purpose .......................................................... 3
Reserves ......................................................... 19
Chairman’s Foreword ............................................ 4
Contingent Resources ..................................... 20
Managing Director’s Report ................................... 6
Review of Operations .......................................... 22
Our Values ........................................................... 11
Safety .............................................................. 22
Our Business ....................................................... 12
Production ....................................................... 22
Our Social and Environmental Commitment ....... 13
Gippsland Basin .............................................. 22
Our Operations .................................................... 14
Otway Basin (Offshore) ................................... 24
Key Results .......................................................... 16
Otway Basin (Onshore) ................................... 25
Financial .......................................................... 16
Cooper Basin ................................................... 27
Operations & Reserves ................................... 17
Portfolio ............................................................... 28
Equity ............................................................... 17
Directors .............................................................. 30
Gas & Oil Revenue .......................................... 18
Executive Leadership .......................................... 34
Capital Expenditure ......................................... 18
Key Performance Indicators ................................. 39
COOPER ENERGY ANNUAL REPORT 2023
3
Chairman’s Foreword
This year Cooper Energy welcomed Jane Norman
as our Managing Director and CEO in March 2023.
Jane brings a wealth of gas and oil experience
following an international career spanning more than
20 years and is already driving a renewed focus on
operational excellence in the business.
2023 saw the retirement of David Maxwell, who
joined Cooper Energy in 2011 at a time when the
Company was a small oil-focused explorer. David
provided the leadership and strategic direction
to target the Southeast Australian gas market,
assembling the group of assets we have today,
and I acknowledge his contribution to the Company.
In FY23, our Company achieved a commendable
health and safety performance, with only one
recordable injury, a minor finger laceration. Our total
recordable injury frequency rate (TRIFR) of 4.38
per million hours worked reflects our commitment
to maintaining a safe work environment for our
employees. While we regret that the TRIFR rate was
not zero, it was ahead of the industry benchmark
of 5.68, underscoring our dedication to surpassing
industry safety standards.
During FY23, the Company achieved a significant
milestone, solidifying its position in the Southeast
Australian gas market through the successful
acquisition of the Orbost Gas Processing Plant.
The necessary processes to transfer operatorship
of the plant were completed in the course of FY23,
with operatorship transferred in the second half of
May 2023.
There have been significant operational challenges
in recent years, including during the transfer of
operatorship to us, and I acknowledge the frustration
caused for shareholders. Nevertheless, plant
ownership will have a significant positive impact on
the Company’s future cashflows. I welcome the new
Cooper Energy employees who have joined as a
result of the plant acquisition and thank everyone
for their efforts as we strive for improved plant
performance and reliability. There is more work to
be done, and the Orbost performance improvement
plan is a key operational priority for the Company
in FY24.
The Company achieved
a significant milestone,
solidifying its position in
the Southeast Australian
gas market through the
successful acquisition of the
Orbost Gas Processing Plant.
Under Jane’s leadership, changes have been made
to the executive leadership team, to ensure roles
have clear accountabilities for performance and
that the team is right sized for our operations now
and into the future. Chad Wilson will be our new
Chief Operating Officer and Nathan Childs will
move to the newly created role of Chief Corporate
Services Officer. Both executives have extremely
strong operational experience and are excellent
appointments reflecting the Company’s focus on
operational excellence.
FY24 Outlook
The Company enters FY24 with clear and well-
defined objectives. We must complete the BMG
abandonment programme on time and on budget,
and we must achieve meaningful performance
improvements at Orbost. The impact of the latter
to the Company’s incremental cashflow and future
prospects cannot be understated. Successful
outcomes on these two key projects reposition
4
COOPER ENERGY ANNUAL REPORT 2023 Board visit to Orbost Gas Processing Plant, August 2023
FY23 scorecard. We have made significant
organisational changes in order to achieve the
success that we all expect in FY24.
I thank all Cooper Energy staff for their hard work,
attention to detail and persistence.
The company’s long-term strategy is appropriate, and
we look forward to achieving improved outcomes for
shareholders in FY24 and beyond.
John Conde AO
Chairman
the company for faster growth including the Otway
Phase 3 Development (OP3D) project. We have the
team, structure and resources to succeed, and the
Board is confident that under Jane’s leadership we
will see improved outcomes for shareholders.
Concluding remarks
Despite the operational challenges at Orbost during
the transition of operatorship, we are achieving
record performance across the key metrics of
production, underlying EBITDAX and cashflow.
This is especially encouraging as operations at
the Athena Gas Plant were also interrupted by
unplanned downtime throughout the year. We expect
results will improve in FY24 as we bed down both
gas hubs, now supported by a fully functioning
engineering and technical support team.
On behalf of the Board, I express my genuine
appreciation to shareholders for their continued
patience. I acknowledge that FY23 was below
expectations which was reflected in the Company's
5
COOPER ENERGY ANNUAL REPORT 2023 Managing Director’s Report
This is my first Annual Report since joining Cooper
Energy as Managing Director and Chief Executive
Officer on 20 March 2023. I would like to thank
my predecessor, David Maxwell for leading the
business during more than 11 years of service to
Cooper Energy.
I recognise that this has been a challenging year
for the company, with production and financial
performance below target as reflected in the
FY23 company scorecard performance. This is a
disappointing result, and I intend to drive business
focus on clear accountability across the leadership
team, to foster a performance-focused culture.
However, I am pleased to see some early wins in
my tenure so far, including the safe and successful
transfer of operatorship of the Orbost Gas
Processing Plant (OGPP) to Cooper Energy
on 22 May.
An Operations Taskforce has been established,
focused on operational excellence, single point of
accountability and ensuring that our Operations
team have the right technical and commercial
support to maximise performance at both Athena
Gas Plant (AGP) and OGPP.
Through 2023, we have significantly de-risked the
execution of the BMG decommissioning project.
I am confident that the expert team we have in
Perth, including an experienced team of
contractors, will deliver the project safely, with
the desired outcomes
The release of the Mandatory Code of Conduct on
10 July confirmed that Cooper Energy is exempt
from the $12/GJ price cap as a small, domestic
market focused producer. Additionally, foundational
projects to support new gas developments will be
exempt from the Code’s expression of interest and
offer timing provisions, which will ensure investment
in new gas supply is not inadvertently discouraged.
Together with joint venture misalignment, the
Federal Government gas market intervention in late
2022 resulted in the delayed sanction of our Otway
growth project. I am optimistic that the reasonable
action by the Government in this case has opened
the door to ongoing communication about the urgent
need for more gas supply to come to market, such
as further development both onshore and offshore
in Victoria, to ensure supply to Australia’s largest
domestic gas market.
At Cooper Energy we
believe gas is not just a
transition fuel, but a
future fuel and that gas
will increasingly be
required to support the
world’s integration of
renewable power.
2023 IN REVIEW
Health, safety and the environment
I am proud to report that Cooper Energy delivered
its FY23 work with a strong health and safety record,
and exceptional environmental performance with
only minor recordable incidents. We have ended
the year with no Lost-Time Injuries and a Total
Recordable Injury Frequency Rate of 4.38 ahead of
the industry benchmark of 5.68. We will continue to
strive for improvement to ensure that all our people
go home safely from work.
Gas market and strategy
Australia requires new gas supply to keep up
with the demands of local manufacturing, industrial
facilities, heating for homes and businesses,
and to provide flexible, firming power for the
electricity network and support the integration
of variable renewables.
Cooper Energy is well positioned to capture more
market share, with our existing infrastructure
position in both the Otway and Gippsland Basins
6
COOPER ENERGY ANNUAL REPORT 2023 Sanction of the project was unfortunately delayed
this year, amidst the lack of joint venture alignment
and uncertainty of government policy. However, our
confidence in the ongoing need for new gas supply
continues to grow. There is no better opportunity than
to develop resources in the Otway, with a clear path
to commercialisation via existing gas processing
infrastructure that is close to market.
To enable future OP3D drilling, Cooper Energy
has worked with other operators in the region to
collectively secure the services of a drilling rig. The
drilling schedule is expected to commence in Q3
FY25. Cooper Energy has one firm well expected to
be drilled in FY26 and options to drill exploration and/
or development wells commencing circa late FY26
or FY27.
We will continue to progress joint venture alignment,
along with our other FY24 business priorities, to
position the project for FID.
Financial performance
FY23 production met revised guidance, although
this was lower than the original figure advised at the
start of the year due to ongoing operational issues at
OGPP and various unplanned maintenance outages
at AGP. These factors, combined with softer spot gas
prices caused by a mild start to winter, resulted in full
year underlying EBITDAX around the midpoint of the
revised guidance, but also below original guidance.
In FY24, we will focus on reducing operational costs
sustainably, including net G&A and the significant
costs associated with the plant variability, including
the weekly absorber cleans at OGPP.
BMG decommissioning
The largest component of our capital budget for FY24
is the delivery of the BMG decommissioning project.
Through the last 12 months, we have completed
a BMG pre-abandonment programme and locked
in the costs wherever possible. Pre-abandonment
activities commenced in June and were successfully
completed in July. This helps ensure a fast start
when the Helix Q7000 heavy well intervention vessel
arrives on location at BMG and also reduces the time
the Q7000 is on location, thereby reducing the overall
project cost.
and our portfolio of untapped Reserves and
Resources which can be developed back through
our existing infrastructure.
In November 2022, we announced our gas sales
agreement with AGL for the next phase of Otway
growth. We appreciate AGL as a high-quality
customer with the portfolio size and balance
sheet strength to underpin sanction of a new gas
development. Despite the project delays, AGL
remains committed to this opportunity.
Orbost Gas Processing Plant and
Gippsland growth opportunities
Our priority over the last year, as we prepared for
the operatorship of OGPP, has been to ensure
that we have the right skills and capabilities to
maximise our production output. This has included
an expert engineering team based in Melbourne
supporting both OGPP and AGP, and a new Plant
Superintendent joining us at OGPP who brings
experience in running major hazard facilities.
Since taking over operatorship of OGPP, our
dedicated internal engineering team has been
focused on production improvement workstreams
to reduce sulphur fouling in the absorber beds and
reduce the time taken for cleaning the absorber beds.
These include capturing immediate opportunities
such as reducing the offline time during weekly
absorber cleans.
In May 2023, we updated the prospective resource
assessment of our exploration portfolio within the
Gippsland Basin. Although our immediate focus is to
maximise production of Sole through OGPP, we see
real opportunity to not only backfill the plant, but also
to debottleneck and expand capacity, to meet the
growing supply-demand gap in the market.
Athena Gas Plant and Otway growth
opportunities
Our Otway assets have benefited from our increased
engineering support capability, with resolution of a
long-standing and systemic issue on one of the main
sales gas compressors in May.
We continue to optimise production from the Casino,
Henry and Netherby wells to lengthen the life of
the asset.
The Otway remains our focus for near-term
growth. Front end engineering and design work
is complete for the Otway Phase 3 Development
(OP3D) project, based on a three well development
plan backfilling the existing Casino, Henry and
Netherby fields.
7
COOPER ENERGY ANNUAL REPORT 2023 Sustainability
We are maintaining our Climate Active
organisational carbon neutral certification¹ by
offsetting our Scope-1, Scope-2 and relevant
Scope-3 emissions². This excludes downstream
transportation and combustion of products by
customers but allows us to offset emissions under
our direct control in addition to an increased
focus on reducing emissions from our operated
sites. We continue to use nature-based carbon
offsets including from our partnership with Canopy
Nature Based Solutions, a subsidiary of Greening
Australia, as well as carbon offsets from other
certified Australian and international projects. In
November 2022, we announced our contribution of
$250,000 towards the $1.1 million private-public-
NGO partnership to lay the foundations for high-
integrity nature-based carbon projects in Vietnam.
The partnership has the potential to deliver a large
number of high-integrity carbon credits to Cooper
Energy’s portfolio, while delivering biodiversity, social
and climate benefits.
With both AGP and OGPP now within our control,
our focus will turn towards identifying more physical
emissions reductions opportunities in our own
operations, especially value-accretive opportunities
to improve energy efficiency and reduce fuel
gas consumption.
2024 Outlook
In FY24, our immediate priorities are clear. We must:
• Maintain our strong health, safety and
environmental performance record;
• Maximise OGPP performance, with a clear,
deliverable plan to reach nameplate capacity
as soon as possible;
• Execute BMG abandonment safely, within
the minimum time possible and the mid-case
cost estimate;
• Right-size the business and deliver the cost-out
program announced in June;
• Maintain our Climate Active organisational
carbon neutral certification¹, in conjunction
with an increased focus on reducing carbon
emissions from our operations to reduce both
our emissions footprint and the cost associated
with offsets; and
• Move forward with our attractive Otway
Growth opportunities which leverage
existing infrastructure.
Orbost Gas Processing Plant
Concluding remarks
At Cooper Energy we believe gas is not just a
transition fuel, but a future fuel, and that gas will
increasingly be required to support the world’s
integration of renewable power. Australian
manufacturers, businesses and homes continue to
need access to reliable, low emissions, affordable
gas. We are very well positioned to supply this
into Southeast Australia. As we move forward
as a Company that is now the operator of two
strategically located gas plants, we aim to deliver
long-term, sustainable value to all shareholders and
stakeholders, customers and the communities in
which we work.
I want to thank our investors, the Board, the
Cooper Energy Management Team, our staff and
contractors, lenders, customers and suppliers for
supporting my transition into this role, and your
commitment to the success of Cooper Energy. I
look forward to an important financial year 2024,
in which we will deliver one of Australia’s largest
decommissioning projects and continue to make
much-needed gas available to Australian customers.
Jane Norman
Managing Director and CEO
¹Cooper Energy has been certified by Climate Active as a carbon neutral
organisation for its Scope-1, Scope-2 and relevant Scope-3 emissions
(embedded energy and business travel). See the 2023 Sustainability Report for
further information.
²Organisational carbon emissions voluntarily offset according to Climate
Active’s scheme for FY22. These consist of Scope-1 (direct), Scope-2
(purchased electricity) and 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 2023 Sustainability Report.
8
COOPER ENERGY ANNUAL REPORT 2023 Orbost Gas Processing Plant
9
COOPER ENERGY ANNUAL REPORT 2023 Awareness
Care
Commitment
Collaboration
Fairness & Respect
Integrity
Transparency
10
COOPER ENERGY ANNUAL REPORT 2023 Our Values
Cooper Energy is a values-driven
business with actions guided at all times
by our seven core values.
Fairness & Respect
Valuing diversity and
difference, acting
without prejudice and
communicating with
courtesy.
Integrity
Striving to be consistent,
staying true to our values
and accountable for our
actions.
Transparency
Being honest, addressing
problems and being clear
with our communications.
Awareness
Taking account of all
identified key issues in our
decisions and considering
future impacts.
Care
Prioritising safety, health,
the environment and
community.
Commitment
Staying focused on the
core objectives, making
pragmatic, and commercial
decisions and being
decisive with the courage of
our convictions.
Collaboration
Sharing ideas and
knowledge, encouraging
cooperation, listening to our
stakeholders and building
long-term relationships.
11
COOPER ENERGY ANNUAL REPORT 2023 Our Business
Cooper Energy is an Australian company providing
energy exclusively for the local domestic market.
Our headquarters are in Adelaide, with offices
in Perth and Melbourne. We operate two gas
processing facilities in regional Victoria which
produce 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.
Key Statistics
Orbost Gas Processing Plant
FY23 Production
2.0
10.7
2P Proved &
Probable Reserves¹
at 30 June 2023
2C Contingent Resources¹
at 30 June 2023
5
22
2
65
47.1
59.7 TJe/day
195
222 PJe
(36.3 MMboe)
229
296 PJe
(48.4 MMboe)
Conversion factors: 1bbl of oil = 1 boe,
1 bbl of condensate = 1 boe,
1 TJ = 0.163 kboe | 1 kboe = 6.12 TJe
¹As announced to the ASX 25 August 2023.
Other key statistics at 30 June 2023
Market cap
Net debt
Issued shares
Shareholders
Employees and contractors
12
Gippsland Basin gas & gas liquids
Otway Basin gas & gas liquids
Cooper Basin oil
$394.7 million
$80.9 million
2,631.5 million
9,039
128.9 FTE
COOPER ENERGY ANNUAL REPORT 2023 Our Social and
Environmental
Commitment
Gender Diversity
57% female representation
on the Board of Directors
27% total female workforce
Health, Safety &
Environment
Zero lost time injuries
Carbon Neutral
100% Scope-1, Scope-2
and relevant Scope-3
emissions offset¹
Maintaining Climate Active
Carbon Neutral Organisation
certification²
Offshore Gippsland Basin
¹Organisational carbon emissions voluntarily offset according to Climate Active’s
scheme for FY22. These consist of Scope-1 (direct), Scope-2 (purchased
electricity) and 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 2023 Sustainability Report.
²Cooper Energy has been certified by Climate Active as a carbon neutral
organisation for its Scope-1, Scope-2 and relevant Scope-3 emissions
(embedded energy and business travel). See the 2023 Sustainability Report for
further information.
13
COOPER ENERGY ANNUAL REPORT 2023 Our Operations
EXPLORATION,
DEVELOPMENT &
PRODUCTION
In the Otway and Gippsland
Basins we explore for,
develop, and produce
natural gas exclusively for
the Southeast Australian
gas market. In the Cooper
Basin onshore in South
Australia, we are a joint
venture partner in low-cost
oil production.
Offices
Cooper Basin
Otway Basin
Gippsland Basin
Perth
• Offshore project support
Adelaide
• Corporate head office.
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.
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 Otway Phase
Three Development.
• 50% Cooper Energy interest
in CHN
• 10% Cooper Energy interest in
VIC/L21 (Minerva)
Melbourne
• Engineering and
technical support.
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 Plant
• Processing hub for offshore
Gippsland Basin gas.
• 100% Cooper Energy interest.
Athena Gas Plant
• Processing hub for Otway
Basin gas.
• 50% Cooper Energy interest
14
COOPER ENERGY ANNUAL REPORT 2023
COOPER ENERGY ANNUAL REPORT 2023
15
Key Results
Financial
• Record production, up 7.8% to 59.7 TJe/d
(3.56 MMboe for the year)
• Record operating cashflow, up 8.7%
to $62.8 million
• Record underlying EBITDAX, up 35.4%
to $109.3 million
Sales revenue ($ million)
Operating cash flow ($ million)
205.4
196.9
62.8
57.8
48.1
131.7
75.5
78.1
20.5
8.1
FY19
FY20
FY21
FY22
FY23
FY19
FY20
FY21
FY22
FY23
Underlying EBITDAX ($ million)
Net (debt)/cash ($ million)
109.3
89.0
80.7
34.3
29.6
30.0
-53.9
FY19
FY20
FY21
FY22
FY23
-97.8
-126.7
-80.9
FY19
FY20
FY21
FY22
FY23
Underlying net profit ($ million)
Total equity ($ million)
13.3
14.4
-6.6
-5.6
498.4
496.9
433.7
351.1
325.8
FY19
FY20
-25.9
FY21
FY22
FY23
FY19
FY20
FY21
FY22
FY23
16
COOPER ENERGY ANNUAL REPORT 2023 Operations & Reserves
• Zero lost time injuries
• More than 1,400 days LTI free
• TRIFR below industry benchmark
• Third consecutive year of record production
Equity
Safety – Total recordable injury frequency rate
Share price (dollars per share at 30 June)
6.92
3.53
4.38
0.54
0.38
0.26
0.25
0.15
0.00
0.00
FY19
FY20
FY21
FY22
FY23
FY19
FY20
FY21
FY22
FY23
Production (TJe/d)¹
Basic earnings per share (cents per share at 30 June)
55.5
44.1
26.1
22.0
59.7
FY19
FY20
FY21
FY22
FY23
-0.7
-0.6
-1.8
-2.6
FY19
FY20
FY21
FY22
FY23
-5.3
Proved and Probable Reserves (PJe)²
Market capitalisation ($ million at 30 June)
322
305
288
875.6
242
222
610.0
583.1
424.1
394.7
FY19
FY20
FY21
FY22
FY23
FY19
FY20
FY21
FY22
FY23
¹1 MMboe = 6.11932 PJe
²As announced to the ASX on 25 August 2023
17
COOPER ENERGY ANNUAL REPORT 2023 Key Results
(Continued)
Gas & oil revenue
Gas
Total sales volume (PJ)
Total revenue ($million)
2P Reserves (PJ)¹
Average realised price ($/GJ)
Oil and condensate
Total sales volume (kbbl)²
Total revenue ($million)
2P Reserves (MMbbl)¹
Average realised price ($/bbl)
FY23
21.4
184.0
217.2
8.59
FY23
91.5
13.0
0.8
136.59
¹As announced to the ASX 25 August 2023
²Changes to PEL92 crude oil marketing arrangements came into effect 1 July 2022 which impacts FY23 comparisons with FY22. FY23 production
total 116.6 kbbls vs FY22 122.2 kbbls.
Capital expenditure
By activity ($million)
Exploration & appraisal
Development
TOTAL
By basin ($million)
Gippsland Basin
Otway Basin
Cooper Basin
Other
TOTAL
FY23
25.1
16.9
42.0
FY23
18.2
18.0
4.8
0.9
42.0
FY22
22.7
188.1
235.1
8.29
FY22
126.6
17.3
1.1
129.14
FY22
4.9
14.6
19.5
FY22
0.4
15.3
3.3
0.5
19.5
18
COOPER ENERGY ANNUAL REPORT 2023 Reserves & Contingent Resources
Reserves
Cooper Energy’s 2P gas and oil Reserves at 30
June 2023 are assessed to be 36.3 MMboe (222.2
PJe)¹. The key factors contributing to the reduction in
Reserves since 30 June 2022 include:
• Production of 3.6 MMboe in FY23
• Upward revisions of 0.5 MMboe (2P) in the
offshore Otway through production performance
and lower Athena turn-down rates
• Downward revisions of 0.2 MMboe (2P) in the
onshore Cooper Basin through reclassification of
some projects from Undeveloped to Contingent
and revised field limits
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).
Reserves at 30 June 2023¹
Category
1P Proved
2P Proved and Probable
3P Proved, Probable
and Possible
Dev.
Undev.
Sales gas (PJ)
Oil + cond (MMbbl)
Total (MMboe)² ³
148.6
0.3
24.6
3.3
0.0
0.6
¹As announced to the ASX on 25 August 2023
Total
151.9
0.4
25.2
Dev.
Undev.
214.7
0.8
35.9
2.5
0.0
0.5
Total
217.2
0.8
36.3
Dev.
Undev.
297.1
1.1
49.7
2.6
0.1
0.5
Total
299.7
1.2
50.2
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.
³ The conversion factor of 1 PJ = 0.163417 MMboe has been used to convert from sales gas (PJ) to oil equivalent (MMboe).
Year-on-year movement in Reserves
Category
Reserves at 30 June 2022¹
FY23 production²
Revisions/acquisitions
Reserves at 30 June 2023³
Unit
MMboe
MMboe
MMboe
MMboe
Proved and Probable 2P Reserves
Cooper
Otway
Gippsland
Total
1.1
(0.1)
(0.2)
0.8
3.7
(0.6)
0.5
3.6
34.7
(2.8)
0.0
39.5
(3.6)
0.3
31.9
36.3
¹As announced to the ASX on 22 August 2022
²Production from 1 July 2022 to 30 June 2023
³As announced to the ASX on 25 August 2023. Totals may not reflect arithmetic addition due to rounding.
19
COOPER ENERGY ANNUAL REPORT 2023 Reserves & Contingent Resources
(Continued)
Gummy Contingent Resources² slightly offset by
minor project and field-life timing related changes in
the Cooper and Otway Basins.
Contingent Resources
Cooper Energy’s 2C Contingent Resources at 30
June 2023 have increased by 11.5 MMboe since
30 June 2022 to 48.4 MMboe (295.9 PJe)¹. The
increase comes primarily from the new booking of
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).
²As announced to the ASX on 25 August 2023
Contingent Resources at 30 June 2023¹
Category
1C
2C
3C
Gas
(PJ)
Oil/Cond
(MMbbl
Total
(MMbbl)
Gas
(PJ)
Oil/Cond
(MMbbll)
Total
(MMbbl)
Gas
(PJ)
Oil/Cond
(MMbbl)
Total
(MMbbl)
Basin
Gippsland
100.9
Otway
Cooper
Total²
42.8
0.0
143.8
2.5
0.0
0.3
2.9
19.0
198.9
7.0
0.3
64.8
0.0
26.4
263.7
4.9
0.1
0.3
5.3
37.4
10.7
0.3
365.0
84.1
0.0
9.7
0.1
0.5
48.4
449.0
10.3
69.3
13.9
0.5
83.7
¹As announced to the ASX on 25 August 2023
²Totals 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.
Year-on-year movement in Contingent Resources
Category
Contingent Resources at 30 June 2022¹
Revisions
Contingent Resources at 30 June 2023²
Unit
MMboe
MMboe
MMboe
1C
23.7
2.7
26.4
2C
36.9
11.5
48.4
3C
55.3
28.4
83.7
¹As announced to the ASX on 22 August 2022
²As announced to the ASX on 25 August 2023. 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.
20
COOPER ENERGY ANNUAL REPORT 2023 Notes on calculation of Reserves and
Contingent Resources
Cooper 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 2023. 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 Andrew Thomas who is a full-time employee of Cooper Energy Limited holding the
position of General Manager Exploration, Subsurface & Projects. Mr Thomas holds a Bachelor of Science
(Hons), 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.
21
COOPER ENERGY ANNUAL REPORT 2023 Review of operations
Safety
Detailed information regarding Cooper Energy’s safety performance is provided in the 2023 Sustainability
Report. The 2023 Sustainability Report was published at the time of this Annual Report and can be viewed and
downloaded from the Company’s website.
Safety metrics
Hours worked
Recordable incidents
Lost-time injuries (LTI)
LTI frequency rate¹
Total recordable injury frequency rate (TRIFR)²
Industry TRIFR³
¹Per million hours worked
FY23
228,482
FY22
220,238
1
0
0
4.38
5.68
0
0
0
0.00
6.91
²TRIFR is recordable injuries (medical treatment injuries + restricted work/transfer case + lost time injuries + fatalities) per million hours worked. Calculated on a
rolling 12-month basis
³Industry TRIFR is the NOPSEMA benchmark for offshore Australian operations; data is updated 6-monthly; published at www.nopsema.gov.au
Production
Cooper Energy achieved record annual gas and oil production of 21.8 PJe (3.56 MMboe) in FY23, mainly due
to increasing gas production from the Sole field in the Gippsland Basin.
Production by basin at 30 June 2023¹
Gas (PJ) Oil & Cond. (kbbl)
Total (PJe)
Gas (PJ) Oil & Cond. (kbbl)
Total (PJe)
FY23
FY22
Gippsland Basin
Otway Basin
Cooper Basin²
TOTAL
17.2
3.9
-
21.1
-
3.6
116.6
120.1
17.2
3.9
0.7
21.8
15.2
4.3
-
19.5
-
3.0
122.2
125.2
15.2
4.3
0.7
20.2
¹MMboe = 6.11932 PJe
²FY22 oil production figures may vary compared to previously reported data as a result of production allocation reconciliations.
Gippsland Basin
Cooper Energy is the operator and 100% interest
holder for all its Gippsland Basin interests. As at 30
June 2023, these interests comprised:
• VIC/L32, which contains the Sole gas and gas
liquids 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
Acquisition and integration of the Orbost Gas
Processing Plant
The OGPP, located 14 kilometres from Orbost,
Victoria, is now fully owned and operated by Cooper
Energy, having been acquired in July 2022. This
facility processes the gas extracted from the Sole
field, with the final product sold into the Southeast
Australian gas market via the Eastern Gas Pipeline.
Cooper Energy's acquisition of OGPP was
announced on June 20, 2022 and the transaction
was finalised on July 28, 2022. Following the
acquisition, a transitional services agreement
(TSA) was established with the previous owner,
APA Group. Under this arrangement, APA Group
continued to operate OGPP on behalf of Cooper
22
COOPER ENERGY ANNUAL REPORT 2023 Energy until the major hazard facility license officially
transferred to Cooper Energy on May 22, 2023.
During this transitional period, plant performance
experienced instability, resulting in lower processing
rates than initially projected. Despite specific
performance-based incentives being included as
part of the acquisition, the threshold triggers for
these incentives were not met and as such none
were payable to the previous owner.
The total cost of acquiring the plant amounts to $270
million on an undiscounted basis, including deferred
payments of $40 million and $20 million in late July
2023 and late July 2024, respectively.
The Orbost performance improvement plan, which
has been underway in parallel with the transfer of
operatorship workstream, is now being accelerated
under Cooper Energy’s control, with specific tasks
identified and being tested, targeting incremental
increases to average processing rates. The great
majority of this activity does not involve significant
capital costs.
BMG abandonment
The BMG abandonment project in the Gippsland
Basin involves decommissioning seven wells,
using the Helix Q7000 abandonment vessel. In
FY23, key milestones achieved include detailed
Gippsland Basin
planning, equipment procurement, contract awards
for support vessels and services, engineering work
finalisation, readiness reviews, and pre-abandonment
programme planning. The pre-abandonment
programme was completed in July 2023.
The project aims to complete well abandonments
in the coming months, with future work required
to remove the remaining flowlines and subsea
infrastructure by December 31, 2026, complying
with regulatory requirements.
Exploration
During FY23, the Company focused on boosting
the potential for a future Manta Hub development,
covering VIC/RL13, VIC/RL14, VIC/RL15, and VIC/
P80. New 3D seismic data was obtained for these
areas in Q1 FY23, enhancing the understanding
of existing fields and providing opportunities for
deeper exploration.
An update on the prospective resource potential of
the Manta Hub was announced to the ASX on 15
May 2023. The combined mean unrisked prospective
resource potential from Manta Deep and Gummy
Deep (VIC/RL13), Chimaera East (VIC/RL15) and
Wobbegong (VIC/P80) is 1.3 Tcf of natural gas and
30 MMbbl of condensate.
Melbourne
VICTORIA
Orbost
E A STERN GAS PIPEL I N E
Orbost Gas Processing Plant
Lakes Entrance
VIC/P72 (100%)
Sweetlips
Moonfish
Snapper
Marlin
Barracouta
VIC/P75 (100%)
Veilfin
VIC/RL16 (100%)
Patricia-
Baleen
Longtom
Sunfish
Tuna
Moby
Judith
Kipper
Scallop
Grunter
Batfish
Angelfish
Flounder
Fortescue
To Sydney
To Sydney
Plan area
TA
VIC/P80 (100%)
Sole
Wobbegong
VIC/L32 (100%)
Manta
Manta Deep
Chimaera
VIC/RL15 (100%)
Chimaera East
Chimaera East
Basker
Gummy
Gummy Deep
VIC/RL13 (100%)
VIC/RL14 (100%)
Luderick
Bream
0
20
kilometres
Gippsland_160
Mackerel
Blackback
Kingfish
Cooper Energy
tenement
Gas field
Oil field
Gas pipeline
Oil pipeline
Prospect
23
COOPER ENERGY ANNUAL REPORT 2023 Review of operations
(Continued)
Otway Basin (offshore)
The Company’s interests in the offshore Otway
Basin as at 30 June 2023 comprised:
• a 50% interest in and operatorship of production
licences VIC/L24 and VIC/L30 containing the
producing Casino, Henry and Netherby gas
and gas liquids 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 which processes gas and gas liquids
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.
Exploration
A prospective resource update for six prospects
(Elanora, Heera, Isabella, Juliet, Nestor and Pecten
East) was announced on 9 February 2022. These
prospects all show strong seismic amplitude support
for the presence of gas and are located close to
existing production infrastructure. There has been
a total of 17 exploration wells drilled with seismic
amplitude support in the offshore Otway Basin to
date, across all operators, of which 16 have been
successful. Work continued during FY23 to progress
drilling options for testing the gas potential of these
exploration prospects in conjunction with OP3D.
Otway Phase 3 Development
The OP3D project is the cornerstone of the next
phase of Otway growth and provides an opportunity
to tie back new resources to existing gas processing
infrastructure at AGP, which has ~150 TJ/d of total
capacity and current utilisation of ~25 TJ/d.
It was planned that OP3D would move to FID in
FY23, however joint venture alignment, together with
the Federal Government’s gas market intervention,
impacted the timeframe for decisions on the project.
The Company nevertheless completed the OP3D
FEED workstreams in H2 FY23, based on a three
well development plan; this work having commenced
in early FY23.
To enable future OP3D drilling, Cooper Energy
has worked with other operators in the region to
collectively secure the services of a drilling rig. The
drilling schedule is expected to commence in Q3
FY25. Cooper Energy has one firm well expected
to be drilled in FY26 and options to drill exploration
and/or development wells commencing in circa late
FY26 or FY27.
OP3D is expected to be a multi-well development
that could include drilling the Nestor, Juliet and/
or Elanora prospects in addition to an Annie
development. The project is positioned to re-start
and proceed to sanction as soon as conditions
permit, most particularly Otway joint venture
partner support, along with our other FY24
business priorities.
24
COOPER ENERGY ANNUAL REPORT 2023 Otway Basin (offshore)
Otway Basin (onshore)
The Company’s interests in the onshore Otway Basin
as at 30 June 2023 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
In PEL 494 the Dombey 3D seismic survey
acquisition was completed in March 2022. The
surveyed area is located approximately 15 kilometres
west of Penola and covers 165 square kilometres.
The 3D seismic data was processed during FY23,
with final data available for interpretation in early
FY24. Assessments of the commercial potential
and future development of the Dombey gas field,
and further exploration drilling, will be evaluated
during FY24.
Additionally, existing 3D seismic surveys in PEP
168 were reprocessed in FY23. The new data has
improved the seismic quality compared to the legacy
dataset. Interpretation of the data will be undertaken
in H1 FY24, with new interpretation informing the
exploration strategy in the permit, including future
exploration drilling.
In PEP 171, which covers the Victorian side of
the Penola trough, progress has been made in
stakeholder engagement in advance of 100 square
kilometres of 3D seismic survey acquisition. The
anticipated timing to acquire this 3D data is currently
during the 2024/2025 summer and aligned with other
operators in the region to reduce costs.
25
COOPER ENERGY ANNUAL REPORT 2023 Otway Basin (onshore)
PEL 92 operations, Cooper Basin
26
COOPER ENERGY ANNUAL REPORT 2023 Development
First oil from the Bangalee field came online in
February 2023 from the Bangalee-1 well, with initial
30-day average gross rates in line with expectations.
Horizontal development wells were drilled in the
Rincon and Callawonga oil fields in Q3 FY23.
Rincon-4 and Callawonga-23 successfully targeted
the undeveloped McKinlay Formation.
Rincon-4 came online in June 2023 and
Callawonga-23 came online subsequent to year end.
Cooper Basin
The Company’s interests in the Cooper Basin as at
30 June 2023 comprised:
• a 25% interest in PRLs 85-104 (formerly PEL 92)
with the remaining interests held by the operator,
Beach Energy
The sale of PRL’s 231-233, PRL 237, PRL’s 207-209
(formerly PEL 100) and PRL’s 183-190 (formerly PEL
110) to Bass Oil Limited (“Bass”), for $0.65 million
was completed on 1 August 2022.
Exploration
No exploration wells were drilled in PRL’s 85-104
during FY23. Integration of the 2022 exploration
drilling results has been completed, including
the Bangalee-1 new field discovery. Work has
progressed to define the 2023 exploration and
appraisal programme, with exploration drilling likely
to commence in the first half of FY24.
Cooper Basin
e
g
d
e
Permia n
Rincon
North
Rincon
140°
AAAAAA
A
RRRRRRR
R
RRRRRRRRRRRRRRRR
RR
R
A
W
A
H
P A T C
HHH
H
GGGGG
G
UUUU
U
O
O
R
R
TT
T
T
Plan area
E
E
G
G
RI DII
RI D
TAS
GGGGGG MMM IMM
G M I
Callawonga
Bangalee
Elliston
Parsons
Perlubie
Germein
Butlers
Sellicks
Windmill
Christies
Silver Sands
Lycium Hub
HHHHH
H
O U GG
TR O U G
Cooper Energy
tenement
TRTT
RI
Gas field
REE
Oil field
M EMM
Gas pipeline
APP
PPPPP
Oil pipeline
NNNNNNNNNAAANNN
NAPPAM ERRI
PRLs 85 to 104 (25%) (ex PEL 92)
MOOMBA
0
10
20
30
kilometres
Cooper 99
27
COOPER ENERGY ANNUAL REPORT 2023 Portfolio
Cooper Energy Exploration & Production Tenements
Gippsland Basin
State
Victoria
Tenement
Interest
Location
Area (km²) Operator
Activity
VIC/P72
VIC/P75
VIC/P80
VIC/RL13
(Basker-Manta-Gunny)
VIC/RL14
VIC/RL15
VIC/RL16
(Patricia-Baleen)
100%
100%
100%
100%
100%
100%
100%
Offshore
Offshore
Offshore
Offshore
Offshore
Offshore
271
808
676
67
67
67
Cooper Energy
Exploration
Cooper Energy
Exploration
Cooper Energy
Exploration
Cooper Energy
Retention
Cooper Energy
Retention
Cooper Energy
Retention
Offshore
135
Cooper Energy
Retention
VIC/L32 (Sale)
100%
Offshore
203
Cooper Energy
Production
Otway Basin
State
Tenement
Interest
Location
Area (km²) Operator
Activity
South Australia
PEL 494
Victoria
PEL 680
PRL 32
PEP 168
PEP 171
VIC/P44
VIC/P76
VIC/L22 (Minerva)
VIC/L24 (Casino)
VIC/L30
(Henry & Netherby))
VIC/L33
VIC/L34
30%
30%
30%
50%
75%
50%
100%
10%
50%
50%
50%
50%
Onshore
Onshore
Onshore
Onshore
1,277
1,929
37
795
Beach Energy
Exploration
Beach Energy
Exploration
Beach Energy
Retention
Beach Energy
Exploration
Onshore
1,974
Vintage Energy
Exploration
Offshore
Offshore
Offshore
Offshore
Offshore
603
162
58
201
201
Cooper Energy
Exploration
Cooper Energy
Exploration
Woodside
Energy
Production
Cooper Energy
Production
Cooper Energy
Production
Offshore
126
Cooper Energy
Production
Offshore
6
Cooper Energy
Production
Cooper Basin
State
Tenement
Interest
Location
Area (km²) Operator
Activity
South Australia
PPL 204 (Sellicks)
PPL 205
(Christies-Silver Sands)
PPL 220 (Callawonga)
PPL 224 (Parsons)
PPL 245 (Butlers)
PPL 246 (Germein)
PPL 247 (Perlubie)
PPL 248 (Rincon)
PPL 249 (Ellison)
PPL 250 (Windmill)
ex-PEL 92¹
25%
25%
25%
25%
25%
25%
25%
25%
25%
25%
25%
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
2.0
4.3
5.5
1.8
2.1
0.1
1.5
2
0.8
0.6
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Onshore
1,889.3
Beach Energy
Exploration
¹ex-PEL 92 consists of PRL’s 85.86.87.88.89.90.92.93.94.95.96.97.98.99.100.101,102,103 and 104
28
COOPER ENERGY ANNUAL REPORT 2023 Orbost Gas Processing Plant
29
COOPER ENERGY ANNUAL REPORT 2023 Directors
CHAIRMAN
Mr John C. CONDE AO
B.Sc. B.E(Hons), MBA
INDEPENDENT NON-EXECUTIVE DIRECTOR
Appointed 25 February 2013
MANAGING DIRECTOR AND CEO
Ms Jane L. NORMAN
B.Sc.,B.Eng.(Hons) PGDip
GAICD
Appointed 20 March 2023
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 and Chairman of the Pymble Ladies’
College Council.
Current and other directorships in the last 3 years
Mr Conde is Chairman of The McGrath Foundation
(since 2013 and director since 2012). He is also
President of the Commonwealth Remuneration Tribunal
(since 2003) and Chairman of Dexus Wholesale
Property Fund (DWPF) (since 2020). Mr Conde is
former Deputy Chairman of Whitehaven Coal Limited
(ASX:WHC) (2007-2022) and former director of Dexus
Property Group (ASX:DXS) (2009–2020).
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
Ms Norman 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 J.P. Morgan Cazenove) and Goldman Sachs.
Ms Norman 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 Ms Norman 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. Ms Norman
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. Ms
Norman 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 Petroleum Production and
Exploration Association (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.
30
COOPER ENERGY ANNUAL REPORT 2023 INDEPENDENT NON-EXECUTIVE DIRECTOR
INDEPENDENT NON-EXECUTIVE DIRECTOR
Mr Timothy G. BEDNALL
LLB (Hons)
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.
Ms Victoria J. BINNS
B. Eng (Mining – Hons 1), Grad Dip SIA, FAusIMM,
GAICD
Appointed 2 March 2020
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 currently 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
Effective 19 August 2021 Ms Binns is the Chairman of
the Audit Committee and is a member of the Risk
& Sustainability Committee.
31
COOPER ENERGY ANNUAL REPORT 2023 Directors
(Continued)
INDEPENDENT NON-EXECUTIVE DIRECTOR
INDEPENDENT NON-EXECUTIVE DIRECTOR
Ms Giselle M. COLLINS
B. Ec, CA
GAICD
Appointed 19 August 2021
Experience and expertise
Ms Collins has broad executive and director experience
across finance, treasury and property disciplines. Ms
Collins is also active with not-for-profit organisations
and has a strong interest in sustainability across many
of her involvements.
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.
Current and other directorships in the last 3 years
Ms Collins is currently Chairman of AMP Limited’s listed
managed investment schemes (since 2020), a trustee
director of the Royal Botanic Gardens and Domain
Trust (since 2019), non-executive director of Generation
Development Group (since 2018), Chairman of Hotel
Property Investments Limited (ASX:HPI) (Chairman
since July 2022 and director since 2017) and Chairman
for Indigenous Business Australia in The Darwin Hotel
Pty Limited (since 2014).
Ms Collins is a former non-executive director
and Chairman of the following companies: Aon
Superannuation (2016-2017), The Travelodge Hotel
Group (2009-2013), The Heart Research Institute
Limited (2003-2011) as well as a 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.
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.
32
COOPER ENERGY ANNUAL REPORT 2023 INDEPENDENT NON-EXECUTIVE DIRECTOR
RETIRED MANAGING DIRECTOR
Mr Jeffrey W. SCHNEIDER
B.Com
INDEPENDENT NON-EXECUTIVE DIRECTOR
Appointed 12 October 2011
Mr David P. MAXWELL
M.Tech, FAICD
MANAGING DIRECTOR
Appointed 12 October 2011
Retired 20 March 2023
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 and a member
of the Governance & Nomination Committee.
Experience and expertise
Mr Maxwell is a leading oil and gas industry executive
with more than 25 years in senior executive roles
with companies such as BG Group, Woodside Energy
and Santos. Mr Maxwell led many large commercial,
marketing and business development projects.
Prior to joining Cooper Energy Mr Maxwell worked
with the BG Group, where he was responsible for
all commercial, exploration, business development,
strategy and marketing activities in Australia and led BG
Group’s entry into Australia and Asia including a number
of material acquisitions.
Mr Maxwell has served on a number of industry
association boards, government advisory groups and
public company boards.
Current and other directorships in the last 3 years
Mr Maxwell was on the board of the Australian
Petroleum Production & Exploration Association
(2018-2023).
Until Mr Maxwell’s retirement from Cooper Energy
he was a director of the Company’s wholly owned
subsidiary companies.
Special responsibilities
Prior to his retirement, Mr Maxwell was Managing
Director. He was responsible for the day-to-day
leadership of Cooper Energy and was the leader of
the Executive Leadership Team.
33
COOPER ENERGY ANNUAL REPORT 2023 Directors
Directors
(Continued)
(Continued)
Executive
Leadership Team
MANAGING DIRECTOR AND CEO
Ms Jane L. NORMAN
B.Sc.,B.Eng.(Hons) PGDip
GAICD
Ms Norman’s biography is shown in the Director’s
section of the report.
RETIRED INDEPENDENT
NON-EXECUTIVE DIRECTOR
Mr Hector M. GORDON
B.Sc. (Hons).
INDEPENDENT NON-EXECUTIVE DIRECTOR
26 June 2012 – 23 June 2017
NON-EXECUTIVE DIRECTOR
Appointed 24 June 2017
Retired 23 June 2023
Experience and expertise
Mr Gordon is a geologist with over 40 years’ experience
in the upstream petroleum industry, primarily in
Australia and Southeast Asia. He joined Cooper Energy
in 2012, initially as Executive Director – Exploration &
Production and subsequently moved to his position as
non-executive director in 2017.
Mr Gordon was previously Managing Director of
Somerton Energy until it was acquired by Cooper
Energy in 2012. Previously he was an Executive
Director with Beach Energy Limited, where he was
employed for more than 16 years. In this time Beach
Energy experienced significant growth and Mr Gordon
held a number of roles including Exploration Manager,
Chief Operating Officer and, ultimately, Chief
Executive Officer.
Current and other directorships in the last 3 years
Mr Gordon is a Non-Executive Director of Bass Oil
Limited ASX: BAS (since 2014).
Special responsibilities
Prior to his retirement, Mr Gordon was the Chairman of
the Risk & Sustainability Committee and a member of
the Audit Committee.
34
COOPER ENERGY ANNUAL REPORT 2023 CHIEF FINANCIAL OFFICER
Mr Daniel YOUNG
B. Com (Hons), MBA (Hons), CA, CFA
GENERAL MANAGER COMMERCIAL
& DEVELOPMENT
Mr Eddy GLAVAS
B. Acc. FCPA, MBA
Mr Young joined Cooper Energy in May 2022. Mr
Young is an energy professional with over 25 years of
experience in Australia, Asia, and Europe. Mr Young
joined Cooper Energy from Jadestone Energy plc
where he held the role of Chief Financial Officer for
over five years, based in Singapore. He also held the
role of Executive Director with Jadestone.
Prior to Jadestone, Mr Young was Head of APAC
Consulting for Wood Mackenzie and earlier worked for
13 years in J.P. Morgan’s investment banking coverage/
mergers & acquisitions group in Europe and Asia, most
recently as head of energy coverage in Southeast Asia
and South Asia. After completing his undergraduate
studies, Mr Young joined Deloitte where he qualified
as a Chartered Accountant. Mr Young is also a
CFA® charterholder.
Mr Glavas joined Cooper Energy in August 2014
and has more than 20 years of experience in
business development, finance, commercial, portfolio
management and strategy, including 18 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.
35
COOPER ENERGY ANNUAL REPORT 2023 Executive Leadership Team
(Continued)
GENERAL MANAGER EXPLORATION,
SUBSURFACE & PROJECTS
Mr Andrew THOMAS
B. Sc. (Hons)
HEAD OF OPERATIONS TASKFORCE
Mr Nathan CHILDS
B. Chem. Eng. (Hons)
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 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 Midstream. 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.
36
COOPER ENERGY ANNUAL REPORT 2023 CHIEF ADVISOR &
GENERAL MANAGER STRATEGY
COMPANY SECRETARY AND
GENERAL COUNSEL
Ms Ying LUO
B. Eng. (Hons), B. Sc. (Hons), MBA, Grad Cert.
Ms Nicole ORTIGOSA
BA LLB (Hons), Grad Dip Legal Practice
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 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.
37
COOPER ENERGY ANNUAL REPORT 2023 Executive Leadership Team
(Continued)
GENERAL MANAGER PEOPLE
& REMUNERATION
Mr Ashley HAREN
Dip. Bus. (HR/IR)
GENERAL MANAGER HSEC
& TECHNICAL SERVICES
Mr Iain MACDOUGALL
B. Sc. (Hons)
Mr Haren joined Cooper Energy in January 2021.
He has more than 25 years of experience in
human resource management in corporate and
operational roles. Mr Haren has worked for global
and domestic publicly listed and private entities within
the professional services, beverage, retail, mining,
and gas and oil sectors.
Prior to Cooper Energy, Mr Haren was the Global
Leader People & Culture – Operations with Woods
Bagot and spent nine years with Pernod Ricard
Winemakers including five years as HR Director –
Australia. His previous appointments included General
Manager HR for Australian Leisure & Hospitality, Group
HR Manager at Foster’s Limited and various HR roles
with Mt Isa Mines (Australia and Argentina) and
Santos Limited.
Mr MacDougall’s career in the upstream petroleum
exploration and production business spans more than
30 years, prior to which he worked in the nuclear
power industry and in automotive powertrain research
and development.
He gained extensive experience with international
oilfield services company Schlumberger, with
operational and management assignments in Australia,
Asia, the UK North Sea, Europe, West Africa and the
Middle East.
Since 2001, he has been based in Australia, initially
with independent Operator Stuart Petroleum as
Production and Engineering Manager and subsequently
as acting CEO prior to the takeover of Stuart Petroleum
by Senex Energy.
Mr MacDougall is an alumnus of Manchester University
in the UK and of the INSEAD Business School
in France.
38
COOPER ENERGY ANNUAL REPORT 2023 Key Performance Indicators
Operational
Production
2P Proved and
Probable Reserves
Wells drilled
Exploration wells
spudded
Reserves
replacement ratio¹
Financial
Sales revenue
Other income
Net profit / (loss)
before tax
Net profit (loss)
after tax
Cash and cash
equivalents
Other financial
assets
FY15
FY16
FY17
FY18
FY19
FY20
FY21
FY22
FY23
PJe
MMboe
#
#
%
2.9
3.1
9
4
2.8
3.0
1
-
5.9
11.7
9.1
52.4
8.0
52.7
9
1
4
2
-
-
9.5
49.9
18
4
16.1
47.1
20.3
39.5
21.8
36.3
1
-
2
2
2
-
333%
18%
768% 2380% (206%)
(65%)
17%
(65%)
24%
$ million
$ million
39.1
1.9
27.4
0.9
EBITDA
$ million
(58.4)
(37.4)
$ million
(18.8)
(26.0)
(7.0)
39.1
1.6
1.9
67.5
4.9
49.9
31.0
75.5
4.2
7.5
78.1
19.8
(75.2)
131.7
205.4
196.9
7.2
23.5
-
-
44.9
20.7
(13.2)
(110.0)
(33.5)
(22.7)
(104.7)
$ million
(63.5)
(34.8)
(12.3)
27.0
(12.1)
(86.0)
(30.0)
(10.6)
(68.5)
$ million
39.4
49.8
147.5
236.9
164.3
131.6
91.3
247.0
77.1
$ million
1.9
1.0
0.7
42.6
21.7
0.6
1.2
0.5
1.1
Working capital
$ million
43.0
44.2
84.0
154.0
131.8
90.4
30.3
190.3
(121.8)
Accumulated profit
$ million
(17.7)
(52.6)
(64.9)
(37.9)
(49.9)
(136.0)
(166.0)
(177.5)
(245.9)
Franking credits
$ million
43.7
Total equity
$ million
103.9
42.9
91.6
42.9
42.9
42.9
42.9
42.9
42.9
42.9
285.0
443.9
433.7
351.1
325.8
498.4
496.9
Earnings per share cents
(19.2)
(10.1)
(1.8)
1.8
(0.7)
(5.3 )
(1.8)
(0.6)
(2.6)
Return on
shareholder funds
Total shareholder
return
%
%
(46.7%)
(38.0%)
(6.5%)
7.4%
(2.6%)
(21.9%)
(8.9%)
(2.6%)
(13.8%)
(51.5%)
(12.2%)
72.7%
6.0%
40.3% (30.6%)
(30.7%)
(5.8%)
(38.8%)
Average oil price
$/bbl
85.48
60.75
61.89
99.61
106.19
83.75
79.56
129.46
136.59
Capital at 30 June
Share price
Issued shares
Market
capitalisation
$
#
0.245
0.215
0.380
0.385
0.540
0.375
0.260
0.245
0.150
331.9
435.2
1,140.2
1,601.1
1,621.6
1,621.6
1,631.0
2,379.8
2,631.5
$ million
81.4
93.6
433.3
616.4
875.5
608.1
424.1
583.1
394.7
Shareholders
#
5,103
4,931
6,292
6,622
6,758
8,094
9,355
9,198
9,039
¹The annual reserve replacement ratio is calculated based on the net 1P reserve additions for the year divided by annual production.
39
COOPER ENERGY ANNUAL REPORT 2023 40
COOPER ENERGY ANNUAL REPORT 2023 FINANCIAL REPORT
30 June 2023
COOPER ENERGY LIMITED
And its controlled entities.
ABN 93 096 170 295
41
COOPER ENERGY ANNUAL REPORT 2023 Table of Contents
Operating and Financial Review .......................... 43
Funding and Risk Management
Directors’ Statutory Report .................................. 60
Remuneration Report .......................................... 64
Consolidated Statement
of Comprehensive Income ................................... 88
Consolidated Statement
of Financial Position............................................. 89
Consolidated Statement
of Changes in Equity ........................................... 90
Consolidated Statement
of Cash Flows ...................................................... 91
Notes to the Consolidated
Financial Statements ........................................... 92
17. Interest bearing loans and borrowings ...... 115
18. Net finance costs ...................................... 115
19. Contributed equity and reserves ............... 116
20. Financial risk management ....................... 117
Group Structure
21. Interests in joint arrangements .................. 121
22. Investments in controlled entities .............. 122
23. Parent entity information ........................... 123
Other Information
Group Performance
24. Commitments for expenditure ................... 124
1. Segment reporting ........................................ 95
25. Contingent liabilities .................................. 124
2. Revenues and expenses ............................... 97
26. Share based payments ............................. 124
3. Income tax .................................................... 99
27. Related party disclosures ......................... 126
4. Earnings per share ..................................... 102
28. Remuneration of Auditors ......................... 126
29. Events after the reporting period .............. 126
Directors’ Declaration ........................................ 127
Independent Auditor’s Report to the Members
of Cooper Energy Limited .................................. 128
Auditor’s Independence Declaration to the
Directors of Cooper Energy Limited .................. 135
Securities Exchange and
Shareholder Information .................................... 136
Abbreviations and Terms ................................... 138
Corporate Directory ........................................... 139
Working Capital
5. Cash and cash equivalents and
term deposits .............................................. 103
6. Trade and other receivables ....................... 104
7. Prepayments .............................................. 104
8. Inventory ..................................................... 104
9. Trade and other payables ............................ 104
Capital Employed
10. Property, plant and equipment .................. 105
11. Intangible assets ....................................... 105
12. Exploration and evaluation assets ............ 106
13. Gas and oil assets .................................... 107
14. Impairment ................................................ 108
15. Provisions ................................................. 111
16. Leases ...................................................... 113
42
COOPER ENERGY ANNUAL REPORT 2023 Operating and Financial Review
For the year ended 30 June 2023
OPERATIONS
Cooper Energy Limited (“Cooper Energy” or the
“Company”) 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;
the Manta and Gummy gas and liquids fields in the
Gippsland Basin; and
• additional exploration and appraisal prospects in the
onshore and offshore Otway, offshore Gippsland and
Cooper Basins.
Health, safety and environment
Zero lost time injuries (“LTI”) and one medical treatment
injury (“MTI”) were recorded for the twelve months to 30
June 2023.
The medical treatment injury occurred at AGP in January,
where a contractor suffered a lacerated finger which
required stitches at the local medical clinic. Consequently,
the total recordable injury frequency rate (“TRIFR”) was
4.38 injuries per million hours worked, compared to 0.00
in the previous twelve months to 30 June 2022. This
remains below the industry benchmark of 5.68¹ injuries
per million hours worked.
There were two reportable environmental incidents
during the period. Both were as a result of emissions
exceedances at AGP above the limits specified in the
EPA licence conditions. The first, in March 2023, involved
emissions of carbon monoxide from a thermal oxidizer
exhaust. The second, in May 2023, involved emissions of
benzene from the same unit. The events were assessed
as not giving rise to actual or potential harm to either
human health or to the environment and were reported
to the Victorian EPA as required under regulations.
Both matters have been remedied with a revision to
operating procedures.
The Company is the operator of all its offshore activities,
including the OGPP and AGP, and non-operator of all its
onshore activities.
Orbost Gas Processing
Plant integration
Workforce
At 30 June 2023, the Company had 128.9 full time
equivalent (“FTE”) employees and 24.4 FTE contractors,
compared with 89.9 FTE employees and 13.3 FTE
contractors at 30 June 2022.
Employee numbers increased in FY23 as a result of the
transition of the OGPP into Cooper Energy operations,
and the associated increase in engineering resources
required to support both gas plants.
Changes to the organisational structure were made
in Q4 FY23, shortly after the commencement of the
new Managing Director and CEO, centred around the
formation of an operations taskforce. This taskforce
ensures a single point of accountability for operations,
maintenance, and engineering to ensure an integrated
approach to operations of both OGPP and AGP, and to
the performance improvement plan for OGPP.
Contractors are engaged via third parties in South
Australia, Western Australia and Victoria, and numbers
fluctuated in line with project requirements, including the
OGPP integration work which was finalised in Q4 FY23.
As of 30 June 2023, all contractors engaged by Cooper
Energy were contracted via third party providers.
The OGPP is located approximately 14 kms from Orbost,
Victoria and is 100% owned and operated by Cooper
Energy, following the acquisition of the plant in July 2022.
The plant processes gas from the offshore Sole field,
in the Gippsland Basin, and connects to the Southeast
Australian market via the Eastern Gas Pipeline.
Cooper Energy announced the acquisition of the
OGPP on 20 June 2022, with the transaction completing
on 28 July 2022, at which point Cooper Energy and the
seller, APA Group, commenced a transitional services
agreement (“TSA”).
The seller continued to operate the OGPP, pursuant to
the TSA, on behalf of Cooper Energy, until the plant’s
major hazard facility licence transferred to Cooper Energy
on 22 May 2023.
A largely contract workforce was engaged to complete
the integration workstreams including the major hazard
facility licence transfer, assurance reviews, operational
readiness, and additional environmental and pipeline
licence transfers.
During the transition to Cooper Energy operatorship,
plant performance was unstable, and as a result average
processing rates were less than anticipated. The
transaction to acquire the plant included performance-
¹NOPSEMA industry rolling 12-month TRIFR to 30 June 2023
43
COOPER ENERGY ANNUAL REPORT 2023 Operating and Financial Review
For the year ended 30 June 2023
based incentives for the seller, however the performance
hurdles were not met and as a result no performance
payments are payable to the seller.
The total consideration paid for the plant is $270 million,
which includes two deferred payments of $40 million
and $20 million to be paid in late July 2023 and late July
2024 respectively.
Reserves and Contingent Resources
Proved and Probable Reserves (2P) at 30 June 2023
are assessed to be 36.3 MMboe compared with 39.5
MMboe at 30 June 2022. Changes to 2P Reserves for
FY23 include production of -3.6 MMboe and 2P Reserves
revisions of +0.3MMboe. Contingent Resources (2C) at
30 June 2023 are assessed to be 48.4 MMboe compared
with 36.9 MMboe at 30 June 2022. 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
2023’, released on 25 August 2023.
Reserves and Contingent Resources
As at 30 June 2023¹
Gippsland Basin
Otway Basin
Cooper Basin
Total Cooper Energy
Proved and Probable Reserves (2P)
Contingent Resources (2C)
Gas
PJ
195.2
22.0
0.0
217.2
Oil &
condensate
MMbbl
Total
MMboe²
0.0
0.0
0.8
0.8
31.9
3.6
0.8
36.3
Gas
PJ
198.9
64.8
0.0
263.7
Oil &
condensate
MMbbl
4.9
0.1
0.3
5.3
Total
MMboe
37.4
10.7
0.3
48.4
¹As announced on 29 August 2023. Totals may not reflect arithmetic addition due to rounding. The method of aggregation is by arithmetic sum by category.
² The conversion factor of 1 PJ = 0.163417 MMboe has been used to convert from sales gas (PJ) to oil equivalent (MMboe).
Production
Gas and oil production for FY23 was 3.56 MMboe, or
9,766 boe/d, 7.8% higher than the prior year, mainly due
to increased gas production from Sole following improved
performance at OGPP.
Total gas production of 21.1 PJ, or 57.7 TJ/d, was
8.3% higher than the prior year. In the Gippsland
Basin, increased Sole production and improved OGPP
performance resulted in a 13.4% increase in gas
production to 17.2 PJ. In the Otway Basin, natural field
decline and processing interruptions at AGP contributed
to a 9.5% decline in gas production to 3.9 PJ (net to
Cooper Energy’s 50% share).
Oil and condensate production was 120.1 kbbl, or
329 bbls/d (net to Cooper Energy), 4.1% lower than the
prior year due to natural field decline in PEL 92 in the
Cooper Basin.
Production by product and basin is summarised in the
following tables.
Production
Production by product
Sales gas
Oil and condensate²
Total production
Production by basin
Gippsland Basin
Sole: sales gas
Otway Basin
Casino Henry: sales gas
Casino Henry: condensate
Cooper Basin
Oil¹
Total production
PJ
kbbl
MMboe
PJ
PJ
kbbl
kbbl
MMboe
FY23
21.1
120.1
3.56
FY23
17.2
3.9
3.6
116.6
3.56
FY22
19.5
125.2
3.31
Change
8.3%
(4.1%)
7.8%
FY22
Change
15.2
4.3
3.0
122.2
3.31
13.4%
(9.5%)
17.8%
(4.6%)
7.8%
² FY22 oil production figures may vary compared to previously reported data as a result of production allocation reconciliations.
44
COOPER ENERGY ANNUAL REPORT 2023 Operating and Financial Review
For the year ended 30 June 2023
Reserves and Contingent Resources
Orbost Gas Processing Plant
The Gas Code aims to ensure that Australian East Coast
gas users can contract for gas at reasonable prices and
on reasonable terms.
As noted above, while the acquisition of OGPP closed
on 28 July 2022, APA continued to operate the plant until
operatorship was transferred on 22 May 2023.
OGPP achieved an average gas processing rate of 47.1
TJ/d during FY23 (FY22: 41.5 TJ/d), with rates largely
dependent on the cycle time of the absorber cleans. The
polishing unit had limited impact during the year, although
showed promising signs with the plant able to achieve an
average of 55.9 TJ/d for the month of September 2022
when the unit was online for the majority of the month.
Although Sole gas production volume was 13.4%
higher in FY23 versus FY22, for the majority of FY23
plant performance was below expectations. Average
processing rates were hampered by regular plant trips,
shutdowns and incidents of operator error. Performance
continues to be impaired by foaming and fouling in
the sulphur recovery unit’s two absorbers, which has
constrained processing rates and required regular
maintenance and cleaning.
The Sole gas field continues to perform in line
with expectations.
Athena Gas Plant
AGP achieved an average gas processing rate of
10.7 TJ/d during FY23 (FY22: 11.8 TJ/d), with rates
impacted by unplanned downtime to the C701 export gas
compressor resulting in 31 days of deferred production
in H2 FY23. The investigation and remediation work to
the compressor is believed to have successfully solved
a long-standing systemic issue that has been present for
over a decade. Well cycling operations were implemented
throughout the year to optimise production from the
CHN fields.
Commercial
Key commercial activities during the financial year are
summarised below.
Gas sales agreement
In November 2022, Cooper Energy and AGL Energy
Limited agreed to enter into a new long-term gas sales
agreement (“GSA”) to supply up to 10 PJ of natural
gas per annum, for a term of up to six years. The GSA
volumes are anticipated to account for approximately
50% to 70% of the Cooper Energy share of Otway gas
production from the commencement of production from
the Otway Phase 3 Development (“OP3D”) project.
The GSA is conditional on an affirmative final investment
decision (“FID”) on OP3D.
Government Mandatory Gas Code
In July 2023 the Federal Government announced the
release of a Mandatory Gas Code of Conduct (“the
Gas Code”), legislated through the Competition and
Consumer (Gas Market Code) Regulations 2023.
Key elements of the Gas Code include:
• a price cap of $12/GJ, subject to an
exemptions framework;
•
information reporting obligations on the amount of
uncontracted gas to be marketed and produced; and
• minimum conduct and process standards for
commercial negotiations.
With annual production of less than 100 PJ, Cooper
Energy qualifies as a small domestic supplier under the
Gas Code and is therefore automatically exempt from the
$12/GJ price cap for any gas sales from 2024 onwards.
Foundational gas sales agreements to support the
commercialisation of undeveloped gas are also exempt
from the Gas Code’s expression of interest and offer
timing provisions, which will ensure investment in new
gas supply is not inadvertently discouraged.
Other suppliers can seek a conditional Ministerial
exemption from the price cap, for gas supply
agreements, by making satisfactory ACCC and
court-enforceable commitments.
Cooper Energy’s future gas marketing activities are not
expected to be materially impacted by complying with the
Gas Code’s requirements.
Changes to petroleum resource rent
tax (“PPRT”)
In early May, the Federal Government announced
changes to PRRT, in response to the Treasury
Gas Transfer Pricing Review together with the
recommendations from the earlier 2018 Callaghan
Review. Cooper Energy is largely unaffected by the PRRT
changes. The key change, introducing a 90% cap on the
use of deductions from 1 July 2023, applies tooffshore
LNG projects only and hence does not impact Cooper
Energy. The intention to legislate to exclude appraisal
costs from the definition of exploration with effect from
2013, is consistent with the Company’s current practise.
Regulatory reporting obligations
During the period Cooper Energy commenced reporting
of new information obligations under the National Gas
Amendment (Market Transparency) Rule 2022.
Cooper Energy is now subject to a suite of additional
weekly and annual information reporting obligations to
the Australian Energy Market Operator and the Australian
Energy Regulator, including reserves and resource
data, gas price assumptions and medium-term gas plant
processing capacity outlooks.
The Company regularly provides information to the
ACCC, AEMO and AER, and monitors compliance with
applicable regulatory reporting requirements.
45
COOPER ENERGY ANNUAL REPORT 2023 Operating and Financial Review
For the year ended 30 June 2023
Physical gas portfolio management
During FY23 Cooper Energy continued to improve its
physical gas portfolio management capability.
a small number of external expert consultants, and does
not involve significant capital costs.
Exploration
This capability enables the Company to deliver on
sales obligations, manage operational and financial risk,
and maximise total value, over both a short and long-
term horizon.
The FY23 exploration focus in the Gippsland Basin has
been on adding further potential to a future Manta Hub
development in VIC/RL13, VIC/RL14, VIC/RL15, and
exploration permit VIC/P80.
Cooper Energy’s physical gas portfolio management
activities include the use of:
•
short-term third-party gas purchase and
sale agreements;
• buying and selling gas within the Victorian Declared
Wholesale Gas Market; and
• pipeline transport and park services.
All customer nominations were met during the period,
in line with contractual obligations.
Cooper Oil processing and marketing
arrangements
Cooper Energy entered into a suite of revised
commercial arrangements effective on 1 July 2022 with
the Santos operated South Australia Cooper Basin joint
venture providing for the processing and marketing of
PEL 92 crude.
The new commercial arrangements include a crude
oil processing service agreement, a crude oil
transportation agreement and a liquids aggregation
agreement. The term of these three agreements run to
31 December 2023.
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 2023,
these interests comprised:
a) VIC/L32, which contains the Sole gas field;
b) 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);
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.
The Orbost performance improvement plan, which
has been underway in parallel with the transfer of
operatorship workstream, is now being accelerated under
Cooper Energy’s control, with specific tasks identified and
targeting incremental increases to average processing
rates. There are six major workstreams under the
performance improvement plan, with work expected to
occur throughout the remainder of calendar year 2023.
The majority of this activity comprises internal costs, with
New 3D seismic data acquired in 2020 covering VIC/
RL13, VIC/RL14, VIC/RL15 and VIC/P80 was licenced
from CGG in Q1 FY23. The new seismic data has
improved the structural definition of the existing BMG
gas and oil fields and exploration prospectivity below
and adjacent to existing fields. Future appraisal or
development of existing fields can be combined with
testing this deeper exploration potential.
An update on the Prospective Resource potential of
the Manta Hub in retention licences VIC/RL13, VIC/
RL14, VIC/RL15, and exploration permit VIC/P80 was
provided on 15 May 2023. The combined mean unrisked
Prospective Resource potential from Manta Deep and
Gummy Deep (VIC/RL13), Chimaera East (VIC/RL15)
and Wobbegong (VIC/P80) is 1.3 Tcf of natural gas and
30 MMbbl of condensate as announced to the ASX on 15
May 2023.
BMG abandonment
The BMG abandonment project in the Gippsland Basin
involves decommissioning seven wells as a first phase,
and subsequently the associated subsea infrastructure
as a second phase. The Helix Q7000 abandonment
vessel was contracted in September 2020 to perform the
work. Key milestones achieved in the BMG abandonment
project during FY23 include:
• detailed planning and ordering of long
lead equipment;
• awarding contracts to support vessels and services;
•
finalising detailed engineering work including activity
workshops with service contractors;
•
‘readiness to operate’ assurance review; and
• pre-abandonment programme planning for data
gathering and equipment interface checks at the BMG
well locations.
The pre-abandonment programme was completed in
July 2023.
It is planned to complete the abandonment activities
of the BMG wells by 31 December 2023 and remove
the remaining infrastructure by 31 December 2026, in
accordance with regulatory requirements.
In June 2023, the Company provided an update on the
cost estimates for the abandonment project, recognising
industry inflation on supporting contracts such as support
vessels, helicopters, rig work and other costs. The mid
case cost to complete the well abandonment is estimated
to be $193-$198 million on a 100% gross basis, with
approximately $27.9 million of this incurred in FY23.
46
COOPER ENERGY ANNUAL REPORT 2023 Operating and Financial Review
For the year ended 30 June 2023
The recently completed BMG pre-abandonment work
programme reduces risks on commencement when
the Q7000 arrives on location. The mid case cost
estimate incorporates contingencies for non-productive
time and weather delays, as well as an additional
general contingency.
While the Company’s focus will be on executing the
programme safely and within the minimum time possible,
there remain certain risks, including variables outside of
Cooper Energy’s control. These risks include delays to
the receipt of the rig beyond the nominated window under
the rig contract, greater than expected decommissioning
work in the event that we are unable to complete the
programme to NOPSEMA’s satisfaction, or other factors,
that could raise the total cost above the mid-case.
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 of the seven wells and related subsea
infrastructure of the BMG oil project.
Pertamina, via an Australian subsidiary, participated in
the BMG oil project during its production life and
Cooper Energy’s claim against Pertamina arises
with respect to obligations under the withdrawal and
abandonment provisions of the BMG joint operating
and production agreement.
OTWAY BASIN (OFFSHORE)
The Company’s interests in the offshore Otway Basin as
at 30 June 2023 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.
Exploration
A Prospective Resource update for six prospects
(Elanora, Heera, Isabella, Juliet, Nestor and Pecten
East) was announced on 9 February 2022. These
prospects all show strong seismic amplitude support for
the presence of gas and are located close to existing
production infrastructure. There has been a total of 17
exploration wells drilled with seismic amplitude support in
the offshore Otway Basin to date, across all operators, of
which 16 have been successful. Work continued during
FY23 to progress drilling options for testing the gas
potential of these exploration prospects in conjunction
with OP3D.
Development
Otway Phase 3 Development Project
The OP3D project is the cornerstone of the next phase
of Otway growth and provides an opportunity to tie back
new resources to existing gas processing infrastructure
at AGP, which has ~150 TJ/d of total capacity and current
utilisation of ~25 TJ/d.
AGP is a strategically important piece of energy
infrastructure; extrapolation from publicly available
analogue gas plant costs in Australia suggests the
estimated replacement cost of this plant is in the range
of $450 - 800 million, if it were constructed today.
Additionally, it is estimated that it would take at least five
years of planning and construction timing to commission
a plant of this scale in Victoria.
It was planned that OP3D would move to FID in
FY23, however joint venture alignment, together with
the Federal Government’s gas market intervention,
announced on 9 December 2022, and in particular the
proposed mandatory code of conduct including pricing
principles, impacted the timeframe for decisions on the
OP3D project. The Company nevertheless completed
the OP3D FEED workstreams based on a three well
development plan in H2 FY23, which had commenced
earlier in FY23. Resolution of the Federal Government’s
gas market intervention is summarised in the Commercial
section of this report.
To enable future OP3D drilling, Cooper Energy has
worked with other operators in the region to collectively
secure the services of a drilling rig. In Q4 FY23 a binding
award for the Transocean Equinox rig was agreed across
a consortium of four separate operators including Cooper
Energy. The consortium drilling schedule is expected to
commence in Q3 FY25. Cooper Energy has one firm
well expected to be drilled in H1 FY26 and options to drill
exploration and/or development wells commencing in late
FY26. OP3D is expected to be a multi-well development
that could include drilling the Nestor, Juliet and Elanora
prospects in addition to an Annie development.
In the same rig campaign, Woodside Energy, the
Operator of VIC/L22 (Cooper Energy share 10%), will
plug up to four subsea wells at the Minerva gas field as
soon as practicable before end of FY25.
OP3D is positioned to re-start and proceed to sanction
as soon as conditions permit, most particularly Otway
47
COOPER ENERGY ANNUAL REPORT 2023 Operating and Financial Review
For the year ended 30 June 2023
joint venture partner support, substantial progress of
the BMG abandonment programme, and higher average
processing rates and cash generation at OGPP as a
result of the performance improvement plan. Otway
growth will be funded from organic cash generation,
supported by the existing committed senior secured bank
facility as well as the $120 million accordion facility.
OTWAY BASIN (ONSHORE)
The Company’s interests in the onshore Otway Basin as
at 30 June 2023 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.
Exploration
In PEL 494 the Dombey 3D seismic survey acquisition
was completed in March 2022. The surveyed area is
located approximately 15 kilometres west of Penola
and covers 165 square kilometres. The 3D seismic data
was processed during FY23, with final data available
for interpretation in early FY24. Assessments of the
commercial potential and future development of the
Dombey gas field, and further exploration drilling, will be
evaluated during H1 FY24.
Existing 3D seismic surveys in PEP 168 were
reprocessed in FY23. The new data has improved
the seismic quality compared to the legacy dataset.
Interpretation of the data will be undertaken in H1 FY24.
The new interpretation will inform the exploration strategy
in the permit, including future exploration drilling.
In PEP-171, which covers the Victorian side of the
Penola trough, progress has been made in stakeholder
engagement in advance of 100 square kilometres 3D
seismic survey acquisition. The anticipated timing to
acquire this 3D data is currently during the 2024/2025
summer and aligned with other operators in the region to
reduce costs.
Onshore Otway well abandonment
PRL 32 permit was renewed until May 2028. The
remaining activity is abandonment of three wells
(Patrick-1, Hollick-1 and Jacaranda-2) that is anticipated
in calendar 2026.
COOPER BASIN
The Company’s interests in the Cooper Basin as at
30 June 2023 comprised:
a) a 25% interest in PRLs 85-104 (formerly PEL 92)
with the remaining interests held by the operator,
Beach Energy.
The sale of PRL’s 231-233, PRL 237, PRL’s 207-209
(formerly PEL 100) and PRL’s 183-190 (formerly PEL
110) to Bass Oil Limited (“Bass”), for $0.65 million
was completed on 1 August 2022. The sale to Bass
demonstrates Cooper Energy’s ongoing focus on portfolio
optimisation and divesting non-core assets.
Cooper Energy’s primary focus remains on
commercialising cost-competitive gas resources
for Southeast Australia.
Exploration
No exploration wells were drilled in PRL’s 85-104 during
FY23. Integration of the 2022 exploration drilling results
has been completed, including the Bangalee-1 new
field discovery. Work has progressed to define the 2023
exploration and appraisal programme, with exploration
drilling likely to commence in the first half of FY24.
Development
First oil from the Bangalee field came online in February
2023 from the Bangalee-1 well, with initial 30-day
average gross rates in line with expectations at around
670 bbls/d.
Horizontal development wells were drilled in the Rincon
and Callawonga oil fields in Q3 FY23. Rincon-4 and
Callawonga-23 successfully targeted the undeveloped
McKinlay Formation.
Rincon-4 came online in June and initially produced
300-350 bbls/d (gross 100%), although constrained
by trucking capacity. Callawonga-23 came online
subsequent to year end, with initial production estimated
at approximately 875 bbls/d (gross 100%).
Other Activities
Vietnam nature-based carbon project
The Company announced on 30 November 2022 its
participation in a A$1.1 million private-public-NGO
partnership in nature-based carbon offset projects in
Vietnam, intended to generate tradeable carbon credits.
The Department of Foreign Affairs and Trade is providing
funding and support to the project through the Business
Partnerships Platform. Contributions have been provided
by Cooper Energy and other implementation partners.
The pilot phase is focused on development of a circa
700-hectare reforestation carbon project scheduled for
implementation in 2025. Subject to a detailed feasibility
study, the project has the potential to involve more than
one million trees being planted, which would generate
approximately 16,000 tonnes of offsets per annum for
a crediting period of 25 years. The initiative has the
potential for significant scale expansion within Vietnam,
supporting Cooper Energy’s commitment to remain
carbon neutral for Scope-1, Scope-2 and relevant
Scope-3 emissions.¹
¹Cooper Energy has been certified by Climate Active as a carbon neutral organisation for its Scope-1, Scope-2 and relevant
Scope-3 emissions (embedded energy and business travel). See 2023 Sustainability Report for further information.
48
COOPER ENERGY ANNUAL REPORT 2023 Operating and Financial Review
For the year ended 30 June 2023
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.
Movement in underlying EBITDAX
30 June 2022 Vs 30 June 2023
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 FY23 underlying EBITDAX
of A$109.3 million, 35.4% higher than FY22 underlying
EBITDAX of A$80.7 million. There are several drivers
behind the change, which are summarised in the
chart below.
A$ Million
80.7
109.3
u-EBITDAX
FY22
Lower
Sales
Volumes
Fewer third
party gas
purchases
Higher
gas price
realisations
Lower
tolling
costs
Higher
production
costs
Lower
crude oil
revenue
Higher
G&A
Other
u-EBITDAX
FY23
The principal factors which contributed to the movement
in underlying EBITDAX between the periods included:
•
•
lower gas sales revenue of A$3.5 million attributed
to lower sales volumes compared to the previous
year (3.59 PJ in FY23, versus 3.83 PJ in FY22),
partially offset by higher realised gas prices across
the portfolio (A$8.59/GJ in FY23, versus A$8.30/GJ
in FY22);
third-party gas purchases and trading costs were
lower by A$17.1 million in FY23 due to the higher
processing rates at OGPP;
• production expenses were higher by A$33.3 million in
FY23, however more than offset by the A$54.0 million
saving in tolling costs due to the cessation of tolling
arrangements with APA following completion of the
acquisition of OGPP in late July 2022;
•
lower crude oil sales revenue of A$5.0 million,
due to lower volumes of lifted oil of 87.7 kbbls in
FY23, versus 125.2 kbbls in FY22 and an increase
in average price realisations to A$138.05/bbl in
FY23 (FY22: A$129.46/bbl). Production at PEL92
averaged 329 bbls/d in FY23 (FY22: 343 bbls/d)
which highlights the other key factor in FY23, namely,
the one-off change in PEL92 crude oil marketing
arrangements as of 1 July 2022, with revenue
recognised upon sale ex-Port Bonython instead of
at the inlet to the South Australia Cooper Basin joint
venture facilities at Moomba; and
• higher administration and other items of A$0.7 million.
The underlying loss after tax (exclusive of the items
noted below) was A$5.6 million compared with an
underlying profit after tax of A$14.4 million in FY22.
Factors driving the change, in addition to those listed
above for underlying EBITDAX, included:
• higher amortisation and depreciation of A$44.8
million of gas and oil assets and property, plant
and equipment, primarily due to higher production,
depreciation associated with OGPP and the reset of
restoration provisions as at 30 June 2022;
• higher net finance costs of A$12.9 million, mostly
due to higher accretion expense of the Company’s
restoration provisions (which were reset at 30 June
2022); and
• higher tax benefit of A$8.9 million.
The Company’s statutory loss after tax was A$68.5
million, which compares with a loss after tax of A$10.6
million recorded in FY22. The FY23 statutory loss
included a number of significant items considered to fall
49
COOPER ENERGY ANNUAL REPORT 2023 Operating and Financial Review
For the year ended 30 June 2023
outside underlying operating performance, which
affected the result by a total of A$62.9 million.
These items comprise:
• non-cash restoration expense of A$46.3 million
resulting from a reassessment of the Patricia Baleen,
BMG and Minerva Field decommissioning provisions;
• a non-cash impairment expense of A$26.1 million in
respect of the Casino Henry Netherby CGU;
• OGPP acquisition costs, integration costs that
were not capitalised, and reconfiguration and
commissioning works under the TSA of A$6.2 million;
• normalisation of the July APA toll of A$2.9 million;
•
leadership restructuring costs of A$2.7 million;
• doubtful debts expense of A$2.8 million;
• other expense of A$1.7 million in respect of the
National Oil & Gas Australia Pty Ltd Commonwealth
Government levy; and
•
tax impact of the above items of A$25.8 million.
Accounting for the financing and acquisition
of OGPP
The acquisition of the OGPP completed in July 2022,
alongside the institutional and retail equity offering and
new underwritten revolving corporate debt facility. The
accounting impacts of the transaction are as follows:
• OGPP capitalised to property, plant and equipment at
a value of A$374.0 million (including A$210.0 million
of upfront consideration, A$58.1 million of deferred
consideration and A$27.0 million of capitalised
acquisition and transaction costs, and A$78.9 million
in relation to the restoration obligations acquired);
• deferred consideration of A$58.1 million recognised
as trade payables (with A$40.0 classified as a current
payable and A$19.3 million as non-current). The
Company will not pay any of the up to A$60.0 million
of additional performance linked incentive payments
that were agreed last year;
•
transaction costs of A$15.1 million associated with
the new debt facility are capitalised and net off
against the current utilised amount. A$1.1 million of
these costs are amortised to the income statement
via the effective interest rate: and
• gross new equity capital raised was A$244.0 million.
After transaction costs of A$8.4 million, net cash
proceeds were A$235.6 million. Of this, an after
tax amount of A$179.5 million was recognised
within reserves in equity in FY22, representing the
institutional portion of the raise which was received
by the Company on 30 June 2022. This was
subsequently transferred to share capital in July 2023
with the issuance of the shares. The after tax retail
portion of the raise of A$58.6 million was recognised
in H1 FY23. Costs of A$1.5 million incurred in FY23
cannot be offset within share capital and are therefore
included within the income statement.
Financial Performance
Production volume
Sales volume
Revenue
Gross profit
Underlying EBITDAX*
Operating cash flow
Underlying profit/(loss) before tax
Underlying profit/(loss) after tax
Reported loss after tax
Cash, other financial assets
and investments
MMboe
MMboe
A$ million
A$ million
A$ million
A$ million
A$ million
A$ million
A$ million
A$ million
FY23
3.56
3.59
196.9
32.5
109.3
62.8
(41.8)
(5.6)
(68.5)
78.2
FY22
3.31
3.83
205.4
47.8
80.7
57.8
2.2
14.4
(10.6)
247.5
Change
0.25
(0.24)
(8.5)
(15.3)
28.6
5.0
(44.0)
(20.0)
(57.9)
%
7.8%
(6.3%)
(4.1%)
(32.0%)
35.4%
8.7%
N/M
N/M
N/M
(169.3)
(68.4%)
* Earnings before interest, tax, depreciation, amortisation, restoration, exploration and evaluation expense and impairment
50
COOPER ENERGY ANNUAL REPORT 2023 Operating and Financial Review
For the year ended 30 June 2023
Operating cashflows for the period were A$62.8 million
in FY23, 8.7% higher than in FY22 of A$57.8 million. The
main line items for operating cashflow comprised:
•
•
cash generated from operations of A$96.7 million
(FY22: A$82.5 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 prepared on an accruals basis;
restoration costs of A$19.6 million (FY22: A$6.1
million), up mostly due to the increasing level of
activity in the lead up to the wells abandonment
activity at BMG in FY24;
• petroleum resource rent tax (PRRT) payments of
A$6.2 million (FY22 A$0.9 million), due to higher
deductible expenditure in FY22; and
• net interest paid of A$8.1 million (
FY22: A$9.2 million).
Financing, investing and other cash flows for the
period were A$233.7 million (FY22: A$96.4 million)
and primarily included:
•
•
the OGPP upfront acquisition cost of A$210.0 million,
plus other acquisition and financing costs of A$27.0
million (FY22: A$6.5 million);
remaining net proceeds from the equity issue,
being the retail portion of the entitlement offer,
of A$57.6 million (FY22: A$178.0 million being
the institutional portion);
• exploration, intangibles, development and property,
plant and equipment costs of A$38.6 million, mainly
in relation to the OP3D select phase, OGPP, Athena
Gas Plant and general exploration and evaluation
activity (FY22: A$20.8 million);
• proceeds from held for sale assets of A$0.7 million
(FY22: nil);
•
repayment of lease liability of A$1.3 million (FY22:
A$1.1 million);
• net repayment of borrowings of nil (FY22:
A$60.0 million);
• prepaid financing costs of A$15.1 million (FY22:
nil), being the costs associated with the refinancing
and expansion of the senior secured revolving credit
facility; and
•
foreign exchange revaluation and other of A$1.0
million (FY22: A$1.8 million).
Excluding the one-off impacts associated with the OGPP
acquisition and financing, cash and cash equivalents
increased by A$24.6 million over the period, as
summarised in the following chart.
51
COOPER ENERGY ANNUAL REPORT 2023 Operating and Financial Review
For the year ended 30 June 2023
Movements in cash and cash equivalents
30 June 2023 vs 30 June 2022
A$ million
A$ million
Total cash and
cash equivalents,
other financial
assets and
investments
Total cash and
cash equivalents,
other financial
assets and
investments
57.6
57.6
0.5
0.5
247.0
247.0
Jun-22
Jun-22
(210.0)
(210.0)
Restoration cash
Restoration cash
flows primarily
flows primarily
relate to costs
relate to costs
associated with
associated with
BMG
BMG
(19.6)
(19.6)
(6.2)
(6.2)
(8.1)
(8.1)
96.7
96.7
(27.0)
(27.0)
(15.1)
(15.1)
OGPP Acquisition
(194.5)
OGPP Acquisition
(194.5)
52.5
52.5
Operating
Operating
62.8
62.8
Capex includes
costs associated
with OGPP
transition &
OP3D FEED
Capex includes
costs associated
with OGPP
transition &
OP3D FEED
(38.6)
(38.6)
115.3
115.3
Total cash and
Total cash and
cash equivalents,
cash equivalents,
other financial
other financial
assets and
assets and
investments
investments
78.2
78.2
0.7
0.7
(1.3)
(1.3)
1.0
1.0
1.1
1.1
Other
(38.2)
Other
(38.2)
77.1
77.1
Proceeds from
equity issue
Proceeds from
equity issue
OGPP purchase Stamp duty and
acquisition costs
OGPP purchase Stamp duty and
acquisition costs
Financing and
other costs
Financing and
other costs
Cash after
OGPP
acquisition
Cash after
OGPP
acquisition
Operations
Operations
Restoration
Restoration
PRRT
PRRT
Interest
Interest
Cash
after OCF
Cash
after OCF
Capex
Capex
Proceeds from
held for sale
assets
Proceeds from
held for sale
assets
Lease
liabilities
Lease
liabilities
FX &
other
FX &
other
Jun-23
Jun-23
Cash & cash equivalents
Cash & cash equivalents
Other financial assets and investments
Other financial assets and investments
52
COOPER ENERGY ANNUAL REPORT 2023
COOPER ENERGY ANNUAL REPORT 2023
53
Operating and Financial Review
For the year ended 30 June 2023
FINANCIAL POSITION
Total equity
Financial
Position
Total
assets
Total
liabilities
Total
equity
Net
(debt)/
cash¹
A$
million
A$
million
A$
million
A$
million
FY23
FY22 Change
%
1,344.4 1,200.0
144.4 12.0%
847.5
701.5
146.0 20.8%
496.9
498.4
(1.5)
(0.3%)
(80.9)
89.0
(169.9)
N/M
Total equity decreased by A$1.5 million from A$498.4
million to A$496.9 million. In comparing equity at 30 June
2023 to 30 June 2022, the key movements were:
• higher contributed equity of A$238.4 million due to
transfer of proceeds from the institutional portion
of the June 2022 equity raise from reserves,
shares issued under the non-institutional portion
of the entitlement offer in July 2022 plus vesting of
performance rights during the period;
•
lower reserves of A$171.6 million due to transfer of
proceeds from the institutional portion of the June
2022 equity raise to share capital; and
• higher accumulated losses of A$68.5 million due to
the statutory loss for the period.
¹ Net debt above is based on drawn debt of A$158.0 million. Debt per Balance
sheet is A$143.9 million which includes $A14.1million of prepaid financing
costs.
STRATEGY AND OUTLOOK
Total assets
Total assets increased by A$144.4 million from
A$1,200.0 million at 30 June 2022 to A$1,344.4 million
at 30 June 2023.
At 30 June 2023, the Company held cash and cash
equivalents of A$77.1 million and investments of
A$1.1 million.
Property, plant and equipment increased by A$321.1
million from A$59.2 million at 30 June 2022 to A$380.4
million at 30 June 2023, due to the acquisition of the
OGPP, with the transaction closing for accounting
purposes on 28 July 2022, offset by impairment of the
Athena Gas Plant. Gas and oil assets decreased by
A$59.5 million from A$595.4 million to A$535.8 million,
mainly as a result of amortisation driven by production
and impairment of the Casino Henry Netherby assets.
Exploration and evaluation assets increased by A$19.7
million from A$164.9 million to A$184.6 million, as a
result of general exploration and evaluation activity, offset
by impairment of the Annie exploration asset.
Total liabilities
Total liabilities increased by A$146.0 million from
A$701.5 million at 30 June 2022 to A$847.5 million at
30 June 2023.
Provisions increased by A$107.0 million from
A$476.6 million to A$583.6 million, primarily driven by the
recognition of the OGPP restoration provision and a reset
of certain other provisions.
The sum of current and non-current trade and other
payables increased by A$55.2 million year-on-year, with
the majority of this increase due to the delayed purchase
consideration of OGPP due to APA Group, which is
$59.3 million inclusive of discounting.
Cooper Energy remains focused on playing a pivotal role
in Australia’s energy future, by commercialising gas for
Australian customers.
We are committed to delivering domestic gas to
our customers, who include manufacturers, major
energy generators and retailers including for gas-fired
power generation.
Gas fired power is a key established electricity generation
technology that provides fast start dispatchable firming
power to support an increasing percentage of variable
renewables in the electricity market.
We operate with an emphasis on health and safety,
environmental and sustainability compliance, reliability
and shareholder value.
In FY24, our strategic imperatives are to:
•
improve the operating performance of OGPP to
maximise production into the Southeast Australian
gas market and capture high spot market prices;
• execute BMG abandonment on schedule and
on Budget;
•
reduce fixed costs across our business;
• work to partner with others to unlock Otway
growth opportunities;
• progress exploration, appraisal and development
activities within Cooper Energy’s existing portfolio of
growth opportunities, across the Company’s twin gas
hubs; and
• maintain our voluntary organisational carbon neutral
certified¹ position with an added focus on physical
abatement opportunities to reduce the absolute
quantum of our Scope-1 and Scope-2 emissions.
¹ Cooper Energy has been certified by Climate Active as a carbon neutral organisation for its Scope-1, Scope-2 and relevant
Scope-3 emissions (embedded energy and business travel). See 2023 Sustainability Report for further information.
54
COOPER ENERGY ANNUAL REPORT 2023 Operating and Financial Review
For the year ended 30 June 2023
FUNDING AND CAPITAL
MANAGEMENT
At 30 June 2023, the Company had cash reserves of
$77.1 million and drawn debt of $158.0 million. The
Company has a reserves based lending debt facility with
a committed limit of A$400.0 million (excluding a A$120.0
million accordion facility), to be used for general corporate
purposes. Management plans to utilise the facility to part
fund the BMG abandonment project as well as a portion
of the planned OP3D development 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$7.7 million has
been utilised in respect of bank guarantees as at 30 June
2023. The facility also includes an additional amount of
up to $120.0 million, under an accordion facility, subject
to certain terms and conditions. The Company’s liquidity
position is illustrated in the following chart:
Funding and liquidity
A$ Million
158.0
20.0
120.0
400.0
7.7
77.1
Cash & cash
equivalents
30/06/2023
RBL
committed
funding
Drawn
portion at
30/06/2023
Working
capital
facility
Utilisation
30/06/2023
451.4
Additional
accordian
Adjusted
subtotal
including
accordian
331.4
Cash &
committed
undrawn
funding
30/06/2023
Further information is detailed in the Basis of
preparation and accounting policies section of the
Financial Statements.
leadership team revise risk assessments and review
risk management actions for corporate level risks on a
regular basis.
The Company continues to assess accretive funding
options as it pursues growth opportunities.
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 continually
reviewed and revised to provide effective management
of operational and business risks. The executive
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 regularly 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.
55
COOPER ENERGY ANNUAL REPORT 2023 Operating and Financial Review
For the year ended 30 June 2023
Risk
Description
Orbost
Gas Plant
performance
BMG wells
abandonment
execution
The OGPP is producing at below nameplate
production capacity. Continuation of the
under performance of the Thiopaq H2S
removal process presents an ongoing
production, revenue, and operating cashflow
risk. Cooper Energy is progressing an
improvement project targeting the Thiopaq
process under performance, and specifically
the impacts associated with sulphur deposition and
fouling in the absorbers.
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.
The Helix Q7000 intervention vessel is
scheduled to commence abandonment works
at seven Basker and Manta field wells in H1
FY24. Risks associated with the execution of
the abandonment campaign include safety
and environmental incidents, unexpected
technical well conditions that prolong
abandonment activities, project delays due to
regulatory and/or contractual uncertainty, and
failure of critical equipment.
Cooper Energy has a comprehensive
approach to the management of health,
safety and environmental. The company’s project
management systems integrate technical and
engineering requirements aimed at mitigating
project execution risks.
Actions taken to reduce execution risks during the
abandonment programme include completion of
an offshore pre-abandonment campaign prior to
arrival of the Q7000, independent assessment of
the abandonment programme by regulators and
external auditors, completion of an abandon-well-
on-paper exercise, and pre-operation readiness
assessments of the Q7000 and key equipment.
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 environmental incident could
jeopardise Cooper Energy’s licence to
operate, leading to delays, disruption
and potentially 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
The ability for Cooper Energy to execute
growth activity in a joint venture (“JV”) can
be impacted by the 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.
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.
56
COOPER ENERGY ANNUAL REPORT 2023 Operating and Financial Review
For the year ended 30 June 2023
Risk
Description
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 will also seek, from time to time,
to access third-party capital to accelerate
organic and 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.
Changes can prolong compliance, delay approvals
and escalate costs, impacting the company’s
financial position or expected financial returns.
Federal or State Government intervention,
legislative, policy or guideline changes can
impact Cooper Energy’s operations and
share value.
Cooper Energy engages with Federal and State
governments and regulators on a regular basis to
maintain open channels of communication.
Climate
change
& energy
transition
Cooper Energy recognises its activities
may be subject to increasing regulation and
costs associated with climate change and
the management of carbon emissions.
electricity) and relevant Scope-3 emissions
(e.g. embedded energy and business travel),
with a blend of Australian and international
carbon credits.
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 lower
carbon 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
The Company’s carbon neutral status¹ 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 investigating opportunities to
invest in carbon credit origination projects, both
in Australia and overseas. Carbon credits allow
us to mitigate the impact of our emissions now
while taking cost effective action to reduce future
emissions through various efficiency projects.
57
COOPER ENERGY ANNUAL REPORT 2023 Operating and Financial Review
For the year ended 30 June 2023
Risk
Description
Climate
change
& energy
transition
(Continued)
In respect of energy transition risk, the
Company’s core gas assets are resilient
to the threat of demand loss from climate
change. AEMO scenarios indicate that
although gas demand may slowly reduce
in Cooper Energy’s markets, gas supply is
declining even faster in the Southern states
of Australia, creating a significant supply-
demand gap. This creates an opportunity for
Cooper Energy 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 conventional energy source
for heating and industrial use, where limited
cost effective or practical alternatives are
available, and secondly, to provide firming of
variable renewable power generation as the
electricity network continues to decarbonise.
The focus of the Company’s strategy on
conventional gas production, located in Southeast
Australia close to its market, is conducive to
lower overall emissions intensity compared to
more remote domestic gas sources or imported
Liquefied Natural Gas (“LNG”) supply.
The Company measures and publicly reports its
emissions and emissions offsets to maintain its
carbon neutral¹ 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 20 of the 2022
Sustainability Report for further information.
AGP asset
performance
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 risk 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 presents an ongoing
production, revenue, and operating cashflow
risk. 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 loss associated with operating events
through insurance.
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.
Access to
skills and
capabilities
Cooper Energy relies on the ability to
attract and retain people with the right skills,
behaviors 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
workplace culture designed to attract and
retain the skills and experience needed to
deliver business objectives. We aim to appeal
to a diverse group of individuals and ensure their
inclusion in our ‘one team’ ethos as core personnel.
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.
¹Cooper Energy has been certified by Climate Active as a carbon neutral organisation for its Scope-1, Scope-2 and relevant
Scope-3 emissions (embedded energy and business travel). See 2023 Sustainability Report for further information.
58
COOPER ENERGY ANNUAL REPORT 2023 Operating and Financial Review
For the year ended 30 June 2023
Reconciliations for net loss to nnderlying net loss and underlying EBITDAX
Reconciliation to
underlying EBITDAX¹
Underlying loss
Add back:
Tax impact of underlying
adjustments
Net finance costs
Accretion expense
Tax benefit
Depreciation
Amortisation
Exploration and evaluation
expense
A$ million
A$ million
A$ million
A$ million
A$ million
A$ million
A$ million
A$ million
Underlying EBITDAX
A$ million
Reconciliation to
underlying loss²
Net loss after income tax
A$ million
Adjusted for:
OGPP reconfiguration and
commissioning works
OGPP acquisition costs
OGPP integration costs
Doubtful debts
APA toll normalisation
Leadership restructuring costs
Restoration expense/(income)
NOGA levy
Impairment
Tax impact of underlying
adjustments
Underlying loss
A$ million
A$ million
A$ million
A$ million
A$ million
A$ million
A$ million
A$ million
A$ million
A$ million
A$ million
FY23
(5.6)
25.8
8.5
18.0
(36.2)
38.7
60.1
-
109.3
FY23
(68.5)
0.4
1.5
4.3
2.8
2.9
2.7
46.3
1.7
26.1
(25.8)
(5.6)
FY22
14.4
10.7
9.1
4.5
(12.2)
3.4
50.6
0.2
80.7
FY22
(10.6)
Change
(20.0)
%
(138.9%)
15.1
141.1%
(0.6)
13.5
(24.0)
35.3
9.5
(0.2)
28.6
(6.6)%
300.0%
(196.7%)
N/M
18.8%
N/M
35.4%
Change
(57.9)
%
N/M
15.1
(14.7)
(97.4%)
-
-
-
-
-
19.0
1.6
-
(10.7)
1.5
4.3
2.8
2.9
2.7
27.3
0.1
26.1
N/M
N/M
N/M
N/M
N/M
143.7%
6.2%
N/M
(15.1)
141.1%
14.4
(20.0)
N/M
¹ Earnings before interest, tax, depreciation, amortisation, restoration, exploration and evaluation expense and impairment.
² No adjustment has been made for the temporary loss in revenue at PEL 92 associated with the change in the crude marketing arrangements (previously oil
was sold at the inlet to the South Australia Cooper Basin joint venture facilities at Moomba whereas, from 1 July 2022, revenue is recognised upon sale
ex-Port Bonython).
59
COOPER ENERGY ANNUAL REPORT 2023
Directors’ Statutory Report
For the year ended 30 June 2023
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 2023, 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 and Chairman
of the Pymble Ladies’ College Council.
Current and other directorships in the last 3 years
Mr Conde is Chairman of The McGrath Foundation (since 2013 and director since
2012). He is also President of the Commonwealth Remuneration Tribunal (since 2003)
and Chairman of Dexus Wholesale Property Fund (DWPF) (since 2020). Mr Conde is
former Deputy Chairman of Whitehaven Coal Limited (ASX:WHC) (2007-2022) and
former director of Dexus Property Group (ASX:DXS) (2009 – 2020).
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 Petroleum Production and Exploration
Association (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.
60
COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
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.
Ms Victoria J. BINNS
B. Eng (Mining – Hons 1),
Grad Dip SIA, FAusIMM,
GAICD
INDEPENDENT NON-
EXECUTIVE DIRECTOR
Appointed 2 March 2020
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.
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 currently 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
Effective 19 August 2021 Ms Binns is the Chairman of the Audit Committee and is a
member of the Risk & Sustainability Committee.
61
COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
Ms Giselle M. COLLINS
B. Ec, CA
GAICD
INDEPENDENT NON-
EXECUTIVE DIRECTOR
Appointed 19 August 2021
Ms Elizabeth A. DONAGHEY
B.Sc., M.Sc.
INDEPENDENT NON-
EXECUTIVE DIRECTOR
Appointed 25 June 2018
Mr Jeffrey W. SCHNEIDER
B.Com
INDEPENDENT NON-
EXECUTIVE DIRECTOR
Appointed 12 October 2011
Experience and expertise
Ms Collins has broad executive and director experience across finance, treasury and
property disciplines. Ms Collins is also active with not-for-profit organisations and has
a strong interest in sustainability across many of her involvements.
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.
Current and other directorships in the last 3 years
Ms Collins is currently Chairman of AMP Limited’s listed managed investment
schemes (since 2020), a trustee director of the Royal Botanic Gardens and Domain
Trust (since 2019), non-executive director of Generation Development Group (since
2018), Chairman of Hotel Property Investments Limited (ASX:HPI) (Chairman since
July 2022 and director since 2017) and Chairman for Indigenous Business Australia
in The Darwin Hotel Pty Limited (since 2014).
Ms Collins is a former non-executive director and Chairman of the following
companies: Aon Superannuation (2016-2017), The Travelodge Hotel Group (2009-
2013), The Heart Research Institute Limited (2003-2011) as well as a 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
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.
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 and a member of the Governance & Nomination Committee.
62
COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
Mr David P. MAXWELL
M.Tech, FAICD
MANAGING DIRECTOR
Appointed 12 October 2011
Retired 20 March 2023
Mr Hector M. GORDON
B.Sc. (Hons).
INDEPENDENT NON-
EXECUTIVE DIRECTOR
26 June 2012 – 23 June 2017
NON-EXECUTIVE DIRECTOR
Appointed 24 June 2017
Retired 23 June 2023
Experience and expertise
Mr Maxwell is a leading oil and gas industry executive with more than 25 years in senior
executive roles with companies such as BG Group, Woodside Energy and Santos.
Mr Maxwell led many large commercial, marketing and business development projects.
Prior to joining Cooper Energy Mr Maxwell worked with the BG Group, where he
was responsible for all commercial, exploration, business development, strategy and
marketing activities in Australia and led BG Group’s entry into Australia and Asia
including a number of material acquisitions.
Mr Maxwell has served on a number of industry association boards, government
advisory groups and public company boards.
Current and other directorships in the last 3 years
Mr Maxwell was on the board of the Australian Petroleum Production & Exploration
Association (2018-2023).
Until Mr Maxwell’s retirement from Cooper Energy he was a director of the Company’s
wholly owned subsidiary companies.
Special responsibilities
Prior to his retirement, Mr Maxwell was Managing Director. He was responsible
for the day-to-day leadership of Cooper Energy and was the leader of the Executive
Leadership Team.
Experience and expertise
Mr Gordon is a geologist with over 40 years’ experience in the upstream petroleum
industry, primarily in Australia and Southeast Asia. He joined Cooper Energy in
2012, initially as Executive Director – Exploration & Production and subsequently
moved to his position as non-executive director in 2017.
Mr Gordon was previously Managing Director of Somerton Energy until it was
acquired by Cooper Energy in 2012. Previously he was an Executive Director with
Beach Energy Limited, where he was employed for more than 16 years. In this time
Beach Energy experienced significant growth and Mr Gordon held a number of
roles including Exploration Manager, Chief Operating Officer and, ultimately, Chief
Executive Officer.
Current and other directorships in the last 3 years
Mr Gordon is a Non-Executive Director of Bass Oil Limited ASX: BAS
(since 2014).
Special responsibilities
Prior to his retirement, Mr Gordon was the Chairman of the Risk & Sustainability
Committee and a member of the Audit Committee.
2. Company secretary
Ms Nicole Ortigosa B.A., LLB (Hons), Grad Dip Legal
Practice was appointed to the position of Acting Company
Secretary and General Counsel effective from 21 April
2023 and was appointed to the permanent position of
Company Secretary and General Counsel effective
17 July 2023.
Nicole has almost 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 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
63
COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
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:
Director
Board Meetings
Audit
Committee
Meetings
Risk &
Sustainability
Committee
Meetings
People &
Remuneration
Committee
Meetings
Governance
& Nomination
Committee
Meetings
Mr J. Conde
Mr J. Norman¹
Mr T. Bednall
Ms V. Binns
Ms E. Donaghey
Mr J. Schneider
Ms G. Collins
Mr D. Maxwell²
Mr H. Gordon³
A
9
2
9
9
9
9
9
7
9
B
9
2
9
9
9
9
9
7
9
A
-
-
4
4
-
-
4
-
4
B
-
-
4
4
-
-
4
-
4
A
-
-
-
4
3
-
4
-
4
B
-
-
-
4
4
-
4
-
4
A
4
-
4
-
3
4
-
-
-
B
4
-
4
-
4
4
-
-
-
A
1
-
1
-
1
1
-
-
-
B
1
-
1
-
1
1
-
-
-
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.
¹Ms Norman was appointed as Managing Director and CEO on 20 March 2023
²Mr Maxwell retired effective from 20 March 2023
³Mr Gordon retired effective from 23 June 2023
4. Remuneration Report (audited)
Information about the remuneration of the Company’s
key management personnel for the financial year ended
30 June 2023 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.
Introduction from the Chairman of the
People & Remuneration Committee
Dear Shareholder,
The 2023 financial year (FY23) has seen significant
change for the Company, including the retirement
of David Maxwell as Managing Director and the
appointment of Jane Norman as Managing Director and
Chief Executive Officer effective 20 March 2023. We also
welcomed the Orbost Gas Processing Plant (OGPP)
team to Cooper Energy following the Major Hazard
Facilities License (MHFL) transfer, effective 22 May 2023.
The Company’s performance in the 2023 financial
year was below the target levels we had set at the start
of the year. This is reflected in our Corporate Scorecard
results. Shareholders, the Board and all staff are acutely
aware that the Company’s underperformance against
our targets has in turn been reflected in weak share
price outcomes. Everyone in the Company is
focused on ensuring material improvement in both
business performance and share price outcomes in the
year ahead.
This Remuneration Report reflects achievement levels in
the 2023 financial year 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 2023 Annual
General Meeting.
The People & Remuneration Committee believes that
the FY23 remuneration outcomes are appropriate, taking
into account the Company’s performance, changes in the
business and the employment market generally.
Remuneration Report context:
2023 financial year
The Company’s performance in the 12 months to
30 June 2023 is reported in the Operating and Financial
Review of the Financial Report. This performance and
how it compared with the specific targets of the
Corporate Scorecard provide the context of the
Remuneration Report.
In the 2023 financial year, the Company has been
successful in maintaining its strong performance in
Health and Safety to industry leading levels together
with no recordable environmental incidents. Whilst these
results were very pleasing, other scorecard dimensions
namely, Production and Financials, Projects and Asset
Management, Growth and Portfolio Management, and
People, Culture and Enablers failed to either achieve or to
exceed target levels.
As a result, the Board determined that there will be no
short-term incentive plan (STIP) payment for FY23 as
it relates to Company performance. This decision is
not intended to diminish the considerable efforts of the
Cooper Energy team, who remain committed to delivering
our key business imperatives in order to bring future
64
COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
October 2023. The next general review of base salaries
will be 1 October 2024.
Short term incentive plan (STIP): The Board determined
that there will be no STIP payment for FY23 as it relates
to Company performance, as overall targets set within
the corporate scorecard were not satisfied to a level that
payment was justified. The Board determined that STIP
relating to individual performance would be awarded to
KMP and staff generally based on achievement against
individual objectives. The FY23 STIP outcomes for the
KMP are included in this report in 4.6.3.
Long term incentive plan (LTIP): Our remuneration
framework is also designed to reward superior
performance over the long term and align executive key
management personnel performance with shareholder
value. The performance of the share price over the
past 3 years has been a concern for all shareholders
including the Board and management. Consistent with
this performance, there was no LTIP vesting in December
2021 (FY22) or December 2022 (FY23). As stated above,
ensuring strong business performance which is in turn
reflected in improved share price performance remains a
key area of focus. LTIP performance outcome is captured
in 4.6.4.
Directors fees: During FY23 there were no increases
to non-executive director remuneration. The recent
increase in statutory superannuation payments has not
resulted in an increase in fees paid to individual directors.
The most recent increase to non-executive director fee
remuneration occurred on 1 July 2019. The Board has no
current plan to increase Directors Fees.
Despite disappointing business outcomes, the level of
energy and commitment to succeed in the Company is
very strong at all locations and levels. The Board is very
appreciative of the efforts of all staff in this regard. We
thank also David Maxwell who as the former Managing
Director recommended the strategy which created
the platform. Under Jane Norman’s leadership we are
confident we will realise the company’s potential.
Yours sincerely
Mr Jeffrey Schneider
Chairman of the People & Remuneration Committee
success. The Board determined that STIP relating to
individual performance will be awarded to KMP and Staff
based on achievement against individual objectives.
The FY23 STIP outcomes for the KMP are included in
this report.
Remuneration developments
The new Managing Director and Chief Executive Officer,
Jane Norman, has implemented a number of changes
to the organisational structure of Cooper Energy. This
is intended to sharpen business accountabilities and
includes a reduction in the number of executive key
management personnel (KMP).
The KMP are those personnel that have the authority and
responsibility for planning, directing and controlling the
activities of the entity, directly or indirectly including any
director (whether executive or otherwise) of the entity.
For completeness, this report provides KMP remuneration
for those included as KMP during FY23. Next year’s
Remuneration Report will report on the revised KMP
executive team being the Managing Director and Chief
Executive Officer, Chief Financial Officer, Chief Operating
Officer (a newly created position with an appointment to
be announced in the first half of FY24), Chief Commercial
Officer, and Chief Exploration and Subsurface Officer.
Other executive roles shown in this report continue
to be part of the Cooper Energy management team.
The revised 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 better aligns with
our industry peers.
Remuneration paid to the previous Managing Director,
David Maxwell, upon his retirement is also set out in this
report. The payments made to him were consistent with
the practice adopted for other senior staff retirements.
The Company’s remuneration framework will be
reviewed during FY24 to ensure it is meeting its intended
objectives of providing incentives to deliver superior
performance to our shareholders, alongside attracting
and retaining high calibre employees. The review is
intended to strengthen the connection between the
shareholder experience and remuneration outcomes.
Remuneration outcomes
Fixed Annual Remuneration: Increases to the statutory
superannuation contribution effective 1 July 2023 have
been applied to all employees including the Managing
Director and Chief Executive Officer.
Those executive KMP who had been with the Company
for the full financial year (FY23) were included in a salary
review with the total increase being 3.55% (including
the statutory change to superannuation). Adjustments
to salary considered any additional responsibility and
benchmarking data within the resources industry
(incorporating the hydrocarbon sector). Increases to base
salaries are seen as comparable to our relevant peer
companies and industry generally and are effective 1
65
COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
Contents
Page
4.1 Introduction .................................................66
Name
Position
Period
as KMP
Key management personnel
4.2 Key Management Personnel covered
in this Report ..............................................66
4.3 Remuneration Governance ........................67
4.4 Nature & Structure of Executive
KMP Remuneration ....................................67
4.5 Cooper Energy’s Five-Year Performance
and Link to Remuneration ...........................73
4.6 2023 Executive KMP Performance and
Remuneration Outcomes ............................74
Non-Executive
Directors
Mr J. Conde AO
Chairman
Full Year
Mr T. Bednall
Non-Executive Director
Full Year
Ms V. Binns
Non-Executive Director
Full Year
Ms G. Collins
Non-Executive Director
Full Year
Ms E. Donaghey
Non-Executive Director
Full Year
Mr J. Schneider
Non-Executive Director
Full Year
Former Non
Executive KMP
4.7 Executive KMP Employment Contracts ......79
Mr H. Gordon
Executive KMP
Ms J. Norman
Former Non-Executive
Director
Part
Year¹
Managing Director &
Chief Executive Officer
Part
Year²
Mr. D. Young
Chief Financial Officer
Full Year
Mr E. Glavas
General Manager
Commercial &
Development
Mr I. MacDougall General Manager HSE,
Technical Services and
IT
Full Year
Full Year
Mr A. Thomas
Mr A. Haren
Former
Executive KMP
Mr D. Maxwell
Mr M. Jacobsen
Ms A. Jalleh
General Manager
Exploration &
Subsurface and Projects
Full Year
General Manager People
& Remuneration
Full Year
Former Managing
Director
Former General
Manager Projects &
Operations
Former Company
Secretary and General
Counsel
Part
Year³
Part
Year4
Part
Year5
1 Mr Gordon retired effective 23 June 2023.
² Ms Norman commenced effective 20 March 2023.
³ Mr Maxwell stood down from the role of Managing Director effective from
20 March 2023. Mr Maxwell retired from Cooper Energy effective
3 July 2023.
4 Mr Jacobsen stood down from the role of General Manager Project
& Operations effective from 24 April 2023.
5 Ms Jalleh resigned effective 19 May 2023.
4.8 2023 Remuneration Outcomes for
Executive KMP ............................................80
4.9 Nature of Non-Executive Director
Remuneration .............................................84
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
selected 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:
66
COOPER ENERGY ANNUAL REPORT 2023
Directors’ Statutory Report
For the year ended 30 June 2023
This report sets out KMP remuneration for those included
as KMP during FY23. Next year’s Remuneration Report
will report solely on the revised KMP team being the
Managing Director and Chief Executive Officer (Jane
Norman), Chief Financial Officer (Dan Young), Chief
Operating Officer (a newly created position with an
appointment to be announced in the first half of FY24),
Chief Commercial Officer (Eddy Glavas), and Chief
Exploration and Subsurface Officer (Andrew Thomas).
All Non-Executive Director roles continue to be captured
in the KMP group. The revised 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
better aligns with our industry peers.
Other executive roles shown in this report continue to be
part of the Cooper Energy management team.
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.
The Company’s remuneration framework will be
reviewed during FY24 to ensure it is meeting its intended
objectives in providing incentives to attract, retain and
incentivise high calibre employees while at the same
time is aligned with shareholder experience. The review
is intended to strengthen the connection between the
shareholder experience and remuneration outcomes.
4.3.2 People & Remuneration Committee
The People & Remuneration Committee (which, as at
the date of this report, is comprised of 4 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 FY23
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);
• STIP participation;
• benefits such as, internet allowance and car
parking; and
• LTIP (composed of performance rights (PRs)
and share appreciation rights (SARs) under the
Company’s amended Equity Incentive Plan approved
by shareholders at the 2022 AGM (EIP)).
In the case of the former Managing Director remuneration
included an allowance for accommodation.
It is the Company’s policy that the 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).
67
COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
4.4 Nature & structure of Executive KMP
remuneration (continued)
4.4.1 Remuneration strategy and framework - linking
reward to performance
The Company’s current remuneration profile for
Executive KMP (at Maximum Performance Super Stretch)
is as follows:
The remuneration strategy sets the remuneration
framework and drives the design and application of
remuneration for the Company, including Executive KMP.
Managing Director & CEO*
Other Executive KMP
30.8%
FAR
30.8%
LTIP
38.5%
STIP
22.7%
STIP
31.8%
LTIP
45.5%
FAR
*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 will be 28.6% FAR, 35.7% STIP and 35.7% LTIP.
A higher LTIP applies to the first-year invitation for the
Managing Director & CEO (Jane Norman) due to the
timing of this appointment. This was disclosed in our ASX
announcement of 19 December 2022.
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
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. No changes to the key
elements of the remuneration framework were made
in FY23.
4.4.2 Remuneration strategy and framework – Overview – FY23
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.
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COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
Performance conditions
Remuneration strategy/performance link
SHORT TERM
INCENTIVE PLAN
(STIP)
Annual incentive
opportunity
delivered in cash
based on Company
and Individual
performance
HSEC and Sustainability KPIs
•
•
Safety incident and
environment prevention
Sustainability targets
Production and Financial KPIs
•
•
•
•
Production
u-EBITDAX
Unit opex
Net G&A
Project and Asset
Management KPIs
•
•
Major projects delivery
Asset management
Growth and Portfolio Management KPIs
•
•
•
•
Reserves and resources
Development project delivery
New gas contracts
Acquisitions and divestments
People, Culture and Enablers KPIs
•
•
•
•
Staff engagement and enablement
Funding
Systems and processes, including IT
Stakeholder relations
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 links to
shareholder returns.
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 line of sight. 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, Stretch and Super 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 individual outcomes
and results align with the shareholder experience and
Cooper Energy values.
LONG TERM
INCENTIVE PLAN
(LTIP)
Three-year incentive
opportunity
delivered through
Performance
Rights and Share
Appreciation Rights
Individual performance KPIs
•
•
Managing Director & CEO (25% weighting)
Executive KMP (30% weighting)
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
Allocation of PRs and SARs encourages executives to
‘behave like shareholders’ from the grant date.
The PRs and SARs 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 becomes shareholders is the best way of aligning
employee interests with those of the Company’s
shareholders. The LTIP also acts as a retention incentive
for key talent (due to the three-year vesting peri-od).
RTSR is designed to encourage executives to focus on
the key performance drivers which underpin sustainable
growth in share-holder value.
The RTSR performance condition is designed to ensure
vesting can only occur where shareholders have
enjoyed superior share price performance compared
to the peer group shareholders. SARs only have value
when there is an increase in the Company’s share price.
In general, the Company’s vesting hurdles are intended
to be tough-er than our industry peers.
LTIP consists of 50% of PRs and 50% SARs.
Maximum LTIP grant is 100% of FAR for
Managing Director & CEO and 70% of FAR for
other Executive KMP.
Note: The first LTIP invitation for the new
Managing Director & CEO is 125% of FAR due
to the timing of their appointment. This was
disclosed in our ASX announcement dated 19
December 2022.
Relative Total Shareholder Return (RTSR) is
the only performance condition. RTSR ensures
that LTIP can only vest when the Company’s
share price performance is at least at the
50th percentile of the peer group. Maximum
LTIP vesting can only occur at or above 90th
percentile of the peer group.
•
•
•
RTSR performance requires a sustained
superior share price performance of the
Company compared to a peer group
of companies.
The peer group companies are 12 ASX-
listed companies in the oil and gas sector,
with a range of market capitalisation.
SARs by their nature have an absolute
total shareholder return requirement.
No SAR will vest unless the share price
appreciates over the measurement period.
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 stakeholder interests through share ownership.
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COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
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 tncentive plan (STIP) - Overview
The STIP is an annual incentive opportunity delivered
in cash 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 FY23 were as follows:
FY23 STIP 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 asset and total company value.
What is the vehicle of the
STIP award?
The STIP award is delivered in the form of a cash payment, usually in October.
What is the maximum award
opportunity (% of Fixed
Remuneration)?
Managing Director & CEO 125%
Former Managing Director 100%
Other Executive KMP 50%
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.
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 a Company scorecard. See section 4.6.2 for the Company scorecard measures
used for FY23. 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, Stretch and Super Stretch (i.e., 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:
Managing Director & CEO: 75% Company: 25% individual
Other Executive KMP: 70% Company: 30% individual
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. Target level KPIs are set
at a challenging and achievable level of performance (and not at the base level of
performance). 0% STIP will be awarded for base level achievement.
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.
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COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
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4.4.5 Long term incentive plan (LTIP) - Overview
In the reporting period, the LTIP involved grants of PRs and SARs under the EIP. The key features of the grants made in
the 2023 financial year (granted December 2022) are set out in the following table:
FY23 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?
During the reporting period, the LTIP involved grants of 50% PRs and 50% SARs.
A PR is a right to acquire one fully paid share in the Company, provided a specified
hurdle is met.
SARs 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.
What is the maximum
an-nual LTIP grant (% of
Fixed Remuneration)?
Managing Director & CEO: 100% (refer note below)
Former Managing Director: 100%
Other Executive KMP: 70%
What is the LTIP
perfor-mance period?
What are the performance
measures?
Note: The first LTIP invitation for the new Managing Director & CEO is 125% of FAR due
to the timing of their appointment. This was disclosed in our ASX announcement dated
19 December 2022.
The performance period is three years.
100% of the grant (both PRs and SARs) is subject to a relative total shareholder return
(“RTSR”) performance measure. RTSR is a common long-term incentive measure
across ASX-listed companies and is 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.
In addition to the RTSR performance measure set by the Board, SARs by their nature
also have a natural absolute total shareholder return measure. No SARs will be
exercisable unless the share price appreciates over the measurement period.
What is the vesting
schedule?
The level of vesting will be determined based on the ranking against the peer group of
12 companies, in accordance with the following schedule:
•
•
•
•
below the 50th percentile, no rights vest;
at the 50th percentile, 30% of the rights vest;
between the 50th percentile and 90th percentile, pro rata vesting; and
at the 90th percentile or above, 100% of the rights will vest.
The vesting schedule reflects the Board’s requirement that performance
measures are challenging, and maximum award opportunities are only achieved
by outstanding performance.
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COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
Features
Details
Which companies make up
the Relative Total Shareholder
Return peer group?
The RTSR of the Company is measured as a percentile ranking compared to the
following comparator group of 12 listed entities: Beach Energy Limited, Buru Energy
Limited, Carnarvon Petroleum Limited, Central Petroleum Limited, Galilee Energy
Limited, Karoon Gas Australia Limited, Norwest Energy (subsequently acquired and
delisted), Santos Limited, Strike Energy Limited, Tamboran Resources Limited, Warrego
Energy Limited (subsequently acquired and delisted), and Woodside Energy Group.
The peer group is based on a group of ASX-listed companies in the oil and gas sector,
with a range of market capitalisation. If following the review of the remuneration strategy
RTSR continues to be used, the composition of this group will be reviewed in FY24.
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?
Will the Company make any
changes to the LTIP for the
grant to be made in the 2024
financial year?
Eligibility is generally restricted to Executive KMP.
As indicated earlier in this Remuneration Report, a review of remuneration structure
will be undertaken in FY24. This may have the effect of changing the approach used
for LTIP.
Mr Maxwell and Mr Jacobsen were deemed to be qualifying leavers by the Board and as such has exercised
discretion to remove the service condition of the LTIP.
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COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
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:
Total recordable injury frequency rate
(events per hours worked, where a lower value is better)
Sales revenue ($ million)
6.92
3.53
0.00
4.38
0.00
75.5
78.1
131.7
205.4
196.9
FY19
FY20
FY21
FY22
FY23
FY19
FY20
FY21
FY22
FY23
Links directly to Company STIP reward outcome as a HSEC
& Sustainability KPI.
Links directly to Company STIP reward outcome as a
Production & Financial KPI.
Annual production (MMboe)
Proved & probable reserves (MMboe)
3.31
3.56
2.63
1.31
1.56
52.7
49.9
47.1
39.5
36.3
FY19
FY20
FY21
FY22
FY23
FY19
FY20
FY21
FY22
FY23
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)
13.3
14.4
(6.6)
(25.9)
(5.6)
FY19
FY20
FY21
FY22
FY23
32.9
29.6
30.0
80.7
109.3
FY19
FY20
FY21
FY22
FY23
Links indirectly to Company STIP reward outcomes via
Production & Financial KPIs.
Links directly to Company STIP reward outcome as a
Financial KPI.
Financial – total shareholder return (%)
Share price – as at 30 June ($ per share)
40.3
(30.6)
FY20
FY19
(5.8)
(30.7)
FY21
FY22
(38.8)
FY23
0.54
0.38
0.26
0.25
0.15
FY19
FY20
FY21
FY22
FY23
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)
875.6
610.0
424.1
583.1
394.7
In FY23, and in the past five 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.
FY19
FY20
FY21
FY22
FY23
Links directly to Company LTIP reward outcome by
increasing shareholder value compared to peers.
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COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
4.6
2023 Executive KMP performance and
remuneration outcomes
4.6.1 Fixed annual remuneration outcome
4.6.2 STIP performance outcomes – Company results
Increases to the statutory superannuation contribution,
effective 1 July 2023, have been applied to all employees
including the Managing Director and Chief Executive
Officer. There has been no increase to the base salary of
the Managing Director and Chief Executive Officer.
Those executive KMP who had been with the Company
for the full financial year (FY23) were included in a salary
review with the total increase being 3.55% (including
the statutory change to superannuation). Adjustments
to salary also considered any additional responsibility
and benchmarking data within the resources industry
(incorporating the hydrocarbon sector). Increases to base
salaries are seen as comparable to our relevant peer
companies and industry generally and are effective 1
October 2023. The next general review of base salaries
will be 1 October 2024.
Performance
measure
(FY23 weighting%) Performance measure outcome
The Board determined that there will be no short-term
incentive plan (STIP) payment for FY23 as it relates
to Company performance. Whilst the Company has
been successful in maintaining its strong performance
in Health, Safety and Environment, other scorecard
dimensions namely, Production and Financials,
Projects and Asset Management, Growth and Portfolio
Management, and People, Culture and Enablers failed to
achieve or exceed target levels.
The Board determined a FY23 scorecard assessment
result of 21.4/100 (21.4%).
Result
Threshold Target
Stretch
Super
stretch
HSEC
(25%)
Result:
16.67/25.00
• LTIs = 0
• TRIFR = 4.38 < industry benchmark (5.68)
• No process safety events
• No recordable environmental incidents ≥ level 2
• Maintained company and gas product carbon
neutral certification
• Emissions offset and new projects being reviewed
Production &
financials (25%)
Result:
0/25.00
• FY23 production of 3.5 MMboe; between threshold
and target
• FY23 u-EBITDAX of $109.3mm; below threshold
• FY23 cash unit; below threshold
• FY23 net G&A; between threshold and target
Project & asset
management
(15%)
• OGPP operatorship effective 22 May 2023; at
threshold; integration spend < budget; at target
• BMG spend and timing; below target as at
Result: 0/15.00
Growth &
portfolio
management
(15%)
Result: 4.72/15.00
People, culture &
enablers
(20%)
Result: 0/20.00
30 June 2023
• OP3D FID delayed by - partner alignment and Govt
energy policy; below threshold
• Otway exploration select phase; at threshold
• Reserve replacement; below threshold, 2C and
prospective resource additions; above target
• Gippsland asset value plan; at threshold
• Term GSA with AGL to support OP3D; at target
• Assessing new add value opportunities; at threshold
• Employee survey deferred
• Gippsland funding plan incorporated into value plan;
at threshold
• OGPP IT systems integrated; at threshold
• IT improvement plan; at target
• Constructive engagement on Gas Code and PRRT
FY23 performance
21.4 / 100
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COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
4.6.3 STIP performance outcomes – Individual results
The Board determined that there will be no STIP payment
for FY23 as it relates to Company performance, as overall
targets set within the corporate scorecard were not satisfied
to a level that payment was justified.
The Board determined that STIP relating to individual
performance measures would be awarded to KMP, and
staff generally, based on achievement against individual
objectives. The FY23 STIP outcomes for the Executive KMP
are shown in the table below:
KMP short term incentive (STIP) for the year ended 30 June 2023
STIP - % of
Fixed annual
remuneration at
target
STIP - % of
fixed annual
remuneration at
maximum
Cash STIP
$
% earned of
maximum STIP
opportunity
% forfeited of
maximum STIP
opportunity
62.5%
25.0%
25.0%
25.0%
25.0%
25.0%
50.0%
25.0%
25.0%
125%
50%
50%
50%
50%
50%
100%
50%
50%
57,144
61,824
45,360
37,440
50,490
34,020
150,000
38,250
-
20.25%
23.70%
20.25%
15.60%
20.40%
21.60%
15.72%
15.30%
0.00%
79.75%
76.30%
79.75%
84.40%
79.60%
78.40%
84.28%
84.70%
N/M
Executive KMP
Ms. J. Norman¹
Mr. D Young²
Mr E. Glavas
Mr. I. MacDougall
Mr. A. Thomas
Mr. A. Haren
Former Executive KMP
Mr. D. Maxwell³
Mr. M. Jacobsen4
Ms. A. Jalleh5
1 Ms. Norman commenced on 20 March 2023. STIP projected to a full year would represent $202,500 gross or 20.25% of her maximum annual STIP opportunity.
2 Mr. Young received an additional STIP payment of $10,304 relating to the months of May and June 2022 (FY22). Mr. Young commenced on 2 May 2022 and received
no STIP payment in FY22 pursuant to customary probationary arrangements in his appointment. Part of his employment conditions stated that his FY23 STIP would
include a STIP calculation based on 14 months service using his individual performance for the full year of FY23. Mr. Young received a total STIP payment for FY23 of
$72,128 gross.
3 Mr Maxwell stood down from the role of Managing Director effective from 20 March 2023. His FY23 STIP award includes the ”personal scorecard” outcome for the
period from 20 March to 3 July 2023 when he had stepped down as Managing Director but was still employed.
4 Mr Jacobsen stood down from the role of General Manager Project & Operations effective from 24 April 2023. His FY23 STIP award includes the ”personal scorecard”
outcome for the full financial year.
5 Ms Jalleh resigned effective 19 May 2023 and was not entitled to any STIP payment from FY23.
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COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
Managing Director & CEO individual performance
Jane Norman, Managing Director and CEO, was appointed 20 March 2023; Jane therefore worked 28.22% of FY23.
Jane’s STIP maximum opportunity is 125% of her Fixed Annual Remuneration (FAR) currently $800,000 gross per
annum. The Board determined a FY23 STIP payment of $57,144 gross will be payable in October 2023 calculated
as follows:
Ms. J Norman
Corporate scorecard
Individual performance
Total
Maximum
Eligibility
% FAR
Maximum
Eligibility
$
FY23
Result
%
93.75%
31.25%
750,000
250,000
125.00%
1,000,000
0%
81%
Annualised
FY23
Result
$
0
202,500
202,500
Time Worked
in FY23
%
FY23
Gross STIP
Payment
$
28.22%
28.22%
28.22%
0
57,144
57,144
Individual performance was assessed by the Board as follows:
Individual FY23
Performance
Measures
Performance Comments
FY23 Outcome
Threshold
Target
Maximum
Plans to achieve
sustainable
improvement of
production levels
at Orbost Gas
Processing Plant
(OGPP).
Weighting 50%
• MHFL transferred 22 May 2023.
• Delivery of phase 1 and 2 integration action
plans achieved.
• Integration of OGPP employees achieved.
• Organisational structure change to improve OGPP
support in place.
• Improvement plan established with
actions commenced.
• No reportable safety or environmental incidents.
BMG
decommissioning
execution plan in
place to deliver a
safe and cost-
effective project
on schedule.
Weighting 20%
Positive platform
established with all
key stakeholders.
Weighting 20%
Organisational
structure change
established to
achieve clear
channels of
accountability.
Weighting 10%
• Leadership and team assembled to deliver project
execution plan.
• Cost estimates in-line with updated FY24 budget.
• Plans including training, in place to mitigate safety and
environmental risk.
• Clear channels of communication in place with service
providers and industry colleagues aimed at successful
cost and schedule delivery.
• Clear communication with all stakeholders on
business priorities and delivery outcomes.
• Clear articulation on impact of mandatory Gas Code
• Well established relationships with key customers and
joint venture partners including future arrangements
relating to OP3D.
• Revised management team to ensure clear, single
point accountability on business imperatives.
• Revised structure to ensure business is fit for purpose.
• Actions commenced to reduce G&A costs.
• Incentives review commenced to ensure alignment of
company performance and shareholder interests.
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COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
Other Executive Key Management Personnel Individual Performance
STIP for other Executive KPMP has a 70% weighting on the corporate scorecard and 30% individual performance
weighting. Commentary on individual performance and FY23 STIP outcomes follow:
D Young
Chief Financial Officer
• Advanced financial strategy, growing commercial culture
• Enhanced financial disclosures, reporting and IR
• New enlarged and broadened senior secured bank
debt facility
• Transformation programme underway including
G&A reduction
• Company safety, environment and diversity
E Glavas
General Manager Commercial & Development
• New gas contract for OP3D in place
• Managed company position on Federal Gas Code
• New Commercial team in place
• Strategy for Offshore Otway & Gippsland basins in place
• Company safety, environment and diversity
targets achieved
targets achieved
Company performance
Individual performance
FY23 STIP outcome as % of maximum
0%
79.00%
23.70%
Company performance
Individual performance
FY23 STIP outcome as % of maximum
0%
67.50%
20.25%
I MacDougall
General Manager HSE, Technical Services & IT
A Thomas
General Manager Exploration & Subsurface and Projects
• Delivering sustainability initiatives
• IT improvement plan on target
• BMG safety and environmental plans in place
• Engineering support increased including structural change
• Company safety, environment and diversity
• Increased 2C and Prospective Resources
• Project responsibility absorbed into role
• BMG decommissioning project ready to proceed
• Contracted drilling rig for OP3D
• Company safety, environment and diversity
targets achieved
Company performance
Individual performance
FY23 STIP outcome as % of maximum
0%
52.00%
15.60%
targets achieved
Company performance
Individual performance
FY23 STIP outcome as % of maximum
0%
68.00%
20.40%
A Haren
General Manager People & Remuneration
• Integration of OGPP employees, phase 1 & 2 achieved
• Increased Engineering support established with
central base
• New industrial instruments in place
• Revised organisational structure and leadership team
in place
• Company safety, environment and diversity
targets achieved
Company performance
Individual performance
FY23 STIP outcome as % of maximum
0%
72.00%
21.60%
Former Executive key management personnel individual performance
D Maxwell
Former Managing Director
M Jacobsen
Former General Manager Projects & Operations
• MHFL transferred to OGPP 22 May 2023
• OGPP integration costs under budget
• Effective transition to new Managing Director
• Workforce collaboration consistent with “one team” ethos
• Company safety, environment and diversity
• MHFL transferred to OGPP 22 May 2023
• OGPP integration costs under budget
• OP3D initial planning completed
• BMG decommissioning resourcing in place
• Company safety, environment and diversity
targets achieved
Company performance
Individual performance
FY23 STIP outcome as % of maximum
0%
62.88%
15.72%
targets achieved
Company performance
Individual performance
FY23 STIP outcome as % of maximum
0%
51.00%
15.30%
77
COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
4.6.4 LTIP outcome
The Company’s RTSR compared to the peer group is set out below for the December 2019 LTIP grant that vested in
December 2022. The base for the graph is 10 December 2019, being the grant date of PRs and SARs that were made
under the Company’s EIP. The terms of the EIP are set out in section 4.4.5.
Share price performance of Cooper Energy Limited versus applicable peer group
10 December 2019 to 9 December 2022
-80%
-80%
-80%
-80%
-80%
-80%
-80%
-80%
-80%
-80%
-80%
-61%
Cooper Energy Limited
109%
67%
61%
41%
0%
-23%
-41%
-46%
-55%
-68%
The vesting of the LTIP award in December 2022 was
impacted by the performance of the Company’s share
price against its peers over the measurement period.
Over the three-year measurement period from 10
December 2019 to 9 December 2022, Cooper Energy’s
total shareholder return was -61% and it achieved a
RTSR percentile rank of 6%. This resulted in a vesting
outcome of 0% of all PRs and SARs that were granted in
December 2019.
In FY23, LTIP grants from 12 December 2018 were re-
tested in December 2022. The percentile rank was below
the 50th percentile and therefore no shares vested as a
result of this re-testing. This was the final re-testing of any
grants made under the LTIP.
In summary, none of the PRs or SARs granted in
December 2018 and December 2019 have vested.
There has been no vesting for the past two years of
any LTIP. All performance rights and share appreciation
rights granted in 2018 and 2019 have lapsed unvested.
78
COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
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 limit in 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:
Indemnity agreement
Treatment on termination by Cooper Energy
Notice by
Cooper
Energy
Notice by
Executive
KMP
6 months
6 months
Executive
KMP
Jane
Norman
Company provides
Indemnity Agreement,
Directors and Officers
indemnity insurance and
access to Company records.
6 months
3 months
Other
Executive
KMP
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.
Where an Executive KMP 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.
Under the rules of STIP and the Equity Incentive Plan (EIP) if an Executive KMP ceases employment prior to the vesting
date of an Incentive (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.
79
COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
4.8
2023 Remuneration outcomes for
Executive KMP
4.8.1 Remuneration realised by Executive KMP
in FY23 and FY22 (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 t
he Company.
The table set out below shows amounts paid and the
cash value of 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 this 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 corporate scorecard and individual
performance outcomes from the prior financial year.
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 FY23 row, relate to STIP payments in respect of
FY22. These amounts were assessed and approved
by the Board in August 2022 and disclosed in 4.6.3 of
the remuneration report for the year ended 30 June
2022. 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 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
Ms J. Norman2
Mr E. Glavas
Mr A. Haren
Mr I. MacDougall
Mr A. Thomas
Mr D. Young3
Year
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
FAR
$
STIP1
$
LTIP
$
Other
$
Total
$
231,017
-
-
-
448,000
175,552
453,761
36,497
315,000
122,336
301,469
12,526
480,000
189,946
461,874
35,535
495,000
190,519
471,874
40,361
516,065
86,667
-
-
-
-
-
-
-
-
-
-
-
-
-
-
401,801
632,818
-
-
6,462
630,014
6,284
496,542
6,462
443,798
1,750
315,745
6,462
676,408
6,284
503,693
6,462
691,981
6,284
518,519
66,299
582,364
90,742
177,409
1 The STIP paid in October 2022 (FY23), though it relates to FY22 performance, is included in the 2023 figure as part of remuneration received in
FY23. The STIP paid in October 2021 (FY22) is included in the 2022 figure. The table in section 4.8.2 aligns STIP awards with the financial year
to which they relate.
2 Ms Norman commenced as an Executive KMP on 20 March 2023 and her entitlements for 2023 are prorated. “Other” remuneration realised
includes $400,000 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 her previous employment.
3 Mr Young’s “Other” remuneration realised included sign on and relocation costs in both 2022 and 2023. The Company considered this sign on
bonus to be a reasonable assessment for the value of incentives forgone from his previous employment.
80
COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
4.8.2 Table of Executive KMP statutory remuneration
disclosure for FY23 and FY22
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).
Short-term
Base
Salary
STIP1
Other
Short-term
Benefits2
Long-
term
Post-
employment
Share pased
remuneration4
Post KMP payments
Long
Service
Base
Leave Superannuation3
LTIP
Salary11 Severance
LTIP12
Total
221,747
57,144 401,801
-
-
-
-
-
9,270
-
-
-
-
Benefits
Executive KMP
Ms J. Norman2
Mr E. Glavas
Mr A. Haren
2023
2022
2023
2022
2023
2022
422,708
45,360
6,462
14,654
430,193
175,552
6,284
10,582
289,708
34,020
277,901
122,336
6,462
1,750
-
-
Mr I. MacDougall
2023
454,708
37,440
6,462
13,850
2022
438,306
189,946
6,284
11,499
Mr A. Thomas
Mr D. Young6
Former
Executive KMP
Mr D. Maxwell7
2023
2022
2023
2022
2023
2022
469,708
50,490
6,462
17,940
448,306
190,519
6,284
11,762
490,773
61,824
76,603
82,739
-
90,742
-
-
666,573
150,000
47,316
33,656
893,306
818,310
67,523
23,438
Mr M. Jacobsen8
2023
395,590
38,250
Ms A. Jalleh9
Ms V. Suttell10
2022
445,900
194,110
2023
2022
2023
2022
375,229
-
378,151
184,781
-
114,576
-
-
410
476
5,934
6,284
-
9,211
13,942
-
-
-
1,998 (48,282)
Totals
2023 3,786,744
474,528
557,912
89,311
2022 3,509,378 1,875,554
187,625
22,941
1Refer to 4.6.3 for STIP amount earned in FY23 which will be paid in FY24.
2Other short-term benefits include fringe benefits on accommodation, 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 FY23.
3Superannuation is the only applicable post-employment benefit ie. No pension
or similar benefits for Executive KMP. Superannuation includes the amounts
required to be contributed by the Company and does not include amounts
salary sacrificed.
4In 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 remuneration 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.
5Ms Norman commenced as an Executive KMP on 20 March 2023 and her
entitlements for 2023 are prorated. “Other” remuneration realised includes
$400,000 which represents 50% of a sign on bonus. The Company considered
this sign on bonus to be a reasonable assessment for the value of incentives
forgone from her previous employment.
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
689,962
-
771,798
900,287
453,184
467,329
815,824
945,170
854,378
961,882
892,292
177,409
257,322
254,108
97,702
41,774
278,072
275,567
284,486
281,443
237,800
-
566,677 293,034
- 1,239,071
3,013,857
782,134
-
-
-
2,608,279
230,335 262,852
319,515
420,132
1,697,372
276,963
241,148
205,393
-
(166,612)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
954,959
645,496
798,177
-
(88,306)
2,193,542 555,886
319,515 1,659,203
9,834,163
1,950,770
-
-
-
7,725,186
25,292
23,568
25,292
23,568
25,292
23,568
25,292
23,568
25,292
3,928
17,530
23,568
21,077
23,568
23,185
23,568
-
10,014
197,522
178,918
6Mr Young’s “Other” remuneration realised included sign on and relocation costs
in both 2022 and 2023. The Company considered this sign on bonus to be a
reasonable assessment for the value of incentives forgone from his previous
employment.
7Mr 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.
8Mr 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.
9Ms Jalleh ceased to be an Executive KMP on 19 May 2023 and her entitlements
for 2023 are prorated.
10 Ms Suttell ceased to be an Executive KMP on 30 September 2021 and her
entitlements for 2022 are prorated.
11Includes base salary, other short term benefits and superannuation.
12Relate to LTIP awards made in December 2020, 2021 and 2022 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. Vesting of these
grants remain contingent on the performance hurdles noted in section 4.4.5.
No cash-settled share-based payment transactions or other forms of share-based payment compensation (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 FY22 or FY23 – namely PRs and SARs granted in December 2018 and December 2019 – met any partial or full
vesting thresholds. As such, all of these PRs and SARs lapsed unvested.
81
COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
4.8.3 Performance rights and share appreciation rights
accounting for the reporting period.
The value of the PRs and SARs issued under the Equity
Incentive Plan (EIP) is recognised as Share Based
Payments in the Company’s statement of comprehensive
income and amortised over the vesting period. PRs and
SARs were granted under the EIP on 9 December 2022.
PRs and SARs are granted for no consideration and
employees receive no cash benefit at the time of
receiving the rights.
shares are issued. Further, the rights can only vest when
the RTSR thresholds described in section 4.4.5 have
been achieved.
PRs and SARs 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 against
performance conditions.
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
The value of PRs and SARs shown in the tables
below are the accounting fair values for grants in the
reporting period:
Performance rights
(Equity incentive plan)
Share appreciation 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 to
30 June
2023
No. of
rights
granted
during
period
Fair
value of
rights at
grant date
No. of
rights
vested
during
period
% of all
rights
vested to
30 June
2023
Directors
Ms J. Norman
Executive KMP
Mr E. Glavas
Mr A. Haren
-
-
627,200
84,045
441,000
59,094
Mr I. MacDougall
672,000
90,048
Mr A. Thomas
Mr D. Young1
693,000
92,862
1,556,935
250,782
Former Executive KMP
Mr D. Maxwell2
1,908,000
255,672
Mr M. Jacobsen3
700,000
93,800
Ms A. Jalleh4
627,200
84,045
-
-
-
-
-
-
-
-
-
-
-
-
25% 1,668,086
106,758
0% 1,172,873
75,064
28% 1,787,235
114,383
28% 1,843,086
117,958
0% 4,542,590
340,126
29% 5,074,470
324,766
7% 1,861,703
119,149
0% 1,668,086
106,758
-
-
-
-
-
-
-
-
-
-
23%
0%
27%
27%
0%
27%
6%
0%
1 Mr. Young commenced on 2 May 2022 and received no LTIP grant in FY22 pursuant to customary probationary arrangements. As part of the terms of his appointment
Mr Young was included in the December 2021 LTIP grant, which was made in FY23 following the completion of his probationary period.
2 Mr Maxwell ceased as an Executive KMP effective from 20 March 2023.
3 Mr Jacobsen ceased as an Executive KMP effective from 24 April 2023.
4 Ms Jalleh ceased as an Executive KMP on 19 May 2023.
The vesting date of the PRs granted on 9 December
2022 is 9 December 2025. The estimated fair value of
these rights is $0.134 per right and the share price on
grant date was $0.195. The performance period for these
PRs commenced on 9 December 2022.
The vesting date of the SARs granted on 9 December
2022 is 9 December 2025. The estimated fair value of
these rights is $0.064 per right and the share price on
grant date was $0.195. The performance period for these
SARs commenced on 9 December 2022.
82
COOPER ENERGY ANNUAL REPORT 2023
Directors’ Statutory Report
For the year ended 30 June 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)
Directors
Ms J. Norman
Executive KMP
Mr E. Glavas
Mr A. Haren
Mr I. MacDougall
Mr A. Thomas
Mr D. Young1
Former Executive KMP
Mr D. Maxwell2
Mr M. Jacobsen3
Ms A. Jalleh4
Held at
1 July 2022
Granted
Lapsed
Vested &
exercised
Held at
30 June 2023
-
-
-
1,665,928
481,607
1,808,599
1,846,735
627,200
441,000
672,000
693,000
-
1,556,935
561,211
613,150
625,363
5,129,370
1,908,000
1,736,571
1,824,695
1,263,109
700,000
627,200
613,150
1,890,309
-
1,731,917
922,607
1,867,449
1,914,372
1,556,935
5,300,799
1,911,545
-
-
-
-
-
-
-
-
-
-
SARs 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)
Directors
Ms J. Norman
Executive KMP
Mr E. Glavas
Mr A. Haren
Mr I. MacDougall
Mr A. Thomas
Mr D. Young1
Former Executive KMP
Mr D. Maxwell2
Mr M. Jacobsen3
Ms A. Jalleh4
Held at
1 July 2022
Granted
Lapsed
Vested &
exercised
Held at
30 June 2023
-
-
-
5,226,649
1,668,086
1,727,602
1,515,000
1,172,873
5,671,891
1,787,235
1,885,458
5,791,951
1,843,086
1,923,408
-
4,542,590
-
16,088,384
5,074,470
5,342,039
5,722,522
1,861,703
1,885,458
4,074,680
1,668,086
5,742,766
-
-
-
-
-
-
-
-
-
-
5,167,133
2,687,873
5,573,668
5,711,629
4,452,590
15,820,815
5,698,767
-
1 Mr. Young commenced on 2 May 2022 and received no LTIP grant in FY22 pursuant to customary probationary arrangements. As part of the terms of his appointment
Mr Young was included in the December 2021 LTIP grant, which was made in FY23 following the completion of his probationary period.
2 Mr Maxwell ceased as an Executive KMP effective from 20 March 2023.
3 Mr Jacobsen ceased as an Executive KMP effective from 24 April 2023.
4 Ms Jalleh ceased as an Executive KMP on 19 May 2023.
83
COOPER ENERGY ANNUAL REPORT 2023
Directors’ Statutory Report
For the year ended 30 June 2023
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
Directors
Mr J. Conde AO
Ms J. Norman
Ms E. Donaghey
Mr J. Schneider
Mr T. Bednall
Ms V. Binns
Ms G. Collins
Former Non Executive KMP
Mr H. Gordon1
Executive KMP
Mr E. Glavas
Mr A. Haren
Mr I. MacDougall
Mr A. Thomas
Mr D. Young
Former Executive KMP
Mr D. Maxwell2
Mr M. Jacobsen3
Ms A. Jalleh4
Held at
1 July 2022
Purchases
Received on
vesting of PRs
& SARs
Sales
Held at
30 June 2023
859,093
1,045,161
-
-
580,000
299,000
1,016,594
1,406,638
132,499
322,857
-
138,000
129,142
160,000
1,746,138
61,224
1,424,203
-
3,474,127
5,147,308
-
-
-
200,000
816,325
-
20,000,086
3,228,944
297,283
115,770
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,904,254
-
879,000
2,423,232
270,499
451,999
160,000
1,807,362
1,424,203
-
3,674,127
5,963,633
-
23,229,030
413,053
-
¹Mr Gordon retired effective 23 June 2023.
2Mr Maxwell ceased as an Executive KMP effective from 20 March 2023.
³Mr Jacobsen ceased as an Executive KMP effective from 24 April 2023.
4Ms Jalleh ceased as an Executive KMP on 19 May 2023.
Options
No options were issued (or forfeited) during the year.
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 Annual General Meeting, is $1.25
million. The Non-Executive Directors’ fee structure for the
reporting period was as follows:
84
COOPER ENERGY ANNUAL REPORT 2023
Directors’ Statutory Report
For the year ended 30 June 2023
Role
Chairman*
Member
Board Fee
$240,000
$115,000
Audit
Committee
$20,000
$10,000
Risk &
Sustainability
Committee
People &
Remuneration
Committee
Governance
& Nomination
Committee
$20,000
$10,000
$20,000
$10,000
$0
$10,000
*Where the Chairman of the Board is a member of a committee, he will not receive any additional committee fees.
The above Board Fee was set on 1 July 2019 and there
has been no increase since that time.
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 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.
4.9.2 Table of Non-Executive KMP remuneration for 2023 and 2022 financial years
Short-term
Long-
term
Post-employment
Share based
remuneration4
Fees
$
STIP1
$
Other
short-term
benefits2
$
Long
service
leave
$
Superannuation3
$
LTIP
$
Total
218,182
218,182
131,818
132,417
136,818
133,015
122,727
106,562
131,818
132,417
136,818
131,818
131,818
132,417
1,010,000
986,828
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
22,909
21,818
13,841
13,242
14,366
13,301
12,886
10,656
13,841
13,242
14,366
13,182
13,841
13,242
106,050
96,683
-
-
-
-
-
-
-
-
-
-
-
-
-
-
241,091
240,000
145,659
145,569
151,184
146,316
135,613
117,218
145,659
145,659
151,184
145,000
145,659
145,659
- 1,116,050
- 1,085,511
Directors
Mr J. Conde AO
Mr T. Bednall
Ms V. Binns
Ms G. Collins5
Ms E. Donaghey
Mr H. Gordon6
Mr J. Schneider
Totals
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
1The STIP values noted for 2022 include an under/over accrual representing the difference between the prior period accrual and what was actually paid in respect of that
year. Refer to 4.6.3 for STIP amount earned in FY23 which will be paid in FY24.
2Other short-term benefits include fringe benefits on accommodation, car parking and other benefits.
3Superannuation includes the amounts required to be contributed by the Company and does not include amounts salary sacrificed.
4In 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 remuneration 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 above and in more detail in Note 27 of the Notes to the Financial Statements.
5Ms Collins commenced on the Board effective 19 August 202. Her 2022 benefits are pro-rated.
6Mr Gordon stepped down from the Board effective 23 June 2023.
End of remuneration report.
85
COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
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 strategies 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
Ms J. Norman
Nil
Mr T. Bednall
Ms V. Binns
270,499
451,999
Ms G. Collins
160,000
Ms E.
Donaghey
Mr J.
Schneider
879,000
2,423,232
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Mr D. Maxwell1
23,229,030
5,300,799
15,820,815
Mr H. Gordon2
1,807,362
Nil
Nil
1Mr Maxwell stepped down from the Board effective from 20 March 2023
2Mr Gordon stepped down from the Board effective 23 June 2023.
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 28,694,792 outstanding PRs and
60,807,624 SARs under the Equity Incentive Plan approved
by shareholders at the 2022 AGM.
During the financial year no shares were issued as a result
of PRs and SARs exercised. At the date of this report, no
PRs have vested and been exercised subsequent to 30
June 2023.
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.
86
COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report
For the year ended 30 June 2023
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
Ernst & Young have been the Company’s auditors for over
ten years and it is anticipated that they will continue in
that role for the financial year ended 30 June 2024.
The Directors have elected to put the Group’s audit out
to tender, with effect from the financial year ended 30
June 2025. It is planned for the tender to be conducted
in the course of H2 FY24, with any resultant change, if
applicable, to be put to shareholders at the November
2024 AGM.
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
Chairman
Ms Jane L. Norman
Managing Director & CEO
Dated at Adelaide 29 August 2023
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 99 and forms part of the Directors’ report for the
financial year ended 30 June 2023.
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 $49,500
(2022: $347,100). The directors are satisfied that the
provision of non-audit services is compatible with the
87
COOPER ENERGY ANNUAL REPORT 2023 Consolidated Statement of Comprehensive Income
For the year ended 30 June 2023
Revenue from gas and oil sales
Cost of sales
Gross profit
Other expenses
Finance income
Finance costs
Loss before tax
Income tax benefit
Petroleum resource rent tax benefit
Total tax benefit
Notes
2
2
2
18
18
3
3
2023
$'000
2022
$'000
196,885
205,389
(164,379)
(157,628)
32,506
47,761
(110,722)
(56,857)
3,019
(29,496)
(104,693)
28,063
8,167
36,230
468
(14,099)
(22,727)
6,057
6,112
12,169
Loss after tax for the period attributable to shareholders
(68,463)
(10,558)
Other comprehensive income/(expenditure)
Items that will not be reclassified subsequently to profit or loss
Fair value movement on equity instruments at fair value through other
comprehensive income
19
648
(332)
Other comprehensive income/(expenditure) for the period net of tax
648
(332)
Total comprehensive loss for the period attributable to shareholders
(67,815)
(10,890)
Basic loss per share
Diluted loss per share
4
4
Cents
(2.6)
(2.6)
Cents
(0.6)
(0.6)
The above Consolidated Statement of Comprehensive Income should be read in conjunction with the
accompanying notes.
88
COOPER ENERGY ANNUAL REPORT 2023
Consolidated Statement of Financial Position
For the year ended 30 June 2023
Notes
2023
$'000
2022
$'000
Assets
Current assets
Cash and cash equivalents
Trade and other receivables
Prepayments
Inventory
Total current assets
Non-current assets
Other financial assets
Contract asset
Property, plant and equipment
Intangible assets
Right-of-use assets
Exploration and evaluation assets
Gas and oil assets
Deferred tax asset
Deferred petroleum resource rent tax asset
Total non-current assets
Exploration assets classified as held for sale
Total sssets
Liabilities
Current liabilities
Trade and other payables
Provisions
Lease liabilities
Interest bearing loans and borrowings
Total Current liabilities
Non-Current liabilities
Trade and other payables
Provisions
Lease liabilities
Interest bearing loans and borrowings
Other financial liabilities
Deferred petroleum resource rent tax liability
Total non-current liabilities
Liabilities directly associated with assets held for sale
Total liabilities
Net assets
Equity
Contributed equity
Reserves
Accumulated losses
Total Equity
5
6
7
8
20
2
10
11
16
12
13
3
3
9
15
16
17
9
15
16
17
20
3
19
19
77,134
28,797
6,303
2,182
114,416
1,131
2,323
380,375
967
7,448
184,569
535,842
92,643
24,659
1,229,957
247,012
30,467
12,854
841
291,174
484
2,062
59,232
1,360
7,520
164,909
595,347
63,563
12,763
907,240
-
1,558
1,344,373
1,199,972
68,679
166,098
1,467
-
236,244
19,262
417,509
9,182
143,956
2,853
18,494
611,256
32,752
29,867
1,251
37,000
100,870
-
446,754
9,612
121,000
3,285
19,118
599,769
-
908
847,500
701,547
496,873
498,425
716,726
26,071
(245,924)
496,873
478,261
197,625
(177,461)
498,425
The above Consolidated Statement of Comprehensive Income should be read in conjunction with the accompanying notes.
89
COOPER ENERGY ANNUAL REPORT 2023
Consolidated Statement of Changes in Equity
For the year ended 30 June 2023
Notes
Issued
Capital
$’000
Reserves
$’000
Accumulated
Losses
$’000
Total
Equity
$’000
Balance at 1 July 2022
478,261
197,625
(177,461)
498,425
Loss for the period
Other comprehensive income
Total comprehensive loss for the period
-
-
-
-
648
648
(68,463)
(68,463)
-
648
(68,463)
(67,815)
Transactions with owners in their capacity as owners:
Equity issue
Share based payments
Transferred to retained earnings
Transferred to issued capital
Balance as at 30 June 2023
19
19
19
19
58,596
-
-
-
7,667
-
179,869
(179,869)
-
-
-
-
58,596
7,667
-
-
716,726
26,071
(245,924)
496,873
Balance at 1 July 2021
477,675
14,118
(165,997)
325,796
Loss for the period
Other comprehensive expenditure
Total comprehensive loss for the period
Transactions with owners in their capacity as owners:
Equity issue
Share based payments
Transferred to retained earnings
Transferred to issued capital
Balance as at 30 June 2022
-
-
-
-
-
-
586
19
19
19
19
-
(10,558)
(10,558)
(332)
-
(332)
(332)
(10,558)
(10,890)
179,508
4,011
906
(586)
-
-
179,508
4,011
(906)
-
-
-
478,261
197,625
(177,461)
498,425
The above Consolidated Statement of Changes in Equity should be read in conjunction with the accompanying notes.
90
COOPER ENERGY ANNUAL REPORT 2023 Consolidated Statement of Cash Flows
For the year ended 30 June 2023
Cash flows from operating activities
Receipts from customers
Payments to suppliers and employees
Payments for restoration
Petroleum resource rent tax paid
Interest received
Interest paid
Net cash from operating activities
Cash flows from investing activities
Payments for property, plant and equipment
Payments for intangibles
Payments for exploration and evaluation
Payments for gas and oil assets
Proceeds from sale of equity instruments
Proceeds from held for sale assets
Net cash flows used in investing activities
Cash flows from financing activities
Repayment of principal portion of lease liabilities
Proceeds from equity issue
Proceeds from borrowings
Repayment of borrowings
Transaction costs associated with borrowings
Net cash flow from financing activities
Net (decrease)/increase in cash held
Net foreign exchange differences
Cash and cash equivalents at 1 July
Cash and cash equivalents at 30 June
Notes
2023
$'000
2022
$'000
198,265
204,205
(101,632)
(130,156)
(19,580)
(6,123)
(6,225)
2,910
(10,974)
62,764
(245,370)
(1,092)
(23,248)
(5,858)
-
650
(925)
419
(9,638)
57,782
(6,119)
(493)
(5,120)
(9,149)
437
-
(274,918)
(20,444)
(1,262)
57,579
158,000
(1,141)
178,000
-
(158,000)
(60,000)
(15,142)
41,175
-
116,859
(170,979)
154,197
1,101
247,012
77,134
1,507
91,308
247,012
5
5
5
5
5
The above Consolidated Statement of Cash Flows should be read in conjunction with the accompanying notes.
91
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
Corporate information
Funding overview
The consolidated financial report of Cooper Energy
Limited and its controlled entities (“Cooper Energy”,
or “the Group”), for the year ended 30 June 2023, was
authorised for issue on 28 August 2023 in accordance
with a resolution of the Directors. Cooper Energy Limited
is a for profit company limited by shares incorporated and
domiciled in Australia 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 in 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.
Plant acquisition
The Company executed a binding asset purchase
agreement with APA Group, on 20 June 2022, for the
purchase of the OGPP. All conditions precedent to
the closing of the transaction were completed by late
July and the transaction closed, with Cooper Energy
becoming the legal owner of the OGPP, on 28 July 2022.
Prior to 28 July 2022, the plant was owned by APA Group
with the Company paying a processing toll.
The Group holds cash balances of $77.1 million and
has drawn debt of $158.0 million as at the end of the
reporting period with a further $242.0 million committed,
available and undrawn under its senior secured reserve
based loan facility. The loan facility has an expected
maturity date of September 2027. The Company also has
a further $12.3 million availability under the Company’s
working capital facility. All debt covenants have been
complied with, as of 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 BMG restoration
provision has been classified as a current provision,
resulting in a net current liability. The Group is well funded
to complete the BMG abandonment work, with no near-
term maturities on outstanding debt and $242.0 million
fully committed and undrawn under the facility.
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
Note 21
assets
Note 14
Impairment
Note 26
Interests in joint
arrangements
Share based
payments
Note 15
Provisions
92
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
Judgements, estimates and assumptions which are
material to the overall financial statements are below:
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 lower emissions intensity
gas supply. The Company measures and reports
its emissions and emissions offsets to maintain its’
carbon neutral¹ 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 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.
New accounting standards and
interpretations
New standards, interpretations and amendments thereof,
adopted by the Group
the Group for the annual reporting period ending 30 June
2023 are outlined below.
The accounting standard and interpretations relevant to
the Group that have recently been issued or amended,
but are not yet effective and have not been adopted by
No new accounting standards, amendments and
interpretations applicable on 1 July 2022 have had a
material impact on the Group’s financial statements.
¹Cooper Energy has been certified by Climate Active as a carbon neutral organisation for its Scope-1, Scope-2 and relevant
Scope-3 emissions (embedded energy and business travel). See 2023 Sustainability Report for further information.
93
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
Accounting standards and interpretations
issued but not yet effective
The accounting standards and interpretations that
have recently been issued or amended, but are not yet
effective and have not been adopted by the Group for
the annual reporting period ending 30 June 2023, are
outlined below:
AASB 2021-5
Summary
Amendments to AASs – Deferred
Tax related to Assets and
Liabilities arising from a Single
Transaction
AASB 112 Income Taxes requires
entities to account for income tax
consequences when economic
transactions take place, and not at
the time when income tax payments
or recoveries are made. Accounting
for such tax consequences means
entities need to consider the
differences between tax rules and the
accounting standards.
This amendment requires entities
to also recognise deferred tax for
all temporary differences related to
leases, decommissioning, restoration
and similar liabilities at the beginning
of the earliest comparative
period presented.
Application Date
of the Standard
1 January 2023
Funding and risk
management
Impact on
Consolidated
Financial
Statements
The impact of this accounting
standard amendment on the Group is
yet to be determined.
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
Working capital
Capital
employed
Provides additional information
regarding financial statement lines
that are most relevant to explaining
the Group’s operating performance
during the period.
Provides additional information
regarding financial statement lines
that are most relevant to explaining
the assets used to generate the
Group’s operating performance
during the period.
Provides additional information
regarding financial statement lines
that are most relevant to explaining
the capital investments made that
allows the Group to generate its
operating result during the period and
liabilities incurred as a result.
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.
94
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
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 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
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, and IOR Energy Pty Ltd.
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 Southeast Australia segment primarily consists of
the operated Sole producing gas assets and the OGPP,
the operated Casino Henry producing gas assets and the
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 2023
Revenue from gas and oil sales to external customers
Total revenue
184,542
184,542
12,343
12,343
-
-
196,885
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
Depreciation and amortisation
Impairment
Net finance costs
Profit/(loss) before tax
Income tax benefit
Petroleum resource rent tax benefit
Net profit/(loss) after tax
Segment assets
Segment liabilities
Additions of non-current assets
Exploration and evaluation assets
Gas and oil assets
Property, plant and equipment
Intangibles
(46,343)
(93,450)
(26,118)
(18,764)
(71,019)
-
8,167
(62,852)
579,625
676,332
23,835
10,981
(9,765)
-
-
-
(2,066)
(3,308)
-
(160)
4,258
-
-
-
(7,553)
(37,932)
28,063
-
(46,343)
(98,824)
(26,118)
(26,477)
(104,693)
28,063
8,167
4,258
(9,869)
(68,463)
27,470
5,244
737,278
165,924
1,344,373
847,500
986
3,181
-
-
-
-
402
1,092
1,494
24,821
14,162
(9,363)
1,092
30,712
Total additions of non-current assets
25,051
4,167
The above Consolidated Statement of Changes in Equity should be read in conjunction with the accompanying notes.
95
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
1. Segment reporting (continued)
Southeast
Australia
$’000
Cooper
Basin
$’000
Corporate
and Other
$’000
Consolidated
$’000
30 June 2023
Revenue from gas and oil sales to external customers
Total revenue
188,139
188,139
17,250
17,250
205,389
205,389
-
Segment result before interest, tax, depreciation,
amortisation and restoration, exploration and evaluation
expense and impairment
69,179
11,045
(16,048)
64,176
Restoration income
Exploration and evaluation expense
Depreciation and amortisation
Net finance costs
Profit/(loss) before tax
Income tax benefit
Petroleum resource rent tax benefit
Net profit/(loss) after tax
Segment assets
Segment liabilities
Additions of non-current assets
Exploration and evaluation assets
Gas and oil assets
Property, plant and equipment
Intangibles
(19,031)
(118)
(48,831)
(13,384)
(12,185)
-
6,112
(6,073)
547,431
521,080
3,499
73,738
28,302
-
-
(89)
(2,165)
(137)
8,654
-
-
-
(2)
(3,036)
(110)
(19,196)
6,057
-
(19,031)
(209)
(54,032)
(13,631)
(22,727)
6,057
6,112
8,654
(13,139)
(10,558)
23,964
5,996
628,577
174,471
1,199,972
701,547
1,927
874
-
-
-
-
4
494
498
5,426
74,612
28,306
494
108,838
Total additions of non-current assets
105,539
2,801
In 2022, revenue from two customers amounted to $97.6 million; and $38.5 million respectively in the Southeast Australia
segment.
96
COOPER ENERGY ANNUAL REPORT 2023
Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
2. Revenues and expenses
Revenues
Revenue from gas and oil sales
Revenue from contracts with customers
Gas revenue from contracts with customers
Oil revenue from contracts with customers
Total revenue from contracts with customers
Other revenue
Fair value movement on crude oil receivables
Total other revenue
Total revenue from gas and oil sales
Contract assets related to contracts with customers
The Group has recognised the following assets related to contracts
with customers.
Opening balance
Contract assets recognised during the year
Unwind of contract asset
Closing balance
Expenses
Cost of sales
Production expenses
Royalties
Third-party product purchases and trading costs
Amortisation of gas and oil assets
Depreciation of property, plant and equipment
Inventory movement
Total cost of sales
Other expenses
Selling expense
General administration
Depreciation of property, plant and equipment
Amortisation of intangibles
Depreciation of right-of-use assets
Care and maintenance
Restoration expense
Exploration and evaluation expense
Impairment expense
Other (including new ventures)
OGPP reconfiguration and commissioning works
Total other expenses
Notes
2023
$'000
2022
$'000
184,542
12,403
196,945
188,138
15,712
203,850
(60)
(60)
1,539
1,539
196,885
205,389
2,062
492
(231)
2,323
-
2,062
-
2,062
(61,081)
(1,118)
(7,604)
(58,654)
(36,853)
931
(80,362)
(1,594)
(24,678)
(49,443)
(1,551)
-
(164,379)
(157,628)
(402)
(637)
(19,063)
(14,729)
(713)
(1,485)
(1,119)
(2,612)
(740)
(1,193)
(1,105)
(2,808)
(46,343)
(19,031)
-
(26,118)
(12,421)
(446)
(110,722)
(209)
-
(1,321)
(15,084)
(56,857)
14
97
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
2. Revenues and expenses (continued)
Employee benefits expense included in general administration
Director and employee benefits
Share based payments
Superannuation expense
Total employee benefits expense (gross)
Accounting policy
Notes
2023
$'000
2022
$'000
(28,960)
(26,417)
(7,667)
(2,365)
(4,011)
(1,953)
(38,992)
(32,381)
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.
The crude oil sales contain provisional pricing.
Revenue from contracts with customers is 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 is 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.
98
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
3. Income tax
Consolidated Statement of Comprehensive Income
Current income tax
Current year
Deferred income tax
Origination and reversal of temporary differences
Recognition of tax losses
Income tax benefit
Current petroleum resource rent tax
Current year
Deferred petroleum resource rent tax
Origination and reversal of temporary differences
Petroleum resource rent tax benefit
2023
$'000
2022
$'000
-
-
7,814
20,249
28,063
28,063
(4,184)
(4,184)
12,351
12,351
8,167
-
-
(2,309)
8,366
6,057
6,057
(4,616)
(4,616)
10,728
10,728
6,112
Total tax benefit
36,230
12,169
Reconciliation between tax expense and pre-tax net profit
Accounting loss before tax from continuing operations
Income tax using the domestic corporation tax rate of 30% (2022: 30%)
(Increase)/decrease in income tax expense due to:
Non-deductible expenditure
Recognition of royalty related income tax benefits
Other
Income tax benefit
Petroleum resource rent tax benefit
Total tax benefit
(104,692)
31,408
(22,727)
6,818
(2,744)
(4,520)
3,919
28,063
8,167
36,230
(1,241)
(2,487)
2,967
6,057
6,112
12,169
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.
99
COOPER ENERGY ANNUAL REPORT 2023
Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
3. Income Tax (continued)
Unrecognised temporary differences
At 30 June 2023, 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
(2022: $nil).
Franking Tax Credits
At 30 June 2023 the parent entity had franking tax
credits of $42.9 million (2022: $42.9 million). The
fully franked dividend equivalent is $142.9 million
(2022: $142.9 million).
Petroleum Resource Rent Tax
Cooper Energy Limited has recognised a deferred tax
liability for PRRT of $18.5 million (2022: $19.1 million)
Deferred income tax from corporate tax
Deferred income tax at 30 June relates to:
Deferred tax liabilities
Trade and other receivables
Gas and oil assets
Exploration and evaluation
Other
Deferred tax assets
Leases
Provisions
Tax losses
Other
Deferred tax benefit
and a deferred tax asset for PRRT of $24.7 million
(2022: $12.8 million).
Income Tax Losses
(a) Revenue Losses
A deferred tax asset has been recognised for the
year ended 30 June 2023 of $96.2 million
(2022: $76.6 million).
(b) Capital Losses
Cooper Energy has not recognised a deferred tax asset
for Australian income tax capital losses of $15.5 million
(2022: $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
2023
$'000
2022
$'000
2023
$'000
2022
$'000
57
45,951
29,049
9,701
84,758
3,195
77,148
96,205
853
5,994
49,533
21,921
1,977
79,425
3,259
57,760
76,595
5,374
177,401
142,988
(5,937)
(3,582)
7,128
7,724
5,333
(64)
19,388
19,610
(4,521)
34,413
39,746
(77)
(3,657)
(2,805)
(1,738)
(8,277)
(342)
7,639
10,205
(1,655)
15,847
7,570
Deferred tax asset from corporate tax
92,643
63,563
Deferred income tax from PRRT
Deferred income tax at 30 June relates to:
Deferred tax liabilities
Gas and oil assets
Deferred tax liability from PRRT
Deferred tax assets
Gas and oil assets
Deferred tax asset from PRRT
Total deferred tax from PRRT
18,494
18,494
24,659
24,659
19,118
19,118
12,763
12,763
(624)
-
(2,035)
-
11,896
12,763
-
-
11,272
10,728
100
COOPER ENERGY ANNUAL REPORT 2023
Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
3. Income Tax (continued)
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 income tax is recognised on all temporary
differences, except for:
•
•
the initial recognition of an asset or liability that
affects neither the accounting profit nor taxable
profit or loss; or
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. Where
allowable by initial recognition exemptions, deferred
tax assets and deferred tax liabilities that arise on
acquisition are not recognised.
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.
101
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
3. Income Tax (continued)
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:
Net loss after tax attributable to shareholders
2023
$'000
2022
$'000
(68,463)
(10,558)
2023
Thousands
2022
Thousands
Weighted average number of ordinary shares used in calculating basic earnings per share
2,621,292
1,646,285
Dilutive performance rights and share appreciation rights¹
-
Weighted average number of ordinary shares used in calculating dilutive earnings per share
2,621,292
1,646,285
Basic loss per share for the period (cents per share)
Diluted loss per share for the period (cents per share)
(2.6)
(2.6)
(0.6)
(0.6)
¹The weighted average number of potentially dilutive shares at 30 June 2023 is 28.9 million (2022: 24.3 million)
At 30 June 2023 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 adjusted for the after tax effect of
dilutive potential ordinary shares that have been
recognised as expenses during the period divided
by the weighted average number of ordinary shares
and dilutive potential ordinary shares.
102
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
Working Capital
5. Cash and cash equivalents and term deposits
Current Assets
Cash at bank and in hand
Cash and cash equivalents
Reconciliation of net profit to net cash flows from operating activities
Net loss after tax
Add/(deduct) non-cash items:
Amortisation of gas and oil assets
Depreciation of property, plant and equipment
Amortisation of intangibles
Depreciation of right-of-use assets
Impairment expense
Exploration and evaluation expense
Restoration (income)/expense
Share based payments
Finance costs
Foreign exchange (gain)/loss
Other non-cash movements
Net cash from operating activities before changes in assets or liabilities
Add/(deduct) changes in operating assets or liabilities:
Increase in trade and other receivables
Decrease/(increase) in inventories
Increase in prepayments
Increase in deferred taxes
Increase in trade and other payables
Decrease in provisions
Net cash from operating activities
Reconciliation of liabilities arising from financing activities
2023
$'000
2022
$'000
77,134
77,134
247,012
247,012
(68,463)
(10,558)
58,654
37,566
1,485
1,119
26,118
-
46,343
7,667
16,850
(705)
(532)
126,102
(1,406)
(1,340)
6,527
(37,556)
(6,331)
(23,232)
62,764
49,443
2,291
1,193
1,105
-
209
19,031
4,011
4,461
(1,527)
22
69,681
(721)
109
(5,255)
(16,785)
13,545
(2,792)
57,782
Balance at beginning of period
Financing cash flows¹
Other
Balance at end of period
Borrowings
Lease Liabilities
2023
$'000
158,000
(15,142)
1,098
2022
$'000
218,000
(60,000)
-
143,956
158,000
2023
$'000
10,863
(1,262)
1,048
10,649
2022
$'000
12,004
(1,141)
-
10,863
¹Financing cash flows consist of the net amount of proceeds from borrowings and 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.
103
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
6. Trade and other receivables
Current Assets
Trade receivables
Accrued revenue
Interest receivable
2023
$'000
2022
$'000
11,360
17,247
190
28,797
10,486
19,901
80
30,467
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 30 to 90 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
Insurance
Prepaid cash calls to joint arrangements
Prepaid plant acquisition and debt refinancing costs¹
Other prepayments
2023
$'000
4,229
1,970
-
104
2022
$'000
3,463
1,975
6,469
947
6,303
12,854
¹A portion of this amount relates to transaction costs incurred in 2022 associated with the acquisition of the OGPP which were subsequently capitalised to property,
plant and equipment on completion of the acquisition in FY23. It also includes costs associated with the new corporate reserves based loan facility, which upon
execution in FY23 were included in the initial measurement of the resulting financial liability.
8. Inventory
Petroleum products
Spares and parts
All inventory items are carried at cost in the current and previous financial years.
9. Trade and other payables
Trade payables
Deferred consideration1
Accruals (capital and operating expenditure)
Non-Current
Deferred consideration¹
2023
$'000
966
1,216
2,182
2023
$'000
6,411
40,000
22,268
68,679
19,262
2022
$'000
-
841
841
2022
$'000
10,506
-
22,246
32,752
¹Deferred consideration represents the fixed payments due 12 and 24 months after financial close of the OGPP acquisition which occurred on 28 July 2022. The Group
records deferred consideration at the present value of consideration payments.
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.
104
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
Capital Employed
10. Property, plant and equipment
Reconciliation of carrying amounts at
beginning and end of period:
Production assets
Corporate assets
2023
$'000
2022
$'000
2023
$'000
2022
$'000
Total
2023
$'000
2022
$'000
Carrying amount at beginning of period
55,928
29,177
3,304
4,040
59,232
33,217
Assets acquired¹
Additions
Restoration
Impairment
Depreciation
Carrying amount at end of period
Cost
Accumulated depreciation
Carrying amount at end of period
374,016
10,724
(20,489)
(5,944)
(36,853)
377,382
419,617
(42,235)
377,382
-
6,115
22,187
-
(1,551)
55,928
61,306
(5,378)
55,928
-
402
-
-
(713)
2,993
8,114
(5,121)
2,993
-
4
-
-
(740)
3,304
7,717
(4,413)
3,304
374,016
11,126
-
6,119
(20,489)
22,187
(5,944)
(37,566)
380,375
427,731
(47,356)
380,375
-
(2,291)
59,232
69,023
(9,791)
59,232
¹Acquisition of OGPP includes $210.0 million upfront consideration, $58.1 million deferred consideration, $27.0 million capitalised acquisition and transaction costs and
$78.9 million in relation to the restoration obligations acquired.
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 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
Reconciliation of carrying amounts at beginning and end of period:
Carrying amount at beginning of period
Additions
Amortisation
Carrying amount at end of period
Cost
Accumulated amortisation
Carrying amount at end of period
2023
$'000
2022
$'000
1,360
1,092
(1,485)
967
4,394
(3,427)
967
2,059
494
(1,193)
1,360
3,302
(1,942)
1,360
Accounting Policy
Intangible assets comprise software and are stated at
historical cost less accumulated amortisation and any
accumulated impairment losses. 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.
105
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
12. Exploration and evaluation assets
Reconciliation of carrying amounts at beginning and end of period:
Carrying amount at beginning of period
Additions¹
Impairment
Exploration and evaluation expense
Exploration expenditure classified as held for sale
Carrying amount at end of period²
Notes
2023
$'000
2022
$'000
14
164,909
159,443
24,821
(5,161)
-
-
5,426
-
(209)
249
184,569
164,909
¹Additions in 2023 relate to OP3D and licensing and interpretation of 3D seismic data in the Gippsland basin. Additions in 2022 relate to drilling two oil exploration wells
in the Cooper Basin and completion of a 3D seismic survey in the Onshore Otway.
² Recoverability is dependent on the successful development and commercial exploration or sale of the respective areas of interest.
The sale to Bass Oil Limited of the Company’s interests
in several of its Cooper Basin exploration and production
licences (PEL 93, PPL 207, PRL 237, PEL 100 and PEL
110) was completed on 1 August 2022 for a consideration
of $0.65 million. The assets and associated liabilities
were classified as held for sale and presented in separate
lines in the Consolidated Statement of Financial Position
as at 30 June 2022.
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:
a. 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
i. such costs are expected to be recouped through
successful development and exploration of the
area of interest, or alternatively by its sale; or
ii. exploration and evaluation activities in the area of
interest have not at the reporting date:
b. reached a stage which permits a reasonable
assessment of the existence or otherwise of
economically recoverable reserves; and
c. 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 in assessing the reserves
and the economic and operating viability of the project is
being made. 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-ii 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.
106
COOPER ENERGY ANNUAL REPORT 2023
Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
13. Gas and oil assets
Reconciliation of carrying amounts at beginning and end of period:
Carrying amount at beginning of period
Additions¹
Amortisation
Impairment
Carrying amount at end of period
Cost²
Accumulated amortisation & impairment²
Carrying amount at end of period
Notes
2023
$'000
2022
$'000
14
595,347
14,162
570,178
74,612
(58,654)
(49,443)
(15,013)
535,842
-
595,347
839,898
834,134
(304,056)
(238,787)
535,842
595,347
¹Updates to restoration provisions have resulted in $9.5 million (2022: $66.7 million) additions to gas and oil assets. Refer to Note 15 for more information.
²Fully written down assets with an original cost of $8.4 million were written-off in their entirety during the period impacting both cost and accumulated
depreciation balances.
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 are impacted
by management’s estimates of reserves and future
development costs. Refer to the significant accounting
judgements, estimates and assumptions section on
page 55 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.
107
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
14. Impairment
Exploration and evaluation assets
Property, plant & equipment
Gas and oil assets
Total impairment recognised
2023
$'000
5,161
5,944
15,013
26,118
2022
$'000
-
-
-
-
As at 30 June 2023, indicators of impairment were
present for the Casino Henry Netherby cash generating
unit (“CGU”).
The combination of the above factors has given
rise to the need to formally estimate the CGU’s
recoverable amount.
The Casino Henry Netherby CGU comprises:
• The Casino, Henry and Netherby producing gas
fields; recorded within gas and oil assets
• The Athena Gas Plant, recorded within property, plant
and equipment ; and
• The Annie gas field, recorded within exploration and
evaluation assets.
A number of factors have contributed to the presence of
indicators of impairment for the Casino Henry Netherby
CGU, including:
• delays to approvals for the development of the Annie
gas field, as part of the broader OP3D. These delays
were due to:
•
the uncertainties arising from the Federal
Government’s gas market intervention, including
the new mandatory gas code of conduct
• partner misalignment on OP3D
•
changes to market conditions, including the upward
pressures from increased industry activity on certain
costs such as drilling rigs, support vessels, helicopter
support and other costs impacting not only future
developments but also decommissioning costs; and
• macro-economic factors such as inflation, cost of
financing and foreign exchange assumptions.
Gas and oil properties – Casino Henry Netherby
Exploration and evaluation – VIC/P44 exploration
Property, plant & equipment – Athena Gas Plant
Total impairment via FVLCD
As part of the amendments to the Sole gas sales
agreement (“GSA”) announced in September 2021,
the Company agreed to the supply of all developed
and uncontracted volumes from the existing Casino
Henry and Netherby wells to AGL Energy Limited at the
Sole GSA price, with effect from 1 January 2022 until
first production from the next phase of development in
the Otway Basin. Whilst softer spot market gas pricing
has been observed in the short term, forward estimates
embedded within the fair value less cost of disposal
(“FVLCD”) estimate for the Casino Henry Netherby
CGU remain largely in line with FY22.
In accordance with the accounting standards, no
repurposing of the plant has been assumed; for example,
into a gas storage facility, or for carbon capture and
storage. This is a conservative position, but appropriate
for the impairment assessment.
The non-cash impairment loss recognised at June 2023
is a result of the above factors. The impairment loss does
not take into account the full value of the OP3D project,
nor does it impact the future sanctioning of the project.
Recoverable amounts and resulting impairment write-
downs recognised in the year ended 30 June 2023 are
as follows:
Segment
Impairment
$’000
Southeast Australia
15,013
Southeast Australia
Southeast Australia
5,161
5,944
26,118
The FVLCD of the Casino Henry Netherby CGU was determined based on expectations of the estimated future cash
flows from both the developed and undeveloped upstream reserves and resources and the Casino Henry Netherby and
Annie fields. A post-tax, discount rate of 8.9% has been applied, reflective of the time value of money and risks specific
to the asset. The FVLCD model and discount rate are prepared on without incorporating assumptions on future inflation/
on a real basis. Other relevant assumptions are those outlined in the Significant Accounting Judgements, Estimates and
Assumptions section that follows.
108
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
14. Impairment (continued)
Changes in key assumptions to which the recoverable amount is most sensitive would result in higher or lower carrying
values as follows:
Resultant impact on carrying value
Uncontracted gas price (+/- $1/GJ) (assumed A$12 real June 2023)
Discount rate (+/- 1%)
Capital expenditure (+/- 10%)
Higher
$'000
3,800
1,500
11,900
Lower
$'000
(1,500)
(400)
(9,800)
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 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 the
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.
The Group’s commodity prices and foreign exchange rates
for impairment testing are based on management’s best
estimates of future market prices, with reference to external
brokers, market data and futures prices. The Group’s gas
price assumptions are based on contract prices applied
against contracted gas volumes. The Group’s view of
109
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
14. Impairment (continued)
Significant accounting judgements, estimates and assumptions (continued)
future uncontracted, long-term gas prices has been revised based on market data available, Southeast Australia gas
market supply and demand information, oil prices and foreign exchange rates. The uncontracted pricing applies to
a later time period as the Group has entered into a long-term gas sales agreement with AGL to supply gas from the
Annie gas field
The Group’s future pricing assumptions in FY23 dollar terms are set out below:
Key assumption
Brent crude oil (US$/bbl)
FY2024
85.00
FY2025
85.00
FY2026
75.00
Uncontracted gas ($/GJ)
10.00 – 19.00
10.00 – 20.00
10.00 – 20.00
FY2027+
75.00
12.00
The Group assumes foreign currency exchange rates
of A$1/US$0.69 in all future periods.
Discount rates applied in the net present value
calculation of the FVLCD are derived from the weighted
average cost of capital. The Group applied a pre-tax
real discount rate of 9.6%.
In the event circumstances vary from the assumptions
used in the impairment assessment, the recoverable
amount of the Group’s assets or CGUs could change
materially and result in further impairment losses. The
key variables that impact on asset values are often
interrelated and therefore, changes in individual variables
rarely occur in isolation of other changes. Furthermore,
management is able to respond to certain changes
in variables and mitigate losses or maximise value
depending on the prevailing conditions that exist at the
time. Accordingly, while sensitivities have been provided
for specific changes in key assumptions, the indirect
impact that a change in one variable has on another is
impractical to estimate, as is the potential for, and size of
any further impairment write-downs or reversals in future
reporting periods.
110
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
15. Provisions
Current Liabilities
Employee benefits
Restoration provisions
Non-Current Liabilities
Employee benefits
Restoration provisions
Movement in carrying amount of the current restoration provision:
Carrying amount at beginning of period
Restoration expenditure incurred
Changes in provisions¹
Transferred from non-current provisions
Carrying amount at end of period
Movement in carrying amount of the non-current restoration provision:
Carrying amount at beginning of period
Provisions acquired
Changes in provisions¹
Transferred to current provisions
Increase through accretion
Restoration expenditure classified as held for sale
Carrying amount at end of period
2023
$'000
2022
$'000
4,547
161,551
166,098
763
416,746
417,509
26,957
(25,720)
33,600
126,714
161,551
2,910
26,957
29,867
395
446,359
446,754
7,994
(3,095)
-
22,058
26,957
446,359
355,652
78,887
1,474
(126,714)
16,740
-
-
108,083
(22,058)
4,433
249
416,746
446,359
¹Changes 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 cost 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 cost 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 2023 ranged from 3.49% to 5.65% (2022:
2.38% to 3.87%) 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 2023 ranged from 2.0% to 3.75
(2022: 2.0% to 4.5%).
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. In December
2022, Cooper Energy filed a claim in the Supreme Court
of Victoria against Pertamina, seeking payment of an
amount equal to 10% of the costs and expenses of the
abandonment operations incurred and to be incurred,
pursuant to Pertamina Australia’s obligations under the
withdrawal and abandonment provisions of the JOA.
This has been incorporated into the judgements in the
estimation of the BMG restoration provision.
111
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
15. Provisions (continued)
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.
producing life of the asset. Where it is not appropriate to
recognise an asset, changes will go 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
or industry practice.
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.
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
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.
112
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
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 covert 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 2023.
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 would therefore extend the
timing of these abandonment activities.
16. Leases
The Group as a lessee
The Group has lease contracts for properties with lease terms of between 1-11 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
Reconciliation of carrying amounts at beginning and end of period:
Carrying amount at beginning of period
Additions
Depreciation
Carrying amount at end of period
Cost
Accumulated depreciation
Carrying amount at end of period
Lease liabilities
Reconciliation of carrying amounts at beginning and end of period:
Carrying amount at beginning of period
Additions
Accretion of interest
Payments
Carrying amount at end of period
Current
Non-Current
2023
$'000
2022
$'000
7,520
1,047
(1,119)
7,448
11,905
(4,457)
7,448
10,863
1,047
495
(1,756)
10,649
1,467
9,182
8,625
-
(1,105)
7,520
10,858
(3,338)
7,520
12,004
546
(1,687)
10,863
1,251
9,612
Short-term and low-value lease asset exemptions
For the year ending 30 June 2023, 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.
Short-term leases
Leases for low-value assets
Total expense recognised
The Group had total cash outflows for leases of $11.2 million (2022: $1.7 million),
inclusive of leases for short-term leases and low-value assets.
9,238
176
9,414
-
91
91
113
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
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 as 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.
114
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
Funding and Risk Management
17. Interest bearing loans and borrowings
Current bank debt
Non-current bank debt
Net of capitalised transaction costs of $14.0 million (2022: $nil).
2023
$'000
-
143,956
2022
$'000
37,000
121,000
In July 2022, Cooper Energy executed a $400.0 million
senior secured reserve based lending facility, secured
across aportfolio of producing assets, together with a
senior secured $20.0 million working capital facility. It is
expected that the facility will be utilised to part fund the
Company’s share of the BMG abandonment project and a
portion of the planned OP3D growth project in the Otway
Basin. Cooper Energy is in compliance with all covenants
at 30 June 2023. A summary of the Group’s secured
facilities is included below.
Facility
Currency
Limit
Senior secured reserve based lending facility Working Capital Facility
Australian dollars
Australian Dollars
$400.0 million¹ (2022: $158.0 million)
$20.0 million (2022: $15.0 million)
Utilised amount
$158.0 million (2022: $158.0 million)
$7.7 million³ (2022: $7.1 million)
Accounting balance
$144.0 million (2022: $158.0 million)
Nil (2022: Nil)
Effective interest rate
9.30% floating
Nil
Maturity²
30 September 2027²
30 September 2024
¹As at 30 June 2023, $242.0 million of the original facility limit of $400.0 million remains available.
²Based on the facility repayment schedule, the reserves profile of the borrowing base assets and the facility maturity date.
³As at 30 June 2023, no cash amounts have been drawn, $7.7 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
Finance Income
Interest income
Finance Costs
Unwind discount on liabilities
Finance costs associated with lease liabilities
Interest expense
Total finance costs
Net finance costs
Accounting policy
2023
$'000
2022
$'000
3,019
468
(17,974)
(495)
(11,027)
(29,496)
(26,477)
(4,461)
(546)
(9,092)
(14,099)
(13,631)
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.
115
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
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.
On 20 June 2022, the Company announced a fully
underwritten $244 million equity offering, comprising a
2-for-5 accelerated, non-renounceable entitlement offer
(“ANREO”) to raise a total of $160 million, together with a
$84 million placement to institutional investors (the “2022
equity raising”).
Share Capital
Ordinary shares issued and fully paid
At 30 June 2023, the Group has utilised $158.0 million of
its reserves based lending facility.
The Group manages its capital structure and makes
adjustments in light of economic conditions and the
requirements of the 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.
2023
$'000
2022
$'000
716,726
478,261
Thousands
2022
$'000
1,631,026
477,675
-
-
1,708
-
-
586
Movement in ordinary shares on issue
At 1 July
Equity issue¹
Transfer from reserves²
Issuance of shares for performance rights and
share appreciation rights
Thousands
1,632,734
248,855
747,097
2,844
2023
$'000
478,261
58,596
179,508
361
At 30 June
2,631,530
716,726
1,632,734
478,261
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.
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.
116
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
19. Contributed equity and reserves (continued)
Cash raised from institutional portion of equity issue¹
179,508
Reserves
Consolidated
At 30 June 2021
Other comprehensive income/ (expenditure)
Transferred to retained earnings
Transferred to issued capital
Share-based payments
At 30 June 2022
Other comprehensive income/ (expenditure)
Transferred to issued capital
Share-based payments
At 30 June 2023
¹See footnote 2 under the Share Capital table above.
Share
capital
reserve
$’000
Consol.
Reserve
$’000
Share
based
payment
reserve
$’000
Option
premium
reserve
$’000
Equity
instrument
reserve
$’000
Total
$’000
-
-
-
-
-
(541)
15,080
25
-
-
-
-
-
-
-
-
(586)
4,011
-
-
-
-
-
179,508
(541)
18,505
25
-
(179,508)
-
-
-
-
-
-
(361)
7,667
-
-
-
(446)
(332)
14,118
(332)
-
179,508
906
-
-
128
648
-
-
906
(586)
4,011
197,625
648
(179,869)
7,667
(541)
25,811
25
776
26,071
Nature and purpose of reserves
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.
20. Financial risk management
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.
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.
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 below table.
Other financial assets – Non-Current
Equity instruments1
Escrow proceeds receivable
1 The equity instruments consist of one investment. The Group has not received dividends during the financial year.
Other financial liabilities – Non-Current
Success fee financial liability
Movement in carrying amount of the success fee financial liability:
Carrying amount at 1 July
Accretion of success fee liability
Fair value adjustment
Carrying amount at 30 June
2023
$'000
1,131
-
1,131
2,853
2,853
3,285
110
(542)
2,853
2022
$'000
483
1
484
3,285
3,285
3,582
28
(325)
3,285
117
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
20. Financial risk management (continued)
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:
Reserves
Financial assets
Trade and other receivables
Equity instruments
Escrow proceeds receivable
Financial liabilities
Trade and other payables
Success fee financial liability
Interest bearing loans and borrowings
Carrying amount
Fair value
Level
2023
$’000
2022
$’000
2023
$’000
2022
$’000
2
1
2
2
3
2
28,797
1,131
-
30,467
483
1
28,797
1,131
-
30,467
483
1
87,941
2,853
32,752
3,285
87,941
2,853
32,752
3,285
143,956
158,000
158,257
161,088
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 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.
Escrow proceeds receivable
During the 2018 financial year, the Group completed the
sale of OGPP to APA Group. A portion of proceeds from
the salewas held in escrow, to be released upon certain
conditions being satisfied. Amounts held in escrow
are measured at amortised cost in the Consolidated
Statement of Financial Position. During the period, the
funds were returned to the Group after financial close of
the acquisition of the OGPP from APA Group in
July 2022.
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 2023 equalled
4.03% (30 June 2022: 3.27%). 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.
118
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
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 2023 and 30 June 2022.
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.
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 Great
British pounds
and United States dollars. 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 2023, 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:
Financial assets
Cash
Trade and other receivables
2023
$'000
2022
$'000
29,956
-
25,631
2,313
b) Commodity price risk
Commodity price risk arises from the sale of oil
denominated in US dollars. The Group has provisional
sales at 30 June 2023 of $nil (2022: $2.3 million). From
time to time, the Group will 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 $158.0 million at 30 June
2023 (2022: $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
as a result of movement in the share price.
119
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
20. Financial risk management (continued)
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.
If the Australian dollar were 10% higher at the balance date
If the Australian dollar were 10% lower at the balance date
If the interest rates were 100 basis points higher at the balance date
If the interest rates were 100 basis points lower at the balance date
If the average Brent crude oil price were 10% higher at the balance date
If the average Brent crude oil price were 10% lower at the balance date
If the share price were 10% higher at the balance date
If the share price were 10% lower at the balance date
Credit risk
Liquidity risk
2023
$'000
2022
$'000
Impact on after tax profit
(2,723)
3,328
(1,580)
1,580
-
-
(2,540)
3,105
(1,580)
1,580
254
(252)
Impact on reserve
113
(113)
48
(48)
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 had no exposure to expected credit
losses. The Group 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 30 to 90 day terms. The Group
has some exposure to credit loss from other receivables
and an amount of $7.3 million calculated on lifetime
expected credit loss has been recognised in respect of
credit-impaired receivables.
Cash and cash equivalents are held at two financial
institutions that each have a Standard & Poor’s credit
rating of AA- (stable).
At 30 June 2023
Trade and other payables
Lease liabilities
Interest bearing loans and borrowings
Success fee financial liability
At 30 June 2022
Trade and other payables
Lease liabilities
Interest bearing loans and borrowings
Success fee financial liability
120
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 very 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
$’000
3 to 12
months
$’000
1 to 5
years
$’000
Greater
than 5
years
$’000
68,679
-
19,262
-
Total
$’000
87,941
12,263
495
3,022
-
1,428
9,066
-
9,284
1,056
197,286
-
209,374
-
5,000
6,056
5,000
314,578
72,196
10,494
225,832
32,752
-
-
-
433
1,308
8,763
2,302
12,149
32,671
128,079
-
-
5,000
-
-
32,752
12,806
172,899
5,000
45,334
33,979
141,842
2,302
223,457
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
Group Structure
21. Interests in joint arrangements
The Group has the following interests in joint arrangements involved in the exploration and/or production of oil and
gas in Australia:
Ownership Interest
2023
2022
Joint Arrangements in Australia in which Cooper Energy Limited is the Operator/manager
VIC/L24 & 30
VIC/P44
Gas exploration and production
Gas exploration
Athena Processing Plant
Gas processing services
Joint Arrangements in Australia in which Cooper Energy Limited is not the Operator/manager
PEL 494
PEP 168
PEP 171
PRL 32
PEL 680
Oil and gas exploration
Oil and gas exploration
Oil and gas exploration
Oil and gas exploration
Oil and gas exploration
PRL 85-104¹ (Formerly PEL 92)
Oil and gas exploration and production
PEL 931,2
PRL 237²
Oil and gas exploration and production
Oil and gas exploration
PRL 207-209 (Formerly PEL 100)²
Oil and gas exploration
PRL 183-190 (Formerly PEL 110)²
Oil and gas exploration
¹Includes associated PPLs.
50%
50%
50%
30%
50%
75%
30%
30%
25%
-
-
-
-
50%
50%
50%
30%
50%
75%
30%
30%
25%
30%
20%
19.165%
20%
²The assets and liabilities associated with these joint arrangements are held for sale as at 30 June 2022. The transaction completed on 2 August 2022.
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:
•
•
•
•
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
121
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
21. Interests in joint arrangements (continued)
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.
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
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.
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
Somerton Energy Limited
Essential Petroleum Exploration Pty Ltd
Cooper Energy (Australia) Pty Ltd
Cooper Energy (PBF) Pty Ltd
Cooper Energy (PB Pipelines) Pty Ltd
Cooper Energy (CH) Pty Ltd
Cooper Energy (TC) Pty Ltd
Cooper Energy (MF) Pty Ltd
Cooper Energy (MGP) Pty Ltd
Cooper Energy (IC) Pty Ltd
Cooper Energy (HC) Pty Ltd
Cooper Energy (EA) Pty Ltd
Cooper Energy (Sole) Pty Ltd
Cooper Energy (VO) Pty Ltd
Cooper Energy (Marketing) Pty Ltd
Country of incorporation
Australia
Note
(a)
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
2023
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
2022
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
122
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
Name
Cooper Energy (BMG) Pty Ltd
Cooper Energy (CB) Pty Ltd
Cooper Energy (Finance) Pty Ltd
Cooper Energy (AGP) Pty Ltd
Cooper Energy (CS) Pty Ltd
Cooper Energy (MS) Pty Ltd
Country of incorporation
Australia
Australia
Australia
Australia
Australia
Australia
Note
(a)
(a)
(a)
(a)
(a)(b)
(a)(b)
Ownership Interest
2023
100%
100%
100%
100%
100%
100%
2022
100%
100%
100%
100%
100%
100%
The parties that comprise the Closed Group are denoted by (a) and parties added to the Closed Group in 2023 are
denoted by (b)
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
Current Assets
Total Assets
Current Liabilities
Total Liabilities
Issued capital
Accumulated loss
Share capital reserve
Option premium reserve
Share based payment reserve
Total shareholders’ equity
Loss of the parent entity
Total comprehensive loss of the parent entity
2023
$'000
472,382
720,192
2022
$'000
576,522
793,012
186,501
223,784
48,322
209,296
716,726
(246,153)
-
25
25,810
496,408
478,261
(92,583)
179,508
25
18,505
583,716
(153,570)
(153,570)
(30,927)
(30,927)
123
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
Other Information
24. Commitments for expenditure
The Group has the following commitments for exploration
expenditure not provided for in the financial statements
and payable.
Due within 1 year
Due within 1-5 years
Total
2023
$'000
32,263
478
32,741
2022
$'000
31,360
32,735
64,095
From time to time through the ordinary course of
business, Cooper Energy enters into contractual
arrangements that may give rise to negotiated outcomes.
As at 30 June 2023 the parent entity has bank
guarantees for $7.7 million (2022: $7.1 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 equity incentive plan (“EIP”)
was approved by shareholders at the 2019 AGM.
Performance rights and share appreciation rights were
issued for no consideration under the EIP. 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
and 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 share
appreciation rights will occur at the end of the three
year performance period.
Rights granted prior to the 2020 financial year may be
retested once, 12 months after the original three year test
date. At the end of the three year measurement period,
those rights that were tested and achieved will vest.
The vesting test is determined from the absolute total
shareholder return of Cooper Energy’s share price ranked
against the absolute total shareholder returns of 12 peer
companies listed on the Australian Securities Exchange.
If Cooper Energy is ranked lower than the 50th percentile,
no rights will vest. If Cooper Energy is ranked in the 50th
percentile, 30% of the eligible rights will vest. If Cooper
Energy is ranked greater than the 50th percentile, but
less than the 90th percentile, the amount of eligible rights
vested will be based on a pro rata calculation. If Cooper
Energy is ranked in the 90th percentile or higher, 100% of
the eligible 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
11 December 2019
11 December 20191,2
10 December 2020
10 December 20202
9 December 2021
9 December 20212
9 December 2022
9 December 20222
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
14,871,802
4,257,209
-
769,605
20,473,191
6,394,202
-
1,885,834
28,449,812
9,043,984
-
3,159,165
20,636,373
7,608,195
-
8,641,505
$0.575
$0.575
$0.390
$0.390
$0.270
$0.270
$0.195
$0.195
3
1
3
1
3
1
3
1
-
-
0.5
-
1.5
-
2.5
0.5
¹Granted in December 2019 and exercised in December 2020.
²Relates to deferred STIP performance rights granted.
124
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
The number of performance rights and share appreciation rights held by employees is as follows:
Balance at beginning of year
- granted
- vested
- expired and not exercised
- forfeited
Balance at end of year
Achieved at end of year
¹Includes deferred STIP issued as performance rights.
Number of Share
Appreciation Rights
Number of Performance Rights¹
2023
2022
2023
2022
71,695,778
57,433,406
20,636,373
28,449,812
-
-
(25,781,761)
(14,187,440)
(5,742,766)
-
60,807,624
71,695,778
-
-
26,086,626
16,249,700
(2,844,324)
(8,772,365)
(2,024,845)
28,694,792
-
20,919,555
12,203,149
(1,708,495)
(5,327,583)
-
26,086,626
-
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 to produce 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
Fair value of share appreciation rights at measurement date
Fair value of performance rights at measurement date
11 December
2020
10 December
2021
9 December
2022
10.9 cents
25.6 cents
8.3 cents
18.5 cents
6.4 cents
13.4 cents
Share price
Risk free interest rate
Expected volatility
Dividend yield
39.0 cents
27.0 cents
19.5 cents
0.11%
45%
0%
0.97%
48%
0%
3.02%
52%
0%
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 to produce 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
125
COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements
For the year ended 30 June 2023
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.
Accounting policy (continued)
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.
27. Related party disclosures
28. Remuneration of Auditors
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:
2023
$
2022
$
Short-term benefits
5,829,184
6,509,385
Other long-term benefits
89,311
22,941
Post-employment benefits
303,572
277,601
Performance rights and share
appreciation rights
2,193,542
1,950,770
Termination benefits
2,534,604
26,076
Total
10,950,213
8,786,773
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
Other services
Services in relation to one off
transactions
2023
$
2022
$
486,380
444,700
486,380
444,700
228,000
Taxation and other services
49,500
119,100
Total fees to Ernst & Young
535,880
791,800
49,500
347,100
In 2022, a portion of total fees paid to Ernst & Young was
in relation to the acquisition of the OGPP.
29. Events after the reporting period
There are no significant events subsequent to 30 June
2023 at the date of this report.
126
COOPER ENERGY ANNUAL REPORT 2023 Directors’ Declaration
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 2023 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; and
(c) 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 2023.
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
Chairman
29 August 2023
Ms Jane L. Norman
Managing Director & CEO
127
COOPER ENERGY ANNUAL REPORT 2023
Independent auditor’s report to the members of
Cooper Energy Limited
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 2023, 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 a summary of significant accounting policies, and the directors’ declaration.
In our opinion, the accompanying financial report of the Group is in accordance with the Corporations
Act 2001, including:
a. Giving a true and fair view of the consolidated financial position of the Group as at 30 June 2023
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.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
128
COOPER ENERGY ANNUAL REPORT 2023 Page 2
1. Carrying value of gas and oil assets and exploration and evaluation assets
Why significant
How our audit addressed the key audit matter
As at 30 June 2023 the Group identified impairment
indicators in respect of a single cash generating unit
(‘CGU’). Impairment testing was undertaken, which
resulted in an impairment charge of $26 million being
recognised, as disclosed in Note 14 of the financial
report.
Australian Accounting Standards require the Group 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 such indication
exists, an entity shall estimate the recoverable amount of
the asset or CGU.
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. 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
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:
The assessments for indicators of impairment and
reversals of impairment are judgmental and include
assessing a range of external and internal factors.
Where impairment indicators are identified, forecasting
cash flows for the purpose of determining the
recoverable amount of a CGU involves accounting
estimates and judgements and is affected by expected
future performance and market conditions. The 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, and the
related disclosures in the financial report, to be a key
audit matter.
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:
Assessing the processes and controls associated
with estimating reserves and resources.
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129
COOPER ENERGY ANNUAL REPORT 2023 Page 3
Why significant
How our audit addressed the key audit matter
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:
Carrying out 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, as set out in 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.
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
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
130
COOPER ENERGY ANNUAL REPORT 2023 Why significant
Page 4
How our audit addressed the key audit matter
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 financial report
Note disclosures regarding the assumptions, key
estimates and judgments applied by the Group in relation
to the carrying values of exploration and evaluation, and
gas and oil assets.
2. Restoration obligations
Why significant
How our audit addressed the key audit matter
At 30 June 2023, the Group has recognised provisions
for restoration obligations relating to onshore and
offshore assets of $578 million. As disclosed in Note 15,
the calculation of restoration provisions is conducted by
specialist engineers and requires judgemental
assumptions 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
2023, 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 2023, there is uncertainty
whether the Australian regulator will approve plans for
these items to be decommissioned in-situ.
The significant assumptions and estimates outlined
above are inherently subjective. Changes to these
assumptions can lead to changes in the restoration
provisions. Accordingly, the disclosures in the financial
report provide information about the assumptions made
in the calculation of the restoration provision and
uncertainties at 30 June 2023, in arriving at the Group’s
best estimate of the present value of future obligations.
We consider the restoration provision calculation and the
related disclosures in the financial report to be 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
A member firm of Ernst & Young Global Limited
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131
COOPER ENERGY ANNUAL REPORT 2023 Page 5
Why significant
How our audit addressed the key audit matter
used to calculate the present value of each of the
provisions.
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 financial report
Note disclosure of the assumptions, key estimates and
judgements applied by the Group.
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 2023 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.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
132
COOPER ENERGY ANNUAL REPORT 2023 Page 6
Responsibilities of the directors for the financial report
The directors of the Company are responsible for the preparation of the financial report that gives a
true and fair view in accordance with Australian Accounting Standards and the Corporations Act 2001
and for such internal control as the directors determine is necessary to enable the preparation of the
financial report that gives a true and fair view and is free from material misstatement, whether due to
fraud or error.
In preparing the financial report, the directors are responsible for assessing the Group’s ability to
continue as a going concern, disclosing, as applicable, matters 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.
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.
A member firm of Ernst & Young Global Limited
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COOPER ENERGY ANNUAL REPORT 2023 Page 7
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 24 to 47 of the directors’ report for the
year ended 30 June 2023.
In our opinion, the Remuneration Report of Cooper Energy Limited for the year ended 30 June 2023,
complies with section 300A of the Corporations Act 2001.
Responsibilities
The directors of the Company are responsible for the preparation and presentation of the
Remuneration Report in accordance with section 300A of the Corporations Act 2001. Our
responsibility is to express an opinion on the Remuneration Report, based on our audit conducted in
accordance with Australian Auditing Standards.
Ernst & Young
D Hall
Partner
Adelaide
29 August 2023
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
134
COOPER ENERGY ANNUAL REPORT 2023 Auditor’s Independence Declaration to
the Directors of Cooper Energy Limited
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 2023, 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
29 August 2023
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
135
COOPER ENERGY ANNUAL REPORT 2023 Securities Exchange and Shareholder Information
As at 31 August 2023
Listing
Number of shareholders
The company’s shares are quoted on the Australian
Securities Exchange under the code of “COE”.
There were 9,051 shareholders. 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 2023)
Size of shareholding
Number of holders
Number of shares
% of issued capital
1 - 1,000
1,001 - 5,000
5,001 - 10,000
10,001 - 100,000
100,000 Over
Total
Unquoted options on issue
Nil
Unquoted Performance Rights
Number of holders of Performance Rights
75
13
Unmarketable parcels
1,000
2,182
1,387
3,485
997
257,014
6,233,347
11,258,934
130,485,296
2,483,296,669
0.01
0.24
0.43
4.96
94.37
9,051
2,631,531,260
100.00
Rights
28,694,792 Performance Rights
60,807,624 Share Appreciation Rights
There were 2,775 members, representing 4,535,383 shares, holding less than a marketable parcel of 4,167 shares in
the company.
Twenty largest shareholders
Rank
Name
Number of
shares
% of issued
capital
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
Citicorp Nominees Pty Limited
HSBC Custody Nominees (Australia) Limited - A/C 2
HSBC Custody Nominees Australia Limited
JP Morgan Nominees Australia Pty Limited
McCusker Holdings Pty Ltd
HSBC Custody Nominees (Australia) Limited - GSI EDA
National Nominees Limited
BNP Paribas Nominees Pty Ltd
BNP Paribas Noms Pty Ltd
UBS Nominees Pty Ltd
585,783,004
435,234,894
332,447,620
305,958,951
60,000,000
55,919,534
52,761,951
50,141,441
41,980,197
38,853,218
HSBC Custody Nominees (Australia) Limited
15,193,337
Invia Custodian Pty Limited
Zero Nominees
Mr Leendert Hoeksema
Invia Custodian Pty Limited
GZ Family Holdings Pty Ltd
Hooks Enterprises Pty Ltd
13,095,442
11,000,000
9,600,000
7,175,387
7,000,000
7,000,000
22.26
16.54
12.63
11.63
2.28
2.12
2.00
1.91
1.60
1.48
0.58
0.50
0.42
0.36
0.27
0.27
0.27
136
COOPER ENERGY ANNUAL REPORT 2023
18.
19.
20.
Mr Simon Hannes + Mrs Mignon Catherine Booth
Citicorp Nominees Pty Limited
Good Dog Enterprises Pty Ltd
6,895,323
6,759,573
6,400,000
0.26
0.26
0.24
Substantial shareholders
The following were substantial holders in the company, as disclosed in substantial holding notices given to the Company
as required by section 671B of the Corporations Act.
Name of entity
L1 Capital Pty Limited
Challenger Limited
Mitsubishi UFJ Financial
Perennial Value Management Limited
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
451,183,158
244,946,190
244,475,047
136,092,120
17.15%
10.29%
9.29%
5.17%
Enquiries and share registry address
Investor information
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. 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. Alternatively, holders can amend
their details on-line via the Computershare website.
Shareholders who have broker sponsored holdings
should contact their broker to update these details.
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: Morgan Wright,
Investor Relations Lead, +61 8 8100 4982
morgan.wright@cooperenergy.com.au
This Annual Report has been prepared to provide
Shareholders with an overview of Cooper Energy
Limited’s performance for the 2023 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 cooperenergy.com.au
Annual Report mailing list
Annual General Meeting
Shareholders who wish to vary their annual report
mailing arrangements should advise Computershare in
writing. 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. Annual Report
election forms can be downloaded from the
Computershare website.
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.
Date of meeting: Thursday, 9 November 2023
Time of meeting: 10:30 am (Australian Central
Daylight Time)
Place of meeting: Peppers Waymouth Hotel,
55 Waymouth 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 the website at
cooperenergy.com.au.
COOPER ENERGY ANNUAL REPORT 2023
137
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 “2023”, or
“2023 financial year” refer to the 12 months ended 30
June 2023 unless otherwise stated. References to “2022”,
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
LTIFR: lost time injury frequency rate: lost time injuries
per million hours worked
Mitsui: Mitsui E&P Australia and its associated entities
AEMO: Australian Energy Market Operator
AER: Australian Energy Regulator
AGP: Athena gas plant
ANREO: accelerated, non-renounceable entitlement offer
Bass: Bass Oil Limited
bbls: barrels of oil
boe: barrels of oil equivalent
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
MMbbl: million barrels of oil
MMboe: million barrels of oil equivalent
MTI: medical treatment injury
NPAT: net profit after tax
OGPP: Orbost gas processing plant
OP3D: Otway phase three development
Pertamina: PT Pertamina Hulu Energi
PJ: petajoules
PRRT: Petroleum resource rent tax
STIP: short-term incentive plan
TJ: terajoules
TRCFR: total recordable case frequency rate. Recordable
cases per million hours worked
FVLCD: fair value less cost of disposal
TRIFR: total recordable injury frequency rate
The Gas Code: Mandatory Gas Code of Conduct
TSA: transitional services agreement
GSA: gas sales agreement
GST: goods and services taxes
US: United States
VUI: value in use
HSEC: health, safety, environment and community
VWAP: volume weighted average price
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
2P: best estimate of reserves. The sum of proved plus
probable reserves
2C: best estimate of contingent resources
138
COOPER ENERGY ANNUAL REPORT 2023
Corporate Directory
Directors
John C Conde AO, Chairman
Jane L Norman, Managing Director & CEO
Timothy G Bednall
Victoria J Binns
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 655 248
International: +61 3 9415 4887
Facsimile: +61 3 9473 2500
COOPER ENERGY ANNUAL REPORT 2023
139